Securities registered pursuant to Section 12(b) of the Act:
BERKSHIRE
HATHAWAY ENERGY COMPANY
None
PACIFICORP
None
MIDAMERICAN FUNDING, LLC
None
MIDAMERICAN ENERGY COMPANY
None
NEVADA POWER COMPANY
None
SIERRA PACIFIC POWER COMPANY
None
EASTERN ENERGY GAS HOLDINGS, LLC
None
EASTERN
GAS TRANSMISSION AND STORAGE, INC.
None
Registrant
Name of exchange on which registered:
BERKSHIRE HATHAWAY ENERGY COMPANY
None
PACIFICORP
None
MIDAMERICAN FUNDING, LLC
None
MIDAMERICAN ENERGY COMPANY
None
NEVADA
POWER COMPANY
None
SIERRA PACIFIC POWER COMPANY
None
EASTERN ENERGY GAS HOLDINGS, LLC
None
EASTERN GAS TRANSMISSION AND STORAGE, INC.
None
Registrant
Securities registered pursuant to Section 12(g) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY
None
PACIFICORP
None
MIDAMERICAN
FUNDING, LLC
None
MIDAMERICAN ENERGY COMPANY
None
NEVADA POWER COMPANY
iCommon Stock, $1.00 stated value
SIERRA PACIFIC POWER COMPANY
iCommon Stock, $3.75 par value
EASTERN
ENERGY GAS HOLDINGS, LLC
None
EASTERN GAS TRANSMISSION AND STORAGE, INC.
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Registrant
iiYes/
iiiiiiNo/////
BERKSHIRE
HATHAWAY ENERGY COMPANY
☐
☒
PACIFICORP
☒
☐
MIDAMERICAN FUNDING, LLC
☐
☒
MIDAMERICAN ENERGY COMPANY
☐
☒
NEVADA POWER COMPANY
☒
☐
SIERRA
PACIFIC POWER COMPANY
☐
☒
EASTERN ENERGY GAS HOLDINGS, LLC
☐
☒
EASTERN GAS TRANSMISSION AND STORAGE, INC.
☐
☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Registrant
iYes
iiiiiiiNo//////
BERKSHIRE
HATHAWAY ENERGY COMPANY
☐
☒
PACIFICORP
☐
☒
MIDAMERICAN FUNDING, LLC
☒
☐
MIDAMERICAN ENERGY COMPANY
☐
☒
NEVADA POWER COMPANY
☐
☒
SIERRA
PACIFIC POWER COMPANY
☐
☒
EASTERN ENERGY GAS HOLDINGS, LLC
☐
☒
EASTERN GAS TRANSMISSION AND STORAGE, INC.
☐
☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Registrant
iiiiiiiYes//////
iNo
BERKSHIRE
HATHAWAY ENERGY COMPANY
☒
☐
PACIFICORP
☒
☐
MIDAMERICAN FUNDING, LLC
☐
☒
MIDAMERICAN ENERGY COMPANY
☒
☐
NEVADA POWER COMPANY
☒
☐
SIERRA
PACIFIC POWER COMPANY
☒
☐
EASTERN ENERGY GAS HOLDINGS, LLC
☒
☐
EASTERN GAS TRANSMISSION AND STORAGE, INC.
☒
☐
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such
files). iiiiiiiiYes///////
☒ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer,""accelerated filer,""smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Registrant
Large
accelerated filer
Accelerated filer
iiiiiiiiNon-accelerated
filer///////
Smaller reporting
company
Emerging growth company
BERKSHIRE HATHAWAY ENERGY COMPANY
☐
☐
☒
i☐
i☐
PACIFICORP
☐
☐
☒
i☐
i☐
MIDAMERICAN
FUNDING, LLC
☐
☐
☒
i☐
i☐
MIDAMERICAN ENERGY
COMPANY
☐
☐
☒
i☐
i☐
NEVADA POWER COMPANY
☐
☐
☒
i☐
i☐
SIERRA
PACIFIC POWER COMPANY
☐
☐
☒
i☐
i☐
EASTERN
ENERGY GAS HOLDINGS, LLC
☐
☐
☒
i☐
i☐
EASTERN
GAS TRANSMISSION AND STORAGE, INC.
☐
☐
☒
i☐
i☐
If
an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. iiiiiiii☐///////
If
securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. iiiiiiii☐///////
Indicate
by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes iiiiiiii☐///////
No ☒
All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of January 31, 2024, i75,627,913 shares of common stock, no par value, were outstanding.
All
shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of January 31, 2024, i357,060,915 shares of common stock, no par value, were outstanding.
All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of January 31, 2024.
All
shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of January 31, 2024, i70,980,203 shares of common stock, no par value, were outstanding.
All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy
Company. As of January 31, 2024, i1,000 shares of common stock, $1.00 stated value, were outstanding.
All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. As of January 31, 2024, i1,000
shares of common stock, $3.75 par value, were outstanding.
All of the member's equity of Eastern Energy Gas Holdings, LLC is held indirectly by its parent company, Berkshire Hathaway Energy Company, as of January 31, 2024.
All shares of outstanding common stock of Eastern Gas Transmission and Storage, Inc. are owned by its parent company, Eastern Energy Gas Holdings, LLC, which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of January 31, 2024, i60,101
shares of common stock, $10,000 par value, were outstanding.
Berkshire Hathaway Energy Company, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing portions of this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10‑K.
This combined Form 10-K is separately filed by Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. Information contained herein
relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.
When used in Forward-Looking Statements, Part I - Items 1 through 4, Part II - Items 5 through 7A, and Part III - Items 10 through 14, the following terms have the definitions indicated.
Entity Definitions
BHE
Berkshire Hathaway Energy Company
Berkshire Hathaway
Berkshire Hathaway Inc.
Berkshire
Hathaway Energy or the Company
Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp
PacifiCorp and its subsidiaries
MidAmerican Funding
MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy
MidAmerican Energy Company
NV Energy
NV Energy, Inc. and its subsidiaries
Nevada Power
Nevada
Power Company and its subsidiaries
Sierra Pacific
Sierra Pacific Power Company and its subsidiaries
Nevada Utilities
Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Eastern Energy Gas
Eastern Energy Gas Holdings, LLC and its subsidiaries
EGTS
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Registrants
Berkshire
Hathaway Energy Company, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, Eastern Energy Gas Holdings, LLC and its subsidiaries and Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Subsidiary Registrants
PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, Eastern Energy Gas Holdings, LLC and its subsidiaries and Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Northern Powergrid
Northern
Powergrid Holdings Company and its subsidiaries
BHE GT&S
BHE GT&S, LLC and its subsidiaries
Northern Natural Gas
Northern Natural Gas Company
Kern River
Kern River Gas Transmission Company
CGT
Carolina Gas Transmission, LLC
BHE Canada
BHE Canada Holdings Corporation
and its subsidiaries
AltaLink
AltaLink, L.P.
BHE U.S. Transmission
BHE U.S. Transmission, LLC and its subsidiaries
HomeServices
HomeServices of America, Inc. and its subsidiaries
BHE Pipeline Group or Pipeline Companies
BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE
Transmission
BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Renewables
BHE Renewables, LLC and its subsidiaries
ETT
Electric Transmission Texas, LLC
Domestic Regulated Businesses
PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC and its subsidiaries, Northern Natural Gas Company and Kern River Gas Transmission Company
Regulated
Businesses
PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC and its subsidiaries, Northern Natural Gas Company, Kern River Gas Transmission Company and AltaLink, L.P.
Utilities
PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
ii
Northern
Powergrid Distribution Companies
Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc
Topaz
Topaz Solar Farms LLC
Topaz Project
550-megawatt solar project in California
Agua Caliente
Agua Caliente Solar, LLC
Agua Caliente Project
290-megawatt solar project in Arizona
Bishop
Hill II
Bishop Hill Energy II LLC
Bishop Hill Project
81-megawatt wind-powered generating facility in Illinois
Pinyon Pines I
Pinyon Pines Wind I, LLC
Pinyon Pines II
Pinyon Pines Wind II, LLC
Pinyon Pines Projects
168-megawatt and 132-megawatt wind-powered generating facilities in California
Jumbo
Road
Jumbo Road Holdings, LLC
Jumbo Road Project
300-megawatt wind-powered generating facility in Texas
Solar Star Funding
Solar Star Funding, LLC
Solar Star Projects
A combined 586-megawatt solar project in California
Solar Star I
Solar Star California XIX, LLC
Solar
Star II
Solar Star California XX, LLC
Cove Point
Cove Point LNG, LP
Iroquois
Iroquois Gas Transmission System, L.P.
DEI
Dominion Energy, Inc.
Liquefaction Facility
A natural gas export/liquefaction facility
Certain
Industry Terms
2020 Wildfires
Wildfires in Oregon and Northern California that occurred in September 2020
2022 McKinney Fire
A wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022
Wildfires
2020 Wildfires and 2022 McKinney Fire
AESO
Alberta
Electric System Operator
AFUDC
Allowance for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income (Loss)
ARO
Asset Retirement Obligation
ASC
Accounting Standards Codification
AUC
Alberta Utilities Commission
BART
Best
Available Retrofit Technology
Bcf
Billion cubic feet
BTER
Base Tariff Energy Rate
California ISO
California Independent System Operator Corporation
CCR
Coal Combustion Residuals
COVID-19
Coronavirus Disease 2019
CPUC
California
Public Utilities Commission
CSAPR
Cross-State Air Pollution Rule
D.C. Circuit
U.S. Court of Appeals for the District of Columbia Circuit
DEAA
Deferred Energy Accounting Adjustment
DOE
U.S. Department of Energy
Dodd-Frank Reform Act
Dodd-Frank Wall Street Reform and Consumer Protection Act
DOT
U.S.
Department of Transportation
Dth
Decatherm
DSM
Demand-side Management
iii
EAC
Energy Adjustment Clause
EBA
Energy
Balancing Account
ECAC
Energy Cost Adjustment Clause
ECAM
Energy Cost Adjustment Mechanism
EEIR
Energy Efficiency Implementation Rate
EEPR
Energy Efficiency Program Rate
EIM
Energy Imbalance Market
EPA
U.S.
Environmental Protection Agency
ERCOT
Electric Reliability Council of Texas
FERC
Federal Energy Regulatory Commission
FIP
Federal Implementation Plan
GAAP
Accounting principles generally accepted in the United States of America
GEMA
Gas and Electricity Markets Authority
GHG
Greenhouse
Gases
GWh
Gigawatt Hour
ICC
Illinois Commerce Commission
IPUC
Idaho Public Utilities Commission
IRP
Integrated Resource Plan
IUB
Iowa Utilities Board
kV
Kilovolt
LNG
Liquefied
Natural Gas
LDC
Local Distribution Company
MATS
Mercury and Air Toxics Standards
MISO
Midcontinent Independent System Operator, Inc.
MW
Megawatt
MWh
Megawatt Hour
NAAQS
National
Ambient Air Quality Standards
NERC
North American Electric Reliability Corporation
NOx
Nitrogen Oxides
NRC
Nuclear Regulatory Commission
OATT
Open Access Transmission Tariff
OCA
Iowa Office of Consumer Advocate
OCI
Other
Comprehensive Income (Loss)
Ofgem
Office of Gas and Electric Markets
OPUC
Oregon Public Utility Commission
PCAM
Power Cost Adjustment Mechanism
PGA
Purchased Gas Adjustment Clause
PTAM
Post Test-year Adjustment Mechanism
PTC
Production
Tax Credit
PUCN
Public Utilities Commission of Nevada
RCRA
Resource Conservation and Recovery Act
RAC
Renewable Adjustment Clause
REC
Renewable Energy Credit
RFP
Request for Proposals
RPS
Renewable
Portfolio Standards
RRA
Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism
RTO
Regional Transmission Organization
iv
SCR
Selective Catalytic Reduction
SEC
U.S.
Securities and Exchange Commission
SIP
State Implementation Plan
SO2
Sulfur Dioxide
TAM
Transition Adjustment Mechanism
UPSC
Utah Public Service Commission
VIE
Variable Interest Entity
WECC
Western
Electricity Coordinating Council
WMP AAC
Wildfire Mitigation Plan Automatic Adjustment Clause
WPSC
Wyoming Public Service Commission
WUTC
Washington Utilities and Transportation Commission
ZEC
Zero Emission Credit
v
Forward-Looking
Statements
This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will,""may,""could,""project,""believe,""anticipate,""expect,""estimate,""continue,""intend,""potential,""plan,""forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, estimates, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control
of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:
•general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry and reliability and safety standards, affecting the respective Registrant's operations or related industries;
•changes in, and compliance with, environmental laws, regulations, decisions and policies, whether directed towards protection of environmental resources, present and future climate considerations or social justice concerns that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility
retirements or delay facility construction or acquisition;
•the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner;
•changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;
•performance, availability and ongoing operation of the respective Registrant's facilities, including facilities
not operated by the Registrants, due to the impacts of market conditions, outages and associated repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions;
•the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, extreme temperature events, wind events, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, costly litigation, wars, terrorism, pandemics, embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;
•the risks and uncertainties associated with wildfires that have occurred, are occurring or may occur in the respective
Registrant's service territory; the damage caused by such wildfires; the extent of the respective Registrant's liability in connection with such wildfires (including the risk that the respective Registrant may be found liable for damages regardless of fault); investigations into such wildfires; the outcomes of any legal proceedings, demands or similar actions initiated against the respective Registrant; the risk that the respective Registrant is not able to recover losses from insurance or through rates; and the effect of such wildfires, investigations and legal proceedings on the respective Registrant's financial condition and reputation;
•the outcomes of legal or other actions and the effects of amounts to be paid to complainants as a result of settlements or final legal determinations associated with the 2020 Wildfires and the 2022 McKinney Fire (referred to together as "the Wildfires"), which
could have a material adverse effect on PacifiCorp's financial condition and could limit PacifiCorp's ability to access capital on terms commensurate with historical transactions or at all and could impact PacifiCorp's liquidity, cash flows and capital expenditure plans;
•the respective Registrant's ability to reduce wildfire threats and improve safety, including the ability to comply with the targets and metrics set forth in its wildfire mitigation plans; to retain or contract for the workforce necessary to execute its wildfire mitigation plans; the effectiveness of its system hardening; ability to achieve vegetation management targets; and the cost of these programs and the timing and outcome of any proceeding to recover such costs through rates;
•the ability to economically obtain insurance coverage, or any insurance coverage at all,
sufficient to cover losses arising from catastrophic events, such as wildfires;
•a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;
vi
•changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;
•the financial condition, creditworthiness and operational stability of the respective Registrant's significant
customers and suppliers;
•changes in business strategy or development plans;
•availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates and credit spreads;
•changes in the respective Registrant's credit ratings, changes in rating methodology and placement on negative outlook or credit watch;
•risks relating to nuclear generation, including unique operational, closure and decommissioning risks;
•hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing
proceedings;
•the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;
•the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;
•fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;
•increases in employee healthcare costs;
•the impact of investment performance, certain participant elections such as lump sum distributions and
changes in interest rates, legislation, healthcare cost trends, mortality, morbidity on pension and other postretirement benefits expense and funding requirements;
•changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and franchising transactions;
•the ability to successfully integrate future acquired operations into a Registrant's business;
•the impact of supply chain disruptions and workforce availability on the respective Registrant's ongoing operations and its ability to timely complete construction projects;
•unanticipated construction delays, changes in costs, receipt of required permits and authorizations,
ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;
•the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
•the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and
•other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.
Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with
the SEC, including Item 1A and other discussions contained in this Form 10-K. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.
vii
PART I
Item 1.Business
GENERAL
BHE
is a holding company that owns a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway that, as of January 31, 2024, owned 92% of BHE's voting common stock. The balance of BHE's voting common stock is privately held by a limited group of investors.
The Company's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE Transmission (which consists of
BHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in the U.S., one of which owns an LNG export, import and storage facility, an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, one of the largest residential real estate brokerage firms and residential real estate brokerage franchise networks in the U.S.
BHE owns a highly diversified portfolio of primarily regulated businesses that generate, transmit, store, distribute and supply energy and serve
customers and end-users across geographically diverse service territories, including 28 states located throughout the U.S. and in Great Britain and Canada.
•Approximately 80% of the Company's consolidated adjusted earnings on common shares during 2023 was generated from rate-regulated businesses.
•The Utilities serve 5.3 million electric and natural gas customers in 11 states in the U.S., Northern Powergrid serves 4.0 million end-users in northern England and AltaLink serves approximately 85% of Alberta, Canada's population.
•As of December 31, 2023, the Company owns approximately 36,000 MWs of generation capacity in operation and under construction:
◦Approximately
30,100 MWs of generation capacity is owned by its regulated electric utility businesses;
◦Approximately 5,900 MWs of generation capacity is owned by its nonregulated subsidiaries, the majority of which provides power to utilities under long-term contracts;
◦Owned generation capacity in operation and under construction consists of 42% wind and solar, 32% natural gas, 21% coal, 4% hydroelectric and geothermal and 1% nuclear and other; and,
◦Cumulative investments in (i) owned wind, solar and geothermal generation facilities of $34.1 billion and (ii) wind projects sponsored by third parties, commonly referred to as tax equity investments, of $5.8 billion.
•The Company owns approximately
36,400 miles of electric transmission lines, a 50% interest in ETT that has approximately 2,000 miles of electric transmission lines, approximately 176,800 miles of electric distribution lines and approximately 2,800 substations.
•The BHE Pipeline Group operates approximately 21,000 miles of pipeline with a design capacity of approximately 21.1 Bcf of natural gas per day, transported approximately 15% of the total natural gas consumed in the U.S. during 2023 and owns assets in 27 states. The BHE Pipeline Group also operates 22 natural gas storage facilities with a total working gas capacity of 515.6 Bcf and an LNG export, import and storage facility.
•HomeServices closed approximately $136.1 billion of home sales in 2023 and has brokerage, mortgage and franchise services in all 50 states. HomeServices' franchise business has approximately
300 franchisees primarily in the U.S.
1
Human Capital
The Registrants are committed to attracting, retaining and developing the highest quality of employees; maintaining a safe, diverse and inclusive work environment; offering competitive compensation and benefit programs; and providing employees with opportunities for growth and development.
Employees
As of December 31, 2023, the Company had approximately 23,700 employees, consisting
of approximately 14,300 (60%) electric and natural gas operations employees, approximately 5,800 (24%) real estate services employees and approximately 3,600 (15%) corporate services employees. HomeServices has approximately 41,000 real estate agents who are independent contractors. As of December 31, 2023, approximately 8,900 employees were covered by union contracts. The majority of the union employees are employed by the Utilities and are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the United Utility Workers Association and the International Brotherhood of Boilermakers.
Safety and Security
Safety and security are integral to the Registrants' culture and will always be a part of the Registrants'
top priorities. The Registrants' safety, cyber and physical security programs are built on personal ownership, compliance with standards, accountability for performance, and continuous improvement. The Registrants provide best-in-class training to ensure that all employees understand the risks and have thorough and specific knowledge to protect themselves, as well as the Registrants' assets, information and operations.
The Registrants use the recordable incident rate to measure employee safety. The recordable incident rate is defined as the number of work-related injuries per 100 full-time workers during a given year. The recordable incident rates for each of the Registrants for the year ended December 31, 2023 are included below:
Recordable
Incident Rate:
PacifiCorp
0.48
MidAmerican Energy
0.90
Nevada Power
0.55
Sierra Pacific
0.57
Eastern
Energy Gas
0.32
EGTS
0.39
BHE Overall
0.41
Compensation and Benefits
The Registrants' commitment to employees is further demonstrated through competitive
compensation and benefits and by providing opportunities for personal growth and career development. In addition to market-based salary, the Registrants' compensation packages include incentive programs to recognize and reward outstanding performance. The Registrants' benefits programs are designed to meet the diverse needs of employees and their families and include among other benefits:
•A comprehensive and flexible benefits package that includes medical, dental and vision coverage; employee assistance programs; pre-tax flexible spending accounts; and adoption assistance;
•Income protection that includes options for short- and long-term disability coverage and life insurance;
•Retirement planning that includes a retirement savings
plan 401(k) and a variety of employee and employer contribution and matching options;
•Family Medical Leave as well as paid time off, bereavement leave and holiday benefits; and
•Career development opportunities that provide access to a variety of learning programs and career development support, including tuition reimbursement or assistance.
BHE was incorporated under the laws of the state of Iowa in 1999 and its principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa50309-2580, its telephone number is
(515) 242-4300 and its internet address is www.brkenergy.com.
2
PACIFICORP
General
PacifiCorp, an indirect wholly owned subsidiary of BHE, is a U.S. regulated electric utility company headquartered in Oregon that serves
approximately 2.1 million retail electric customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is principally engaged in the business of generating, transmitting, distributing and selling electricity. PacifiCorp's combined service territory covers approximately 141,500 square miles and includes diverse regional economies across six states. No single segment of the economy dominates the combined service territory, which helps mitigate PacifiCorp's exposure to economic fluctuations. In the eastern portion of the service territory, consisting of Utah, Wyoming and southeastern Idaho, the principal industries are manufacturing, mining or extraction of natural resources, agriculture, technology, recreation and government. In the western portion of the service territory, consisting of Oregon, southern Washington and northern California, the principal industries are agriculture, manufacturing, forest products, food processing, technology,
government and primary metals. In addition to retail sales, PacifiCorp buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants to balance and optimize the economic benefits of electricity generation, retail customer loads and existing wholesale transactions. Certain PacifiCorp subsidiaries support its electric utility operations by providing coal mining services.
PacifiCorp's operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The average term of the franchise agreements is approximately 22 years. Several of these franchise agreements allow the municipality the right to seek amendment to the franchise agreement at a specified time during the term. PacifiCorp generally has an exclusive right to
serve electric customers within its service territories and, in turn, has an obligation to provide electric service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow PacifiCorp an opportunity to recover its costs of providing services and to earn a reasonable return on its investments.
PacifiCorp was incorporated under the laws of the state of Oregon in 1989. Its principal executive offices are located at 825 N.E. Multnomah Street, Suite 1900 Portland, Oregon97232, its telephone number is (888)
221-7070 and its internet address is www.pacificorp.com. PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington and California under the trade name Pacific Power.
All shares of PacifiCorp's common stock are indirectly owned by BHE. PacifiCorp also has shares of preferred stock outstanding that are subject to voting rights in certain limited circumstances.
Regulated Electric Operations
Customers
The GWhs and percentages of
electricity sold to PacifiCorp's retail customers by jurisdiction for the years ended December 31 were as follows:
2023
2022
2021
Utah
26,062
46
%
26,110
46
%
25,657
46
%
Oregon
13,949
25
13,701
24
13,510
24
Wyoming
8,579
15
8,666
15
8,557
15
Washington
3,850
7
4,181
7
4,199
8
Idaho
3,496
6
3,707
7
3,553
6
California
760
1
799
1
798
1
Total
56,696
100
%
57,164
100
%
56,274
100
%
3
Electricity
sold to PacifiCorp's retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:
2023
2022
2021
GWhs
sold:
Residential
18,159
31
%
18,425
30
%
17,905
29
%
Commercial
20,491
34
19,570
32
18,839
31
Industrial
16,705
28
17,622
28
17,909
29
Other
1,341
2
1,547
2
1,621
3
Total
retail
56,696
95
57,164
92
56,274
92
Wholesale
2,911
5
4,836
8
5,113
8
Total
GWhs sold
59,607
100
%
62,000
100
%
61,387
100
%
Average
number of retail customers (in thousands):
Residential
1,806
87
%
1,775
87
%
1,745
87
%
Commercial
227
11
225
11
222
11
Industrial
9
1
9
1
9
1
Other
27
1
28
1
27
1
Total
2,069
100
%
2,037
100
%
2,003
100
%
Variations
in weather, economic conditions and various conservation, energy efficiency and private generation measures and programs can impact customer energy requirements. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate electricity.
The annual hourly peak customer demand, which represents the highest demand on a given day and at a given hour, occurs in the summer when air conditioning and irrigation systems are heavily used. Peak demand in the winter occurs due to heating requirements. During 2023, PacifiCorp's peak demand was 10,802 MWs in the summer and 8,998 MWs in the winter.
Generating Facilities and Fuel Supply
PacifiCorp has ownership interest in a diverse portfolio
of generating facilities. The following table presents certain information regarding PacifiCorp's owned generating facilities as of December 31, 2023:
Facility
Net
Owned
Installed /
Net Capacity
Capacity
Generating Facility
Location
Energy Source
Repowered(1)
(MWs)(2)
(MWs)(2)
COAL:
Hunter
Nos. 1, 2 and 3
Castle Dale, UT
Coal
1978-1983
1,363
1,158
Huntington Nos. 1 and 2
Huntington, UT
Coal
1974-1977
909
909
Dave
Johnston Nos. 1, 2, 3 and 4
Glenrock, WY
Coal
1959-1972
745
745
Jim Bridger Nos. 3 and 4(3)
Rock Springs, WY
Coal
1976-1979
1,049
700
Naughton
Nos. 1 and 2
Kemmerer, WY
Coal
1963-1968
357
357
Wyodak No. 1
Gillette, WY
Coal
1978
332
266
Craig
Nos. 1 and 2
Craig, CO
Coal
1979-1980
837
161
Colstrip Nos. 3 and 4
Colstrip, MT
Coal
1984-1986
1,480
148
Hayden
Nos. 1 and 2
Hayden, CO
Coal
1965-1976
441
77
7,513
4,521
NATURAL GAS:
Lake
Side 2
Vineyard, UT
Natural gas/steam
2014
631
631
Lake Side
Vineyard, UT
Natural gas/steam
2007
546
546
Currant
Creek
Mona, UT
Natural gas/steam
2005-2006
524
524
Chehalis
Chehalis, WA
Natural gas/steam
2003
477
477
Naughton
No. 3(4)
Kemmerer, WY
Natural gas
1971
247
247
Gadsby Steam
Salt Lake City, UT
Natural gas
1951-1955
238
238
Hermiston
Hermiston,
OR
Natural gas/steam
1996
461
231
4
Facility
Net
Owned
Installed /
Net Capacity
Capacity
Generating Facility
Location
Energy Source
Repowered(1)
(MWs)(2)
(MWs)(2)
Gadsby
Peakers
Salt Lake City, UT
Natural gas
2002
119
119
3,243
3,013
WIND:
TB
Flats
Medicine Bow, WY
Wind
2020-2021
500
500
Ekola Flats
Medicine Bow, WY
Wind
2020
250
250
Pryor
Mountain
Bridger, MT
Wind
2020-2021
240
240
Marengo
Dayton, WA
Wind
2007-2008 / 2020
234
234
Cedar
Springs II
Douglas, WY
Wind
2020
199
199
Glenrock
Glenrock, WY
Wind
2008-2009 / 2019
139
139
Seven
Mile Hill
Medicine Bow, WY
Wind
2008 / 2019
119
119
Dunlap Ranch
Medicine Bow, WY
Wind
2010 / 2020
111
111
Leaning
Juniper
Arlington, OR
Wind
2006 / 2019
100
100
Rolling Hills
Glenrock, WY
Wind
2009 / 2019
100
100
High
Plains
McFadden, WY
Wind
2009 / 2019
99
99
Goodnoe Hills
Goldendale, WA
Wind
2008 / 2019
94
94
Foote
Creek I
Arlington, WY
Wind
1999 / 2021
41
41
McFadden Ridge
McFadden, WY
Wind
2009 / 2019
28
28
Foote
Creek III
Arlington, WY
Wind
2023
25
25
Foote Creek IV
Arlington, WY
Wind
2023
17
17
2,296
2,296
HYDROELECTRIC:
Lewis
River System
WA
Hydroelectric
1931-1958
578
578
North Umpqua River System
OR
Hydroelectric
1950-1956
204
204
Bear
River System
ID, UT
Hydroelectric
1908-1984
105
105
Rogue River System
OR
Hydroelectric
1912-1957
52
52
Minor
hydroelectric facilities
Various
Hydroelectric
1895-1986
32
32
971
971
OTHER:
Blundell
Milford,
UT
Geothermal
1984, 2007
32
32
32
32
Total
Available Generating Capacity
14,055
10,833
PROJECTS UNDER CONSTRUCTION:
Various
projects
642
642
14,697
11,475
(1)Repowered dates are associated with component replacements on existing wind-powered generating facilities commonly referred
to by the U.S. Internal Revenue Service ("IRS") as repowering. IRS rules provide for re-establishment of the PTCs for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement in such projects meets IRS guidelines, PTCs are re-established for 10 years beginning with the date the repowered facility is placed in‑service.
(2)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates PacifiCorp's ownership of Facility Net Capacity.
(3)During
2023, Jim Bridger Units 1 and 2 operated under a consent decree as described in "Environmental Laws and Regulations" in Item 1 of this Form 10-K. PacifiCorp removed Jim Bridger Units 1 and 2 from coal-fueled service in December 2023 and will convert them to natural gas-fueled generation facilities in 2024.
(4)Naughton No. 3 was converted from a coal-fueled to a natural gas-fueled generating facility in 2020.
5
The following table shows the percentages of PacifiCorp's total energy supplied by energy source for the years ended December 31:
2023
2022
2021
Coal
34
%
43
%
48
%
Natural
gas
22
21
20
Wind(1)
10
11
10
Hydroelectric and other(1)
5
5
5
Total
energy generated
71
80
83
Energy purchased - long-term contracts (renewable)(1)
16
15
15
Energy purchased - short-term contracts and other
12
5
2
Energy
purchased - long term contracts (non-renewable)
1
—
—
100
%
100
%
100
%
(1)All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with
RPS or other regulatory requirements, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.
PacifiCorp is required to have resources available to continuously meet its customer needs and reliably operate its electric system. The percentage of PacifiCorp's energy supplied by energy source varies from year to year and is subject to numerous operational, economic and environmental factors such as planned and unplanned outages, fuel commodity prices, fuel availability, fuel transportation costs, weather, legislative considerations, transmission constraints and wholesale market prices of electricity. PacifiCorp evaluates these factors continuously in order to facilitate economic dispatch of its generating facilities. When factors for one energy source are less favorable, PacifiCorp places more reliance on other energy sources.
For example, PacifiCorp can generate more electricity using its low-cost wind-powered and hydroelectric generating facilities when factors associated with these facilities are favorable. In addition to meeting its customers' energy needs, PacifiCorp is required to maintain operating reserves on its system to mitigate the impacts of unplanned outages or other disruption in supply, and to meet intra-hour changes in load and resource balance. This operating reserve requirement is dispersed across PacifiCorp's generation portfolio on a least-cost basis based on the operating characteristics of the portfolio. Operating reserves may be held on hydroelectric, coal-fueled, natural gas-fueled or certain types of interruptible load. PacifiCorp manages certain risks relating to its supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives and may include forwards, options, swaps and other agreements. Refer to "General
Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and to PacifiCorp's Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.
Coal
PacifiCorp has interests in coal mines that support its coal-fueled generating facilities and jointly operates the Bridger surface coal mine. The Bridger underground mine ceased coal production in November 2021. These mines supplied 18%, 21% and 21% of PacifiCorp's total coal requirements during the years ended December 31, 2023, 2022 and 2021, respectively.
Most
of PacifiCorp's coal reserves are held through agreements with the federal Bureau of Land Management and from certain states and private parties. The agreements generally have multi-year terms that may be renewed or extended and require payment of rents and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities.
Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves.
Recoverability by surface mining methods typically ranges from 90% to 95%. To meet applicable standards,
PacifiCorp blends its coal with contracted coal and utilizes emissions reduction technologies for controlling SO2 and other emissions.
6
For fuel needs at PacifiCorp's coal-fueled generating facilities in excess of coal reserves available, PacifiCorp believes it will be able to purchase coal under both long- and short-term third-party contracts to supply the remaining coal requirements at its coal-fueled generating facilities over their currently expected remaining useful lives but at significantly higher prices. PacifiCorp has experienced higher costs to procure coal supply for its Utah coal-fueled generating facilities as a result of reduced suppliers, fires in third-party mines,
coal supplier solvency and financing issues, labor shortages, transportation limitations, delays in federal leasing processes, and production delays due to unfavorable geologic conditions.
Natural Gas
PacifiCorp uses natural gas as fuel for its generating facilities that use combined-cycle, simple-cycle and steam turbines. Oil and natural gas are also used for igniter fuel and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp's needs.
PacifiCorp enters into forward natural gas purchases at fixed or indexed market prices. PacifiCorp purchases natural gas in the spot market with both fixed and indexed market prices for physical delivery to fulfill any fuel requirements
not already satisfied through forward purchases of natural gas and sells natural gas in the spot market for the disposition of any excess supply if the forecasted requirements of its natural gas-fueled generating facilities decrease. PacifiCorp also utilizes financial swap contracts to mitigate price risk associated with its forecasted fuel requirements.
Wind
PacifiCorp has pursued renewable resources as a viable, economical and environmentally prudent means of supplying electricity and complying with laws and regulations. Renewable resources have low to no emissions and require little or no fossil fuel. The generation from PacifiCorp's wind-powered generating fleet, comprised of newly constructed and recently repowered wind-powered generating facilities, qualifies for federal PTCs for 10 years beginning
with the date the new or repowered facility is placed in‑service. In addition to the discussion contained herein regarding repowering activities, refer to "Regulatory Matters" in Item 1 of this Form 10-K.
Hydroelectric and Other Renewable Resources
The amount of electricity PacifiCorp is able to generate from its hydroelectric generating facilities depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric generating facilities, reservoir storage, precipitation in its watersheds, generating unit availability and restrictions imposed by oversight bodies due to competing water management objectives.
PacifiCorp operates the majority of its hydroelectric generating
portfolio under long-term licenses. The FERC regulates 98% of the net capacity of this portfolio through 14 individual licenses, which have terms of 30 to 50 years. The licenses for these hydroelectric generating facilities expire at various dates through 2061. A portion of this portfolio is licensed under the Oregon Hydroelectric Act. For discussion of PacifiCorp's hydroelectric relicensing activities, including updated information regarding the Klamath River hydroelectric system, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.
Wholesale Activities
PacifiCorp purchases and sells electricity in the wholesale markets as
needed to balance its generation with its retail load obligations. PacifiCorp may also purchase electricity in the wholesale markets when it is more economical than generating electricity from its own facilities and may sell surplus electricity in the wholesale markets when it can do so economically. When prudent, PacifiCorp enters into financial swap contracts and forward electricity sales and purchases for physical delivery at fixed prices to reduce its exposure to electricity price volatility.
7
Energy Imbalance Market
PacifiCorp and the California ISO implemented an EIM in November 2014, which reduces costs to serve customers through
more efficient dispatch of a larger and more diverse pool of resources, more effectively integrates renewables and enhances reliability through improved situational awareness and responsiveness. The EIM expands the real-time component of the California ISO's market technology to optimize and balance electricity supply and demand every five minutes across the EIM footprint. The EIM is voluntary and available to all balancing authorities in the western U.S. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation
resource bids, the California ISO market operator also receives continuous real-time updates of the transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. Outside the EIM footprint, utilities in the western U.S. do not utilize comparable technology and are largely limited to transactions within the borders of their balancing authority area to balance supply and demand intra-hour using a combination of manual and automated dispatch. The EIM delivers customer benefits by leveraging automation and resource diversity to result in more efficient dispatch, more effective integration of renewables and improved situational awareness. Benefits are expected to increase further with renewable resource expansion and as more entities join the EIM, bringing incremental resource diversity. PacifiCorp is working with the California ISO to join the California ISO Extended Day-Ahead Market ("EDAM") in 2026. The EDAM
is a voluntary day-ahead electricity market designed to deliver significant reliability, economic, and environmental benefits to balancing areas and utilities throughout the West.
Transmission and Distribution
PacifiCorp operates one balancing authority area in the western portion of its service territory ("PacifiCorp-West") and one balancing authority area in the eastern portion of its service territory ("PacifiCorp-East"). A balancing authority area is a geographic area with transmission systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority areas, PacifiCorp is responsible for continuously balancing electricity supply and demand by dispatching generating resources and interchange transactions
so that generation internal to the balancing authority area, plus net imported power, matches customer loads. Deliveries of energy over PacifiCorp's transmission system are managed and scheduled in accordance with the FERC's requirements.
PacifiCorp's transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. PacifiCorp's transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements. PacifiCorp's transmission and distribution systems included approximately 17,100 miles of transmission lines in 10 states, 66,300 miles of distribution lines and 900 substations as of December 31, 2023.
PacifiCorp's
transmission and distribution system is managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of PacifiCorp's transmission and distribution systems are located:
•On property owned or used through agreements by PacifiCorp;
•Under or over streets, alleys, highways and other public places, the public domain and national forests and state and federal lands under franchises, easements or other rights that are generally subject to termination;
•Under or over private property as a result of easements obtained primarily from the title holder of record; or
•Under or over Native American reservations through agreements with the U.S. Secretary of Interior or Native American
tribes.
It is possible that some of the easements and the property over which the easements were granted may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.
8
PacifiCorp's Energy Gateway Transmission Expansion Program represents plans to build over 2,000 miles of new high-voltage transmission lines, with an estimated cost of approximately $13 billion, primarily in Wyoming, Utah, Idaho and Oregon. The approximately $13 billion estimated cost includes: (a) the 135-mile, 345-kV transmission line between the Terminal substation near the Salt Lake City Airport and the Populus substation in
Downey, Idaho, placed in-service in 2010; (b) the 100-mile, 345/500-kV transmission line between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley, placed in-service in 2013; (c) the 170-mile, 345-kV transmission line between the Sigurd substation in central Utah and the Red Butte substation in southwest Utah, placed in-service in 2015; (d) the 140-mile, 500-kV transmission line between the Aeolus substation near Medicine Bow, Wyoming and the Jim Bridger generating facility, placed in-service in 2020; (e) the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation and the Clover substation near Mona, Utah, expected to be placed in-service in 2024; (f) the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation, expected to be placed in-service in 2024; (g) the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near
Boardman, Oregon to the Hemingway substation near Boise, Idaho (a joint project), expected to be placed in-service in 2026; (h) the 14-mile, 345-kV high-voltage transmission line between the Oquirrh substation and the Terminal substation, expected to be placed in-service in 2024; and (i) remaining segments that are expected to be placed in-service in future years, depending on load growth, economic analysis, IRP results, siting, permitting and construction schedules. The transmission line segments are intended to: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable and zero carbon resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area. Proposed transmission line segments are evaluated to ensure optimal benefits and timing before committing to move forward with permitting and construction. Through
December 31, 2023, $4.8 billion had been spent and $2.3 billion, including AFUDC, had been placed in-service.
Wildfire Mitigation Plans
PacifiCorp has developed detailed wildfire mitigation plans for each of the six states in which it operates. Wildfire mitigation plans are filed annually with the OPUC, the CPUC and the UPSC. Although not required, a wildfire mitigation plan is provided annually to the WUTC. In 2024, wildfire mitigation plans will also be provided to the IPUC and the WPSC with a similar schedule of providing annual future updates. These plans include capital investment in asset hardening and meteorological systems, the implementation of risk modeling tools and PacifiCorp's ongoing elevated fire risk settings, inspections, vegetation management,
public safety power shutoff ("PSPS") and wildfire encroachment programs and policies.
Asset Hardening
PacifiCorp has and continues to invest in rebuilding overhead transmission and distribution lines with covered conductor and in some cases has converted overhead distribution lines to underground. These system hardening efforts reduce the exposure of PacifiCorp's lines to interference from trees and other objects. Covered conductor helps mitigate the risk of fault-caused electrical arcs that could cause an ignition. Overall, mitigated overhead lines help reduce ignition risk and improve reliability during storms or periods of significant wildfire risk.
Approximately 6,100 miles, or 9%, of PacifiCorp's distribution
lines are in fire high consequence areas ("FHCA"), covering approximately 8% of its service territory and approximately 5% of its customer base. Approximately 1,000 miles of transmission lines are in the FHCA. In 2023, the process for updating the risk modeling for the identification of the FHCA was initiated and is on track for finalization in early 2024. It is expected that as the wildfire mitigation program evolves, its targeted programs will cover more service territory.
As of December 31, 2023, all 1,000 miles of transmission lines in the FHCA were mitigated by system relay protection schemes. All 6,100 miles of distribution lines in the FHCA include some form of mitigation including:
•3,100 miles, or 51%, with bare conductor mitigated by system relay protection
schemes;
•400 miles, or 6%, with new covered conductor; and
•2,600 miles, or 43%, underground.
The on-going asset hardening of the FHCA is a priority for PacifiCorp and a key part of the developed wildfire mitigation plans.
Refer to "Future Uses of Cash" in Item 7 of this Form 10-K for further discussion of PacifiCorp's wildfire mitigation related capital expenditures, including asset hardening.
9
Elevated Fire Risk Settings
Elevated
fire risk settings are available across PacifiCorp's service territory, including the ongoing installation of new microprocessor relays to detect faults occurring on transmission and distribution lines in the FHCA and de-energize the line quickly limiting the arc-energy and potential for wildfire ignition. Field reclosers are being upgraded with similar fault detection capability in the FHCA.
Meteorology and Risk Modeling
PacifiCorp has installed over 450 weather stations that monitor weather conditions and model the impact to the electrical infrastructure. These weather stations combined with the around-the-clock weather forecasting team servicing PacifiCorp's service territory, provide PacifiCorp with the ability to forecast weather and fire risk impact data twice daily. PacifiCorp will continue to
install additional weather stations to refine weather modeling in areas where geographic terrain conditions require a dense network of weather stations in order to provide the necessary granular data.
Asset Inspection Program
Within the FHCA PacifiCorp conducts an annual inspection of overhead facilities with an accelerated correction timeline for any conditions noted. A detailed inspection of facilities is conducted every five years, which is twice as often as areas outside the FHCA.
Vegetation Management
PacifiCorp's vegetation management program includes annual vegetation inspections and ground clearing of equipment poles in the FHCA along with three-year trimming cycles
in place, including in Oregon and California where fire hazard risk is highest.
Public Safety Power Shutoff and Wildfire Encroachment Policy
A PSPS is used as a preventative measure during periods of extreme wildfire risk where the electrical network is de-energized proactively under certain conditions. In determining whether to initiate a PSPS, PacifiCorp works with local public safety authorities in consideration of data from meteorological systems and forecasting tools. PacifiCorp also has a wildfire encroachment policy under which it will de-energize its lines when a known wildfire is within a specified distance of its assets based on criteria such as system configuration, line structure material, weather conditions and wind. In August 2023, in response to potentially encroaching lightning-caused
wildfires in the area at the time, PacifiCorp de‑energized transmission lines serving customers in Crescent City and Del Norte County, California, providing a temporary power solution to nearly all of the impacted customers.
Future Generation, Conservation and Energy Efficiency
Energy Supply Planning
As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations. The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs, accounting for
planning uncertainty, risks, reliability, state energy policies and other factors. The IRP is prepared following a public process, which provides an opportunity for stakeholders to participate in PacifiCorp's resource planning process. PacifiCorp files its IRP biennially with the state commissions in each of the six states where PacifiCorp operates. Five states indicate whether the IRP meets the state commission's IRP standards and guidelines, a process referred to as "acknowledgment" in some states. Acknowledgment by a state commission does not address recovery or prudency of resources ultimately selected.
In March 2023, PacifiCorp filed its 2023 IRP in Idaho, Oregon and Wyoming. The March 2023 filing was considered informational in Utah. PacifiCorp filed its 2023 IRP (Amended Final) report on May 31, 2023, following a 60-day extended
comment period. In October 2023, the IPUC acknowledged the 2023 IRP. In November 2023 through February 2024, PacifiCorp responded to Wyoming, Utah and Oregon stakeholder reply comments as part of the 2023 IRP acknowledgement and related processes.
10
The 2023 IRP is off cycle with regard to Washington's four-year IRP cycle and has instead been filed in that state as the "Washington Two-Year Progress Report," aligned with the Clean Energy Transformation Act requirements. In October, the WUTC approved a multi-party settlement agreement that resolved challenges to the Clean Energy Implementation Plan ("CEIP").
PacifiCorp's petition to
the WUTC to approve an alternative IRP filing schedule has been partially accepted and will extend the existing timeline of the 2025 IRP filing by three months to align with the filing schedules of the other five states within PacifiCorp's six-state territory. This is pertinent to maintaining a March 31, 2025 filing date for the 2025 IRP. Related 2025 IRP filing dates are also extended, however, the filing dates for Washington's CEIP are unchanged.
Requests for Proposals
PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands and regulatory policy changes. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load and state-specific compliance obligations.
Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.
PacifiCorp's most recent RFP, the 2022 All-Source ("2022AS") RFP, was issued to the market in April 2022. In September 2023, PacifiCorp suspended its 2022AS RFP. No final shortlist will be announced while the RFP is paused. As indicated in the 2022AS RFP, PacifiCorp reserves the right, without limitation or qualification and in its sole discretion, to reject any or all bids, and to terminate or suspend the RFP in whole or in part at any time.
Key drivers behind PacifiCorp's decision to suspend the RFP included:
•A
federal court's stay of the EPA's proposed ozone transport rule.
•Ongoing rulemaking by the EPA regarding greenhouse gas emissions.
•Wildfire risk and associated liability across PacifiCorp's six-state service area and throughout the West.
•Evolving extreme weather risks that necessitate further decision-making regarding PacifiCorp's operational and resource requirements.
As of this filing, PacifiCorp has made no decision specific to the 2022AS RFP's reinstatement or termination. Next steps regarding the 2022 AS RFP will be further informed by the findings from the 2023 IRP updates scheduled for release in the first quarter of 2024.
Energy
Efficiency Programs
PacifiCorp has provided its customers with a comprehensive set of DSM programs since the 1970s. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. PacifiCorp offers services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, PacifiCorp offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for energy project management, efficient building operations and efficient construction. Incentives are also paid to solicit participation in load management programs by residential, business
and agricultural customers through programs such as PacifiCorp's residential and small commercial air conditioner load control program, battery control program and irrigation equipment load control programs. Although subject to prudence reviews, state regulations allow for recovery of costs incurred for the DSM programs through state-specific energy efficiency surcharges to retail customers or for recovery of costs through rates. During 2023, PacifiCorp spent $178 million on these DSM programs, resulting in an estimated 642,569 MWhs of first-year energy savings and an estimated 459 MWs of peak load management. In addition to these DSM programs, PacifiCorp has load curtailment contracts with a number of large industrial customers that deliver up to 372 MWs of load reduction when needed, depending on the customers' actual operations. Costs associated with the large industrial load curtailment program are captured in the respective customers' retail special contracts. The
corresponding recovery of costs was approved by the respective state commissions or through PacifiCorp's general rate case process.
11
Human Capital
Employees
As of December 31, 2023, PacifiCorp had approximately 5,000 employees, of which approximately 2,800 were covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America and the International Brotherhood of Boilermakers. For more information regarding PacifiCorp's human capital disclosures,
refer to Item 1. Business - General section of this Form 10-K.
MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY
General
MidAmerican Funding and MHC
MidAmerican Funding, a wholly owned subsidiary of BHE, is a holding company headquartered in Iowa that owns all of the outstanding common stock of MHC Inc. ("MHC"), which is a holding company owning all of the common stock of MidAmerican Energy and Midwest Capital Group, Inc. ("Midwest Capital"). MidAmerican Funding and MidAmerican Energy are
indirect consolidated subsidiaries of Berkshire Hathaway. MidAmerican Funding conducts no business other than activities related to its debt securities and the ownership of MHC. MHC conducts no business other than the ownership of its subsidiaries. MidAmerican Energy is a substantial portion of MidAmerican Funding's and MHC's assets, revenue and earnings.
MidAmerican Funding was formed as a limited liability company under the laws of the state of Iowa in 1999 and its principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa50309-2580 and its telephone number is (515) 242-4300.
MidAmerican
Energy
MidAmerican Energy, an indirect wholly owned subsidiary of BHE, is a U.S. regulated electric and natural gas utility company headquartered in Iowa that serves 0.8 million retail electric customers in portions of Iowa, Illinois and South Dakota and 0.8 million retail and transportation natural gas customers in portions of Iowa, South Dakota, Illinois and Nebraska. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electricity and in distributing, selling and transporting natural gas. MidAmerican Energy's service territory covers approximately 11,000 square miles. MidAmerican Energy has a diverse customer base consisting of urban and rural residential customers and a variety of commercial and industrial customers. Principal industries served by MidAmerican Energy include electronic data storage; processing and sales of
food products; manufacturing, processing and fabrication of primary metals, farm and other non-electrical machinery; cement and gypsum products; and government. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electricity principally to markets operated by RTOs and natural gas to other utilities and market participants on a wholesale basis. MidAmerican Energy is a transmission-owning member of the MISO and participates in its capacity, energy and ancillary services markets.
MidAmerican Energy's regulated electric and natural gas operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 20- to 25-year terms. Several of these franchise agreements give either party the right to seek amendment
to the franchise agreement at one, two, three or four specified times during the term. MidAmerican Energy generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electricity service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow MidAmerican Energy an opportunity to recover its costs of providing services and to earn a reasonable return on its investment. In Illinois, MidAmerican Energy's regulated retail electric customers may choose their energy supplier.
12
MidAmerican Energy's operating revenue and operating income derived from the following business activities
for the years ended December 31 were as follows (dollars in millions):
2023
2022
2021
Operating
revenue:
Regulated electric
$
2,673
79
%
$
2,988
74
%
$
2,529
71
%
Regulated
gas
713
21
1,030
26
1,003
28
Other
7
—
7
—
15
1
Total
operating revenue
$
3,393
100
%
$
4,025
100
%
$
3,547
100
%
Operating
income:
Regulated electric
$
471
90
%
$
372
85
%
$
358
86
%
Regulated
gas
50
10
66
15
58
14
Total operating income
$
521
100
%
$
438
100
%
$
416
100
%
MidAmerican
Energy was incorporated under the laws of the state of Iowa in 1995 and its principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa50309-2580, its telephone number is (515) 242-4300 and its internet address is www.midamericanenergy.com.
Regulated Electric Operations
Customers
The
GWhs and percentages of electricity sold to MidAmerican Energy's retail customers by jurisdiction for the years ended December 31 were as follows:
2023
2022
2021
Iowa
27,554
93
%
27,024
92
%
25,909
92
%
Illinois
1,827
6
1,970
7
1,895
7
South
Dakota
294
1
296
1
270
1
29,675
100
%
29,290
100
%
28,074
100
%
13
Electricity
sold to MidAmerican Energy's retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:
2023
2022
2021
GWhs
sold:
Residential
6,759
15
%
7,006
15
%
6,718
15
%
Commercial
3,992
9
4,017
9
3,841
9
Industrial
17,307
39
16,646
35
15,944
36
Other
1,617
3
1,621
3
1,571
4
Total
retail
29,675
66
29,290
62
28,074
64
Wholesale
15,129
34
17,964
38
16,011
36
Total
GWhs sold
44,804
100
%
47,254
100
%
44,085
100
%
Average
number of retail customers (in thousands):
Residential
703
86
%
697
86
%
690
86
%
Commercial
101
12
99
12
98
12
Industrial
2
—
2
—
2
—
Other
14
2
15
2
14
2
Total
820
100
%
813
100
%
804
100
%
Variations
in weather, economic conditions and various conservation and energy efficiency measures and programs can impact customer energy requirements. Wholesale sales are primarily impacted by market prices for energy.
There are seasonal variations in MidAmerican Energy's electricity sales that are principally related to weather and the related use of electricity for air conditioning. Additionally, electricity sales are priced higher in the summer months compared to the remaining months of the year. As a result, 40% to 50% of MidAmerican Energy's regulated electric retail revenue is reported in the months of June through September.
A degree of concentration of sales exists with certain large electric retail customers. Sales to the 10 largest customers, from a variety of industries, comprised 26%, 25% and 24% of
total retail electric sales in 2023, 2022 and 2021, respectively. Sales to electronic data storage customers included in the 10 largest customers comprised 20%, 18% and 16% of total retail electric sales in 2023, 2022 and 2021, respectively.
The annual hourly peak demand on MidAmerican Energy's electric system usually occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On August 23, 2023, retail customer usage of electricity caused a new record hourly peak demand of 5,851 MWs on MidAmerican Energy's electric distribution system, which is 465 MWs greater than the previous record hourly peak demand of 5,386 MWs set August 2, 2022.
Generating
Facilities and Fuel Supply
MidAmerican Energy has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding MidAmerican Energy's owned generating facilities as of December 31, 2023:
Facility
Net
Year
Installed /
Net Capacity
Owned Capacity
Generating Facility
Location
Energy Source
Repowered(1)
(MWs)(2)
(MWs)(2)
WIND:
Ida
Grove
Ida Grove, IA
Wind
2016-2019
500
500
Orient
Greenfield, IA
Wind
2018-2019
500
500
Highland
Primghar,
IA
Wind
2015
475
475
Rolling Hills
Massena, IA
Wind
2011 / 2022
443
443
Beaver
Creek
Ogden, IA
Wind
2017-2018
340
340
North English
Montezuma, IA
Wind
2018-2019
340
340
Palo
Alto
Palo Alto, IA
Wind
2019-2020
340
340
Arbor Hill
Greenfield, IA
Wind
2018-2020
316
316
14
Facility
Net
Year
Installed /
Net Capacity
Owned Capacity
Generating Facility
Location
Energy Source
Repowered(1)
(MWs)(2)
(MWs)(2)
Pomeroy
Pomeroy,
IA
Wind
2007-2011 / 2018-2019, 2021
286
286
Diamond Trail
Ladora, IA
Wind
2020
250
250
Lundgren
Otho,
IA
Wind
2014
250
250
O'Brien
Primghar, IA
Wind
2016
250
250
Southern
Hills
Orient, IA
Wind
2020-2021
250
250
Chickasaw
New Hampton, IA
Wind
2023
200
200
Century
Blairsburg,
IA
Wind
2005-2008 / 2017-2018
200
200
Eclipse
Adair, IA
Wind
2012 / 2022
200
200
Plymouth
Remsen,
IA
Wind
2021
200
200
Intrepid
Schaller, IA
Wind
2004-2005 / 2017
176
176
Adair
Adair,
IA
Wind
2008 / 2019-2020
175
175
Prairie
Montezuma, IA
Wind
2017-2018
169
169
Carroll
Carroll,
IA
Wind
2008 / 2019
150
150
Walnut
Walnut, IA
Wind
2008 / 2019
150
150
Vienna
Gladbrook,
IA
Wind
2012-2013
150
150
Adams
Lennox, IA
Wind
2015
150
150
Wellsburg
Wellsburg,
IA
Wind
2014
139
139
Laurel
Laurel, IA
Wind
2011 / 2022
120
120
Macksburg
Macksburg,
IA
Wind
2014
119
119
Contrail
Braddyville, IA
Wind
2020
110
110
Morning
Light
Adair, IA
Wind
2012 / 2022-2023
100
100
Victory
Westside, IA
Wind
2006 / 2017-2018
99
99
Ivester
Wellsburg,
IA
Wind
2018
90
90
Pocahontas Prairie
Pomeroy, IA
Wind
2020 / 2021
80
80
Charles
City
Charles City, IA
Wind
2008 / 2018
75
75
7,392
7,392
COAL:
Louisa
Muscatine,
IA
Coal
1983
746
656
Walter Scott, Jr. Unit No. 3
Council Bluffs, IA
Coal
1978
706
558
Walter
Scott, Jr. Unit No. 4
Council Bluffs, IA
Coal
2007
806
481
Ottumwa
Ottumwa, IA
Coal
1981
724
376
George
Neal Unit No. 3
Sergeant Bluff, IA
Coal
1975
510
367
George Neal Unit No. 4
Salix, IA
Coal
1979
647
263
4,139
2,701
NATURAL
GAS AND OTHER:
Greater Des Moines
Pleasant Hill, IA
Gas
2003-2004
510
510
Electrifarm
Waterloo,
IA
Gas or Oil
1975-1978
190
190
Pleasant Hill
Pleasant Hill, IA
Gas or Oil
1990-1994
154
154
Sycamore
Johnston,
IA
Gas or Oil
1974
145
145
River Hills
Des Moines, IA
Gas
1966-1967
115
115
Coralville
Coralville,
IA
Gas
1970
64
64
Moline
Moline, IL
Gas
1970
61
61
27 portable power
modules
Various
Oil
2000
54
54
Parr
Charles City, IA
Gas
1969
33
33
1,326
1,326
NUCLEAR:
Quad
Cities Unit Nos. 1 and 2
Cordova, IL
Uranium
1972
1,809
452
SOLAR:
Holliday
Creek
Fort Dodge, IA
Solar
2022
100
100
15
Facility
Net
Year
Installed /
Net Capacity
Owned Capacity
Generating Facility
Location
Energy Source
Repowered(1)
(MWs)(2)
(MWs)(2)
Arbor Hill
Adair,
IA
Solar
2022
24
24
Franklin
Hampton, IA
Solar
2022
7
7
Neal
Salix,
IA
Solar
2022
4
4
Waterloo
Waterloo, IA
Solar
2022
3
3
Hills
Hills,
IA
Solar
2022
3
3
141
141
HYDROELECTRIC:
Moline
Unit Nos. 1-4
Moline, IL
Hydroelectric
1941
4
4
Total Available Generating Capacity
14,811
12,016
(1)Repowered
dates are associated with component replacements on existing wind-powered generating facilities commonly referred to by the IRS as repowering. IRS rules provide for re-establishment of the PTCs for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement in such projects meets IRS guidelines, PTCs are re-established for 10 years beginning with the date the repowered facility is placed in-service.
(2)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned
Capacity indicates MidAmerican Energy's ownership of Facility Net Capacity.
The following table shows the percentages of MidAmerican Energy's total energy supplied by energy source for the years ended December 31:
2023
2022
2021
Wind
and other renewable(1)
55
%
58
%
52
%
Coal
22
21
27
Nuclear
8
8
9
Natural
gas
5
3
3
Total energy generated
90
90
91
Energy purchased - short-term contracts and other
9
9
8
Energy
purchased - long-term contracts (renewable)(1)
1
1
1
100
%
100
%
100
%
(1)All
or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.
MidAmerican Energy is required to have accredited resources available for dispatch by MISO to continuously meet its customer's needs and reliably operate its electric system. The percentage of MidAmerican Energy's energy supplied by energy source varies from year to year and is subject to numerous operational and economic factors such as planned and unplanned outages, fuel commodity prices, fuel transportation costs, weather, environmental considerations, transmission constraints, and wholesale market prices of electricity. MidAmerican Energy evaluates these factors continuously in order to facilitate
economic dispatch of its generating facilities by MISO. When factors for one energy source are less favorable, MidAmerican Energy places more reliance on other energy sources. For example, MidAmerican Energy can generate more electricity using its low cost wind-powered generating facilities when factors associated with these facilities are favorable. When factors associated with wind resources are less favorable, MidAmerican Energy must increase its reliance on more expensive generation or purchased electricity. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction.
16
Wind
MidAmerican
Energy owns more wind-powered generating capacity than any other U.S. rate-regulated electric utility and believes wind-powered generation offers a viable, economical and environmentally prudent means of supplying electricity and complying with laws and regulations. Pursuant to ratemaking principles approved by the IUB, facilities accounting for 89% of MidAmerican Energy's wind-powered generating capacity in-service at December 31, 2023, are authorized to earn a fixed rate of return on equity over their regulatory lives ranging from 10.75% to 12.2% on the depreciated cost of their original construction, which excludes the cost of later replacements, in any future Iowa rate proceeding. MidAmerican Energy's wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for federal renewable electricity PTCs
for 10 years beginning with the date the facilities are placed in-service. PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold. PTCs for MidAmerican Energy's wind-powered generating facilities currently in-service began expiring in 2014, with final expiration in 2033. Since 2014, MidAmerican Energy has repowered, or plans to repower, 2,357 MWs of wind-powered generating facilities for which PTCs had expired by the end of 2022.
Of the 7,617 MWs (nameplate capacity) of wind-powered generating facilities in-service as of December 31, 2023, 7,416 MWs were generating PTCs, including 2,316 MWs of repowered facilities. PTCs earned by MidAmerican Energy's wind-powered generating facilities placed in-service prior to 2013, except for repowered facilities, were included in MidAmerican Energy's Iowa EAC,
through which MidAmerican Energy is allowed to recover fluctuations in its electric retail energy costs. All of the eligibility of those facilities to earn PTCs had expired by the end of 2022. MidAmerican Energy earned PTCs totaling $681 million, $710 million and $574 million in 2023, 2022 and 2021, respectively, of which —%, 4% and 12%, respectively, were included in the Iowa EAC.
Coal
All of the coal-fueled generating facilities operated by MidAmerican Energy are fueled by low-sulfur, western coal from the Powder River Basin in northeast Wyoming. MidAmerican Energy's coal supply portfolio includes multiple suppliers and mines under short-term and multi-year agreements of varying terms and quantities through 2027. MidAmerican Energy believes supplies from these sources are presently adequate and available
to meet MidAmerican Energy's needs. A substantial share of MidAmerican Energy's expected coal supply requirements for 2024 and 2025 are covered under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market for opportunities to enhance its coal supply portfolio.
MidAmerican Energy has a multi-year long-haul coal transportation agreement with BNSF Railway Company ("BNSF"), an affiliate company, for the delivery of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities other than the George Neal Energy Center. Under this agreement, BNSF delivers coal directly to MidAmerican Energy's Walter Scott, Jr. Energy Center and to an interchange point with Canadian Pacific Kansas City Railway Company for short-haul delivery to the Louisa Energy Center. MidAmerican Energy has a multi-year long-haul coal transportation agreement with Union
Pacific Railroad Company for the delivery of coal to the George Neal Energy Center.
Nuclear
MidAmerican Energy is a 25% joint owner of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station"), a nuclear generating facility, which is currently licensed by the NRC for operation until December 14, 2032. Constellation Energy Generation, LLC ("Constellation Energy"), is the 75% joint owner and the operator of Quad Cities Station. Approximately one-third of the nuclear fuel assemblies in each reactor core at Quad Cities Station is replaced every 24 months. MidAmerican Energy has been advised by Constellation Energy that it expects to obtain the necessary uranium concentrates or conversion, enrichment or fabrication services to meet
the nuclear fuel requirements of Quad Cities Station. In reaction to concerns about the profitability of Quad Cities Station and Constellation Energy's ability to continue its operation, in December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. Currently, Quad Cities is operating under agreements to provide Illinois load serving entities ZECs through June 1, 2027.
Natural Gas and Other
MidAmerican Energy uses natural gas and oil as fuel for intermediate and peak demand
electric generation, igniter fuel, transmission support and standby purposes. These sources are presently in adequate supply and available to meet MidAmerican Energy's needs.
17
Regional Transmission Organizations
MidAmerican Energy sells and purchases electricity and ancillary services related to its generation and load in wholesale markets pursuant to the tariffs in those markets. MidAmerican Energy participates predominantly in the MISO energy and ancillary service markets, which provide MidAmerican Energy with wholesale opportunities over a large market area. MidAmerican Energy can enter into wholesale bilateral transactions in addition to
market activity related to its assets. MidAmerican Energy is also authorized to participate in the Southwest Power Pool, Inc. and PJM Interconnection, L.L.C. markets and can contract with several other utilities in the region. MidAmerican Energy utilizes financial swaps and physical fixed-price electricity sales and purchases contracts to reduce its exposure to electricity price volatility.
MidAmerican Energy's decisions regarding additions to or reductions of its generation portfolio may be impacted by the MISO's minimum reserve margin requirement. The MISO requires each member to maintain a minimum seasonal reserve margin of its accredited generating capacity over its seasonal peak demand obligation based on the member's seasonal load forecast filed with the MISO each year. The MISO's reserve requirements for the 2023-2024 planning year were 7.4% for summer 2023, 14.9% for fall 2023,
25.5% for winter 2023-2024 and 24.5% for spring 2024. For the summer peak demand season, MidAmerican Energy's owned and contracted capacity accredited for the 2023-2024 MISO capacity auction was 5,984 MWs compared to a peak demand obligation of 5,332 MWs, or a reserve margin of 12.2%. Additionally, MidAmerican Energy had more than adequate reserve margin for the fall, winter and spring seasons when peak demands are typically lower. Some of the excess capacity may be sold through bilateral or MISO capacity auction transactions. The reserve requirements for the 2024-2025 planning year will be 9.0% for summer 2024, 14.2% for fall 2024, 27.4% for winter 2024-2025 and 26.7% for spring 2025. Accredited capacity represents the amount of generation available to meet the requirements of MidAmerican Energy's retail customers and consists of MidAmerican Energy-owned generation, interruptible retail customer load, certain customer private generation that MidAmerican Energy is contractually
allowed to dispatch and the net amount of capacity purchases and sales, excluding sales into the MISO annual capacity auction. Accredited capacity may vary significantly from the nominal capacity ratings, particularly for wind or solar facilities whose output is dependent upon energy resource availability at any given time. Additionally, the actual amount of generating capacity available at any time may be less than the accredited capacity due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons.
Transmission and Distribution
MidAmerican Energy's transmission and distribution systems included 4,700 circuit miles of transmission lines in four states, 25,500 circuit
miles of distribution lines and 340 substations as of December 31, 2023. Electricity from MidAmerican Energy's generating facilities and purchased electricity is delivered to wholesale markets and its retail customers via the transmission facilities of MidAmerican Energy and others. MidAmerican Energy participates in the MISO capacity, energy and ancillary services markets as a transmission-owning member and, accordingly, operates its transmission assets at the direction of the MISO. The MISO manages its energy and ancillary service markets using reliability-constrained economic dispatch of the region's generation. For both the day-ahead and real-time (every five minutes) markets, the MISO analyzes generation commitments to provide market liquidity and transparent pricing while maintaining transmission system reliability by minimizing congestion and maximizing efficient energy transmission. Additionally, through its FERC-approved
OATT, the MISO performs the role of transmission service provider throughout the MISO footprint and administers the long-term planning function. The MISO costs of the participants are shared among the participants through a number of mechanisms in accordance with the MISO tariff.
Regulated Natural Gas Operations
MidAmerican Energy is engaged in the distribution of natural gas to customers in its service territory and the related procurement, transportation and storage of natural gas for the benefit of those customers. MidAmerican Energy purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the gas to MidAmerican Energy's service territory and for storage and balancing services. MidAmerican Energy sells natural gas and delivery services to
end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for end-use customers who have independently secured their supply of natural gas. During 2023, 58% of the total natural gas delivered through MidAmerican Energy's distribution system was associated with transportation service.
Natural gas property consists primarily of natural gas mains and service lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of MidAmerican Energy included 24,900 miles of natural gas main and service lines as of December 31, 2023.
18
Customer
Usage and Seasonality
The percentages of natural gas sold to MidAmerican Energy's retail customers by jurisdiction for the years ended December 31 were as follows:
2023
2022
2021
Iowa
75
%
76
%
76
%
South
Dakota
14
14
13
Illinois
10
9
10
Nebraska
1
1
1
100
%
100
%
100
%
The
percentages of natural gas sold to MidAmerican Energy's retail and wholesale customers by class of customer, total Dths of natural gas sold, total Dths of transportation service and the average number of retail customers for the years ended December 31 were as follows:
2023
2022
2021
Residential
45
%
47
%
44
%
Commercial(1)
21
22
20
Industrial(1)
5
5
5
Total
retail
71
74
69
Wholesale(2)
29
26
31
100
%
100
%
100
%
Total
Dths of natural gas sold (in thousands)
106,912
119,508
111,916
Total Dths of transportation service (in thousands)
106,422
102,827
112,631
Total average number of retail customers (in thousands)
796
789
781
(1)Commercial
and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers that use natural gas principally for heating. Industrial customers are non-residential customers that use natural gas principally for their manufacturing processes.
(2)Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.
There are seasonal variations in MidAmerican Energy's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 50-60% of MidAmerican Energy's regulated retail natural gas revenue is reported in the months of January, February, March and December.
On
December 22, 2022, MidAmerican Energy recorded its all-time highest peak-day delivery through its distribution system of 1,325,160 Dths. This peak-day delivery consisted of 72% traditional retail sales service and 28% transportation service. MidAmerican Energy's 2023/2024 winter heating season preliminary peak-day delivery as of January 31, 2024, was 1,309,311 Dths, reached on January 15, 2024. This preliminary peak-day delivery consisted of 66% traditional retail sales service and 34% transportation service.
Natural Gas Supply and Capacity
MidAmerican Energy uses several strategies designed to maintain a reliable natural gas supply and reduce the impact
of volatility in natural gas prices on its regulated retail natural gas customers. These strategies include the purchase of a geographically diverse supply portfolio from producers and third-party energy marketing companies, the use of interstate pipeline storage services and MidAmerican Energy's LNG peaking facilities, and the use of financial derivatives to fix the price on a portion of the anticipated natural gas requirements of MidAmerican Energy's customers. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of the PGAs.
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MidAmerican Energy contracts for firm natural gas pipeline capacity to transport natural gas from key production areas and liquid market centers to its service territory
through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Northern Natural Gas, an affiliate company. MidAmerican Energy has multiple pipeline interconnections into several larger markets within its distribution system. Multiple pipeline interconnections create competition among pipeline suppliers for transportation capacity to serve those markets, thus reducing costs. In addition, multiple pipeline interconnections increase delivery reliability and give MidAmerican Energy the ability to optimize delivery of the lowest cost supply from the various production areas and liquid market centers into these markets. Benefits to MidAmerican Energy's distribution system customers are shared among all jurisdictions through a consolidated PGA.
At times, the natural gas pipeline capacity available through MidAmerican Energy's firm capacity
portfolio may exceed the requirements of retail customers on MidAmerican Energy's distribution system. Firm capacity in excess of MidAmerican Energy's system needs can be released to other companies to achieve optimum use of the available capacity. Past IUB and South Dakota Public Utilities Commission ("SDPUC") rulings have allowed MidAmerican Energy to retain 30% of the revenue on the resold capacity, with the remaining 70% being returned to customers through the PGAs.
MidAmerican Energy utilizes interstate pipeline natural gas storage services to meet retail customer requirements, manage fluctuations in demand due to changes in weather and other usage factors and manage variation in seasonal natural gas pricing. MidAmerican Energy typically withdraws natural gas from storage during the heating season when customer demand is historically at its peak and injects natural gas into
storage during off-peak months when customer demand is historically lower. MidAmerican Energy also utilizes its three LNG facilities to meet peak day demands during the winter heating season. Interstate pipeline storage services and MidAmerican Energy's LNG facilities reduce dependence on natural gas purchases during the volatile winter heating season and can deliver a significant portion of MidAmerican Energy's anticipated retail sales requirements on a peak winter day. For MidAmerican Energy's 2023/2024 winter heating season preliminary peak-day of January 15, 2024, supply sources used to meet deliveries to traditional retail sales service customers included 51% from purchases delivered on interstate pipelines, 37% from interstate pipeline storage services and 12% from MidAmerican Energy's LNG facilities.
MidAmerican Energy attempts
to optimize the value of its regulated transportation capacity, natural gas supply and interstate pipeline storage services by engaging in wholesale transactions. IUB and SDPUC rulings have allowed MidAmerican Energy to retain 50% of the respective jurisdictional margins earned on certain wholesale sales of natural gas, with the remaining 50% being returned to customers through the PGAs.
MidAmerican Energy is not aware of any factors that would cause material difficulties in meeting its anticipated retail customer demand under normal operating conditions for the foreseeable future.
Energy Efficiency Programs
MidAmerican Energy has provided a comprehensive set of DSM programs to its Iowa electric and natural gas customers
since 1990. The programs, collectively referred to as energy efficiency programs, are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, MidAmerican Energy offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the nonresidential load management program. In Iowa, legislation passed in 2018 provides that projected cumulative average
annual costs for a natural gas energy efficiency plan cannot exceed 1.5% of expected Iowa natural gas retail revenue and, for an electric demand response plan and separately for an electric energy efficiency plan other than demand response, cannot exceed 2.0% of expected annual Iowa electric retail revenue. Although subject to prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for energy efficiency programs through state-specific energy efficiency service charges paid by all retail electric and natural gas customers. In 2023, $43 million was expensed for MidAmerican Energy's energy efficiency programs, which resulted in estimated first-year energy savings of 119,000 MWhs of electricity and 113,000 Dths of natural gas and an estimated peak load reduction of 406 MWs of electricity and 1,641 Dths per day of natural gas.
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Human
Capital
Employees
All of MidAmerican Funding's employees are employed by MidAmerican Energy. As of December 31, 2023, MidAmerican Energy had approximately 3,500 employees, of which approximately 1,400 were covered by union contracts. MidAmerican Energy has three separate contracts with locals of the International Brotherhood of Electrical Workers and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union. A contract with the International Brotherhood of Electrical Workers covering substantially all of the union employees expires April 30, 2027. For more information regarding MidAmerican Funding's and MidAmerican Energy's human capital
disclosures, refer to Item 1. Business - General section of this Form 10-K.
NV ENERGY (NEVADA POWER AND SIERRA PACIFIC)
General
NV Energy, an indirect wholly owned subsidiary of BHE, is an energy holding company headquartered in Nevada whose principal subsidiaries are Nevada Power and Sierra Pacific. Nevada Power and Sierra Pacific are indirect consolidated subsidiaries of Berkshire Hathaway. Nevada Power is a U.S. regulated electric utility company serving 1.0 million retail customers primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. Sierra Pacific is a U.S. regulated electric and natural
gas utility company serving 0.4 million retail electric customers and 0.2 million retail and transportation natural gas customers in northern Nevada. The Nevada Utilities are principally engaged in the business of generating, transmitting, distributing and selling electricity and, in the case of Sierra Pacific, in distributing, selling and transporting natural gas. Nevada Power and Sierra Pacific have electric service territories covering approximately 4,500 square miles and 41,400 square miles, respectively. Sierra Pacific has a natural gas service territory covering approximately 900 square miles in Reno and Sparks. Principal industries served by the Nevada Utilities include gaming, recreation, warehousing, manufacturing and governmental services. Sierra Pacific also serves the mining industry. The Nevada Utilities buy and sell electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants
to balance and optimize economic benefits of electricity generation, retail customer loads and wholesale transactions.
The Nevada Utilities' electric and natural gas operations are conducted under numerous nonexclusive franchise agreements, revocable permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 10- to 20-year terms. The Nevada Utilities operate under certificates of public convenience and necessity as regulated by the PUCN, and as such the Nevada Utilities have an obligation to provide electricity service to those customers within their service territory. In return, the PUCN has established rates on a cost-of-service basis, which are designed to allow the Nevada Utilities an opportunity to recover all prudently incurred costs of providing services and an opportunity to earn a reasonable
return on their investment.
NV Energy's monthly net income is affected by the seasonal impact of weather on electricity and natural gas sales and seasonal retail electricity prices from the Nevada Utilities'. For 2023, 86% of NV Energy annual net income was recorded in the months of June through September.
Regulated electric utility operations is Nevada Power's only segment while regulated electric utility operations and regulated natural gas operations are the two segments of Sierra Pacific.
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Sierra Pacific's operating revenue and operating income derived from
the following business activities for the years ended December 31 were as follows (dollars in millions):
2023
2022
2021
Operating
revenue:
Electric
$
1,194
83
%
$
1,025
86
%
$
848
88
%
Gas
237
17
168
14
117
12
Total
operating revenue
$
1,431
100
%
$
1,193
100
%
$
965
100
%
Operating
income:
Electric
$
133
88
%
$
146
88
%
$
148
89
%
Gas
19
12
19
12
19
11
Total
operating income
$
152
100
%
$
165
100
%
$
167
100
%
Nevada Power was incorporated under the laws of the state
of Nevada in 1929 and its principal executive offices are located at 6226 West Sahara Avenue, Las Vegas, Nevada89146, its telephone number is (702) 402-5000 and its internet address is www.nvenergy.com.
Sierra Pacific was incorporated under the laws of the state of Nevada in 1912 and its principal executive offices are located at 6100 Neil Road, Reno,
Nevada89511, its telephone number is (775) 834-4011 and its internet address is www.nvenergy.com.
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Regulated Electric Operations
Customers
The Nevada Utilities' sell electricity to retail
customers in a single state jurisdiction. Electricity sold to the Nevada Utilities' retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:
2023
2022
2021
Nevada
Power:
GWhs sold:
Residential
9,584
41
%
10,299
42
%
10,415
44
%
Commercial
4,807
20
4,904
21
4,838
21
Industrial
5,827
25
5,630
23
5,270
22
Other
179
1
191
1
198
1
Total
fully bundled
20,397
87
21,024
87
20,721
88
Distribution only service
2,831
12
2,786
11
2,646
11
Total
retail
23,228
99
23,810
98
23,367
99
Wholesale
230
1
586
2
356
1
Total
GWhs sold
23,458
100
%
24,396
100
%
23,723
100
%
Average
number of retail customers (in thousands):
Residential
899
89
%
886
89
%
871
88
%
Commercial
114
11
113
11
112
12
Industrial
2
—
2
—
2
—
Total
1,015
100
%
1,001
100
%
985
100
%
Sierra
Pacific:
GWhs sold:
Residential
2,655
23
%
2,747
22
%
2,769
23
%
Commercial
2,998
25
3,124
26
3,056
26
Industrial
2,684
23
2,867
23
3,716
31
Other
11
—
13
—
15
—
Total
fully bundled
8,348
71
8,751
71
9,556
80
Distribution only service
2,829
24
2,757
23
1,639
14
Total
retail
11,177
95
11,508
94
11,195
94
Wholesale
621
5
741
6
656
6
Total
GWhs sold
11,798
100
%
12,249
100
%
11,851
100
%
Average
number of retail customers (in thousands):
Residential
326
87
%
322
87
%
316
87
%
Commercial
50
13
49
13
49
13
Total
376
100
%
371
100
%
365
100
%
Variations
in weather, economic conditions, particularly for gaming, mining and wholesale customers and various conservation, energy efficiency and private generation measures and programs can impact customer energy requirements. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.
There are seasonal variations in the Nevada Utilities' electric business that are principally related to weather and the related use of electricity for air conditioning. Typically, 47-52% of Nevada Power's and 37-40% of Sierra Pacific's regulated electric revenue is reported in the months of June through September.
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The
annual hourly peak customer demand on the Nevada Utilities' electric systems occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On July 21, 2023, customer usage of electricity caused an hourly peak demand of 6,311 MWs on Nevada Power's electric system, which is 11 MWs more than the record hourly peak demand of 6,300 MWs set July 9, 2021. On July 21, 2023, customer usage of electricity caused an hourly peak demand of 1,825 MWs on Sierra Pacific's electric system, which is 281 MWs less than the record hourly peak demand of 2,106 MWs set July 12, 2021.
Generating Facilities and Fuel Supply
The
Nevada Utilities have ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding the Nevada Utilities' owned generating facilities as of December 31, 2023:
Facility
Net
Owned
Net Capacity
Capacity
Generating Facility
Location
Energy Source
Installed
(MWs)(1)
(MWs)(1)
Nevada
Power:
NATURAL GAS:
Lenzie
Las Vegas, NV
Natural gas
2006
1,218
1,218
Clark
Las
Vegas, NV
Natural gas
1973-2008
1,102
1,102
Harry Allen
Las Vegas, NV
Natural gas
1995-2011
628
628
Higgins
Primm,
NV
Natural gas
2004
602
602
Silverhawk
Las Vegas, NV
Natural gas
2004
590
590
Las
Vegas
Las Vegas, NV
Natural gas
1994-2003
272
272
Sun Peak
Las Vegas, NV
Natural gas/oil
1991
210
210
4,622
4,622
RENEWABLES:
Nellis
Las
Vegas, NV
Solar
2015
15
15
Goodsprings
Goodsprings, NV
Waste heat
2010
5
5
20
20
Total
Available Generating Capacity
4,642
4,642
Sierra Pacific:
NATURAL
GAS:
Tracy
Sparks, NV
Natural gas
1974-2008
763
763
Ft. Churchill
Yerington,
NV
Natural gas
1968-1971
196
196
Clark Mountain
Sparks, NV
Natural gas
1994
128
128
1,087
1,087
COAL:
Valmy
Unit Nos. 1 and 2
Valmy, NV
Coal
1981-1985
522
261
RENEWABLES:
Ft.
Churchill
Yerington, NV
Solar
2015
20
20
Total Available Generating Capacity
1,629
1,368
Total
NV Energy Available Generating Capacity
6,271
6,010
PROJECTS UNDER CONSTRUCTION:
Silverhawk
peakers project
Las Vegas, NV
Natural Gas
Est. 2024
444
444
Dry Lake (2)
Dry Lake, NV
Solar
Est. 2024
150
150
6,865
6,604
(1)Facility
Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates Nevada Power or Sierra Pacific's ownership of Facility Net Capacity.
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(2)In addition to the 150-MW solar photovoltaic facility, Dry Lake has 100 MW of co-located battery energy storage that will be developed in Clark County, Nevada with commercial operation expected by 2024.
In
December 2023, Nevada Power put into service its Reid Gardner battery energy storage system located in Moapa, Nevada, having total Facility Net Capacity and Net Owned Capacity of 220 MWs.
The following table shows the percentages of the Nevada Utilities' total energy supplied by energy source for the years ended December 31:
2023
2022
2021
Nevada
Power:
Total energy generated(1) - natural gas
65
%
60
%
64
%
Energy
purchased - long-term contracts (renewable)(2)
24
23
19
Energy purchased - long-term contracts (non-renewable)
5
9
10
Energy purchased - short-term contracts and other
6
8
7
100
%
100
%
100
%
Sierra
Pacific:
Natural gas
44
%
41
%
43
%
Coal
8
11
11
Total
energy generated(1)
52
52
54
Energy purchased - long-term contracts (renewable)(2)
32
28
17
Energy purchased - long-term contracts (non-renewable)
9
11
14
Energy
purchased - short-term contracts and other
7
9
15
100
%
100
%
100
%
(1) Energy generated from renewable generating facilities is not meaningful.
(2) All or some of the renewable energy attributes associated with generation from
these sources may be: (a) used in future years to comply with RPS or other regulatory requirements, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.
The Nevada Utilities are required to have resources available to continuously meet their customer needs and reliably operate their electric systems. The percentage of the Nevada Utilities' energy supplied by energy source varies from year-to-year and is subject to numerous operational and economic factors such as planned and unplanned outages; fuel commodity prices; fuel transportation costs; weather; environmental considerations; transmission constraints; and wholesale market prices of electricity. The Nevada Utilities evaluate these factors continuously in order to facilitate economic dispatch of their generating facilities. When factors for one energy source are less
favorable, the Nevada Utilities place more reliance on other energy sources. As long as the Nevada Utilities' purchases are deemed prudent by the PUCN, through their annual prudency review, the Nevada Utilities are permitted to recover the cost of fuel and purchased power. The Nevada Utilities also have the ability to reset quarterly the BTERs, with PUCN approval, based on the last 12 months fuel costs and purchased power and to reset the quarterly DEAA.
The Nevada Utilities have adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines for procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation, and with the growth of private generation serving a small but growing group of customers with partial requirements.
The second element is an energy risk management and control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Nevada Utilities pursue a process of ongoing regulatory involvement and acknowledgment of the resource portfolio management plans.
The Nevada Utilities have entered into multiple long-term power purchase contracts (three or more years) with suppliers that generate electricity utilizing renewable resources and natural gas. Nevada Power has entered into contracts with a total capacity of 2,937 MWs with contract termination dates ranging from 2024 to 2067. Included in these contracts are 2,852 MWs of capacity from renewable energy, of which 818 MWs of capacity are under development or construction and not currently
available. Sierra Pacific has entered into contracts with a total capacity of 1,098 MWs with contract termination dates ranging from 2024 to 2053. Included in these contracts are 1,086 MWs of capacity from renewable energy, of which 140 MWs of capacity are owned and under development or construction and not currently available.
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The Nevada Utilities manage certain risks relating to their supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives, including forwards, futures, options, swaps and other agreements. Refer to NV Energy's "General Regulation" section in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and Nevada Power's
Item 7A and Sierra Pacific's Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.
Natural Gas
The Nevada Utilities rely on indexed physical gas purchases for the majority of natural gas needed to operate their generating facilities. To secure natural gas supplies for the generating facilities, the Nevada Utilities execute purchases pursuant to a PUCN approved four-season laddering strategy. In 2023, natural gas supply net purchases averaged 299,343 and 154,897 Dths per day with the winter period contracts averaging 290,172 and 195,554 Dths per day and the summer period contracts averaging 305,813 and 126,209 Dths per day for Nevada Power and Sierra Pacific, respectively. The Nevada Utilities believe supplies from these sources are presently adequate and available
to meet its needs.
The Nevada Utilities contract for firm natural gas pipeline capacity to transport natural gas from production areas to their service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Nevada Power who contracts with Kern River, an affiliated company. Sierra Pacific utilizes natural gas storage contracted from interstate pipelines to meet retail customer requirements and to manage the daily changes in demand due to changes in weather and other usage factors. The stored natural gas is typically replaced during off-peak months when the demand for natural gas is historically lower than during the heating season.
Coal
Sierra Pacific
relies on spot market solicitations for coal supplies and will regularly monitor the western coal market for opportunities to meet these needs. Sierra Pacific has a transportation services contract with Union Pacific Railroad Company to ship coal from various origins in central Utah, western Colorado and Wyoming that expires December 31, 2025. Sierra Pacific has a transportation services contract with Burlington Northern Sante Fe Railroad Company to ship coal from western Montana that expires December 31, 2024. The Valmy generating facility, Sierra Pacific's remaining facility requiring coal, has an approved retirement date of December 2025. Sierra Pacific has proposed in its Fifth Amendment to the 2021 Joint Integrated Resource Plan to convert the existing coal fueled plant to a cleaner natural gas fueled plant. Nevada Power has no coal requirements.
Energy
Imbalance Market
The Nevada Utilities participate in the EIM operated by the California ISO, which reduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrates renewables and enhances reliability through improved situational awareness and responsiveness. The EIM expands the real-time component of the California ISO's market technology to optimize and balance electricity supply and demand every five minutes across the EIM footprint. The EIM is voluntary and available to all balancing authorities in the western U.S. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator
uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation resource bids, the California ISO market operator also receives continuous real-time updates of the transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. Outside the EIM footprint, utilities in the western U.S. do not utilize comparable technology and are largely limited to transactions within the borders of their balancing authority area to balance supply and demand intra-hour using a combination of manual and automated dispatch. The EIM delivers customer benefits by leveraging automation and resource diversity to result in more efficient dispatch, more effective integration of renewables and improved situational awareness. Benefits are expected to increase further with renewable resource
expansion and as more entities join the EIM bringing incremental diversity.
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Transmission and Distribution
The Nevada Utilities' transmission system is part of the Western Interconnection, a regional grid in the U.S. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. The Nevada Utilities' transmission system, together with contractual rights on other transmission systems, enables the Nevada Utilities to integrate and access generation resources to meet their customer load requirements. Nevada Power's transmission and distribution systems included approximately
1,900 miles of transmission lines, 14,300 miles of distribution lines and 220 substations as of December 31, 2023. Sierra Pacific's transmission and distribution systems included approximately 4,200 miles of transmission lines, 9,600 miles of distribution lines and 210 substations as of December 31, 2023.
ON Line is a 231-mile, 500-kV transmission line connecting Nevada Power's and Sierra Pacific's service territories. ON Line provides the ability to jointly dispatch energy throughout Nevada and provide access to renewable energy resources in parts of northern and eastern Nevada, which enhances the Nevada Utilities' ability to manage and optimize their generating facilities. ON Line provides between 600 MWs northbound and 900 MWs southbound of transfer capability with interconnection between
the Robinson Summit substation on the Sierra Pacific system and the Harry Allen substation on the Nevada Power system. ON Line was a joint project between the Nevada Utilities and Great Basin Transmission, LLC. The Nevada Utilities own a 25% interest in ON Line and have entered into a long-term transmission use agreement with Great Basin Transmission, LLC for its 75% interest in ON Line until 2054. The Nevada Utilities share of its 25% interest in ON Line and the long-term transmission use agreement is split 75% for Nevada Power and 25% for Sierra Pacific.
The PUCN has approved the Nevada Utilities' Greenlink Nevada transmission expansion program, with an estimated cost of approximately $3.1 billion, which builds a foundation for the Nevada Utilities to accommodate existing and future transmission network customers, increase transmission system reliability, create access to diversified
renewable resources, facilitate development of existing designated solar energy zones, facilitate conventional generation retirement and achieve Nevada's carbon reduction and eventual net-zero objectives. The Greenlink program consists of a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation, near Yerington, Nevada to the Northwest substation, near Las Vegas, Nevada to the Harry Allen substation, near Las Vegas, Nevada; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Mira Loma substations, near Yerington, Nevada; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Comstock Meadows substations, near Yerington, Nevada. The Greenlink
program will be constructed in stages that are estimated to be placed in-service between May 2027 and December 2028. The Nevada Utilities will jointly own and operate the Greenlink transmission lines with Nevada Power having a 70% ownership share in Greenlink West and North and Sierra Pacific having a 30% ownership share. Sierra Pacific will have a 100% ownership share in the Greenlink Common Ties. Through December 31, 2023, $187 million had been spent.
Natural Disaster Protection Plan
The Nevada Utilities have developed detailed natural disaster protection plans for its service territory and areas in which it owns and operates assets. Natural disaster protection plans are filed annually with the PUCN on or before March 1 of every third year with annual
updates to be filed on or before September 1 of the second and third years of the plan. These plans include capital investment in asset hardening and meteorological systems, the implementation of risk modeling tools and the Nevada Utilities' ongoing elevated fire risk settings, inspections, vegetation management, enhancement to situational awareness to include implementation of wildfire alert cameras and weather stations in extreme fire-risk areas and public safety outage management ("PSOM") programs and policies.
Asset Hardening
The Nevada Utilities have and continue to invest in rebuilding overhead transmission and distribution lines with covered conductor and fire mesh and in some cases have converted overhead distribution lines to underground. These system hardening efforts reduce the exposure
of the Nevada Utilities' lines to interference from trees and other objects. Covered conductor helps mitigate the risk of fault-caused electrical arcs that could cause an ignition. Overall, mitigated overhead lines help reduce ignition risk and improve reliability during storms or periods of significant wildfire risk.
The Nevada Utilities compiled an assessment of heightened threat areas ("HTAs") for wildfires that are presented as different tiers to characterize wildfire risk and potential catastrophic wildfire risk. The different tiers that the Nevada Utilities use to categorize their HTAs are Tier 1, Tier1E - Elevated ("Tier 1E"), Tier 2 (high) and Tier 3 (extreme).
27
Approximately
2,730 miles, or 9%, of the Nevada Utilities' transmission and distribution lines are in Tier 1E, Tier 2 and Tier 3 HTAs, covering approximately 6% of its service territory and approximately 0.2% of its customer base.
As of December 31, 2023, the 2,730 miles of transmission and distribution lines in Tier 1E, Tier 2 and Tier 3 HTAs were as follows:
•1,964 miles, or 72%, with bare conductor miles, a portion of which in Tier 3 is fully mitigated by system relay fast trip protection schemes that are expanding into Tiers 2 and 1E with completion by the end of 2024;
•16 miles, or 1%, with new covered conductor miles; and
•750 miles, or 27%,
with underground miles.
The on-going asset hardening of the HTAs is a priority for the Nevada Utilities and a key part of the developed wildfire mitigation plans.
Refer to "Future Uses of Cash" in Item 7 of this Form 10-K for further discussion of the Nevada Utilities' natural disaster protection plan related capital expenditures, including asset hardening.
Elevated Fire Risk Settings
Elevated fire risk settings are available across the HTAs in the Nevada Utilities' service territory. Upon declaration of wildfire season, the Nevada Utilities place all Tier 3 circuits and certain Tier 2 and Tier 1E circuits into fire season mode with no circuit
reclosing which reduces the potential for sparking on multiple reclosing events when faults occur. Additionally, Fast Trip Fire Mode is an instantaneous lockout setting available at most HTA substations that is enabled when certain risk conditions are present to provide an enhanced level of protection to limit the potential for wildfire ignition.
Meteorology and Risk Modeling
The Nevada Utilities have installed 65 weather stations that monitor weather conditions and model the impact to the electrical infrastructure. These weather stations combined with the Nevada Utilities' dedicated full-time meteorologist provide the Nevada Utilities with the ability to forecast weather and fire risk impact data twice daily. The Nevada Utilities will continue to install additional weather stations to refine weather modeling in areas where
geographic terrain conditions require a dense network of weather stations in order to provide the necessary granular data. The Nevada Utilities have also installed 11 fire cameras equipped with artificial intelligence that provide around-the-clock monitoring and alerts of new fire starts.
Asset Inspection Program
Within the identified HTAs, the Nevada Utilities conduct an annual inspection of overhead facilities with an accelerated correction timeline for any conditions noted. A detailed inspection of facilities located in HTAs is conducted every three to 10 years based on the identified risk level.
Vegetation Management
The Nevada Utilities' vegetation management program consists
of prioritized patrols and inspections and vegetation clearing work including right-of-way clearing, tree trimming and ground clearing of equipment poles in all HTAs. The Nevada Utilities collaborate with state and federal agencies for enhanced ground clearing to create resilient corridors of cleared vegetation to deter fire spread.
Public Safety Outage Management
A PSOM is used as a preventative measure prior to extraordinary weather conditions that may pose threats to the public, customers, infrastructure or the environment where the electrical network is de-energized proactively under certain conditions. This program includes areas of wildfire risk in Tier 3, Tier 2 and Tier 1E where proactive de-energization zones are identified. In determining whether to initiate a PSOM, the Nevada Utilities evaluate conditions that may
create an unacceptable level of risk of electric infrastructure being damaged and causing an ignition using data from meteorological systems and forecasting tools. During 2023, the Nevada Utilities continued to actively utilize the PSOM program to address extreme-risk weather conditions.
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Future Generation, Conservation and Energy Efficiency
Energy Supply Planning
Within the energy supply planning process, there are four key components covering different time frames:
•IRPs
are filed by the Nevada Utilities for approval by the PUCN every three years and the Nevada Utilities may, as necessary, file amendments to their IRPs. IRPs are prepared in compliance with Nevada laws and regulations and cover a 20-year period. Nevada law governing the IRP process was modified in 2017 and now requires joint filings by Nevada Power and Sierra Pacific. IRPs develop a comprehensive, integrated plan that considers customer energy requirements and propose the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the IRPs is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of the Nevada Utilities' customers. Costs incurred to complete projects approved through the IRP process still remain subject to review for reasonableness by the PUCN.
•Energy Supply Plans
("ESP") are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP. The ESP has a one- to three-year planning horizon and is an intermediate-term resource procurement and risk management plan that establishes the supply portfolio strategies within which intermediate-term resource requirements will be met with PUCN approval required for executing contracts of longer than three years.
•Distributed Resource Plans ("DRP") are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP. The DRP establishes a formal process to aid in the cost-effective integration of distributed resources into the Nevada Utilities' distribution and transmission process and ultimately the NV Energy utilities' electricity grid.
•Action plans are filed with the PUCN for approval
and operate in conjunction with the PUCN-approved 20-year IRP and PUCN-approved ESP. The action plan establishes tactical execution activities with a three-year focus.
In its 2021 Integrated Resource Plan Fourth Amendment filed November 30, 2022, NV Energy requested approval for a 20-megawatt Advanced Geothermal System power purchase agreement with Eavor, a 120-megawatt geothermal portfolio power purchase agreement with Ormat, and the development of a company-owned, 200-megawatt, 800 megawatt-hour grid-tied battery energy storage system in Sierra Pacific's territory at Valmy station. In June 2023, the PUCN granted in part and denied in part the fourth amendment as delineated in the order.
In compliance with SB 448, the Nevada Utilities filed their second
and third amendments to the 2021 joint IRP in July and September 2022, respectively. The Nevada Utilities requested an approval to amend the Demand Side Plan for the action period for 2022-2024 in July's filing and requested in September an approval of a DRP amendment to implement the state's first Transportation Electrification Plan ("TEP") and approve proposed tariffs and schedules to implement the TEP. In November 2022, the Nevada Utilities filed an all-party settlement stipulation of the second amendment to the IRP, resolving all issues. In March 2023, the PUCN issued an order accepting the stipulation, granting in part and denying in part the Joint Application as modified by the Order and the Stipulation, accepting in part, deeming inadequate in part, and modifying the third amendment to the Joint IRP, and approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on the program management and contingency
budget amounts. The unapproved programs have been deferred for approval in future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs. In April 2023, interveners filed a petition for reconsideration of the PUCN's March 2023 order. In May 2023, the PUCN granted in part and denied in part the petition for reconsideration and affirmed the March 2023 order.
In August 2023, the Nevada Utilities filed its Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part (1) to convert the existing coal fueled plant at North Valmy Generating Station to a cleaner natural gas fueled plant (2) to construct a company-owned 400 MW solar plant along with a 400 MW, four-hour battery storage system in Northern Nevada; (3) to continue operation of Tracy units 4 and 5 to 2049; (4) to purchase development
assets for a 149 MW photovoltaic and 149 MW battery energy storage system known as the Crescent Valley Solar project; (5) to construct the Esmeralda and Amargosa substations transformers; and (6) to construct the necessary infrastructure in the Apex Area Master Plan. The Nevada Utilities seek approval of approximately $1.8 billion in total costs of new projects with an order expected in 2024.
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Energy Efficiency Programs
The Nevada Utilities have provided a comprehensive set of DSM programs which include energy efficiency, demand response, and conservation programs to their Nevada electric customers. The programs are designed to reduce energy
consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy audits and customer education and awareness efforts that provide information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, the Nevada Utilities have offered rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, electric water heating, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the smart thermostat and energy storage demand response program and nonresidential load management program. Energy efficiency program costs are recovered through
annual rates set by the PUCN and adjusted based on the Nevada Utilities' annual filing to recover current program costs and any over or under collections from the prior filing, subject to prudence review. During 2023, Nevada Power spent $46 million on energy efficiency programs, resulting in an estimated 225,753 MWhs of electric energy savings and an estimated 156 MWs of electric peak load management. During 2023, Sierra Pacific spent $13 million on energy efficiency programs, resulting in an estimated 53,195 MWhs of electric energy savings and an estimated 25 MWs of electric peak load management.
Regulated Natural Gas Operations
Sierra Pacific is engaged in the distribution of natural gas to customers in its service territory and the related procurement, transportation and storage of natural gas for
the benefit of those customers. Sierra Pacific purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the natural gas from the production areas to Sierra Pacific's service territory and for storage services to manage fluctuations in system demand and seasonal pricing. Sierra Pacific sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. During 2023, 6% of the total natural gas delivered through Sierra Pacific's distribution system was for transportation service.
Natural gas property consists primarily of natural gas mains and service lines, meters, and related
distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of Sierra Pacific included 3,600 miles of natural gas mains and service lines as of December 31, 2023.
Customer Usage and Seasonality
The percentages of natural gas sold to Sierra Pacific's retail and wholesale customers by class of customer, total Dths of natural gas sold, total Dths of transportation service and the average number of retail customers for the years ended December 31 were as follows:
2023
2022
2021
Residential
52
%
55
%
53
%
Commercial(1)
26
28
28
Industrial(1)
12
11
10
Total
retail
90
94
91
Wholesale(2)
10
6
9
100
%
100
%
100
%
Total
Dths of natural gas sold (in thousands)
23,613
20,622
20,050
Total Dths of transportation service (in thousands)
1,453
1,576
1,850
Total average number of retail customers (in thousands)
183
180
177
(1)Commercial
and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers with monthly gas usage less than 12,000 therms during five consecutive winter months. Industrial customers are non-residential customers that use natural gas in excess of 12,000 therms during one or more winter months.
(2)Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.
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There are seasonal variations in Sierra Pacific's regulated natural gas business that are principally
due to the use of natural gas for heating. Typically, 47-56% of Sierra Pacific's regulated natural gas revenue is reported in the months of December through March.
On January 31, 2023, Sierra Pacific recorded its highest peak-day natural gas delivery of 160,974 Dths, which is 2,600 Dths less than the record peak-day delivery of 163,574 Dths set on December 9, 2013. This peak-day delivery consisted of 95% traditional retail sales service and 5% transportation service.
Fuel Supply and Capacity
The purchase of natural gas for Sierra Pacific's regulated natural gas operations is done in combination with the purchase of natural
gas for Sierra Pacific's regulated electric operations. In response to energy supply challenges, Sierra Pacific has adopted an approach to managing the energy supply function that has three primary elements, as discussed earlier under Generating Facilities and Fuel Supply. Similar to Sierra Pacific's regulated electric operations, as long as Sierra Pacific's purchases of natural gas are deemed prudent by the PUCN, through its annual prudency review, Sierra Pacific is permitted to recover the cost of natural gas. Sierra Pacific also has the ability, with PUCN approval, to reset quarterly the BTERs, based on the last 12 months fuel costs, and to reset quarterly DEAA.
Human Capital
Employees
As of December 31,
2023, Nevada Power had approximately 1,500 employees, of which approximately 800 were covered by a union contract with the International Brotherhood of Electrical Workers.
As of December 31, 2023, Sierra Pacific had approximately 1,000 employees, of which approximately 500 were covered by a union contract with the International Brotherhood of Electrical Workers.
For more information regarding Nevada Power's and Sierra Pacific's human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.
NORTHERN POWERGRID
Northern
Powergrid, an indirect wholly owned subsidiary of BHE, is a holding company which owns two companies that distribute electricity in Great Britain, Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc. In addition to the Northern Powergrid Distribution Companies, Northern Powergrid also owns a meter asset rental business that leases meters to energy suppliers in the United Kingdom, an engineering contracting business that provides electrical infrastructure contracting services primarily to third parties, a hydrocarbon exploration and development business that is focused on developing integrated upstream gas projects in Europe and Australia ("CE Gas") and ownership interests in two solar generation facilities in Australia having a total net owned capacity of 260 MWs.
The Northern Powergrid Distribution Companies serve 4.0 million end-users and operate in the
north-east of England from North Northumberland through Tyne and Wear, County Durham and Yorkshire to North Lincolnshire, an area covering 10,000 square miles. The principal function of the Northern Powergrid Distribution Companies is to build, maintain and operate the electricity distribution network through which the end-user receives a supply of electricity.
The Northern Powergrid Distribution Companies receive electricity from the national grid transmission system and from generators that are directly connected to the distribution network and distribute it to end-users' premises using their networks of transformers, switchgear and distribution lines and cables. Substantially all of the end-users in the Northern Powergrid Distribution Companies' distribution service areas are directly or indirectly connected to the Northern Powergrid Distribution Companies' networks and electricity
can only be delivered to these end-users through their distribution systems, thus providing the Northern Powergrid Distribution Companies with distribution volumes that are relatively stable from year to year. The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to the suppliers of electricity.
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The suppliers purchase electricity from generators, sell the electricity to end-user customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to an industry standard "Distribution Connection and Use of System Agreement." During 2023, E.ON and certain of its affiliates and British Gas Trading Limited represented 19% and 15%, respectively, of the
total combined distribution revenue of the Northern Powergrid Distribution Companies. Variations in demand from end-users can affect the revenues that are received by the Northern Powergrid Distribution Companies in any year, but such variations have no effect on the total revenue that the Northern Powergrid Distribution Companies are allowed to recover in a price control period. Under- or over-recoveries against price-controlled revenues are carried forward into prices for future years.
The Northern Powergrid Distribution Companies' combined service territory features a diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a broad customer base ranging from domestic usage through farming and retail to major industry including automotives, chemicals, mining, steelmaking and offshore marine construction. The industry within the area
is concentrated around the principal centers of Newcastle, Middlesbrough, Sheffield and Leeds.
The price-controlled revenue of the Northern Powergrid Distribution Companies is set out in the special conditions of the licenses of those companies. The licenses are enforced by the regulator, GEMA, through Ofgem, and limit increases to allowed revenues (or may require decreases) based upon the rate of inflation, other specified factors and other regulatory action. The current electricity distribution price control became effective April 1, 2023 and will continue through March 31, 2028.
GWhs and percentages of electricity distributed to the Northern Powergrid Distribution Companies' end-users and the total number
of end-users as of and for the years ended December 31 were as follows:
2023
2022
2021
GWhs
distributed:
Residential
11,638
38
%
11,880
37
%
13,334
40
%
Commercial
3,534
11
3,737
12
3,643
10
Industrial
15,655
50
16,239
50
16,424
49
Other
279
1
301
1
318
1
31,106
100
%
32,157
100
%
33,719
100
%
Number
of end-users (in thousands):
3,954
3,953
3,941
As
of December 31, 2023, the combined electricity distribution network of the Northern Powergrid Distribution Companies included approximately 17,100 miles of overhead lines, 44,000 miles of underground cables and 790 major substations.
BHE PIPELINE GROUP (EASTERN ENERGY GAS AND EGTS)
The BHE Pipeline Group consists of BHE GT&S, Northern Natural Gas and Kern River, each an indirect wholly owned subsidiary of BHE. The BHE Pipeline Group operates approximately 21,000 miles of pipeline with a design capacity of approximately 21.1 Bcf of natural gas per day, transported approximately 15% of the total natural gas consumed in the U.S. during
2023 and owns assets in 27 states. The BHE Pipeline Group also operates 22 natural gas storage facilities with a total working gas capacity of 515.6 Bcf and an LNG export, import and storage facility.
The Pipeline Companies compete with other pipelines on the basis of cost, flexibility, reliability of service and overall customer service, with the customer's decision being made primarily on the basis of delivered price, which includes both the natural gas commodity cost and transportation costs. The Pipeline Companies also compete with midstream operators and gas marketers seeking to provide or arrange transportation, storage and other services to meet customer needs. Natural gas competes with alternative energy sources, including coal, nuclear energy, wind, geothermal, solar and fuel oil and the electricity generated from these alternative energy sources. The Pipeline Companies generate
a substantial portion of their revenue from long-term firm contracts for transportation and storage services and are therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, the Pipeline Companies face competitive pressures from other natural gas pipeline facilities.
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Subject to regulatory requirements, the Pipeline Companies attempt to recontract or remarket capacity at the maximum rates allowed under their tariffs, although at times the Pipeline Companies discount these rates to remain competitive. Historically, the Pipeline Companies have been able to provide competitively priced services because of access to a variety of relatively low cost supply basins, cost
control measures and the relatively high level of firm entitlement that is sold on a seasonal and annual basis, which lowers the per unit cost of transportation. To date, the Pipeline Companies have avoided significant pipeline system bypasses.
BHE GT&S
BHE GT&S' operations, through its ownership of Eastern Energy Gas, includes three interstate natural gas pipeline systems, one of the nation's largest underground natural gas storage systems and one LNG export, import and storage facility. BHE GT&S' operations also include smaller LNG facilities and a gathering and processing company.
Eastern Energy Gas' principal subsidiaries are EGTS and CGT. EGTS' operations include natural gas transmission and storage pipelines
located in Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. EGTS also operates one of the nation's largest underground natural gas storage systems located in New York, Pennsylvania and West Virginia. CGT's operations include an interstate natural gas pipeline system located in South Carolina and Georgia. Eastern Energy Gas also owns a 50% equity interest in Iroquois Gas Transmission System L.P. ("Iroquois"). Iroquois owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut.
Eastern Energy Gas' LNG operations involve the export, import and storage of LNG at the Cove Point LNG Facility that is owned by Cove Point, located in Maryland, as well as the transmission of regasified LNG to the interstate pipeline grid and mid-Atlantic markets and the liquefaction of natural gas for export as LNG. Cove Point's LNG Facility
has an operational peak regasification daily send-out capacity of approximately 1.8 million Dth and an aggregate LNG storage capacity of approximately 14.6 billions of cubic feet equivalent ("Bcfe"). In addition, Cove Point has a small liquefier that has the potential to produce approximately 15,000 Dth/day. The Liquefaction Facility consists of one LNG train with a nameplate outlet capacity of 5.25 million tonnes per annum ("Mtpa"). Cove Point has authorization from the DOE to export up to 0.77 Bcfe/day (approximately 5.75 Mtpa) should the Liquefaction Facility perform better than expected. Cove Point's 36-inch diameter underground interstate natural gas pipelines are approximately 139 miles, with interconnections to Transcontinental Gas Pipeline, LLC in Fairfax County, Virginia, and with Columbia Gas Transmission, LLC and EGTS in Loudoun County, Virginia. Eastern Energy Gas operates, as the general partner, and prior to September
1, 2023, owned a 25% limited partner interest in the Cove Point LNG export, import and storage facility. On September 1, 2023, Eastern Energy Gas completed its acquisition of 50% of the limited partner interests in Cove Point from DEI, and accordingly, owns an aggregate of 75% of the limited partner interests and continues to own 100% of the general partner interest of Cove Point. BHE GT&S also operates and has ownership interests in three smaller LNG facilities in Alabama, Florida and Pennsylvania.
In total, Eastern Energy Gas operates approximately 5,400 miles of natural gas transmission, gathering and storage pipelines, of which approximately 5,200 miles are owned by Eastern Energy Gas, with a design capacity of 12.6 Bcf per day as well as approximately 100 miles of natural gas liquids pipelines operated by BHE GT&S. EGTS
operates approximately 3,900 miles of natural gas transmission and storage pipelines with a design capacity of 9.9 Bcf per day. EGTS also operates 17 underground storage fields with a total working gas capacity of approximately 420 Bcf, of which approximately 307 Bcf relates to natural gas storage field capacity that EGTS owns. BHE GT&S' pipeline system is configured with approximately 360 active receipt and delivery points. In 2023, BHE GT&S delivered over 2.1 trillion cubic feet ("Tcf") of natural gas to its customers.
BHE GT&S' natural gas transmission and storage earnings primarily result from rates established by FERC. Revenues derived from BHE GT&S' pipeline operations are primarily from reservation charges for firm transmission and storage services as provided for in their FERC-approved tariffs. Reservation charges are required to be paid regardless of volumes
transported or stored. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. As of December 31, 2023, 84% of BHE GT&S' transmission capacity is subscribed, including 79% under long-term contracts and 5% on a year-to-year basis, and 100% of EGTS' storage capacity is subscribed, including 97% under long-term contracts. As of December 31, 2023, the weighted average remaining contract term for Eastern Energy Gas' and EGTS' firm transmission contracts is seven years and five years, respectively, and EGTS' storage contracts is four years. Additionally, BHE GT&S receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain pipeline transmission and LNG storage and terminal services. Variability
in BHE GT&S' earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.
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BHE GT&S' operating revenue for the year ended December 31 was as follows (in millions):
2023
2022
Transmission
$
881
39
%
$
849
35
%
LNG
796
36
790
33
Storage
329
15
316
13
Gas,
liquids and other sales
233
10
447
19
Total operating revenue
$
2,239
100
%
$
2,402
100
%
Except
for quantities of natural gas owned and managed for operational and system balancing purposes, BHE GT&S does not own the natural gas that is transported through its system.
During 2023, BHE GT&S had two customers that each accounted for greater than 15% of its operating revenue and its 10 largest customers accounted for 48% of its total operating revenue. BHE GT&S has agreements with terms through 2038 to retain the majority of its two largest customers' volumes. The loss of any of these significant customers, if not replaced, could have a material adverse effect on BHE GT&S.
Human Capital
As of December 31, 2023, Eastern Energy Gas had approximately 1,500 employees,
consisting of approximately 1,200 natural gas operations employees and 300 corporate services employees. As of December 31, 2023, approximately 600 employees were covered by a union contract with the Utility Workers Union of America.
As of December 31, 2023, EGTS had approximately 1,300 employees, consisting of approximately 1,000 natural gas operations employees and 300 corporate services employees. As of December 31, 2023, approximately 600 employees were covered by a union contract with the Utility Workers Union of America.
For more information regarding Eastern Energy Gas' and EGTS' human capital disclosures, refer to Item 1. Business - General section
of this Form 10-K.
Northern Natural Gas
Northern Natural Gas owns the largest interstate natural gas pipeline system in the U.S., as measured by pipeline miles, which reaches from west Texas to Michigan's Upper Peninsula. Northern Natural Gas primarily transports and stores natural gas for utilities, municipalities, gas marketing companies and industrial and commercial users. Northern Natural Gas' pipeline system consists of two commercial segments. Its traditional end-use and distribution market area in the northern part of its system, referred to as the Market Area, includes points in Iowa, Nebraska, Minnesota, Wisconsin, South Dakota, Michigan and Illinois. Its natural gas supply and delivery service area in the southern part of its system, referred to as the Field Area, includes points in Kansas,
Texas, Oklahoma and New Mexico. The Market Area and Field Area are separated at a Demarcation Point ("Demarc"). Northern Natural Gas' pipeline system consists of 14,200 miles of natural gas pipelines, including 5,800 miles of mainline transmission pipelines and 8,400 miles of branch and lateral pipelines, with a Market Area design capacity of 6.3 Bcf per day, a Field Area delivery capacity of 1.7 Bcf per day to the Market Area and 1.5 Bcf per day to the West Texas area and 95.6 Bcf of working gas capacity in five storage facilities. Northern Natural Gas' pipeline system is configured with approximately 2,362 active receipt and delivery points which are integrated with the facilities of LDCs. Many of Northern Natural Gas' LDC customers are part of combined utilities that also use natural gas as a fuel source for electric generation. Northern Natural Gas delivered over 1.4 Tcf of natural gas to its customers in 2023.
34
Northern
Natural Gas' transportation rates and most of its storage rates are cost-based. These rates are designed to provide Northern Natural Gas with an opportunity to recover its costs of providing services and earn a reasonable return on its investments. Substantially all of Northern Natural Gas' Market Area transportation revenue is generated from reservation charges, with the balance from usage charges. Most of Northern Natural Gas' transportation capacity in the Market Area is committed to customers under firm transportation contracts, where customers pay Northern Natural Gas a monthly reservation charge for the right to transport natural gas through Northern Natural Gas' system. Reservation charges are required to be paid regardless of volumes transported or stored. As of December 31, 2023, approximately 72% of Northern Natural Gas' customers' entitlement in the Market Area have terms beyond 2026 and approximately 49% beyond
2027. As of December 31, 2023, the weighted average remaining contract term for Northern Natural Gas' Market Area firm transportation contracts is six years. Northern Natural Gas' Field Area customers consist primarily of energy marketing companies, midstream companies and power generators that are connected to Northern Natural Gas' system in Texas and New Mexico that are contracted on a long-term basis with a weighted average remaining contract term of five years. Northern Natural Gas' storage services are provided through the operation of one underground natural gas storage field in Iowa and two underground natural gas storage facilities in Kansas. Additionally, Northern Natural Gas has two LNG storage peaking units, one in Iowa and one in Minnesota, that support its transportation service. The three underground natural gas storage facilities and two LNG storage peaking units have a total working gas capacity of over
95.6 Bcf and approximately 2.2 Bcf per day of peak delivery capability. The average remaining contract term for firm storage contracts is five years.
Northern Natural Gas' operating revenue for the years ended December 31 was as follows (in millions):
2023
2022
2021
Transportation:
Market
Area
$
815
65
%
$
688
62
%
$
658
61
%
Field Area
249
22
210
18
177
17
Total
transportation
1,064
87
898
80
835
78
Storage
113
9
97
9
94
9
Total
transportation and storage revenue
1,177
96
995
89
929
87
Gas, liquids and other sales
49
4
123
11
143
13
Total
operating revenue
$
1,226
100
%
$
1,118
100
%
$
1,072
100
%
Except for quantities of natural gas owned and managed for operational and system balancing purposes,
Northern Natural Gas does not own the natural gas that is transported through its system. The sale of natural gas for operational and system balancing purposes accounts for the majority of the remaining operating revenue.
During 2023, Northern Natural Gas had two customers that each accounted for greater than 10% of its transportation and storage revenue and its 10 largest customers accounted for 64% of its system-wide transportation and storage revenue. Northern Natural Gas has agreements with terms through 2027 and 2034 to retain the majority of its two largest customers' volumes. The loss of either of these significant customers, if not replaced, could have a material adverse effect on Northern Natural Gas.
Kern River
Kern
River owns an interstate natural gas pipeline system that extends from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. Kern River operates 1,400 miles of mainline natural gas pipelines, with a year-round design capacity of 2,166,575 Dths, or 2.2 Bcf, per day. Additional seasonal design capacity (Bell-Curve) is contracted in all months except July, August and September. The mainline pipeline extends from the system's point of origination near Opal, Wyoming, through the Central Rocky Mountains to Daggett, California. The mainline section consists of 1,300 miles of 36-inch diameter pipeline and 100 miles of various laterals that connect to the mainline. Kern River primarily transports natural gas for utilities, municipalities, energy marketing companies, electric generating companies and other industrial and commercial users.
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Kern
River's rates are designed to provide Kern River with an opportunity to recover its costs of providing services and earn a reasonable return on its investments and are based on a levelized rate design that assumes recovery of 70% of the original investment during the initial long-term contracts ("Period One rates"). After expiration of the initial term, eligible customers have the option to elect service at rates ("Period Two rates") that are lower than Period One rates because they are designed to recover the remaining 30% of the original investment. To the extent that eligible customers do not contract for service at Period Two rates, the volumes are turned back to Kern River, and it resells capacity at market rates for varying terms. As of December 31, 2023, approximately 87% of Kern River's design capacity, including seasonal Bell-Curve, totaled 2,345,381 Dths per day and is contracted pursuant to long-term
firm natural gas transportation service agreements, whereby Kern River receives natural gas on behalf of customers at designated receipt points and transports the natural gas on a firm basis to designated delivery points. In return for this service, each customer pays Kern River a fixed monthly reservation fee based on each customer's maximum daily quantity, which represents nearly 81% of total operating revenue, and a commodity charge based on the actual amount of natural gas transported pursuant to its long-term firm natural gas transportation service agreements and Kern River's tariff. These long-term firm natural gas transportation service agreements expire between February 2024 and December 2045 and have a weighted-average remaining contract term of over eight years. As of December 31, 2023, 74% of the year-round design capacity of 2,166,575 Dths under firm contract has primary delivery points in California, with
the flexibility to access secondary delivery points in Nevada and Utah.
Except for quantities of natural gas owned for operational purposes, Kern River does not own the natural gas that is transported through its system. Kern River's transportation rates are cost-based.
During 2023, Kern River had two customers, including Nevada Power Company, an affiliated company, that each accounted for greater than 10% of its revenue. The loss of these significant customers, if not replaced, could have a material adverse effect on Kern River.
BHE TRANSMISSION
BHE
Transmission consists of BHE Canada, an indirect wholly owned subsidiary of BHE, BHE U.S. Transmission, a wholly owned subsidiary of BHE, ownership interests in generating facilities and 300 MWs of long-term northbound transmission rights on the Montana Alberta Tie Line (commencing April 30, 2026). BHE Canada and BHE U.S. Transmission together own and operate the Montana Alberta Tie Line, which is a 214-mile, 230-kV transmission line that runs from Lethbridge, Alberta, Canada to Great Falls, Montana, U.S. and connects power grids in the two jurisdictions. BHE Canada also owns AlbertaEx, a cross-border operations center to optimize in real-time the value of BHE Canada and BHE U.S. Transmission's existing physical generation assets on the Montana Alberta Tie Line. Operations are set to commence in January 2025.
BHE Canada
BHE
Canada primarily owns AltaLink, a regulated electric transmission utility company headquartered in Alberta, Canada serving approximately 85% of Alberta's population. AltaLink's high voltage transmission lines and related facilities transmit electricity from generating facilities to major load centers, cities and large industrial plants throughout its 87,000 square mile service territory, which covers a diverse geographic area including most major urban centers in central and southern Alberta. AltaLink's transmission facilities, consisting of approximately 8,300 miles of transmission lines and approximately 310 substations as of December 31, 2023, are an integral part of the Alberta Interconnected Electric System ("AIES").
The AIES is a network or grid of transmission facilities operating at high voltages ranging from 69 kV to 500
kV. The grid delivers electricity from generating units across Alberta, Canada through approximately 16,000 miles of transmission lines. The AIES is interconnected to British Columbia's transmission system that links Alberta with the North American western interconnected system, interconnection with Saskatchewan's transmission system and interconnection with Montana's transmission system.
AltaLink is a transmission facility owner within the electricity industry in Alberta and is permitted to charge a tariff rate for the use of its transmission facilities. Such tariff rates are established on a cost-of-service regulatory model, which is designed to allow AltaLink an opportunity to recover its costs of providing services and to earn a reasonable return on its investments. Transmission tariff rates are approved by the AUC and are collected from the AESO.
36
The
electricity industry in Alberta consists of four principal segments. Generators sell wholesale power into the power pool operated by the AESO and through direct contractual arrangements. Alberta's transmission system or grid is composed of high voltage power lines and related facilities that transmit electricity from generating facilities to distribution networks and directly connected end-users. Distribution facility owners are regulated by the AUC and are responsible for arranging for, or providing, regulated rate and regulated default supply services to convey electricity from transmission systems and distribution-connected generators to end-use customers. Retailers can procure energy through the power pool, through direct contractual arrangements with energy suppliers or ownership of generation facilities and arrange for its distribution to end-use customers.
The AESO mandate is defined
in the Electric Utilities Act (Alberta) and its regulations and requires the AESO to assess both current and future needs of Alberta's interconnected electrical system. In January 2022, the AESO released the 2022 Long-Term Transmission Plan. Updated every two years, the Long-Term Transmission Plan seeks to optimize the use of the existing transmission system and plan the development of new transmission to ensure a safe and reliable electricity system that enables a fair, efficient and openly competitive electricity market. The 2022 Long-Term Transmission Plan identifies C$1.3 billion in transmission projects over a 10-year period, which results in C$150 million to C$200 million per year on average over that 10-year period. This results in a cumulative transmission rate impact of C$2 per MWh for the first five to eight years, increasing to C$3 per MWh after 15 years. The Long-Term Transmission Plan identifies approximately
C$900 million of projects in AltaLink's service territory with in-service dates before 2030. On November 15, 2023, the AESO issued a preliminary update on the 2024 Long-term Outlook. The AESO is re-evaluating scenarios to include decarbonization by 2050, as well as decarbonization by 2035. AltaLink and other stakeholders provided feedback to the AESO which was published on the AESO's website on December 8, 2023. The final 2024 Long-term Outlook is expected in the second quarter of 2024. The next Long-Term Transmission Plan is expected to be completed in the first quarter of 2025.
Wildfire Risk
Alberta may experience a heightened incidence of wildfires, or wildfire severity due to climate change and other
factors. AltaLink cannot predict how the AUC will respond to such heightened incidence, or how the AUC might treat recovery of its investment or damages and whether or not it might impose fines. AltaLink has a robust set of procedures to address wildfire risk. AltaLink reviews and updates these procedures based on the best practices in other jurisdictions. AltaLink applies to the AUC for approval for funds to implement these procedures and mitigation investments. Additional requirements may be imposed by the regulator or legislators in response to heightened risk. AltaLink is monitoring all changes to its regulatory framework and will respond to any such changes as they arise. Electricity transmission facilities may also start wildfires as a result of causes such as equipment operation or failure, trees contacting transmission lines, or lightning strikes on transmission lines or equipment.
Wildfire
Mitigation Plans
AltaLink has developed and implemented detailed wildfire mitigation plans for its service territory since 2019. AltaLink files and gets AUC approval for its wildfire mitigation plan as part of its GTA process. AltaLink has received approval for its wildfire mitigation plan in both the 2019-2021 and 2022-2023 GTA periods. These plans include improvements in situational awareness, meteorological systems, and risk modeling; investments in asset hardening and vegetation management; and AltaLink's ongoing elevated fire risk operating practices and policies, including inspections, recloser blocking procedures, and PSPS.
AltaLink filed an amendment to its 2024-2025 GTA with additional measures to proactively expand and accelerate its 2024-2025 Wildfire Mitigation Plan in response to the increase
in wildfire risk to Albertans and AltaLink's critical infrastructure which delivers reliable electricity to customers. AltaLink proposes a catastrophic wildfire damages deferral account for damages in excess of commercial insurance. Despite its actions, AltaLink may be liable for firefighting costs, damages to personal property, structures, and natural resources, fines, and third-party claims including for personal injuries in connection with such fires. These costs could substantially exceed insurance coverage, if any, and such amounts may not be approved by the AUC for recovery, in whole or in part, through increased tariff revenues.
Asset Hardening and Vegetation Management
AltaLink has and continues to invest in specific asset improvements targeted to reduce the risk of wildfire ignition from AltaLink's
operations. These hardening efforts reduce the likelihood of AltaLink's transmission lines to spark a wildfire at locations of high fire risk.
37
Approximately 15% of AltaLink's transmission lines are in High Risk Fire Areas ("HRFAs"). Of these HRFA lines, 27% are in urban areas and communities, 23% are in forested areas, with the remaining 50% located in agricultural, grassland or native prairie.
Situational Awareness, Meteorology, and Risk Modeling
AltaLink uses available integrated meteorology and camera systems available from the Alberta Government and
has installed 13 of 17 planned incremental weather and camera stations in support of improvements to its situational awareness. This weather information, combined with expert third-party assessment, provides weather and fire risk forecasting daily for AltaLink's service territory. AltaLink has established a Daily Hazard Forecast Report provided to the organization and field crews as well as implemented an information portal in the control room. AltaLink initially completed its fire risk modeling and HRFA mapping in 2020 and is planning to complete an update of the modeling in 2024. AltaLink is developing further enhanced fire weather modeling tools in 2024. AltaLink has completed policy updates and training regarding field operations and contractor crew fire management and preventive practices.
Asset Inspection Program
AltaLink
completes asset inspections for all its facilities on an annual basis. For lines located in HRFAs, inspection frequencies are twice per year to review structure and vegetation conditions.
Public Safety Power Shutoff
A PSPS is an operating protocol used as a preventative measure of last resort during periods of extreme wildfire risk where a transmission line or lines would be de-energized proactively under certain conditions to reduce the risk of wildfire ignition. In determining whether to initiate a PSPS, AltaLink works with local public safety authorities in consideration of data from its wildfire risk forecasting tools and meteorological systems. If the forecast exceeds thresholds, escalating action is taken proactively starting from the seven-day forecast outlook. AltaLink has and continues to conduct
stakeholder engagement and exercises related to its PSPS process.
BHE U.S. Transmission
BHE U.S. Transmission is engaged in various joint ventures to develop, own and operate transmission assets and is pursuing additional investment opportunities in the U.S. Currently, BHE U.S. Transmission has two joint ventures with transmission assets that are operational, ETT, a 50% owned joint venture with subsidiaries of American Electric Power Company, Inc. ("AEP"), and Prairie Wind Transmission, LLC, a 25% owned joint venture with AEP and Evergy, Inc. ETT owns and operates electric transmission assets in the ERCOT and, as of December 31, 2023, had total assets of $3.8 billion. ETT's transmission system includes approximately
2,000 miles of transmission lines and 47 substations as of December 31, 2023. Prairie Wind Transmission, LLC, owns and operates a 108-mile, 345-kV transmission project in Kansas having total assets of $131 million as of December 31, 2023.
38
Generating Facilities
BHE Transmission has ownership interests in the following generating facilities as of December 31, 2023:
Power
Facility
Net
Purchase
Net
Owned
Energy
Year
Agreement
Power
Capacity
Capacity
Generating
Facility
Location
Source
Installed
Expiration
Purchaser
(MWs)(1)
(MWs)(1)
WIND:
Rattlesnake
Alberta
Wind
2022
2042/2032
Telus,
RBC, Bullfrog, Shopify
130
130
Rim Rock
Montana
Wind
2012
2026
Morgan Stanley
189
189
Glacier
1
Montana
Wind
2008
N/A
N/A
107
107
Glacier 2
Montana
Wind
2009
N/A
N/A
103
103
529
529
NATURAL
GAS:
Nat-1
Alberta
Natural gas
2015
N/A
N/A
20
20
20
20
Total
Available Generating Capacity
549
549
(1) Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates BHE Transmission' ownership
of Facility Net Capacity.
BHE RENEWABLES
The subsidiaries comprising the BHE Renewables reportable segment own interests in several independent power projects in the U.S. The following table presents certain information concerning these independent power projects as of December 31, 2023:
Power
Facility
Net
Purchase
Net
Owned
Energy
Year
Agreement
Power
Capacity
Capacity
Generating
Facility
Location
Source
Installed
Expiration
Purchaser(1)
(MWs)(2)
(MWs)(2)
WIND:
Grande
Prairie
Nebraska
Wind
2016
2036
OPPD
400
400
Jumbo Road
Texas
Wind
2015
2033
AE
300
300
Santa
Rita
Texas
Wind
2018
2025-2038
KC, CODTX, MES
300
300
Mariah Del Norte
Texas
Wind
2016
N/A
N/A
230
230
Walnut
Ridge
Illinois
Wind
2018
2028
USGSA
212
212
Flat Top
Texas
Wind
2019
2038
Shaw
200
200
Pinyon
Pines I
California
Wind
2012
2035
SCE
168
168
Fluvanna II
Texas
Wind
2019
2034
Heinz
158
158
Pinyon
Pines II
California
Wind
2012
2035
SCE
132
132
Bishop Hill II
Illinois
Wind
2012
2032
Ameren
81
81
Marshall
Kansas
Wind
2016
2036
MJMEC,
KPP, KMEA & COIMO
72
72
Independence
Iowa
Wind
2021
2041
CIPCO
54
54
2,307
2,307
SOLAR:
Topaz
California
Solar
2013-2014
2039
PG&E
550
550
Solar
Star 1
California
Solar
2013-2015
2035
SCE
310
310
39
Solar
Star 2
California
Solar
2013-2015
2035
SCE
276
276
Agua Caliente
Arizona
Solar
2012-2013
2039
PG&E
290
142
Alamo
6
Texas
Solar
2017
2042
CPS
110
110
Community Solar Gardens(5)
Minnesota
Solar
2016-2018
2041-2043
(4)
98
98
Pearl
Texas
Solar
2017
2042
CPS
50
50
1,684
1,536
NATURAL
GAS:
Cordova
Illinois
Natural Gas
2001
N/A
N/A
512
512
Power
Resources
Texas
Natural Gas
1988
N/A
N/A
140
140
Saranac
New York
Natural Gas
1994
N/A
N/A
245
196
Yuma
Arizona
Natural
Gas
1994
2024
SDG&E
50
50
947
898
GEOTHERMAL:
Imperial
Valley Projects
California
Geothermal
1982-2000
(3)
(3)
345
345
345
345
HYDROELECTRIC:
Wailuku
Hawaii
Hydroelectric
1993
2028
HELCO
10
10
10
10
Total
Available Generating Capacity
5,293
5,096
PROJECTS
UNDER CONSTRUCTION
Solar Star 3 & 4
California
Solar
Est. 2024
48
48
5,341
5,144
(1)Omaha
Public Power District ("OPPD"); Austin Energy ("AE"); Kimberly-Clark Corporation ("KC"); City of Denton, TX ("CODTX"); MidAmerican Energy Services, LLC ("MES"); U.S. General Services Administration ("USGSA"); Shaw Industries Group, Inc ("Shaw"); Southern California Edison ("SCE"); Kraft Heinz Food Company ("Heinz"); Ameren Illinois Company ("Ameren"); Missouri Joint Municipal Electric Commission ("MJMEC"); Kansas Power Pool ("KPP"); Kansas Municipal Energy Agency ("KMEA"); City of Independence, MO ("COIMO"); Central Iowa Power Cooperative ("CIPCO"); Pacific Gas and Electric Company ("PG&E"); CPS Energy ("CPS"); San Diego Gas & Electric Company ("SDG&E"); and Hawaii Electric Light Company, Inc. ("HELCO").
(2)Facility Net Capacity represents the lesser of nominal
ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates BHE Renewables' ownership of Facility Net Capacity.
(3)Approximately 12% of the Company's interests in the Imperial Valley Projects' Contract Capacity are currently sold to Southern California Edison Company under a long-term power purchase agreement expiring in 2026. Certain long-term power purchase agreement renewals for 252 MWs have been entered into with other parties at fixed prices that expire from 2028 to 2039, of which 202 MWs mature in 2039.
(4)The
power purchasers are commercial, industrial and not-for-profit organizations.
(5)The community solar gardens project is consolidated in the table above for convenience as it consists of 98 distinct entities that each own an approximately 1-MW solar garden with independent but substantially similar terms and conditions.
40
BHE Renewables' operating revenue derived from the following business activities for the years ended December 31 were as follows (dollars in millions):
2023
2022
2021
Solar
$
427
26
%
$
477
28
%
$
468
27
%
Wind
276
16
228
13
160
10
Geothermal
210
12
212
12
178
11
Hydro
4
—
5
—
32
2
Natural
gas
105
6
71
4
143
9
Retail energy services
688
40
744
43
680
41
Total
operating revenue
$
1,710
100
%
$
1,737
100
%
$
1,661
100
%
HOMESERVICES
HomeServices,
a wholly owned subsidiary of BHE, is one of the largest residential real estate brokerage firms in the U.S. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations and mortgage banking; title and closing services; property and casualty insurance; home warranties; relocation services; and other home-related services. HomeServices' real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices' operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices' owned brokerages currently operate in nearly 900 offices in 34 states and the District of Columbia with approximately 41,000 real estate agents under 50 brand names. The U.S. residential real estate
brokerage business is subject to the general real estate market conditions, is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions.
HomeServices' franchise network currently includes approximately 300 franchisees and over 1,500 brokerage offices with approximately 48,000 real estate agents under two brand names, primarily in the U.S. In exchange for certain fees, HomeServices provides the right to use the Berkshire Hathaway HomeServices or Real Living brand names and other related service marks, as well as providing orientation programs, training and consultation services, advertising programs and other services.
GENERAL
REGULATION
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive governmental regulation, which significantly influences their operating environment, prices charged to customers, capital structure, costs and, ultimately, their ability to recover costs and earn a reasonable return on invested capital. In addition to the discussion contained herein regarding general regulation, refer to "Regulatory Matters" in Item 1 of this Form 10-K for further discussion regarding certain regulatory matters.
Domestic Regulated Public Utility Subsidiaries
The Utilities are subject to comprehensive regulation by various state, federal and local agencies. The more significant aspects of this regulatory framework
are described below.
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State Regulation
Historically, state regulatory commissions have established retail electric and natural gas rates on a cost-of-service basis, which are designed to allow a utility the opportunity to recover what each state regulatory commission deems to be the utility's reasonable costs of providing services, including the opportunity to earn a fair and reasonable return on its investments based on its cost of debt and equity. In addition to return on investment, a utility's cost of service generally reflects a representative level of prudent expenses, including cost of sales, operating expense, depreciation and amortization
and income and other tax expense, reduced by wholesale electricity and other revenue. The allowed operating expenses are typically based on actual historical costs adjusted for known and measurable or forecasted changes. State regulatory commissions may adjust cost of service for various reasons, including pursuant to a review of: (a) the utility's revenue and expenses during a defined test period, (b) the utility's level of investment and (c) changes in income tax laws. State regulatory commissions typically have the authority to review and change rates on their own initiative; however, they may also initiate reviews at the request of a utility, utility customers or organizations representing groups of customers. In certain jurisdictions, the utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.
The
retail electric rates of the Utilities are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. The Utilities have established ECAMs and other cost recovery mechanisms in certain states, which help mitigate their exposure to changes in costs from those assumed in establishing base rates.
With certain limited exceptions, the Utilities have an exclusive right to serve retail customers within their service territories and, in turn, have an obligation to provide service to those customers. In some jurisdictions, certain classes of customers may choose to purchase all or a portion of their energy from alternative energy suppliers, and in some jurisdictions retail customers can generate all or a portion of their own energy. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electricity
distribution services to all residential and nonresidential customers within its allocated service territory; however, nonresidential customers have the right to choose an alternative provider of energy supply. The impact of this right on PacifiCorp's consolidated financial results has not been material. In Washington, state law does not provide for exclusive service territory allocation. PacifiCorp's service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the WUTC. Under California law, PacifiCorp has the exclusive right and obligation to provide electricity distribution services to all residential and nonresidential customers within its allocated service territory; however, cities, counties and certain other public agencies have the right to choose to generate energy supply or elect an alternative provider of energy supply through the formation
of a Community Choice Aggregator ("CCA"). To date, no CCA activity has occurred in PacifiCorp's California service territory. If a CCA is formed, PacifiCorp would continue to provide CCA customers transmission, distribution, metering and billing services and the CCA would provide generation supply. In addition, PacifiCorp would likely be able to collect costs from CCA customers for the generation-related costs that PacifiCorp incurred while they were customers of PacifiCorp. PacifiCorp would remain the electricity provider of last resort for these customers. In Illinois, state law has established a competitive environment so that all Illinois customers are free to choose their retail service supplier. For customers that choose an alternative retail energy supplier, MidAmerican Energy continues to have an ongoing obligation to deliver the supplier's energy to the retail customer. MidAmerican Energy bills the retail customer for such delivery services. MidAmerican
Energy also has an obligation to serve customers at regulated cost-based rates and has a continuing obligation to serve customers who have not selected a competitive electricity provider. The impact of this right on MidAmerican Energy's financial results has not been material. In Nevada, Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one MW or more to file a letter of intent and application with the PUCN to acquire electric energy and ancillary services from another energy supplier. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN to meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Nevada Utilities, the departure must not burden the Nevada Utilities with increased costs or cause any remaining customers to pay increased costs and the departing customers must pay their portion of
any deferred energy balances, all as determined by the PUCN. SB 547 revised Chapter 704B to establish limits on the amount of load eligible to take service under Chapter 704B and to set those limits as a part of the IRP filed by the Nevada Utilities. Also, the Utilities and the state regulatory commissions are individually evaluating how best to integrate private generation resources into their service and rate design, including considering such factors as maintaining high levels of customer safety and service reliability, minimizing adverse cost impacts and fairly allocating costs among all customers.
In Nevada, large natural gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the incentive natural gas rate tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative
energy sources and choose its source of natural gas. In addition, natural gas customers using greater than 1,000 therms per day have the ability to secure their own natural gas supplies under the gas transportation tariff.
42
PacifiCorp
Rate Filings
Under Utah law, the UPSC must issue a written order within 240 days of a public utility's application for a general rate change. Absent an order, the proposed rates go into effect as filed and are not subject to refund. The UPSC may allow interim rates to take effect within 45 days
of an application, subject to refund or surcharge, if an adequate prima facie showing is established in hearing that the interim rate change is justified.
In Oregon, the OPUC has the authority to suspend proposed new rates for a period not to exceed more than six months, with an additional three-month extension, beyond the 30-day time period when the new rates would otherwise go into effect. Absent suspension or other action from the OPUC, new rates automatically go into effect 30 days from filing by the utility. Upon suspension by the OPUC, the OPUC is authorized to allow the collection of an interim rate, subject to refund, during the pendency of the OPUC's review of the rate request.
In Wyoming, the WPSC can allow interim rates to go into effect 30 days after the initial application but may require
a bond to secure a refund for the amount. The WPSC may suspend the rates for final approval for a period not to exceed 10 months.
In Washington, the WUTC has the authority to suspend proposed new rates, subject to hearing, for a period not to exceed 10 months beyond the 30-day time period when the new rate would otherwise go into effect.
Under Idaho law, the IPUC can suspend a filing for an initial period not to exceed five months and an additional extension of 60 days with a showing of good cause.
In California, the CPUC has the authority to suspend proposed new rates, subject to hearing, for a period not to exceed 18 months. The CPUC may extend the suspension period on a case-by-case basis.
Adjustment
Mechanisms
In addition to recovery through base rates, PacifiCorp also achieves recovery of certain costs through various adjustment mechanisms as summarized below.
State Regulator
Base Rate Test Period
Adjustment Mechanism
UPSC
Forecasted or historical
with known and measurable changes(1)
EBA under which 100% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Wheeling revenue is also included in the mechanism. Beginning in 2021, the mechanism includes a true-up of PTCs at 100%.
Balancing account to provide for 100% recovery or refund of the difference between the level of REC revenues included in base rates and actual REC revenues after adjusting for a REC incentive authorized by the UPSC.
Recovery
mechanism for single capital investments that in total exceed 1% of existing rate base when a general rate case has occurred within the preceding 18 months.
Effective January 1, 2021, Wildland Fire Mitigation Balancing Account to recover operating expenses and capital expenditures incurred to implement PacifiCorp's Utah Wildland Fire Protection Plan incremental to those included in base rates.
OPUC
Forecasted
PCAM under which 90% of the difference between forecasted net variable power costs and PTCs established under the annual TAM and actual net variable power costs and PTCs is deferred and reflected in future rates. The difference between the forecasted and actual net variable power costs and PTCs must fall outside of an established asymmetrical deadband, with a negative annual power cost variance deadband of $15 million; and a positive annual power cost variance deadband of $30 million and is subject to an earnings test of +/- 1% on PacifiCorp's allowed return on equity.
Annual TAM
based on forecasted net variable power costs and PTCs.
RAC to recover the revenue requirement of new renewable resources and associated transmission costs that are not reflected in general rates.
Balancing account for recovery of costs associated with the purchase of RECs necessary to meet Oregon's RPS requirements.
43
State
Regulator
Base Rate Test Period
Adjustment Mechanism
Effective January 1, 2021, Annual Wildfire Mitigation and Vegetation Management Cost Recovery Mechanism approved through 2024 to recover vegetation management and wildfire mitigation operations and maintenance costs and wildfire mitigation capital costs, incremental to those included in base rates. Recovery is subject to performance metrics and earnings tests. After 2024, the mechanism will be assessed to determine whether continued use is warranted.
Effective
May 10, 2023, the WMP AAC was approved to recover the capital and operations and maintenance costs associated with implementation and operation of PacifiCorp's Oregon Wildfire Mitigation Plan beginning with the 2022 plan.
WPSC
Forecasted or historical with known and measurable changes(1)
ECAM under which 80% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Within the mechanism, chemical costs and start-up fuel costs
are also included at the 80% symmetrical sharing band and PTCs are included at 100% symmetrical sharing.
REC and SO2 revenue adjustment mechanism to provide for recovery or refund of 100% of any difference between actual REC and SO2 revenues and the level in rates.
WUTC
Historical
with known and measurable changes
PCAM under which the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates after applying a $4 million deadband for positive or negative net power cost variances. For net power cost variances between $4 million and $10 million, amounts to be recovered from customers are allocated 50/50 and amounts to be credited to customers are allocated 75/25 (customers/PacifiCorp). Positive or negative net power cost variances in excess of $10 million are allocated 90/10 (customers/PacifiCorp). Beginning in 2021, the mechanism includes a true-up of PTCs at 100%.
Deferral
mechanism of costs for up to 24 months of new base load generation resources and eligible renewable resources and related transmission that qualify under the state's emissions performance standard and are not reflected in base rates.
REC revenue tracking mechanism to provide credit of 100% of REC revenues to customers.
Decoupling mechanism
under which the difference between actual annual revenues and authorized revenues per customer per specified rate schedules is deferred and reflected in future rates, subject to an earnings test. Under the earnings test, 50% of any proportional excess earnings over PacifiCorp's authorized return on equity is returned to customers in addition to any surcharge or surcredit related to the revenue variance. The earnings test is asymmetrical, and adjustments are not made when PacifiCorp earns at or below authorized returns on equity. To trigger a rate adjustment, the deferral balance must exceed plus or minus 2.5% of the authorized revenue at the end of each deferral period by rate class. Rate adjustments must not exceed a surcharge of 5% of the actual normalized revenue by class.
IPUC
Historical
with known and measurable changes
ECAM under which 90% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Also provides for recovery or refund of 100% of the difference between the level of REC revenues included in base rates and actual REC revenues and differences in actual PTCs compared to the amount in base rates.
CPUC
Forecasted
PTAM for major capital additions that allows for rate adjustments outside of the context of a traditional
general rate case for the revenue requirement associated with capital additions exceeding $50 million on a total-company basis. Filed as eligible capital additions are placed into service.
ECAC that allows for an annual update to actual and forecasted net power costs.
PTAM for attrition, a mechanism that allows for an annual adjustment to costs other
than net power costs.
Catastrophic Events Memorandum Account for catastrophic events, allows for deferral and cost recovery of reasonable costs incurred as the result of catastrophic events, which are events for which a state or federal agency has declared a state of emergency.
Fire Risk Mitigation Memorandum Account to track costs related
to wildfire mitigation activities incremental to what is in base rates and Wildfire Mitigation Plan Memorandum Account to track costs associated with the implementation of PacifiCorp's approved wildfire mitigation plan.
(1)PacifiCorp has relied on both historical test periods with known and measurable adjustments, as well as forecasted test periods.
44
MidAmerican Energy
Rate Filings
Under
Iowa law, a utility may implement temporary rates, without IUB review and subject to refund, on or after 10 days of filing a request for higher base rates. If the IUB has not issued a final order within 10 months after the filing date, the temporary rates become final. Under Illinois law, new base rates may become effective 45 days after the filing of a request with the ICC, or earlier with ICC approval. The ICC has authority to suspend the proposed new rates, subject to hearing, for a period not to exceed approximately 11 months after filing. South Dakota law authorizes the SDPUC to suspend new base rates for up to six months during the pendency of rate proceedings; however, a utility may implement all or a portion of the proposed new rates six months after the filing of a request for a rate increase subject to refund pending a final order in the proceeding.
Iowa law also permits rate-regulated
utilities to seek ratemaking principles with the IUB prior to the construction of certain types of new generating facilities. Pursuant to this law, MidAmerican Energy has applied for and obtained IUB ratemaking principles orders for a 484-MW (MidAmerican Energy's share) coal-fueled generating facility, a 495-MW combined cycle natural gas-fueled generating facility and 6,841 MWs (nominal ratings) of wind-powered generating facilities as of December 31, 2023. These ratemaking principles established cost caps for the projects, below which such costs are deemed prudent by the IUB and authorized a fixed rate of return on equity for the respective generating facilities over the regulatory life of the facilities in any future Iowa rate proceeding. As of December 31, 2023, the generating facilities in-service totaled $7.5 billion, or 35%, of MidAmerican Energy's regulated property,
plant and equipment, net and were subject to these ratemaking principles at a weighted average return on equity of 11.3% with a weighted average remaining life of 32 years.
Ratemaking principles for several wind-powered generation projects have established mechanisms in Iowa where electric rate base may be reduced. The current revenue sharing mechanism is in accordance with Wind PRIME ratemaking principles and reduces rate base for Iowa electric returns on equity exceeding an established benchmark. Sharing is triggered by MidAmerican Energy's actual equity return being above a threshold calculated annually. The threshold, not to exceed 11%, is the weighted average equity return of rate base with returns authorized via ratemaking principles proceedings and all other rate base. For all other rate base, the return is based on interest rates on 30-year A-rated utility bond yields plus 400
basis points, with a minimum return of 9.5%. MidAmerican Energy shares with customers 90% of the revenue in excess of the trigger. A second mechanism, the retail customer benefit mechanism, reduces electric rate base for the value of higher cost retail energy displaced by covered wind-powered production and applies to the wind-powered generating facilities constructed under the Wind X and Wind XII projects, and wind-powered generating facilities placed in service in 2023 and future projects yet to be constructed under the Wind PRIME project that was approved by the IUB in December 2023. Rate base reductions under these mechanisms are applied to coal and other generation facilities in specified orders. A third mechanism, the Iowa EAC rate mitigation mechanism, provides EAC rate stability to customers by allocating revenue sharing amounts as required to reduce retail electric energy cost recoveries to a targeted amount.
Adjustment
Mechanisms
Under its current Iowa, Illinois and South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in electric energy costs for its retail electric sales through fuel, or energy, cost adjustment mechanisms. Additionally, MidAmerican Energy has transmission adjustment clauses to recover certain transmission charges related to retail customers in all jurisdictions. The transmission adjustment mechanisms recover costs billed by the MISO for regional transmission service. The Illinois adjustment mechanism additionally recovers MidAmerican Energy's entire transmission revenue requirement attributable to Illinois. The adjustment mechanisms reduce the regulatory lag for the recovery of energy and transmission costs related to retail electric customers in these jurisdictions and accomplish, with limited timing differences, a pass-through of the related costs
to these customers. Recoveries through these adjustment mechanisms are reflected in operating revenue, and the related costs are reflected in cost of fuel and energy or operations and maintenance expense, as applicable.
Of the wind-powered generating facilities placed in-service as of December 31, 2023, 5,225 MWs (nominal ratings) have not been included in the determination of MidAmerican Energy's Iowa retail electric base rates. In accordance with related ratemaking principles, until such time as these generation assets are reflected in base rates and ceasing thereafter, MidAmerican Energy will continue to reduce its revenue from Iowa EAC recoveries by $12 million each calendar year.
MidAmerican Energy's cost of natural gas purchased for resale is collected
for each jurisdiction through a uniform PGA, which is updated monthly to reflect changes in actual costs. Subject to prudence reviews, the PGA accomplishes a pass-through of MidAmerican Energy's cost of natural gas purchased for resale to its customers and, accordingly, has no direct effect on net income.
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MidAmerican Energy's electric and natural gas energy efficiency program costs are collected through bill riders that are adjusted annually based on actual and expected costs in accordance with the energy efficiency plans filed with and approved by the respective state regulatory commission. As such, the energy efficiency program costs, which are reflected in operations and maintenance expense, and related recoveries, which
are reflected in operating revenue, have no direct impact on net income.
MidAmerican Energy has income tax rider mechanisms in Iowa and Illinois that were established in response to significant changes to the Internal Revenue Code enacted in 2017, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. As a result of these changes, MidAmerican Energy re-measured its accumulated deferred income tax balances at the 21% rate and increased regulatory liabilities pursuant to the approved mechanisms. In December 2018, the IUB approved in final form a tax expense revision mechanism that reduces customer electric rates for the impact of the lower income tax rate on current operations, as calculated annually, and defers the amortization of excess accumulated deferred income taxes created by their re-measurement at the 21% income tax rate to a regulatory
liability, the disposition of which will be determined in MidAmerican Energy's next rate case. In 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduced the state of Iowa corporate tax rate in stages from 12% to its current 8.4%, and the impacts of such changes are included in the Iowa tax expense revision mechanism.
NV Energy (Nevada Power and Sierra Pacific)
Rate Filings
Nevada enacted Assembly Bill 524 ("AB 524") on June 15, 2023. The legislation, among other things, allows an electric utility to file a general rate application more frequently than once every three years. Under AB 524, Nevada statutes
require the Nevada Utilities to file electric general rate cases at least every three years with the PUCN and prohibit the Nevada Utilities from filing another general rate application until all pending general rate applications filed have been decided by the Commission unless, after application and hearing, the Commission determines that a substantial financial emergency would exist if the public utility or its affiliate is not permitted to file another general rate case sooner. Sierra Pacific may also file natural gas general rate cases with the PUCN. The Nevada Utilities are also subject to a two-part fuel and purchased power adjustment mechanism. The Nevada Utilities make quarterly filings to reset the BTERs, based on the last 12 months of fuel and purchased power costs. The difference between actual fuel and purchased power costs and the revenue collected in the BTERs is deferred into a balancing account. The DEAA rate clears amounts deferred into the balancing
account. Nevada regulations allow an electric or natural gas utility that adjusts its BTERs on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. During required annual DEAA proceedings, the prudence of fuel and purchased power costs is reviewed, and if any costs are disallowed on such grounds, the disallowances will be incorporated into the next quarterly BTERs change. Also, on an annual basis, the Nevada Utilities (a) seek a determination that energy efficiency program expenditures were reasonable, (b) request that the PUCN reset base and amortization EEPR, and (c) request that the PUCN reset base and amortization EEIR.
EEPR and EEIR
EEPR was established to allow the Nevada Utilities to recover the costs of implementing
energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by the Nevada Utilities and approved by the PUCN in the IRP proceedings. When the Nevada Utilities' regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, they are obligated to refund energy efficiency implementation revenue previously collected for that year.
Net Metering
Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The legislation, among other things,
established net metering crediting rates for private generation customers with installed net metering systems less than 25 kilowatts. Under AB 405, private generation customers will be compensated for excess energy on a monthly basis at 95% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the first 80 MWs of cumulative installed capacity of all net metering systems in Nevada, 88% of the rate for the next 80 MWs, 81% of the rate for the next 80 MWs and 75% of the rate for any additional private generation capacity. As of December 31, 2023, the cumulative installed and applied-for capacity of net metering systems under AB 405 in Nevada was 753 MWs.
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Natural
Disaster Protection Plan ("NDPP")
SB 329, Natural Disaster Mitigation Measures, was signed into law on May 22, 2019. The legislation requires the Nevada Utilities to submit a NDPP to the PUCN. The PUCN adopted NDPP regulations on January 29, 2020, that require the Nevada Utilities to file their NDPP for approval on or before March 1 of every third year. The regulations also require annual updates to be filed on or before September 1 of the second and third years of the plan. The plan must include procedures, protocols and other certain information as it relates to the efforts of the Nevada Utilities to prevent or respond to a fire or other natural disaster. The expenditures incurred by the Nevada Utilities in developing and implementing the NDPP are required to be held in a regulatory
asset account, with the Nevada Utilities filing an application for recovery on or before March 1 of each year. The PUCN reopened its investigation and rulemaking on SB 329 and the comment period for the reopened investigation ended in early February 2021. Final regulations are pending.
Federal Regulation
The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Natural Gas Act ("NGA"), the Energy Policy Act of 2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding companies; accounting and records retention; securities issuances;
construction and operation of hydroelectric facilities; and other matters. The FERC also has the enforcement authority to assess civil penalties of up to $1.5 million per day per violation of rules, regulations and orders issued under the Federal Power Act. The Utilities have implemented programs and procedures that facilitate and monitor compliance with the FERC's regulations described below. MidAmerican Energy is also subject to regulation by the NRC pursuant to the Atomic Energy Act of 1954, as amended ("Atomic Energy Act"), with respect to its ownership interest in the Quad Cities Station.
Wholesale Electricity and Capacity
The FERC regulates the Utilities' rates charged to wholesale customers for electricity and transmission capacity and related services. Much of the Utilities' wholesale electricity
sales and purchases occur under market-based pricing allowed by the FERC and are therefore subject to market volatility. The Utilities are precluded from selling at market-based rates in the PacifiCorp-East, PacifiCorp-West, Nevada Utilities, Idaho Power Company and NorthWestern Energy balancing authority areas. Wholesale electricity sales in those specific balancing authority areas are permitted at cost-based rates. PacifiCorp and the Nevada Utilities have been granted the authority to bid into the California EIM at market-based rates.
The Utilities' authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the Utilities are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their
respective market areas. PacifiCorp, the Nevada Utilities and certain affiliates, representing the BHE Northwest Companies, file together for market power study purposes. The BHE Northwest Companies' most recent triennial filing was made in June 2022 and is under review by the FERC. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2023, and it remains under review by the FERC. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2023, and it remains pending under review. Under the FERC's market-based rules, the Utilities must also file with the FERC a notice of change in status when there is a change in the conditions that the FERC relied upon in granting market-based rate
authority. MidAmerican Energy filed a notice of non-material change in status in July 2022, and the filing is currently under review by the FERC. In January 2024, MidAmerican Energy filed a change in status filing due to the addition of the Chickasaw wind farm generation, and the filing is currently under review by the FERC.
Transmission
PacifiCorp's and the Nevada Utilities' wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp's and the Nevada Utilities' OATTs. These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp's and the Nevada Utilities' transmission business is managed and operated independently from its wholesale marketing
business in accordance with the FERC's Standards of Conduct. PacifiCorp and the Nevada Utilities have made several required compliance filings in accordance with these rules.
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In December 2011, PacifiCorp adopted a cost-based formula rate under its OATT for its transmission services. Cost-based formula rates are intended to be an effective means of recovering PacifiCorp's investments and associated costs of its transmission system without the need to file rate cases with the FERC, although the formula rate results are subject to discovery and challenges by the FERC and intervenors. A significant portion of these services are provided to PacifiCorp's energy supply management function.
MidAmerican
Energy participates in the MISO as a transmission-owning member. Accordingly, the MISO is the transmission provider under its FERC-approved OATT. While the MISO is responsible for directing the operation of MidAmerican Energy's transmission system, MidAmerican Energy retains ownership of its transmission assets and, therefore, is subject to the FERC's reliability standards discussed below. MidAmerican Energy's transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC's Standards of Conduct.
MidAmerican Energy constructed and owns four Multi-Value Projects ("MVPs") located in Iowa and Illinois that added approximately 250 miles of 345-kV transmission line to MidAmerican Energy's transmission system since 2012. The MISO's OATT allows for broad cost allocation for MidAmerican Energy's MVPs, including similar MVPs
of other MISO participants. Accordingly, a significant portion of the revenue requirement associated with MidAmerican Energy's MVP investments is shared with other MISO participants based on the MISO's cost allocation methodology, and a portion of the revenue requirement of the other participants' MVPs is allocated to MidAmerican Energy, which MidAmerican Energy recovers from customers via a rider mechanism. The transmission assets and financial results of MidAmerican Energy's MVPs are excluded from the determination of its base retail electric rates.
The FERC has established an extensive number of mandatory reliability standards developed by the NERC and the WECC, including planning and operations, critical infrastructure protection and regional standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the FERC; the NERC; and the WECC for PacifiCorp,
Nevada Power, and Sierra Pacific; and the Midwest Reliability Organization for MidAmerican Energy.
Hydroelectric
The FERC licenses and regulates the operation of hydroelectric systems, including license compliance and dam safety programs. Most of PacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Under the Federal Power Act, 16 of PacifiCorp's hydroelectric developments are classified as "high hazard potential," meaning it is probable in the event of a dam failure that loss of human life in the downstream population could occur. PacifiCorp uses the FERC's guidelines to develop public safety programs consisting of a dam safety program and emergency action
plans.
For an update regarding PacifiCorp's Klamath River hydroelectric system, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.
Nuclear Regulatory Commission
General
MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station. Constellation Energy, the operator and 75% owner of Quad Cities Station, is under contract with MidAmerican Energy to secure and keep in effect all necessary
NRC licenses and authorizations.
The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. Current licenses for Quad Cities Station provide for operation until December 14, 2032. The NRC review and regulatory process covers, among other things, operations, maintenance, environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.
Federal regulations provide that any nuclear operating facility may be required to
cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Constellation Energy has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Constellation Energy has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.
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The NRC also regulates the decommissioning of nuclear-powered generating facilities, including the planning and funding for the eventual decommissioning of the facilities. In accordance with these regulations, MidAmerican Energy
submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay its share of the costs of decommissioning Quad Cities Station. MidAmerican Energy has established a trust for the investment of funds collected for nuclear decommissioning of Quad Cities Station.
Under the Nuclear Waste Policy Act of 1982 ("NWPA"), the DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Constellation Energy, as required by the NWPA, signed a contract with the DOE under which the DOE was to receive spent nuclear fuel and high-level radioactive waste for disposal beginning not later than January 1998. The DOE did not begin receiving spent nuclear fuel on the scheduled date and remains unable to receive such fuel and waste. The costs to be incurred by the DOE
for disposal activities were previously being financed by fees charged to owners and generators of the waste. In accordance with a 2013 ruling by the D.C. Circuit, the DOE, in May 2014, provided notice that, effective May 16, 2014, the spent nuclear fuel disposal fee would be zero. In 2004, Constellation Energy, reached a settlement with the DOE concerning the DOE's failure to begin accepting spent nuclear fuel in 1998. As a result, Quad Cities Station has been billing the DOE, and the DOE is obligated to reimburse the station for all station costs incurred due to the DOE's delay. Constellation Energy has constructed an interim spent fuel storage installation ("ISFSI") at Quad Cities Station consisting of two pads to store spent nuclear fuel in dry casks in order to free space in the storage pool. The first dry cask was placed in-service in 2005. As of December 31,
2021, the first pad at the ISFSI is full, and the second pad is in operation. The first and second pads at the ISFSI are expected to facilitate storage of casks to support operations at Quad Cities Station through the end of its current operating licenses, which is 2032.
Nuclear Insurance
MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Constellation Energy, insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988 ("Price-Anderson"), which was amended and extended by the Energy Policy Act. The general types of coverage maintained
are: nuclear liability, property damage or loss and nuclear worker liability, as discussed below.
Constellation Energy purchases private market nuclear liability insurance for Quad Cities Station in the maximum available amount of $450 million, which includes coverage for MidAmerican Energy's ownership. In accordance with Price-Anderson, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the U.S. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Quad Cities Station is approximately $83 million per incident, payable in installments not to exceed $12 million annually.
The
insurance for nuclear property damage losses covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Constellation Energy purchases primary property insurance protection for the combined interests in Quad Cities Station, with coverage limits for nuclear damage losses up to $1.5 billion for nuclear perils and $500 million for non-nuclear perils. MidAmerican Energy also directly purchases extra expense coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Constellation Energy, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments to be called upon based
on the industry mutual board of directors' discretion for adverse loss experience. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $10 million.
The master nuclear worker liability coverage, which is purchased by Constellation Energy for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of $450 million for the nuclear industry as a whole, which is in effect to cover tort claims of workers in nuclear-related industries.
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U.S. Mine Safety
PacifiCorp's
surface mining operations are regulated by the Federal Mine Safety and Health Administration, which administers federal mine safety and health laws and regulations, and state regulatory agencies. The Federal Mine Safety and Health Administration has the statutory authority to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay penalties or fines for violations of federal mine safety standards. Information regarding PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.
Interstate Natural Gas Pipeline Subsidiaries
The
Pipeline Companies are regulated by the FERC, pursuant to the NGA and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (a) rates, charges, terms and conditions of service, (b) the construction and operation of interstate pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities and (c) the construction and operation of LNG export/import facilities. The Pipeline Companies hold certificates of public convenience and necessity and LNG facility authorizations issued by the FERC, which authorize them to construct, operate and maintain their pipeline and related facilities and services.
In February 2022, the FERC updated its certificate policy that guides the authorization of natural gas projects and issued an interim policy providing guidance on how the FERC will review a natural gas project
for its impact on climate change. The policies apply to pending and future natural gas projects. On March 24, 2022, the FERC revoked application of the policies and sought further comments.
FERC regulations and the Pipeline Companies' tariffs allow each of the Pipeline Companies to charge approved rates for the services set forth in their respective tariffs. Generally, these rates are a function of the cost of providing services to customers, including prudently incurred operations and maintenance expenses, taxes, depreciation and amortization and a reasonable return on invested capital. Tariff rates for each of the Pipeline Companies have been developed under a rate design methodology whereby substantially all fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid
by firm transportation and storage customers regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, costs. Kern River's reservation rates have historically been approved using a "levelized" cost-of-service methodology so that the rate remains constant over the levelization period. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as the cost of capital decreases on declining rate base. Each of the Pipeline Companies also hold authority to negotiate rates for their services, subject to requirements to offer cost-based rate alternatives, and to publish such negotiated rates. In addition, for services that are not subject to FERC rate jurisdiction pursuant to Section 3 of the Natural Gas Act, Cove Point charges rates that are established by contract.
The
Pipeline Companies' rates are subject to change in future general rate proceedings. Rates for natural gas pipelines are changed by filings under either Section 5 or Section 4 of the Natural Gas Act. Section 5 proceedings are initiated by the FERC or the pipeline's customers for a potential reduction to rates that the FERC finds are no longer just and reasonable. In a Section 5 proceeding, the initiating party has the burden of demonstrating that the currently effective rates of the pipeline are no longer just and reasonable, and of demonstrating alternative just and reasonable rates. Any rate decrease as a result of a Section 5 proceeding is implemented prospectively upon the issuance of a final FERC order adopting the new just and reasonable rates. Section 4 rate proceedings are initiated by the natural gas pipeline, who must demonstrate that the new proposed rates are just and reasonable. The new rates as a result of a Section 4 proceeding are typically implemented
six months after the Section 4 filing if higher than prior rates and are subject to refund upon issuance of a final order by the FERC.
The FERC-regulated natural gas companies may not grant undue preference to any customer. FERC regulations require that certain information be made public for market access, through standardized internet websites. These regulations also restrict each pipeline's marketing affiliates' access to certain non-public information that could affect price or availability of service.
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Interstate natural gas pipelines are also subject to regulations administered by the Office of Pipeline Safety within the Pipeline and Hazardous
Materials Safety Administration, an agency of the DOT. Federal pipeline safety regulations are issued pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("NGPSA"), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas facilities, and requires an entity that owns or operates pipeline facilities to comply with such plans. Major amendments to the NGPSA include the Pipeline Safety Improvement Act of 2002 ("2002 Act"), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 ("2006 Act"), the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 ("2011 Act") the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 ("2016 Act") and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 ("2020 Act").
The
2002 Act established additional safety and pipeline integrity regulations for all natural gas pipelines in high-consequence areas. The 2002 Act imposed major new requirements in the areas of operator qualifications, risk analysis and integrity management. The 2002 Act mandated more frequent periodic inspection or testing of natural gas pipelines in high-consequence areas, which are locations where the potential consequences of a natural gas pipeline accident may be significant or may do considerable harm to persons or property. Pursuant to the 2002 Act, the DOT promulgated regulations that require natural gas pipeline operators to develop comprehensive integrity management programs, to identify applicable threats to natural gas pipeline segments that could impact high-consequence areas, to assess these segments and to provide ongoing mitigation and monitoring. The regulations require recurring inspections of high-consequence area segments every seven years after the
initial baseline assessment.
The 2006 Act required pipeline operators to institute human factors management plans for personnel employed in pipeline control centers. DOT regulations published pursuant to the 2006 Act required development and implementation of written control room management procedures.
The 2011 Act was a response to natural gas pipeline incidents, most notably the San Bruno natural gas pipeline explosion that occurred in September 2010 in California. The 2011 Act increased the maximum allowable civil penalties for violations, directs operator assistance for Federal authorities conducting investigations and authorized the DOT to hire additional inspection and enforcement personnel. The 2011 Act also directed the DOT to study several topics, including the definition of high-consequence areas,
the use of automatic shutoff valves in high-consequence areas, expansion of integrity management requirements beyond high-consequence areas and cast iron pipe replacement. The studies are complete, and a number of notices of proposed rulemaking have been issued. The Pipeline and Hazardous Materials Safety Administration ("PHMSA") issued the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments final rule in October 2019. The primary change was the expansion of the pipeline integrity assessment requirements to cover moderate-consequence areas and reconfirming maximum allowable operating pressures. Pipeline operators were required to develop procedures to address assessment requirements by July 2021 and complete 50% of the required MAOP reconfirmation actions by 2028 and the remaining by 2035. The BHE Pipeline Group has updated procedures, identified pipeline segments subject to the rule and
has planned projects to complete required assessments. PHMSA sent Part 2 of the rule to the Federal Register for publishing August 4, 2022, and it was published in the Federal Register August 24, 2022. The rule initially had an effective date of May 2023, but has been extended to February 2024. The third part of the rule, the gas gathering rule, has also been issued, but has minimal impact on the BHE Pipeline Group.
The 2016 Act required the Pipeline and Hazardous Materials Safety Administration to set federal minimum safety standards for underground natural gas storage facilities and authorized emergency order authority. In February 2020, the Pipeline and Hazardous Materials Safety Administration issued a final rule regarding underground natural gas storage facilities that incorporates
by reference the American Petroleum Institute's Recommended Practice 1171, "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs," clarifies certain aspects of the mandatory nature of the standard and defines regulatory completion dates for underground storage facility risk assessments. The BHE Pipeline Group has 20 total underground natural gas storage fields at EGTS and Northern Natural Gas that fall under this regulation and is complying with the final rule. The BHE Pipeline Group underground storage fields have had several audits under the Final Rule with no notices of probable violations issued. Kern River, Carolina Gas and Cove Point do not have underground natural gas storage facilities.
The 2020 Act required operations to review and update their inspection and maintenance plans to address how the plans contribute to eliminate
hazardous leaks of natural gas, reduction of fugitive emissions and replacement or remediation of pipelines that are known to leak based on the material, design or past operating maintenance history. BHE Pipeline Group has completed the review and update of its inspection and maintenance plans. To assist in this effort, Kern River participated in a non-punitive pilot inspection with the Pipeline and Hazardous Materials Safety Administration.
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The DOT and related state agencies routinely audit and inspect the pipeline facilities for compliance with their regulations. The Pipeline Companies conduct periodic internal audits of their facilities with more frequent reviews of those deemed higher risk. The Pipeline Companies also conduct
preliminary audits in advance of agency audits. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis. The Pipeline Companies believe their pipeline systems comply in all material respects with the NGPSA and with DOT regulations issued pursuant to the NGPSA.
Northern Powergrid Distribution Companies
The Northern Powergrid Distribution Companies, as holders of electricity distribution licenses, are subject to regulation by GEMA. GEMA regulates distribution network operators ("DNOs") within the terms of the Electricity Act 1989 and the terms of DNO licenses, which are revocable with 25 years notice. Under the Electricity Act 1989, GEMA has a duty to ensure that DNOs can finance their regulated activities and DNOs have a duty to maintain
an investment grade credit rating. GEMA discharges certain of its duties through its staff within Ofgem. Each of fourteen licensed DNOs distributes electricity from the national grid transmission system and distribution-connected generators to end users within its respective distribution services area.
DNOs are subject to price controls, enforced by Ofgem, that limit the revenue that may be recovered and retained from their electricity distribution activities. The regulatory regime that has been applied to electricity distributors in Great Britain encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DNOs to reflect a number of factors, including, but not limited to, the rate of inflation (as measured by the United Kingdom's Retail Prices Index) and the quality of service delivered by
the licensee's distribution system. The current price control, Electricity Distribution 2 ("ED2"), has been set for a period of five years, starting April 1, 2023. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Ofgem's judgment of the future allowed revenue of licensees is likely to take into account, among other things:
•the actual operating and capital costs of each of the licensees;
•the operating and capital costs that each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the more efficient licensees;
•the actual value of certain costs which are judged to be beyond the control of the licensees;
•the
taxes that each licensee is expected to pay;
•the regulatory value ascribed to the expenditures that have been incurred in the past and the efficient expenditures that are to be incurred in the forthcoming regulatory period;
•the rate of return to be allowed on expenditures that make up the regulatory asset value;
•the financial ratios of each of the licensees and the license requirement for each licensee to maintain investment grade status;
•an allowance in respect of the repair of the pension deficits in the defined benefit pension schemes sponsored by each of the licensees; and
•any under- or over-recoveries of revenues, relative
to allowed revenues, in the previous price control period.
A number of incentive schemes also operate within the current price control period to encourage DNOs to provide an appropriate quality of service to end users. This includes specified payments to be made for failures to meet prescribed standards of service. The aggregate of these guaranteed standards payments is uncapped but may be excused in certain prescribed circumstances that are generally beyond the control of the DNOs.
The current electricity distribution price control became effective April 1, 2023 and is due to terminate on March 31, 2028, and will be immediately replaced with a new price control. Although it has been the convention in Great
Britain for regulators to conduct periodic regulatory reviews before making proposals for any changes to the price controls, a new price control can be implemented by GEMA without the consent of the DNOs. If a licensee disagrees with a change to its license, it can appeal the matter to the United Kingdom's CMA, as can certain other parties. Any appeals must be notified within 20 working days of the license modification by GEMA. If the CMA determines that the appellant has relevant standing, then the statute requires that the CMA complete its process within six months, or in some exceptional circumstances seven months. The Northern Powergrid Distribution Companies appealed Ofgem's proposals for the resetting of the formula that commenced April 1, 2023, the CMA remitted the matter back to Ofgem to determine and implement a remedy.
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Ofgem
completed the price control review that resulted in a new price control effective April 1, 2023. The license modifications that give effect to the price control were published by Ofgem on February 3, 2023 and were subject to appeal to the CMA, if an appeal is filed by March 3, 2023. Many aspects of the prior price control were maintained and the changes made generally follow the template that was set by the price controls implemented in April 2021 for transmission and gas distribution in Great Britain. Specific changes include new service standard incentives and mechanisms to adjust cost allowances in specific circumstances, particularly related to investment required to support decarbonization efforts, and partially updating the allowed return on equity within the period for changes in the interest rate on government bonds.
Ofgem's final determinations also included an allowed cost of equity of 5.23% plus inflation (calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs) and cost allowances representing a 20% real-term increase compared to the current regulatory period annual average. The base allowed revenue, excluding the effects of incentive schemes, pass-through costs and any deferred revenues from the prior price control, will decrease approximately 4.0% at Northern Powergrid (Northeast) plc and will increase approximately 2.5% at Northern Powergrid (Yorkshire) plc, respectively, in 2023-24 before the addition of inflation.
Ofgem also monitors DNO compliance with license conditions and enforces the remedies resulting from any breach of condition. License conditions include the prices and terms of service, financial strength of the DNO, the provision of information
to Ofgem and the public, as well as maintaining transparency, non-discrimination and avoidance of cross-subsidy in the provision of such services. Ofgem also monitors and enforces certain duties of a DNO set out in the Electricity Act 1989, including the duty to develop and maintain an efficient, coordinated and economical system of electricity distribution. Under changes to the Electricity Act 1989 introduced by the Utilities Act 2000, GEMA is able to impose financial penalties on DNOs that contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or that are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee's revenue.
AltaLink
AltaLink
is regulated by the AUC, pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Alberta Utilities Commission Act (Alberta) and the Hydro and Electric Energy Act (Alberta). The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems. The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing.
The AUC
has various core functions in regulating the Alberta electricity transmission sector, including the following:
•regulating and adjudicating issues related to the operation of electric utilities within Alberta;
•processing and approving general tariff applications relating to revenue requirements, capital expenditure prudency and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable, and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of AltaLink's transmission system;
•approving the need for new electricity transmission facilities and permits
to build and licenses to operate electricity transmission facilities;
•reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;
•adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
•collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.
In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated
utilities.
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AltaLink's tariffs are regulated by the AUC under the provisions of the Electric Utilities Act (Alberta) in respect of rates and terms and conditions of service. The Electric Utilities Act (Alberta) and related regulations require the AUC to consider that it is in the public interest to provide consumers the benefit of unconstrained transmission access to competitive generation and the wholesale electricity market. In regulating transmission tariffs, the AUC must facilitate sufficient investment to ensure the timely upgrade, enhancement or expansion of transmission facilities, and foster a stable investment climate and a continued stream of capital investment for the transmission system.
Under
the Electric Utilities Act (Alberta), AltaLink prepares and files applications with the AUC for approval of tariffs to be paid by the AESO for the use of its transmission facilities, and the terms and conditions governing the use of those facilities. The AUC reviews and approves such tariff applications based on a cost-of-service regulatory model under a forward test year basis. Under this model, the AUC provides AltaLink with a reasonable opportunity to (i) earn a fair return on equity; and (ii) recover its forecast costs, including operating expenses, depreciation, borrowing costs and taxes (including deemed income taxes) associated with its regulated transmission business. The AUC must approve tariffs that are just, reasonable and not unduly preferential, arbitrary or unjustly discriminatory. AltaLink's transmission tariffs are not dependent on the price or volume of electricity transported through its transmission system.
The
AESO is an independent system operator in Alberta, Canada that oversees the Alberta Interconnected Electric System ("AIES") and wholesale electricity market. The AESO is responsible for directing the safe, reliable and economic operation of the AIES, including long-term transmission system planning. AltaLink and the other transmission facility owners receive substantially all of their transmission tariff revenues from the AESO. The AESO, in turn, charges wholesale tariffs, approved by the AUC, in a manner that promotes fair and open access to the AIES and facilitates a competitive market for the purchase and sale of electricity. The AESO monitors compliance with approved reliability standards, which are enforced by the Market Surveillance Administrator, which may impose penalties on transmission facility owners for non-compliance with the approved reliability standards.
The AESO
determines the need and plans for the expansion and enhancement of the transmission system in Alberta in accordance with applicable law and reliability standards. The AESO's responsibilities include long-term transmission planning and management, including assessing the current and future transmission system capacity needs of market participants. When the AESO determines an expansion or enhancement of the transmission system is needed, with limited exceptions, it submits an application to the AUC for approval of the proposed expansion or enhancement. The AESO then determines which transmission provider should submit an application to the AUC for a permit and license to construct and operate the designated transmission facilities. Generally, the transmission provider operating in the geographic area where the transmission facilities expansion or enhancement is to be located is selected by the AESO to build, own and operate the transmission facilities. In addition, Alberta
law provides that certain transmission projects may be subject to a competitive process open to qualified bidders.
Independent Power Projects
The Yuma, Cordova, Saranac, Power Resources, Topaz, Agua Caliente, Solar Star 1, Solar Star 2, Bishop Hill II, Jumbo Road, Marshall, Grande Prairie, Walnut Ridge, Pinyon Pines I, Pinyon Pines II, Santa Rita, Independence, Fluvanna II, Flat Top, Mariah del Norte, Alamo 6 and Pearl independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act, while the Community Solar Gardens, Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978. Both EWGs and QFs generally are exempt from compliance with extensive federal
and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.
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The Yuma, Cordova, Saranac, Imperial Valley, Topaz, Agua Caliente, Solar Star 1, Solar Star 2, Bishop Hill II, Marshall, Grande Prairie, Walnut Ridge, Independence, Pinyon Pines I and Pinyon Pines II independent power projects have obtained authority from the FERC to sell their power at market-based rates. This authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the respective independent power projects are required to submit triennial filings to the FERC that
demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. The Pinyon Pines I, Pinyon Pines II, Solar Star 1, Solar Star 2, Topaz and Yuma independent power projects and power marketers CalEnergy, LLC and BHER Market Operations, LLC file together for market power study purposes of the FERC-defined Southwest Region. The most recent triennial filing for the Southwest Region was made in June 2022 and is awaiting FERC action. The Cordova and Saranac independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2023 and is awaiting FERC action. The Bishop Hill II and Walnut Ridge independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates
for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2023 and is awaiting FERC action. The Marshall and Grande Prairie independent power projects and power marketer CalEnergy, LLC file together for market power study purposes in the FERC-defined Southwest Power Pool Region. The most recent triennial filing for the Southwest Power Pool Region was made in December 2021, was supplemented in July 2022 and an order accepting it was issued in January 2023. Power marketers CalEnergy LLC and BHER Market Operations, LLC also file for market power study purposes in the FERC-defined Northwest Region together with PacifiCorp, Nevada Power Company, Sierra Power Company and certain affiliates. The most recent triennial filing for the Northwest Region was made in June 2022, was supplemented in December 2022, and is awaiting FERC action.
The
entire output of Jumbo Road, Santa Rita, Fluvanna II, Flat Top, Mariah del Norte, Alamo 6, Pearl and Power Resources is within the ERCOT and market-based authority is not required for such sales solely within ERCOT as the ERCOT market is not a FERC-jurisdictional market. Similarly, Wailuku sells its output solely to the Hawaii Electric Light Company within the Hawaii electric grid, which is not a FERC-jurisdictional market and therefore, Wailuku does not require market-based rate authority.
EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility's "avoided cost" and to sell back-up power to the QFs on a non-discriminatory basis, unless they have successfully petitioned the FERC for an exemption from this
purchase requirement. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utility's avoided cost.
Residential Real Estate Brokerage Company
HomeServices and its operating subsidiaries are regulated by the U.S. Consumer Financial Protection Bureau which enforces the Truth In Lending Act ("TILA"), the
Equal Credit Opportunity Act ("ECOA") and the Real Estate Settlement Procedures Act ("RESPA"); by the U.S. Federal Trade Commission with respect to certain franchising activities; by the U.S. Department of Housing and Urban Development, which enforces the Fair Housing Act ("FHA"); and by state agencies where its subsidiaries operate. TILA and ECOA regulate lending practices. FHA prohibits housing-related discrimination on the basis of race, color, national origin, religion, sex, familial status, and disability. RESPA regulates real estate settlement services including real estate closing practices, lender servicing and escrow account practices and business relationships among settlement service providers and third parties to the transaction.
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REGULATORY
MATTERS
In addition to the discussion contained herein regarding regulatory matters, refer to "General Regulation" in Item 1 of this Form 10-K for further information regarding the general regulatory framework.
PacifiCorp
Utah
In May 2023, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2022. The filing requested a rate increase of $98 million, or 4.6%, which was effective on an interim basis July 1, 2023. The UPSC held a hearing in January 2024 and an order is expected in February 2024.
In
June 2023, PacifiCorp filed its annual wildland fire cost and compliance report with the UPSC, which reported on calendar year 2022 wildland fire mitigation activities. The report included a request to recover $7 million in deferred costs associated with implementing the wildland fire mitigation plan incremental to those included in base rates. PacifiCorp proposed to recover the amounts over one year. Intervening parties requested a hearing to review the rate request, which was held in October 2023. In November 2023, the UPSC issued an order denying the rate request without prejudice. PacifiCorp may continue to defer the 2022 wildland fire mitigation plan costs, and the UPSC may approve recovery of these costs, if PacifiCorp is able to provide substantial evidence that the claimed costs are not already recovered through base rates. PacifiCorp will request recovery as part of its upcoming general rate case expected to be filed in April 2024.
Oregon
In
July 2021, in accordance with the OPUC's December 2020 general rate case order, PacifiCorp filed an application with the OPUC to initiate the review of PacifiCorp's estimated decommissioning and other closure costs per third-party studies associated with its coal-fueled generating facilities. The application requested an initial rate increase of $35 million, or 2.8%, to become effective January 1, 2022, to recover the incremental costs from those approved in the last general rate case. In November 2022, an independent evaluator was selected. Until the independent evaluator completes its work reviewing the third-party studies that contain the estimated decommissioning and other closure costs and the OPUC issues an order, there will be no change to rates related to this filing.
In July 2022, PacifiCorp filed an application requesting approval
of an automatic adjustment clause with a balancing account to recover costs associated with implementing PacifiCorp's wildfire protection plan in Oregon. Per formal rulemaking at the OPUC, the wildfire protection plan was changed to be known as the wildfire mitigation plan, resulting in the requested automatic adjustment clause being referred to as the Wildfire Mitigation Plan Automatic Adjustment Clause ("WMP AAC"). In December 2022, a stipulation with certain parties was filed agreeing to the establishment of an automatic adjustment clause. In May 2023, the OPUC approved the stipulation, which resulted in an overall annual increase of $20 million, or 1.6%, effective May 24, 2023 for estimated 2022 incremental operation and maintenance costs in excess of those reflected in base rates as a result of the last general rate case. In June 2023, PacifiCorp filed its WMP AAC to recover remaining 2022 deferred operations
and maintenance costs, projected incremental 2023 operations and maintenance costs and capital costs incremental to amounts previously included in general rate case filings. The filing requested a rate increase of $27 million over the existing amount approved in May 2023, to become effective November 5, 2023. When combined with the previously approved increase, the rate schedule would be set to recover $47 million. In October 2023, in response to discussions with the OPUC staff, PacifiCorp requested the effective date for the WMP AAC shift to December 13, 2023, to allow more time for the OPUC staff to review the filing, and in November 2023, PacifiCorp requested the effective date move to January 10, 2024, to allow PacifiCorp to participate in the public meeting when the matter is brought before the OPUC. In January 2024,
PacifiCorp filed a supplemental filing reducing the requested rate increase to $25 million, or 1.4%, and in the public meeting the OPUC approved the rate increase with an effective date of January 10, 2024.
In April 2023, PacifiCorp filed its TAM requesting approval to update net power costs for 2024. The filing requested a rate increase of $164 million, or 9.5%, to become effective January 1, 2024. In July 2023, PacifiCorp updated its filing to reduce the requested rate increase to $131 million to reflect changes in PacifiCorp's forecast net power costs for 2024. In September 2023, a stipulation with certain intervening parties was filed settling substantially all issues in the 2024 TAM and in October 2023, the OPUC issued an order approving the stipulation, subject to final updates and
excluding costs associated with the Washington Cap and Invest program. The final update, filed in November 2023, resulted in a rate increase of $150 million, or 8.7%, effective January 1, 2024.
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In May 2023, PacifiCorp filed its 2022 PCAM requesting recovery of the difference between actual power costs and base power costs established in the 2022 TAM. The filing requested recovery of $131 million, which PacifiCorp proposed to recover over a two-year period with interest, resulting in a rate increase of $69 million, or 4.0%, effective January 1, 2024. In October 2023, a stipulation was filed providing for the requested amounts.
In December 2023, the OPUC issued an order accepting the stipulation. As established in the stipulation, because the combined January 1, 2024 rate increase for residential customers from all January 1 rate changes was less than 15%, the rate effective date of the 2022 PCAM for residential customers remained January 1, 2024.
In February 2024, PacifiCorp filed a general rate case requesting a rate increase of $322 million, or 17.9%, to become effective January 1, 2025. The request includes new capital investments in transmission and wind-powered generating facilities, higher insurance premiums for third-party liability coverage and proposed funding for a catastrophic fire fund.
In
February 2024, PacifiCorp filed its TAM requesting approval to update net power costs for 2025. The filing requests a rate decrease of $18 million, or 1.0%, subject to updates throughout the course of the proceeding, to become effective January 1, 2025.
Wyoming
In March 2023, PacifiCorp filed a general rate case requesting a rate increase of $140 million, or 21.6%, to become effective January 1, 2024. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities. In September 2023, PacifiCorp filed updated testimony that included updated net power costs and increased insurance premium costs associated
with third-party liability coverage. As a result of the updates, the requested rate increase has been revised to $137 million, or 21.1%. In November 2023, the WPSC approved a rate increase of $54 million, or 8.3%, effective January 1, 2024. The approved rate increase reflects a reduction in the requested return on equity compared to what was sought by PacifiCorp, the exclusion of the increased insurance premium costs that will be addressed outside of the general rate case and a reduction in net power costs determined by the WPSC. The approved rate increase also excludes from the net power costs the costs associated with the Washington Cap and Invest program. In January 2024, PacifiCorp filed an application for rehearing requesting the WPSC consider three items, including the WPSC's net power costs adjustment, costs associated with the Washington Cap and Invest program and the opportunity to revise PacifiCorp's initial
revenue requirement request for updates, corrections and revisions reflected in rebuttal testimony.
In April 2023, PacifiCorp filed its ECAM, REC and RRA to recover deferred net power costs from 2022. The combined filing requested a rate increase of $49 million, or 7.4%, which was effective on an interim basis July 1, 2023. In October 2023, PacifiCorp filed rebuttal testimony updating the ECAM calculation. As a result of the updates, the requested combined rate increase was revised to $42 million, or 6.3%. In December 2023, a stipulation and settlement agreement was filed, reflecting a combined rate increase of $40 million, or 6.0%. The WPSC approved the stipulation in December 2023, with an effective date of January 1, 2024.
Washington
In
March 2023, PacifiCorp filed a general rate case requesting a two-year rate plan with a rate increase of $27 million, or 6.6%, to become effective March 1, 2024, and a second rate increase of $28 million, or 6.5%, to become effective March 1, 2025. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities. In October 2023, PacifiCorp filed updated testimony that included updated net power costs, increased insurance premium costs and removal of some capital projects. As a result of the updates, the requested rate increases have been revised to $19 million, or 4.6%, to become effective March 1, 2024, and $22 million, or 5.2%, to become effective March 1, 2025. In December
2023, a multi-party settlement stipulation was filed updating the requested rate increase to $14 million, or 3.4%, to become effective March 19, 2024, and $21 million, or 5.0%, to become effective March 1, 2025. A hearing on the settlement stipulation was held in January 2024 and a final decision from the WUTC is pending.
In June 2023, PacifiCorp filed its PCAM to recover deferred net power costs from 2022. The filing requested recovery of over $71 million, which PacifiCorp proposed to recover over a two-year period with interest, resulting in a rate increase of $37 million, or 9.5%, to become effective January 1, 2024. In November 2023, the WUTC suspended PacifiCorp's PCAM filing in response to an intervening party's petition for adjudication
request. PacifiCorp's hedging practices will be evaluated in the adjudicative proceeding that is scheduled for hearing in June 2024.
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Idaho
In October 2022, PacifiCorp filed an application for authority to implement the residential rate modernization plan. The plan proposed a five-year transition to increase the monthly customer service charge from $8.00 to $29.25 per month with a corresponding reduction to the energy rate, eliminated the tiered rates, and adjusted the on-peak off-peak period for time-of-day customers. In response to concerns about the combined impact of the proposed changes, PacifiCorp proposed a modification to, rather than
elimination of, the tiered rates. In May 2023, the IPUC issued an order approving PacifiCorp's request to increase the customer service charge over five years, to adjust peak periods for time-of-day customers, and to modify the tiered rate structure. The changes to the residential rates became effective June 1, 2023.
California
In May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to establish a memorandum account to track the change in rates beginning January 1, 2023 until
the new rates become effective, upon the issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in February 2023 with a slight adjustment of an overall rate increase of $27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling requesting additional information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum accounts. In March 2023, the CPUC split the general rate case into two tracks. The first track addresses the general rate case and the second track addresses the wildfire memorandum accounts. In October 2023, PacifiCorp filed updated testimony in the first track that removed the costs considered in the second track, as directed by the CPUC. The updated testimony clarified that the rate increase for the first track is $22 million, or 20.1%. In December 2023, the CPUC issued an order for the first track approving a rate increase of $19 million, or 17.5%, effective January
12, 2024. Additionally, the CPUC approved recovery of $19 million associated with the aforementioned memorandum account over three years. In the second track of the general rate case, PacifiCorp filed the independent audit of the wildfire memorandum accounts in January 2024, indicating no findings. A decision in the second track is expected by late 2024.
In September 2023, PacifiCorp filed its 2024 combined ECAC and GHG related costs application requesting an overall rate increase of $30 million, or 25.0%, effective March 1, 2024. Approximately $36 million of the increase is attributed to the ECAC rate, which is offset by $6 million decrease to the GHG rate. In January 2024, PacifiCorp filed a joint motion for approval of the GHG portion of the filing.
Deferral
Accounting Treatment for Increased Costs Associated with Wildfires
In June 2023, PacifiCorp filed deferral applications with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC to track the costs associated with third-party liability from litigation due to the 2020 Wildfires. The deferred accounting applications enable PacifiCorp to preserve its ability to seek recovery in the future in the event the outcome could potentially impact its financial stability. The applications state that PacifiCorp is not seeking recovery of these costs from customers at this time and does not expect to determine if it will seek recovery until the appeals process has concluded. In August 2023, PacifiCorp filed a motion to withdraw without prejudice with the UPSC, and in September 2023, PacifiCorp filed a notice of withdrawal without prejudice with the IPUC. These filings preserve the ability of PacifiCorp
to file for deferred accounting treatment when the actual liability costs are more certain.
In June 2023, PacifiCorp filed an application with the CPUC for authority to establish a Wildfire Expense Memorandum Account to track the costs associated with third-party liability from litigation due to the 2020 Wildfires, increased insurance premium costs associated with third-party liability coverage and costs associated with potential liability for future catastrophic wildfires. The CPUC issued a proposed decision in February 2024 and PacifiCorp anticipates a final order by April 2024, approving the Wildfire Expense Memorandum Account to be able to track costs incurred on or after June 21, 2020.
In August 2023, PacifiCorp filed deferral applications with the
UPSC, the OPUC, the WUTC and the IPUC for costs associated with increased insurance premium costs associated with third-party liability coverage. In December 2023, PacifiCorp filed a deferral application with the WPSC for the incremental insurance premium costs. The IPUC and the OPUC approved the request for authorization to defer the increased insurance premium costs in December 2023 and January 2024, respectively.
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MidAmerican Energy
Iowa
In June 2023, MidAmerican Energy filed a request with the IUB for an increase in its Iowa retail natural gas rates, which
would increase revenue by $39 million annually or increase retail customer's bills by an average of 6.1%. Interim rates of $31 million annually, or an average increase to customer's bills of 4.8%, were effective in June 2023. In January 2024, MidAmerican Energy filed a non-unanimous settlement with the OCA, which would allow for an increase in revenue of $30 million annually, or an average increase to customer's bills of 4.6%. On January 23, 2024, the IUB held a hearing regarding the non-unanimous settlement agreement. MidAmerican Energy expects the IUB to issue an order on the non-unanimous settlement in the first quarter of 2024 with final rates effective in the second quarter of 2024.
Wind PRIME
In January 2022, MidAmerican Energy
filed an application with the IUB for advance ratemaking principles for Wind PRIME, which consists of up to 2,042 MWs of new wind generation and up to 50 MWs of solar generation. If all Wind PRIME generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind generation and nearly 200 MWs of solar generation. Wind PRIME is projected to allow MidAmerican Energy to generate renewable energy greater than or equal to all of its Iowa retail customers' annual energy needs. MidAmerican Energy expects to be eligible for 100% PTCs under current tax law for the Wind PRIME projects. In December 2022, MidAmerican Energy, the OCA and the Iowa Business Energy Coalition filed a non-unanimous settlement with the IUB. On April 27, 2023, the IUB issued its final order regarding the application and found that MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application,
but rejected the settlement and proposed its own principles for the project. MidAmerican Energy reviewed the order and filed a motion for reconsideration or rehearing on May 17, 2023. On June 15, 2023, the IUB granted the motion for reconsideration and rehearing. In August 2023, MidAmerican Energy, the OCA and the Environmental Intervenors filed a revised non-unanimous settlement with the IUB that included a return on equity of 10.75%. The settlement would also benefit customers by providing a rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. On December 14, 2023, the IUB issued its final order on rehearing, approving the revised non-unanimous settlement. MidAmerican Energy accepted the ratemaking principles on December
18, 2023, and plans to move forward with the construction of Wind PRIME.
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Iowa Transmission Legislation
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law provides MidAmerican Energy, as an incumbent electric transmission owner, the legal right to construct, own and maintain transmission lines in MidAmerican
Energy's service territory that have been approved by the MISO (or another federally registered planning authority) and are eligible to receive regional cost allocation. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for the construction of eligible electric transmission lines that it intends to construct, own and maintain. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the eligible electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the eligible electric transmission line. In October 2020, national transmission interests filed a lawsuit that challenged the law on state constitutional
grounds. The suit argues that the law was enacted in violation of the "single-subject" provision of Iowa's state constitution because it was "log-rolled" into a late session appropriations bill and violates the equal protection provision of the Iowa constitution. The State of Iowa defended the law, and MidAmerican Energy and ITC Midwest both intervened and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of standing, and the national transmission interests appealed. In June 2022, the Iowa Court of Appeals upheld the district court's decision, after which the national transmission interests asked the Iowa Supreme Court to reconsider. In November 2022, the Iowa Supreme Court granted the motion to reconsider. On March 24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower courts, held the national transmission interests had standing, and remanded
the case to the district court to consider the state constitutional claims on their merits. The opinion also imposed a temporary injunction that stayed enforcement of the law pending a decision on the merits. On April 7, 2023, the State of Iowa, acting individually, and MidAmerican Energy and ITC Midwest, acting jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19, 2023, the national transmission interests filed a reply that (1) expressed its opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to hold that the injunction specifically applied to and precluded advancement of MidAmerican Energy's Long Range Transmission Projects ("LRTP") Tranche 1 projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on the constitutional claims on the merits without further briefing or argument. On April
26, 2023, the Iowa Supreme Court issued an order that denied the petitions for rehearing without comment and made minor, non-substantive changes to the decision, with no changes to the injunction. On May 30, 2023, the Iowa Supreme Court remanded the case to the district court for further proceedings on the merits, where the national transmission interests filed a motion for summary judgment. The State of Iowa, MidAmerican Energy and ITC Midwest collaborated to resist the motion and submit a cross motion for summary judgment. The Iowa district court held a hearing on the motions for summary judgment on September 29, 2023. On December 4, 2023, the district court issued an order that granted LS Power's motion for summary judgment. The decision found that the manner in which the legislature passed the Right of First Refusal
law violated the title and single-subject provisions of the Iowa Constitution and therefore held that the law was unconstitutional and unenforceable. The court also granted LS Power's request to enjoin MidAmerican Energy and ITC Midwest from further developing the LRTP Tranche 1 projects, without addressing the federal jurisdictional issues implicated in disrupting MISO's approval of construction of the projects by MidAmerican Energy and ITC Midwest. The court did not rule on the equal protection challenge raised by LS Power and instead held that it was not necessary to reach the merits of those arguments because the title and single-subject violations rendered the statute void and unenforceable. On December 19, 2023, MidAmerican Energy and ITC Midwest filed motions for reconsideration with the Iowa district court that focus on the injunctive relief granted and asked the court to correct legal errors in the order, including
over breadth, and to lift the injunction as it relates to the LRTP Tranche 1 projects. To this point, MISO has taken no action to reverse or disrupt its approval of MidAmerican Energy's LRTP Tranche 1 projects. This matter only potentially affects the manner in which MidAmerican Energy would secure the right to construct transmission lines that are eligible for regional cost allocation and are otherwise subject to competitive bidding under the MISO tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing rights to construct any other transmission lines, including lines required to serve new or expanded retail load, connect new generators or meet reliability criteria.
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NV
Energy (Nevada Power and Sierra Pacific)
Regulatory Rate Review
In June 2023, Nevada Power filed a regulatory rate review with the PUCN that requested an annual revenue increase of $93 million, or 3.3%. In addition, a filing was made to revise depreciation rates based on a study, the results of which are reflected in the proposed revenue requirement. In August, 2023, Nevada Power filed an updated certification filing that requested an annual revenue increase of $96 million, or 3.3%. Parties to the review filed testimony and evidence in August and September 2023. Hearings in the cost of capital, revenue requirement and rate design phases were held in October and November 2023. In December 2023, the PUCN issued an order approving an increase in base rates of $37 million, effective January
1, 2024, reflecting a reduction in Nevada Power's requested rate of return and updated depreciation and amortization rates for its electric operations. In January 2024, Nevada Power filed a petition for reconsideration and clarification of the order. In February of 2024, the PUCN issued a final order approving in part and denying in part the petition for reconsideration.
In February 2024, Sierra Pacific filed electric and gas regulatory rate reviews with the PUCN that requested annual revenue increases of $94.7 million, or 8.8% and $11.1 million, or 4.9%, respectively. Orders are expected by the third quarter of 2024 and, if approved, would be effective October 1, 2024.
Northern Powergrid Distribution Companies
Ofgem
has completed the five-year RIIO-ED2 price control review that became effective April 1, 2023. The license modifications that gave effect to the price control were published by Ofgem in February 2023. In March 2023, Northern Powergrid sought permission from the Competition and Markets Authority ("CMA") to appeal against those license modifications. The appeal related to two specific areas:
•An error in the method that Ofgem used to allocate price control allowances into the different funding mechanisms resulting in underfunding; and
•Failure by Ofgem to award Northern Powergrid (Yorkshire) plc with a reward under its business plan incentive mechanism.
In September 2023, the CMA found that Ofgem's
decision on the allocation of price control allowances was unlawful on the grounds of irrationality and remitted the matter back to Ofgem to redetermine. The CMA found that Ofgem's decision not to grant Northern Powergrid (Yorkshire) plc a reward under its business plan incentive mechanism was valid.
In February 2024, Ofgem published its redetermination on the allocation of Northern Powergrid's price control allowances, resulting in access to Ł97 million of additional funding for the period April 2023 to March 2028 in 2020/21 prices. This closes Northern Powergrid's appeal.
BHE Pipeline Group
BHE GT&S
In November 2023, CGT filed a
general rate case for its FERC-jurisdictional services, with proposed rates to be effective January 1, 2024. CGT's current rates were established by a 2011 settlement. CGT proposed an annual cost-of-service of $167 million, and requested increases in various rates, including Zone 1 general system transportation rates by 84% and Zone 2 general system transportation rates by 23%. In December 2023, the FERC suspended the rate changes for five months following the proposed effective date, until June 1, 2024, subject to refund and the outcome of hearing procedures. This matter is pending.
BHE Transmission
AltaLink
2024-2025
General Tariff Application
In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total transmission tariffs of C$902 million and C$909 million for 2024 and 2025, respectively. The application also requested the approval to reinstate C$99 million cost of removal to rate base which was not previously approved, based on additional information filed.
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In July 2023, AltaLink requested the AUC to suspend the schedule for its 2024-2025 GTA until August 31, 2023. AltaLink required the schedule delay to amend its application in response to the unprecedented wildfire events that AltaLink experienced
in Alberta, Canada in May and June 2023. In August 2023, AltaLink filed an amendment to its 2024-2025 GTA. The amendment increased AltaLink's Wildfire Mitigation Plan capital expenditures from C$16 million to C$39 million in 2024 and from C$15 million to C$38 million for 2025. AltaLink's total amended transmission tariffs for 2024 and 2025 are C$904 million and C$912 million, respectively.
In December 2023, AltaLink advised the AUC that it reached a negotiated settlement with customer groups on the majority of its 2024-2025 GTA and filed the agreement with the AUC for approval. In February 2024, the AUC issued its decision with respect to AltaLink's 2024-2025 GTA, approving the negotiated settlement agreement as filed. Under the agreement, AltaLink will reduce its applied-for operating expenses by C$7 million and sustaining capital expenditures by C$39 million for the 2024-2025 test
period. The agreement does not include AltaLink's proposed wildfire deferral account, certain components of the wildfire mitigation plan, and actual and forecast salvage expenditures from its 2019-2023 GTA and 2024-2025 GTA, respectively. AltaLink's total revised transmission tariffs adjusted for the negotiated settlement are C$900 million for 2024 and C$904 million for 2025. Information responses and AltaLink's rebuttal evidence on the negotiated settlement and the items excluded from the negotiated settlement were provided in February 2024. AltaLink will be adjusting its 2024 transmission tariff and the 8.50% return on equity included in its application filed on December 19, 2023, to the 9.28% return on equity approved by the AUC in the 2024 GCOC proceeding. An oral hearing to address the excluded matters is scheduled in March 2024.
Also,
in December 2023, AltaLink filed an application with the AUC to recover all costs incurred as a result of the 2023 spring wildfire and storm events. The application includes capital expenditures of C$18.5 million and salvage expenditures of C$6 million.
In December 2023, the AUC approved 2024 interim refundable transmission tariffs for AltaLink, including monthly tariffs for PLP and KLP, of C$74 million per month effective January 1, 2024.
Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the generic cost of capital proceeding. The proceeding was conducted in two stages. The first stage determined the cost of capital parameters for 2023 and the second
stage considered returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with respect to the first stage of the generic cost of capital proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial markets. In June 2022, the AUC initiated the second stage to explore a formula-based approach to determine the return on equity for 2024 and future test periods.
In February 2023, AltaLink and other stakeholders filed evidence. AltaLink filed expert evidence recommending a 10.3% return on equity, on a recommended equity ratio of 40%. Other utilities filed similar recommendations. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the Industrial Power Consumers
Association of Alberta recommended returns on equity ranging from 6.75% to 7.7% and equity ratios ranging from 35% to 37%. AltaLink's expert witness, as well as all other utility experts, submitted that they are generally not in favor of implementing a formulaic adjustment mechanism for allowed return on equity due to the challenges in maintaining the Fair Return Standard through formulaic adjustments. The interveners are generally in favor of a formula.
In October 2023, the AUC issued its decision on the Generic Cost of Capital for 2024 and beyond for Alberta's regulated electric and gas utilities, approving an equity ratio and formula to determine return on equity. The AUC set the deemed equity ratio of 37% and the notional return on equity of 9.00%, which is subject to formulaic adjustments utilizing 30-year Government of Canada bond yields and Canadian utility spreads. In November
2023, the AUC issued an order approving 9.28% as the final return on equity for 2024.
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BHE U.S. Transmission
A significant portion of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base regulatory rate review scheduled for no later than February 1, 2025. In February 2023, the Public Utilities Commission of Texas ("PUCT") approved ETT's request to suspend a base regulatory rate review filing scheduled for February 2023. Results of a base regulatory rate review
would be prospective except for any deemed disallowance by the PUCT of the transmission investment since the initial base regulatory rate review in 2007. In June 2018, the PUCT approved ETT's application to reduce its transmission revenue by $28 million to reflect the lower federal income tax rate due to the federal tax rate change from 35% to 21% in 2017, with the amortization of excess accumulated deferred federal income taxes expected to be addressed in the next base rate case.
ENVIRONMENTAL LAWS AND REGULATIONS
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality,
coal ash disposal and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts.
The Company has cumulative investments in (i) owned wind, solar and geothermal generating facilities of $34.1 billion and (ii) wind tax equity investments of $5.8 billion and has ceased coal operations at 18 coal-fueled generation
facilities. As a result, as of December 31 2023, the Company reduced its annual GHG emissions by more than 34% as compared to 2005 levels. The Company plans to continue investing in wind, solar and other low-carbon generation and storage in the future, including (i) $6.9 billion on the construction of renewable generating facilities and repowering certain existing wind-powered generating facilities through 2026 and (ii) $2.0 billion on the construction of electric battery and pumped hydro storage facilities through 2026, and to cease coal operations at an additional 15 coal-fueled generation facilities between 2025 and 2030 in a reliable and cost-effective manner, thereby achieving a 50% reduction in GHG emissions from 2005 levels in 2030. Refer to "Liquidity and Capital Resources" of each respective Registrant in Item 7 of this Form 10-K for discussion of each Registrant's renewable generation-related capital expenditures.
On
August 16, 2022, the Inflation Reduction Act of 2022 (the "2022 Act") was signed into law. The 2022 Act contains numerous provisions, including expanded tax credits for clean energy incentives and a 15% corporate alternative minimum income tax on "adjusted financial statement income". The provisions of the 2022 Act become effective for tax years beginning after December 31, 2022. The Company currently does not expect a material impact on its consolidated financial statements. However, the Company expects future guidance from the Treasury Department and will continue to evaluate the impact of the 2022 Act as more guidance becomes available.
Air Quality Regulations
The Clean Air Act, as well
as state laws and regulations impacting air emissions, provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. These laws and regulations continue to be promulgated and implemented and will impact the operation of BHE's generating facilities and require them to reduce emissions at those facilities to comply with the requirements. In addition, the potential adoption of state or federal clean energy standards, which include low-carbon, non-carbon and renewable electricity generating resources, may also impact electricity generators and natural gas providers.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx,
particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Currently, with the exceptions described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainment of the current NAAQS.
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On
June 4, 2018, the EPA published final ozone designations for much of the U.S. Relevant to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the 2015 ozone standards for contravening the Clean Air Act. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency
to approve or disapprove the "good neighbor" provisions of interstate ozone plans of dozens of states. Relevant to the Registrants, the EPA must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan, Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's SIP after re-analyzing the state's data. In addition, the EPA must approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. On April 15, 2022,
the EPA issued its final rule approving Iowa's SIP as meeting the good neighbor provisions for the 2015 ozone standard. On May 24, 2022, the EPA disapproved the Utah and Wyoming interstate ozone SIPs. On January 30, 2023, the EPA entered into a stipulated extension to the deadline for action on the Wyoming SIP, setting a new deadline of December 15, 2023. The EPA explained that the extra time is needed to fully consider updated air quality information and public comments. The EPA published its proposed approval of Wyoming's SIP on August 14, 2023 and finalized the approval December 19, 2023. As a result Wyoming is not subject to the Good Neighbor Rule and litigation over Wyoming's SIP was terminated after the effective date
of the rule on January 18, 2024. The EPA is also reevaluating SIPs for Tennessee and Arizona. On January 31, 2023, the EPA issued final disapproval of the 19 SIPs proposed in April 2022, setting the stage to include those states in the federal implementation plan described under the Cross-State Air Pollution Rule. Separately, on March 28, 2022, the EPA proposed determinations as to whether certain areas have achieved levels of ground-level ozone pollution that meet the 2008 and 2015 ozone NAAQS. Relevant to Registrants, the Southern Wasatch Front in Utah and Yuma, Arizona are proposed to have met the 2015 ozone standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch Front in Utah are proposed to have not met the 2015 ozone standard and to be reclassified as Moderate Non-Attainment, and have until
August 3, 2024 to meet the standard. Until the EPA takes final action on the proposal and the affected states submit any required SIPs, the relevant Registrants cannot determine the impacts of the proposed rule.
On February 7, 2024, the EPA released final standards for fine particulate matter, PM2.5. The EPA strengthened the primary, health-based annual PM2.5 standard from 12 micrograms per cubic meter to 9 micrograms per cubic meter. The standards were last updated in 2012. Most PM2.5 particles form in the atmosphere as a result of chemical reactions of substances, such as sulfur dioxide and nitrogen oxides, that are emitted from power plants, industrial sources and automobiles. National ambient air quality standards are implemented through compliance plans submitted by states and tribes
that are then approved by the EPA. The EPA stated that 119 counties in the 48 contiguous states do not meet the revised standard but predicted that that number would be reduced to 52 counties by 2032, the earliest year by which a compliance requirement is anticipated. 23 of these 52 counties are located in California. There are no immediate impacts on the relevant Registrants. Until additional rulemaking and litigation is exhausted, the relevant Registrants cannot determine the full impacts of the revised standard.
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Cross-State Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2,
precursors of ozone and particulate matter, from down-wind sources in the eastern U.S. to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 Eastern and Midwestern states. In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key industry regulated by the rule and will be subject to emissions allowance trading beginning in summer 2023. The final rule shifted the maximum daily backstop rate for coal-fueled generating units, which drives the installation of new controls or
curtailment, to take effect in 2030 instead of 2027. PacifiCorp's Hunter Units 1-3 and Huntington Units 1-2, which do not have SCR controls, are impacted by the rule. PacifiCorp's 2023 IRP selected the installation of SNCR on the Hunter and Huntington Units by 2026 as part of the preferred portfolio. The level of NOx allowances for the Utah units remains similar to 2021 levels, with significant reductions for the coal units beginning in 2026. The daily limit, which takes effect in 2030, will further restrict operation of coal-fueled units without SCR. NV Energy's fossil-fueled units are also covered by the final rule. North Valmy Units 1 and 2, which do not have SCR, will require additional controls or reduced operations during the ozone season if operated beyond 2025. Nevada's regional haze SIP has an enforceable retirement date for North Valmy Units 1 and 2 of December 31,
2028, and NV Energy's IRP identified a December 31, 2025, retirement date for the units and is seeking a request of approval from the PUCN to convert the existing coal-fueled generating facility at the North Valmy Generating Station to a cleaner natural gas-fueled generating facility. The EPA's updated modeling suggests that Arizona, Iowa and Kansas may be significantly contributing to nonattainment in downwind states. The EPA intends to undertake additional assessment of its modeling for these states and will determine if it is necessary to address obligations for these states in future actions. The EPA also deferred final action for Wyoming, pending further review of updated air quality and contribution modeling and analysis. Additional notice and comment rulemaking, such as a supplemental rule, would be required to rescind Iowa's approved SIP and incorporate additional states into the program. The states of Nevada,
Utah and Wyoming challenged the EPA's denials and deferral, respectively, of their interstate ozone transport SIPs in the Ninth, Tenth and D.C. Circuit. PacifiCorp also filed petitions with the court opposing the EPA's action in Utah and Wyoming. At the time of filing, at least 11 other states have challenged the EPA's action to disapprove SIPs in seven different regional federal courts of appeal. Stays have been granted by six circuit courts for SIP disapprovals in 12 states. Relevant to Registrants, the states of Nevada, Texas and Utah were granted stays. The final Good Neighbor Rule was published June 5, 2023 and took effect August 4, 2023. The EPA issued several interim final rules stating that the federal rule will not take effect in states in which the SIP disapprovals have been deferred or stayed. In addition to litigation over SIP disapprovals, there are numerous
appeals of the final Good Neighbor Rule pending in four different circuit courts, and at least four motions to stay the final rule have been filed in four different circuit courts. On September 25, 2023, the D.C. Circuit denied the motion to stay the Good Neighbor Rule filed by several state and industry parties. The denial means that states that do not have stays on their SIP disapprovals are subject to the Good Neighbor Rule. The states of Ohio, Indiana and West Virginia filed a request for stay of the Good Neighbor Rule with the U.S. Supreme Court on October 13, 2023. Several industry groups representing utilities as well as pipeline, paper, cement and other industries affected by the rule filed supportive requests for stay on the same day. The U.S. Supreme Court will hear oral arguments on the emergency stay requests February
21, 2024. Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants cannot be determined.
For the first time, the EPA included additional sectors beyond the electric generation sector in the 2023 expanded CSAPR program. Relevant to the Registrants, this includes the pipeline transportation of natural gas. Requirements for that sector focus on emissions reductions from reciprocating internal combustion engines involved in the transport of natural gas and take effect in 2026. There is no access to allowance trading for the non-electric generation sectors. The EPA excluded emergency engines and engines that do not operate during the ozone season, included a facility-wide averaging plan and eased requirements for monitoring in the final rule. Northern Natural Gas operates 18 affected units; BHE GT&S operates 157 affected
units; and Kern River is not affected by the final rule.
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On January 24, 2024, the EPA released a supplemental proposal to expand the Good Neighbor Plan to an additional five states - Arizona, Iowa, Kansas, New Mexico and Tennessee. The EPA cites new modeling showing the states' significant contribution to ozone problems in downwind states. Under the proposal, fossil-fueled generating facilities in these five states would be required to participate in the allowance-based ozone season nitrogen oxides emissions trading program beginning in 2025. Relevant to the Registrants, the new state budget for Iowa was determined by optimizing existing post-combustion controls and installation
of neural networks. It does not appear that Iowa's revised budget would require additional emissions control equipment because the EPA determined that Iowa contributed to downwind monitor violations only in 2023 (the base year for the Good Neighbor Plan) and not in 2026 (the latest compliance date under the Good Neighbor Plan). However, because the EPA determined that Arizona contributes to monitor violations in both 2023 and 2026, the requirements for that state are more stringent and may drive installation of additional controls. The EPA will accept comment on the supplemental proposal through May 16, 2024. Until the EPA takes final action and litigation is exhausted, the full impacts of the rule cannot be determined.
Regional Haze
The EPA's Regional
Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
In June 2019, the state of Utah incorporated a BART alternative into its SIP for regional haze planning period one. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install
SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA approved the SIP revision with the BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. The EPA defended the SIP, and PacifiCorp and the state of Utah intervened in the litigation in support of the EPA. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. On August 14, 2023, the Tenth Circuit denied the petition to vacate Utah's first planning period regional
haze plan.
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The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. The EPA's final action on the Wyoming SIP in 2014 approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim
Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls by 2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental groups also filed an appeal of the EPA's final action. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The parties worked to mediate claims under
the Wyoming regional haze requirements until the abatement on litigation was lifted in September 2022. On August 15, 2023, the Tenth Circuit ruled in favor of Wyoming and remanded the Wyodak portion of Wyoming's state plan to EPA for further review, with instructions to give appropriate deference to the state's determinations. For Naughton Units 1 and 2, the court determined the EPA properly approved Wyoming's Naughton determination and denied environmental groups' petition. Separately, on February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree.
Consistent with the terms and conditions of the consent decree, PacifiCorp must convert Jim Bridger Units 1 and 2 to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. The EPA and PacifiCorp executed an administrative order on consent June 9, 2022, covering compliance for Jim Bridger Units 1 and 2 under the regional haze rule. The federal order contains the same emission and operating limits as the Wyoming consent decree and adds federal approval of the compliance pathway outlined in the state consent decree, including revision of the SIP to include conversion of Jim Bridger Units 1 and 2 to natural gas. The order includes a one-year deadline to complete the SIP revision. On December 30, 2022, the Wyoming Air Quality Division submitted the state-approved revised regional haze
SIP requiring natural gas conversion of Jim Bridger Units 1 and 2 to the EPA for approval. The plan revision replaces a previous requirement for selective catalytic reduction at the units. The Wyoming Air Quality Division also issued an air permit for the natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. PacifiCorp submitted a notice of compliance to the EPA on March 9, 2023, to certify completion of the Jim Bridger administrative compliance order requirements through compliance with the Wyoming consent decree and Wyoming's revised SIP submission. PacifiCorp remains subject to the compliance terms of the Wyoming consent decree as it works to convert Jim Bridger Units 1 and 2 to natural gas. The EPA is in on-going discussions with Wyoming to finalize a determination on the SIP revisions for Jim Bridger Units 1 and 2, with a decision anticipated by
spring 2024.
The state of Colorado first planning period regional haze SIP requires SCR equipment at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are in-service. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August
31, 2021 with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp retained a December 31, 2025, retirement date for Craig Unit 1 in its 2023 IRP.
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Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA and received completeness determinations in August 2022. The EPA has not yet made determinations on these plans. It was
required to make final determinations on the SIPs by August 2023. On August 25, 2022, the EPA promulgated a finding of failure to submit a SIP for the regional haze second planning period for 15 states, including Iowa. The finding establishes a two-year deadline for the agency to promulgate FIPs to address the requirements, unless prior to promulgating a FIP, the state submits, and the agency approves, a SIP meeting the requirements. The finding says the agency intends to continue to work with states in developing approvable SIP submittals in a timely manner. The Iowa Department of Natural Resources continues to work with the EPA on development of its SIP. Iowa issued a SIP in August 2023 that requires operational improvements to existing control equipment at MidAmerican Energy Company's Louisa Generation Station and Walter Scott Jr. Energy Center - Unit 3. Iowa submitted that plan to the EPA in fall 2023, where review
is pending. In August 2023, the Nevada Utilities filed a Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part, to convert the existing coal-fueled North Valmy Generating Station to natural gas and to continue operation of Tracy units 4 and 5 to 2049. Based in this filing, the state of Nevada partially withdrew portions of the State Implementation plan for Regional Haze to re-evaluate emission control measures that may be necessary to achieve reasonable progress during the second implementation period of the Regional Haze Rule in Nevada. That review is ongoing at the time of filing.
The states of Utah and Wyoming filed deadline suits in the Utah and Wyoming federal district courts in October and November of 2023, asking the court to require EPA to perform its statutory duty to approve or disapprove the states'
regional haze second planning period SIPs. PacifiCorp also filed a deadline suit in both courts. Three environmental groups filed similar deadline suits in the federal district court in Washington, D.C. for seven different states on June 15, 2023, The environmental groups amended their lawsuit on November 10, 2023, after Wyoming and PacifiCorp's suits were filed, to include Utah's and Wyoming's state plans. PacifiCorp has intervened in the D.C. district court case and asked that court to stay the Utah and Wyoming cases in that court while they proceed in the relevant state courts. The EPA is consulting with all groups on appropriate deadlines for agency action on specific state SIPs as the cases move forward in separate courts. As parties in the deadline suits the states and PacifiCorp will be included in settlement discussions and court oversight of the EPA's review of
the Utah and Wyoming SIPs. Until the cases are settled and additional rulemaking is completed by the EPA, any potential impacts to the relevant Registrants cannot be determined.
Climate Change
In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius and reaching a global peak of GHG emissions as soon as possible to achieve climate neutrality by mid-century; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments;
commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the U.S. agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016; however, the U.S. completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement on January 20, 2021, and the U.S. completed its reentry February
19, 2021. New commitments to the Paris Agreement were announced in April 2021, with the U.S. pledging to cut its overall GHG emissions 50% to 52% from 2005 levels by 2030 and to reach 100% carbon pollution-free electricity by 2035. Increasingly, states are adopting legislation and regulations to reduce GHG emissions, and local governments and consumers are seeking increasing amounts of clean and renewable energy.
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Federal Greenhouse Gas Standards
Performance Standards for New and Existing Generating Facilities
In June 2014, the EPA released proposed regulations
to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "best system of emission reduction." In August 2015, the final Clean Power Plan was released, which established the best system of emission reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the U.S. Supreme Court in February 2016 while litigation proceeded. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule. In the Affordable Clean Energy rule, the EPA determined that the best system of
emission reduction for existing coal-fueled generating facilities is limited to actions that can be taken at a point source facility, specifically heat rate improvements and identified a set of candidate technologies and measures that could improve heat rates. Measures taken to meet the standards of performance must be achieved at the source itself. The Affordable Clean Energy rule was challenged by environmental and health groups in the D.C. Circuit. On January 19, 2021, the D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA, finding that the rule "rested critically on a mistaken reading of the Clean Air Act" that limited the best system of emission reduction to actions taken at a facility. In October 2021, the U.S. Supreme Court agreed to hear an appeal of that decision. Arguments in the case were held February 28, 2022, and on June
30, 2022, the U.S. Supreme Court issued its decision regarding the scope of the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The U.S. Supreme Court held that the "generation shifting" approach in the Clean Power Plan exceeded the powers granted to the EPA by Congress, although the court did not address whether the EPA may only adopt measures applied at the individual source as it did in the Affordable Clean Energy rule. A key area where the EPA went astray was using the Clean Power Plan to give states the option to promulgate regulations that would encourage "generation shifting," or moving away from higher-polluting power sources like coal to lower-polluting sources like natural gas or renewables. The U.S. Supreme Court found that type of regulation, which would impact larger economic forces beyond the fence lines of individual generating facilities, is not permitted under Section 111(d) of the Clean Air Act. The U.S.
Supreme Court reversed the D.C. Circuit's vacatur of the Affordable Clean Energy rule and remanded the case for further proceedings. In May 2023, the EPA proposed rules addressing greenhouse gas emissions from new and reconstructed natural gas-fueled combustion turbines (Clean Air Act Section 111(b) rule) and existing coal- and gas- or oil-fueled steam units and natural gas-fueled combustion turbines (Clean Air Act Section 111(d) rule). The proposed requirements for existing units would take effect January 1, 2030, through state implementation plans. Requirements for new combustion turbines are subcategorized based on capacity factor, where low-load units would be required to meet an emissions limit, intermediate-load units would be required to use a blend of low-emitting hydrogen and natural gas and base-load units would be required to utilize carbon capture and sequestration technology or a high-percentage blend of
low-emitting hydrogen. Requirements for existing gas- and oil-fueled steam units are also subcategorized based on capacity factor, where low-load units would be subject to routine maintenance to demonstrate no increase in emissions, intermediate-load units would be subject to an emission limit of 1,500 pounds of CO2 / MWh-gross and base-load units would be subject to an emission limit of 1,300 pounds of CO2 / MWh-gross. Control equipment requirements for existing combustion turbines only apply to large, high load turbines that are greater than 300MW in capacity and operate at a greater than 50% capacity factor. These units would be required to begin utilizing carbon capture and sequestration with a 90% capture rate by 2035 or use a blend of low-emitting hydrogen starting in 2032. Requirements for existing coal-fueled units are subcategorized based on retirement date. Units with
earlier retirement dates would be subject to less stringent requirements while units that commit to later retirement dates would be subject to annual capacity factor limits or natural gas co-firing requirements. Units that will continue operating after December 31, 2039, would be required to utilize carbon capture and sequestration with a 90% carbon capture rate. Clean Air Act Section 111 establishes a cooperative approach between the EPA and the states. The EPA establishes nationwide standards based on the best system of emissions reductions it identifies for a source category. States are then expected to develop plans to implement those standards at affected units. States may adopt the EPA's standards or develop state-specific standards that achieve the same air quality results. The EPA accepted comments on the proposal through August 8, 2023. In November 2023, the EPA issued a supplement to the proposed rule, seeking
comment on impacts to small businesses and whether to include options to address potential reliability issues. The EPA accepted comment on the supplemental proposal through December 20, 2023. The EPA has indicated it intends to finalize the rules by April 2024. The relevant Registrants operate facilities that may be affected by these proposals. Until the EPA takes final action on the proposals, the states submit any required SIPs and litigation is exhausted, the relevant Registrants cannot determine the impacts of the proposed rule.
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New Source Performance Standards for Methane Emissions
In August
2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. The rule was immediately challenged by environmental and tribal groups, as well as numerous states. In January 2021, the D.C. Circuit lifted an administrative stay and allowed the rule to take effect, finding that groups challenging the rule had not met the standard for a long-term stay. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution reinstated the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for
the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA proposed rules that would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposals would expand and strengthen emission reduction requirements for new, modified and reconstructed oil and natural gas sources and would require states to reduce methane emissions from existing sources nationwide. The EPA took comment on the proposed rules through January 31, 2022. The EPA issued a supplemental proposal in November 2022 to further strengthen emission reduction requirements. The EPA issued the final rule in December 2023, establishing emissions standards and leak detection and repair requirements for a number of components across the natural gas system. Kern River is not affected by the rule. Northern Natural Gas and BHE GT&S
are affected by the rule and anticipate replacing some pneumatic controls and seals at centrifugal and reciprocating compressors. Additional leak detection and repair surveys and reports are also anticipated. In January 2024, the EPA proposed the methane fee rule, which is required under the Inflation Reduction Act. The fee, called a waste emissions charge, will be assessed on natural gas facilities that are subject to Greenhouse Gas Reporting Program Subpart W reporting. For transmission and storage operations, any facility that reports methane emissions over the congressionally-determined "0.11% of the methane sent to sale from or through such facility" will pay a fee to the federal government. The fee can be reduced by the netting of emissions, or altogether eliminated by certain statutory exemptions. The amount of the fee is scaled, beginning at $900 per metric ton of methane over the 0.11% threshold beginning in 2025 and increasing to $1500 per metric ton
of methane over the 0.11% threshold in 2027. The relevant Registrants do not expect significant impacts from the proposed fee rule due to the combination of the excess emissions threshold, netting allowance and compliance with the methane emissions standards rule. The EPA is accepting comments on the proposed fee rule through March 11, 2024. Until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.
Water Quality Standards
The Clean Water Act establishes the framework for maintaining and improving water quality in the U.S. through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology
available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The final rule was released in May 2014 and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the U.S. must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when
organisms are drawn into the facility). PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than 125 million gallons per day of water from waters of the U.S. for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter and Huntington generating facilities currently utilize closed cycle cooling towers but are designed to withdraw more than two million gallons of water per day. If PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant to the consolidated financial statements. Nevada Power and Sierra Pacific are not impacted by the §316(b) final rule since they do not utilize once-through cooling water intake or discharge structures at any of their generating facilities.
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In
November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. In November 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule took effect in December 2020. The final rule changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport water, revises the voluntary incentives program for flue gas desulfurization wastewater, and adds subcategories for high-flow units, low utilization units, and those that will transition away from coal combustion by 2028. While most of the issues raised by this rule are already being addressed through the CCR rule and are not expected to impose significant additional
requirements, the Dave Johnston generating facility is impacted by the rule's bottom ash handling requirements at Units 1 and 2. The generating facility submitted notice to the Wyoming Department of Environmental Quality that it will either achieve a cessation of coal combustion at Units 1 and 2 by December 31, 2028, or install bottom ash transport treatment technology by December 31, 2025. On March 8, 2023, the EPA proposed additional changes to the effluent limitations guidelines to replace the 2020 rule and provide stricter limits for bottom ash transport water, flue gas desulfurization wastewater and coal combustion residual leachate. The relevant Registrants use a combination of zero discharge, enrollment in cessation-of-coal subcategory and dry bottom ash handling to manage the affected wastestreams. As a result,
significant impacts are not anticipated. However, until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined. The EPA accepted public comments through May 30, 2023, and intends to finalize a rule by spring 2024.
In March 2023, the latest changes to the definition of "waters of the U.S.," a rule that determines which waters are regulated under the federal Clean Water Act, took effect. Under this rule, tributaries, many wetlands, intrastate lakes, intrastate ponds, intrastate streams and some impoundments must meet either test from the 2006 Rapanos plurality decision to be considered a water of the U.S. That is, a water must be relatively permanent and have a continuous surface connection to an included waterbody (the "relatively permanent"
test) or it must significantly affect the biological, physical or chemical integrity of a traditional navigable water, territorial seas or interstate waters (the "significant nexus" test). The rule was challenged in multiple courts. On May 23, 2023, the U.S. Supreme Court issued a decision in Sackett v. EPA, a case that challenged the Clean Water Act's applicability to certain wetlands. In its decision, the U.S. Supreme Court significantly narrowed protections for wetlands and intermittent streams under the federal Clean Water Act. The U.S. Supreme Court unanimously rejected the significant nexus test as unworkable. A divided U.S. Supreme Court determined that jurisdiction applies to waters that are adjacent to traditional interstate navigable waters and that have a continuous surface connection with that traditional interstate navigable waters. In light of the Sackett
decision, the EPA secured stays of litigation over its definitional rule in two of three pending challenges in order to conduct rulemaking to conform to the U.S. Supreme Court's decision. On September 8, 2023, the EPA issued a new rule conforming to the U.S. Supreme Court's decision.
Coal Ash Disposal
In April 2015, the EPA released a final rule to regulate the management and disposal of coal combustion residuals (CCR) under the RCRA. The rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts will need to be closed unless they can meet the more stringent regulatory
requirements.
At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal
combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017, and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated 10 evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.
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Multiple
parties filed challenges over various aspects of the final rule in the D.C. Circuit, resulting in settlement of some of the issues and subsequent regulatory action by the EPA. The EPA finalized the first phase of the CCR rule amendments in July 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted the EPA's request to remand the rule and left the October
31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 rule has not been finalized. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of 2016. The federal permit rule has not been finalized. In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking comment on and information related to issues relevant to development of regulations for legacy impoundments. On May 18, 2023, the EPA proposed the legacy surface impoundments rule and accepted comment on the proposal
through July 17, 2023. The proposal encompasses legacy surface impoundments, which are inactive surface impoundments at inactive facilities; and CCR management units ("CCRMU"), which include CCR surface impoundments and landfills that closed prior to October 19, 2015, inactive CCR landfills, and other areas where CCR has been or is managed directly on the land. CCRMUs include all units meeting that definition at active CCR facilities, as well as those at inactive facilities with one or more legacy surface impoundment. EPA proposes the impose substantially the same regulatory obligations for both legacy surface impoundments and CCRMUs as are applicable to currently regulated units, including groundwater monitoring and corrective action. All legacy surface impoundments and CCRMUs would be required to initiate closure, including reclosure, within one year after the
rule is finalized. The EPA has indicated it intends to finalize the legacy surface impoundment rule by spring 2024.
The EPA includes lists of potential legacy surface impoundments and CCRMUs in the rulemaking docket and those lists include several BHE facilities. The EPA also specifically identifies PacifiCorp's Huntington Power Plant and NV Energy's Reid Gardner Generating Station as potential CCRMU damage cases based on the EPA's review of compliance information. BHE corrected the record in comments that: (1) The north and south ash ponds at MidAmerican's Riverside Generating Station are incorrectly classified as legacy impoundments rather than CCRMUs; (2) historical impoundments, which were closed according to state requirements and no longer contain CCR or liquids, should be removed from the list of CCRMUs; (3) the EPA erroneously identified NV Energy's Reid Gardner Generating Station
and the Old Landfill at PacifiCorp's Huntington generating facility as potential damage cases; and (4) two impoundments at PacifiCorp's former Carbon generating facility are incorrectly included on the list of legacy impoundments because PacifiCorp never managed or disposed of CCR materials in wastewater ponds at the former Carbon generating facility.
The EPA published a Notice of Data Availability on November 14, 2023, in support of its proposed legacy impoundments rule. The notice sought information on two specific pieces of information: (1) an updated list of legacy impoundments and CCRMUs, based on information received during the comment period for the proposed rule; and (2) a risk assessment for legacy impoundments and CCRMUs. The EPA included lists of potential legacy surface impoundments and CCRMUs in the rulemaking docket and those
lists included several Berkshire Hathaway Energy facilities. Berkshire Hathaway Energy identified a number of errors and inaccuracies in those lists in comments submitted December 11, 2023.
In August 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule"). This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule established a new deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure. The Part A rule also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023; and (2) a site-specific
extension for facilities that agree to shut down the coal-fueled unit and complete ash pond closure activities by October 17, 2028. PacifiCorp developed a demonstration for the development of alternative capacity for the Jim Bridger facility's FGD Pond 2 and a demonstration for closure of the Naughton generating facility and ash pond and submitted them to the EPA in November 2020. On January 11, 2022, the EPA deemed these submittals complete but has not taken additional action on them. No other Registrants used the provisions of the Part A rule. On October 12, 2023, Jim Bridger FGD Pond 2 ceased receiving waste and the newly constructed FGD Pond 3 came into service. The EPA was notified on October 12, 2023, of PacifiCorp's withdrawal of its pending Part A alternative storage
capacity demonstration request.
Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.
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Notwithstanding the status of the final CCR rule, citizens' suits have been filed against regulated entities seeking judicial relief for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately released or connected to surface water. In addition, actions have been filed against regulated entities seeking to
require that surface impoundments containing CCR be subject to closure by removal rather than being allowed to effectuate closure in place as provided under the final rule. The Registrants are not a party to these lawsuits and until they are resolved, the Registrants cannot predict the impact on overall compliance obligations.
Other
Other laws, regulations and agencies to which the relevant Registrants are subject include, but are not limited to:
•The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental
remediation costs. Certain Registrants have been identified as potentially responsible parties in connection with certain disposal sites. The relevant Registrants have completed several cleanup actions and are participating in ongoing investigations and remedial actions. Costs associated with these actions are not expected to be material and are expected to be found prudent and included in rates.
•The Nuclear Waste Policy Act of 1982, under which the DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 14 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 11 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's nuclear decommissioning
obligations.
•The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of PacifiCorp's mining activities.
•The FERC evaluates hydroelectric systems to ensure environmental impacts are minimized, including the issuance of environmental impact statements for licensed projects both initially and upon relicensing. The FERC monitors the hydroelectric facilities for compliance with the license terms and conditions, which include environmental provisions. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for information regarding PacifiCorp's
Klamath River hydroelectric system.
The Registrants expect they will be allowed to recover their respective prudently incurred costs to comply with the environmental laws and regulations discussed above. The Registrants' planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (d) state-specific energy policies, resource preferences and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping
rates affordable. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Registrants at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Registrants have established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.
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Item 1A. Risk
Factors
Each Registrant is subject to numerous risks and uncertainties, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by the relevant Registrant, should be made before making an investment decision. Additional risks and uncertainties not presently known or which each Registrant currently deems immaterial may also impair its business operations. Unless stated otherwise, the risks described below generally relate to each Registrant.
Liquidity, Capital Requirements and Corporate Structure Risks
BHE is a holding company and depends on distributions from subsidiaries, including
joint ventures, to meet its obligations.
BHE is a holding company with no material assets other than the ownership interests in its subsidiaries and joint ventures, collectively referred to as its subsidiaries. Accordingly, cash flows and the ability to meet BHE's obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to BHE in the form of dividends or other distributions. As a result of material wildfire litigation at PacifiCorp, no dividends will be paid to BHE by PacifiCorp over the next several years, which could impact BHE's ability to fund its operations, make interest payments, fund debt maturities and increase BHE's reliance on debt.
BHE's subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay
amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, or to make funds available, whether by dividends or other payments, for the payment of amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, and do not guarantee the payment of any of its obligations. Distributions from subsidiaries may also be limited by:
•PacifiCorp's liquidity concerns resulting from wildfire litigation (described below);
•their respective earnings, capital requirements, and required debt and preferred stock payments;
•the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and
•regulatory restrictions that
limit the ability of BHE's regulated utility subsidiaries to distribute profits.
BHE is substantially leveraged, the terms of its existing senior and junior subordinated debt do not restrict the incurrence of additional debt by BHE or its subsidiaries, and BHE's senior debt is structurally subordinated to the debt of its subsidiaries, and each of such factors could adversely affect BHE's consolidated financial results.
A significant portion of BHE's capital structure is comprised of debt, and BHE expects to incur additional debt in the future to fund items such as, among others, acquisitions, capital investments and the development and construction of new or expanded facilities. As of December 31, 2023, BHE had the following outstanding obligations:
•senior
unsecured debt of $13.1 billion;
•junior subordinated debentures of $100 million;
•guarantees and letters of credit in respect of subsidiaries, equity method investments and other related parties aggregating $2.6 billion; and
BHE's consolidated subsidiaries also have significant amounts of outstanding debt, which totaled $41.2 billion as of December 31, 2023. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) BHE's share of the outstanding debt of its own or its subsidiaries' equity method investments.
Given BHE's substantial leverage, it may
not have sufficient cash to service its debt, which could limit its ability to finance future acquisitions, develop and construct additional projects, or operate successfully under difficult conditions, including those brought on by adverse national and global economies, unfavorable financial markets or growth conditions where its capital needs may exceed its ability to fund them. BHE's leverage could also impair its credit quality or the credit quality of its subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.
The terms of BHE's and its subsidiaries' debt do not limit BHE's ability or the ability of its subsidiaries to incur additional debt or issue preferred stock. Accordingly, BHE or its subsidiaries could enter into acquisitions, new financings, refinancings,
recapitalizations, leases or other highly leveraged transactions that could significantly increase BHE's or its subsidiaries' total
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amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect BHE's or its subsidiaries' financial results. Many of BHE's subsidiaries' debt agreements contain covenants, or may in the future contain covenants, that restrict or limit, among other things, such subsidiaries' ability to create liens, sell assets, make certain distributions, incur additional debt or miss contractual deadlines or requirements, and BHE's ability to comply with these covenants may be affected by events beyond its control. Further, if an event of default accelerates a repayment obligation and such acceleration
results in an event of default under some or all of BHE's other debt, BHE may not have sufficient funds to repay all of the accelerated debt simultaneously, and the other risks described under "Corporate and Financial Structure Risks" may be magnified as well.
Because BHE is a holding company, the claims of its senior debt holders are structurally subordinated with respect to the assets and earnings of its subsidiaries. Therefore, the rights of its creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders, if any. In the event of default due to the bankruptcy, insolvency, or reorganization of a significant subsidiary, all of BHE's debt will become immediately due. In addition, pursuant to separate financing agreements, substantially all of PacifiCorp's
electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties, the equity interest of MidAmerican Funding's subsidiary and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects, are directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of BHE's debt.
A downgrade in BHE's credit ratings or the credit ratings of its subsidiaries, including the Subsidiary Registrants, could negatively affect BHE's or its subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements and PacifiCorp's credit rating has been downgraded as a result of
wildfire litigation related risks.
BHE's senior unsecured debt and its subsidiaries' long-term debt, including the Subsidiary Registrants, are rated by various rating agencies. BHE cannot give assurance that its senior unsecured debt rating or any of its subsidiaries' long-term debt ratings will not be reduced in the future. Although none of the Registrants' outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase any such Registrant's borrowing costs and commitment fees on its revolving credit agreements and other financing arrangements, perhaps significantly. In addition, such Registrant would likely be required to pay a higher interest rate in future financings, the potential pool of investors would likely decrease and depending on the rating, require some investors to sell the Registrants' bonds. Further,
access to the commercial paper market could be significantly limited, resulting in higher interest costs.
Similarly, any downgrade, change in rating methodology impacting subsidiaries credit rating, placement on negative outlook or credit watch or other event negatively affecting the credit ratings of BHE's subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause BHE to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing its and its subsidiaries' liquidity and borrowing capacity; however BHE is not obligated to provide liquidity to its subsidiaries.
Most of the Registrants' large wholesale customers, suppliers and counterparties require such Registrant to have sufficient creditworthiness
in order to enter into transactions, particularly in the wholesale energy markets. If the credit ratings of a Registrant were to decline, especially below investment grade, the relevant Registrant's financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other form of security for existing transactions and as a condition to entering into future transactions with such Registrant. Amounts could be material and could adversely affect such Registrant's liquidity and cash flows.
Refer to "PacifiCorp Wildfire Litigation Risks" section below for additional information regarding PacifiCorp.
Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon
or renew existing credit facilities and have other adverse effects on each Registrant.
Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant. Significant dislocations and liquidity disruptions in the U.S., Great Britain, Canada and global credit markets, such as those that occurred in 2008, 2009 and 2020, may materially impact liquidity in the bank and debt capital markets, making financing terms less attractive for borrowers that are able to find financing and, in other cases, may cause certain types of debt financing, or any financing, to be unavailable. Additionally, economic uncertainty in the U.S. or globally may adversely affect the U.S. credit markets and could negatively impact each Registrant's ability to access funds on favorable
terms or at all. If a Registrant is unable to access the bank and debt markets to
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meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of its capital expenditures, acquisition financing and its financial results.
Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning and mine reclamation trust funds could unfavorably impact each Registrant's cash flows, liquidity and financial results.
Costs of providing each Registrant's defined benefit pension and other postretirement
benefit plans and costs associated with the joint trustee plan to which PacifiCorp contributes depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, mortality assumptions, the interest rates used to measure required minimum funding levels, the funded status of the plans, changes in benefit design, tax deductibility and funding limits, changes in laws and government regulation and each Registrant's required or voluntary contributions made to the plans. Furthermore, the timing of recognition of unrecognized gains and losses associated with the Registrants' defined benefit pension plans is subject to volatility due to events that may give rise to settlement accounting. Settlement events resulting from lump sum distributions offered by certain of the Registrants' defined benefit pension plans are influenced by the interest rates used to discount a participant's lump sum distribution. When
the applicable interest rates are low, lump sum distributions in a given year tend to increase resulting in a higher likelihood of triggering settlement accounting.
If the Registrant's pension or other postretirement benefit plans are in underfunded positions, the respective Registrant may be required to make cash contributions to fund such underfunded plans in the future. Additionally, each Registrant's plans have investments in domestic and foreign equity and debt securities and other investments that are subject to the risk of loss. Losses from investments could add to the volatility, size and timing of future contributions.
Furthermore, the funded status of the UMWA 1974 Pension Plan multiemployer plan to which PacifiCorp's subsidiary previously contributed is considered critical and declining. PacifiCorp's
subsidiary involuntarily withdrew from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp has recorded its best estimate of the withdrawal obligation.
In addition, MidAmerican Energy is required to fund over time the projected costs of decommissioning Quad Cities Station, a nuclear generating facility, and Bridger Coal Company, a joint venture of PacifiCorp's subsidiary, Pacific Minerals, Inc., is required to fund projected mine reclamation costs. The funds that MidAmerican Energy has invested in a nuclear decommissioning trust and a subsidiary of PacifiCorp has invested in a mine reclamation trust are invested in debt and equity securities and poor performance of these investments will reduce the amount of funds available for their intended purpose, which could require MidAmerican Energy or PacifiCorp's subsidiary to
make additional cash contributions. As contributions to the trust are being made over the operating life of the respective facility, reductions in the expected operating life of the facility could also require MidAmerican Energy and PacifiCorp's subsidiary to make additional contributions to the related trust. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on MidAmerican Energy's or PacifiCorp's liquidity by reducing their available cash. Additionally, PacifiCorp's mine reclamation obligation for Bridger Coal Company is secured by a surety bond. Refer to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding the impact of wildfire litigation risks on PacifiCorp's liquidity and ability to obtain security.
BHE's majority shareholder, Berkshire Hathaway, could exercise
control over BHE in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors and BHE could exercise control over the Subsidiary Registrants in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors and PacifiCorp'spreferred stockholders.
Berkshire Hathaway is majority owner of BHE and has control over all decisions requiring shareholder approval. In circumstances involving a conflict of interest between Berkshire Hathaway and BHE's creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors.
BHE indirectly owns all of the common stock of PacifiCorp, Nevada Power, Sierra Pacific and EGTS and the membership interest
in Eastern Energy Gas. BHE is also the sole member of MidAmerican Funding and, accordingly, indirectly owns all of MidAmerican Energy's common stock. As a result, BHE has control over all decisions requiring shareholder approval, including the election of directors. In circumstances involving a conflict of interest between BHE and the creditors of the Subsidiary Registrants, BHE could exercise its control in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors.
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PacifiCorp Wildfire Risks
PacifiCorp's litigation risk associated with the Wildfires is inherently uncertain and the ultimate outcomes of the associated
claims could materially and adversely affect PacifiCorp's financial condition and results of operations and its ability to obtain financing, to fund its operations, capital investments and settlements arising from the Wildfires, and to obtain and fund third-party liability insurance coverage.
Litigation
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damages, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). Additionally, a major wildfire began in PacifiCorp's service territory in July 2022 causing private and public property damage, personal injuries, loss of life and power outages in Northern California
(the "2022 McKinney Fire"). Together, the 2020 Wildfires and the 2022 McKinney Fire are referred to as "the Wildfires."
A significant number of complaints and demands alleging similar claims related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint. Additionally, multiple complaints associated with the 2022 McKinney Wildfire have been filed in California. Refer to Item 3. Legal Proceedings, BHE's Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K and PacifiCorp's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the Wildfires. PacifiCorp may be subject to additional complaints and demands (collectively "actions") associated with the Wildfires. Further, the amounts specified in the original filed actions do not limit the amount
of damages that ultimately may be awarded in a court proceeding, and therefore PacifiCorp's liability for damages could be substantially greater than the original amounts specified and its estimated losses. For example, plaintiffs frequently are permitted to amend their complaints, such as to seek punitive and additional noneconomic damages.
As described in BHE's Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K and PacifiCorp's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K, the jury in an initial June 2023 trial related to the 2020 Wildfires (captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon, and referred to as "James") issued a verdict finding PacifiCorp liable to the 17 individual plaintiffs and making certain findings as to
the class with respect to four wildfires. While PacifiCorp disagrees with and has appealed the court's granting of class certification (among other matters), the potential class size, if class certification is not overturned on appeal, could be significant and the liability for damages may be substantially higher than current estimated losses. Additional trials related to the Wildfires, including damages-only reserves for James, are expected and could also result in an increase in current estimated losses. Damages with respect to certain plaintiffs may be significantly higher or lower than with respect to other plaintiffs. PacifiCorp intends to appeal adverse decisions, starting with the James decisions, such that it is possible that a final determination of its liability and damages could take several years. While certain settlements have occurred, PacifiCorp cannot be certain that additional settlements can be achieved
on terms it finds reasonable, if at all.
Liquidity
As a result of the litigation risk and estimated losses recorded to date associated with the Wildfires, PacifiCorp's liquidity has been materially impacted and its credit ratings have been downgraded. PacifiCorp could experience further declines in its credit ratings, changes to its ratings methodology, placed on credit watch or outlook negative if additional unfavorable litigation or similar outcomes occur as a result of the Wildfires.
These changes in PacifiCorp's credit ratings have and are expected to continue to have a material impact on PacifiCorp's liquidity and may result in, among other things, PacifiCorp being unable to maintain sufficient levels of cash or
to obtain necessary short- and long-term financing to fund its operations and financial obligations, capital investments and potential future settlements associated with the Wildfires. PacifiCorp may be unable to access debt capital markets for an extended period of time in the event of unfavorable jury verdicts, additional declines in PacifiCorp's credit ratings and potential uncertainty around PacifiCorp's ultimate exposure associated with the James class action and future catastrophic wildfires that may occur despite PacifiCorp's wildfire mitigation efforts. PacifiCorp may also be subject to borrowing limitations due to long-term debt covenants and increasing leverage ratios. Furthermore, investors in PacifiCorp's First Mortgage Bonds may be unable to hold existing bonds or to invest in new bonds, and perceived risks associated with the Wildfires may limit PacifiCorp's ability to attract investors. At a minimum, the cost
of any short- or long-term financing is expected to be higher as a result of the wildfire litigation risks and decline in PacifiCorp's credit ratings.
In addition to the above-described financing constraints, PacifiCorp may be required to provide additional collateral, letters of credit, adequate assurance, or other forms of security to achieve otherwise routine transactions and at a higher cost than has
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been experienced in the past. Collateral may be required to be posted in association with commodity contracts with credit-risk-related contingent features or material adverse change clauses.
Refer
to Item 7 "Liquidity and Capital Resources" for further information regarding the liquidity impacts arising from the Wildfires.
Insurance
PacifiCorp has experienced material increases in the cost of third-party liability insurance as a result of worsening damage claims in the utility industry associated with catastrophic wildfires in the geographic regions in which PacifiCorp operates. Such costs may continue to increase materially to the point of being prohibitively expensive, and it is possible that PacifiCorp may be unable to obtain third-party liability insurance. Increases in the cost of insurance may be challenged when PacifiCorp seeks cost recovery and such amounts may not be recoverable in customer rates. To the extent third-party liability insurance costs continue to increase, becomes
cost prohibitive or is unavailable and such increased costs are not recoverable in customer rates, PacifiCorp's financial condition and results of operations could be materially adversely affected and its liquidity position further negatively impacted.
Regulatory, Legislative and Legal Risks
Each Registrant may be subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety, reliability, data privacy and other laws and regulations that may affect its operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations, including, but not limited to, initiatives regarding deregulation and restructuring of the utility industry, are continually being
proposed and enacted that may impose new or revised requirements or standards on each Registrant.
Each Registrant is required to comply with numerous federal, state, local or foreign laws and regulations as described in "General Regulation" and "Environmental Laws and Regulations" in Item 1 of this Form 10-K that have broad application to each Registrant and limits the respective Registrant's ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring, disposing or retiring operating assets; operating and maintaining generating facilities and transmission and distribution system assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; managing and reporting transactions
between subsidiaries and affiliates; and paying dividends or similar distributions. These laws and regulations, which are followed in developing the Registrants' safety and compliance programs and procedures, are implemented and enforced by federal, state and local regulatory agencies, such as the Occupational Safety and Health Administration, the FERC, the EPA, the DOT, the NRC, the Federal Mine Safety and Health Administration and various state regulatory commissions in the U.S., and by foreign regulatory agencies, such as GEMA, which discharges certain of its powers through its staff within Ofgem, in Great Britain and the AUC in Alberta, Canada.
Compliance with applicable laws and regulations generally requires each Registrant to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require
significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs and damages arising out of contaminated properties. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, each Registrant could be required to shut down some facilities or materially alter its operations. Further, each Registrant may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for its operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay each Registrant from operating its facilities, developing or favorably locating new facilities or expanding existing facilities.
If any Registrant fails to comply with any environmental or other regulatory requirements, such Registrant may be subject to penalties and fines or other sanctions, including changes to the way its electricity generating facilities are operated that may adversely impact generation or how the Pipeline Companies are permitted to operate their systems that may adversely impact throughput. The costs of complying with laws and regulations could adversely affect each Registrant's financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require such Registrant to increase its purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect such Registrant's financial results.
Existing laws and regulations, while comprehensive, are subject to changes and revisions
from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition and decreased revenue within each Registrant's service
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territories; new environmental or climate-related requirements, including the implementation of or changes to the Affordable Clean Energy rule, RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to each Registrant's service territories as a result
of condemnation or takeover by municipalities or other governmental entities, particularly where it lacks the exclusive right to serve its customers; the inability of each Registrant to recover its costs on a timely basis, if at all; new pipeline safety requirements; or a negative impact on each Registrant's current cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on each Registrant. For example, in April 2022, the EPA proposed the "Cross-State Ozone Transport Rule", which contains requirements intended to address ozone transport between states through federally required nitrogen oxide reductions from fossil-fuel generating facilities. The rule included Wyoming, Utah and Nevada for the first time. If finalized as proposed, the rule will have impacts on PacifiCorp's coal-fueled generating facilities
in both Utah and Wyoming that do not have an SCR as early as 2026 and threatens early coal-fueled unit retirements and reliability impacts. PacifiCorp has engaged with state and federal agencies to make adjustments to the rule and mitigate potential reliability impacts. Adverse rulings in GHG-related cases could result in increased or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities. The GHG rules, changes to those rules, and the Registrants' compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.
New federal, regional, state and international accords, legislation, regulation, or judicial proceedings limiting GHG emissions could have a material adverse impact on the Registrants, the U.S. and the global economy. Companies and industries with higher GHG emissions, such
as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Registrants include:
•Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of
allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;
•Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;
•Additional costs may be incurred to purchase and deploy new generating technologies;
•Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;
•Operating costs may be higher and generating unit outputs may be lower;
•Higher
interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and
•The relevant Registrant's natural gas pipeline operations and capacity sales, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.
The impact of events or conditions caused by climate change, whether from natural processes or human activities, are uncertain and could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risks through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand
for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Registrants' existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.
Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones are among the most challenging aspects of managing utility operations. The Registrants cannot accurately predict the type or scope of future laws and regulations that may
be enacted, changes in existing ones or new interpretations by agency orders or court decisions, nor can each Registrant determine their impact on it at this time; however, any one of these could
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adversely affect each Registrant's financial results through higher capital expenditures and operating costs, early closure of generating facilities or lower tax benefits or restrict or otherwise cause an adverse change in how each Registrant operates its business. To the extent that each Registrant is not allowed by its regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the costs of complying with such additional requirements could have a material adverse effect on the relevant Registrant's financial
results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on the relevant Registrant's financial results.
Recovery of costs and certain activities by each Registrant is subject to regulatory review and approval, and the inability to recover costs or undertake certain activities may adversely affect each Registrant's financial results.
State Regulatory Rate Review Proceedings
The Utilities establish rates for their regulated retail services through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and
officials, consumer advocacy groups and various consumers of energy, who have differing concerns but generally have the common objective of limiting rate increases or requesting rate decreases while also requiring the Utilities to ensure system reliability. Decisions are subject to judicial appeal, potentially leading to further uncertainty associated with the approval proceedings.
States set retail rates for consumers within their jurisdiction based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state or other jurisdiction. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient
to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense, investment and capital structure that it deems are prudently incurred in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standard. Additionally, each state regulatory commission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital. While rate regulation is premised on providing a fair opportunity to
earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that each Registrant will be able to realize the allowed rate of return or recover all of its costs even if it believes such costs to be prudently incurred.
Some state regulatory commissions have authorized recovery of certain costs above the level assumed in establishing base rates through adjustment mechanisms, which may be subject to customer sharing. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on the Utilities, despite efforts to minimize this impact through the use of hedging contracts and adjustment mechanisms or through future general regulatory rate reviews. Further, interjurisdictional cost allocation constraints could limit PacifiCorp's ability to recover such costs despite the adjustment mechanisms.
Any of these consequences could adversely affect each Registrant's financial results.
FERC and Other Jurisdictions
The FERC authorizes cost-based rates associated with transmission services provided by the Utilities' transmission facilities. Under the Federal Power Act, the Utilities, or MISO as it relates to MidAmerican Energy, may voluntarily file, or may be obligated to file, for changes, including general rate changes, to their system-wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity in the wholesale market, has jurisdiction over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The
FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect each Registrant's financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. As a transmission owning member of MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. As participants in EIM, PacifiCorp, Nevada Power and Sierra Pacific are also subject to applicable California ISO rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.
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The
NERC has standards in place to ensure the reliability of the electric generation system and transmission grid. The Utilities are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.
The FERC has jurisdiction over, among other things, the construction, abandonment, modification and operation of natural gas pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including all rates, charges and terms and conditions of service. The FERC also has market transparency authority and has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.
Rates
for the interstate natural gas transmission and storage operations at the Pipeline Companies, which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for charges, are authorized by the FERC. In accordance with the FERC's ratemaking principles, the Pipeline Companies' current maximum tariff rates are designed to recover prudently incurred costs included in their pipeline systems' regulatory cost of service that are associated with the construction, operation and maintenance of their pipeline systems and to afford the Pipeline Companies an opportunity to earn a reasonable rate of return. Nevertheless, the rates the FERC authorizes the Pipeline Companies to charge their customers may not be sufficient to recover the costs incurred to provide services in any given period. Moreover, from time to time, the FERC may change, alter or refine its policies or methodologies for establishing pipeline rates and terms and conditions of service. In addition,
the FERC has the authority under Section 5 of the Natural Gas Act of 1938 ("NGA") to investigate whether a pipeline may be earning more than its allowed rate of return and, when appropriate, to institute proceedings against such pipeline to prospectively reduce rates. Any such proceedings, if instituted, could result in significantly adverse rate decreases.
Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the maximum tariff rate for that service or the pipeline may agree to provide a discounted rate, which would be a rate between the maximum and minimum tariff rates. In a rate proceeding, rates in these contracts are generally not subject to adjustment. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the cost used in the determination of the
negotiated or discounted rates, which could result either in losses or lower rates of return for providing such services. Under certain circumstances, FERC policy allows interstate natural gas pipelines to design new maximum tariff rates to recover such costs in regulatory rate reviews. However, with respect to discounts granted to affiliates, the interstate natural gas pipeline must demonstrate that the discounted rate was necessary in order to meet competition.
The Northern Powergrid Distribution Companies, as DNOs and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year-to-year but is a control on revenue that operates independent of a significant portion
of the DNO's actual costs. A resetting of the formula does not require the consent of the DNO, but if a licensee disagrees with a change to its license, it can appeal the matter to the United Kingdom's CMA. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of any price control, additional costs have a direct impact on the financial results of the Northern Powergrid Distribution Companies.
The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including
AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems.
The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing. In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.
Each Registrant is involved in a variety of legal proceedings, the outcomes of which are uncertain and could adversely affect its financial
results.
Each Registrant is, and in the future may become, a party to a variety of legal proceedings. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of individual matters with certainty. It is possible that the final resolution of some of the matters in which each Registrant is involved could result in additional material payments substantially in excess of established liabilities or in terms that could require each Registrant to change business practices and procedures or divest ownership of assets. Further, litigation could result in the imposition of operational or financial penalties or injunctions and adverse regulatory consequences, any of which could limit each Registrant's ability to take certain desired actions or the
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denial
of needed permits, licenses or regulatory authority to conduct its business, including the siting, operation or permitting of facilities. Unfavorable judgments could also require posting of surety bonds as security until the amounts awarded to plaintiffs are paid or the judgment is overturned in the appeals process. To the extent the Registrant or affected subsidiary is unable to post such a bond, other forms of security may be required such as cash or letters of credit that could reduce borrowing capacity under credit facility agreements. Any of these outcomes could have a material adverse effect on such Registrant's or BHE's financial results. Refer to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding PacifiCorp's wildfire litigation risks.
Operational and Development Risks
The
Registrants are subject to operating uncertainties and events beyond each respective Registrant's control that impact the costs to operate, maintain, repair and replace utility and interstate natural gas pipeline systems and the ability to self-insure many risks, which could adversely affect each respective Registrant's financial results.
The operation of complex utility systems or interstate natural gas pipeline and storage systems that are spread over large geographic areas involves many operating uncertainties and events beyond each respective Registrant's control. These potential events include the breakdown or failure of the Registrants' thermal, nuclear, hydroelectric, solar, wind and other electricity generating facilities and related equipment, compressors, pipelines, transmission and distribution lines and associated electric operations equipment or other equipment or processes,
which could lead to catastrophic events; unscheduled outages; coal supply challenges occurring as a result of the transition away from coal-fueled resources; strikes, lockouts, other labor-related actions or shortages of qualified labor, including with respect to the Registrants' suppliers and vendors; transmission and distribution system constraints; failure to obtain, renew or maintain rights-of-way, easements and leases on U.S. federal, Native American, First Nations or tribal lands; terrorist activities or military or other actions, including physical or cyber attacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; third-party excavation errors; unexpected degradation of transmission lines, pipeline systems or storage reservoirs; design, construction or manufacturing defects; and catastrophic
events such as severe storms, floods, fires, extreme temperature events, wind events, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, costly litigation, wars, terrorism, pandemics and embargoes. A catastrophic event might result in injury or loss of life, extensive property damage, environmental or natural resource damages or excessive economic loss. For example, in the event of an uncontrolled release of water at one of PacifiCorp's high hazard potential hydroelectric dams, it is probable that loss of human life, disruption of lifeline facilities and property damage could occur in the downstream population and civil or other penalties could be imposed by the FERC. The extent of that liability would be determined by the applicable state law where any such damage occurred. Any of these events or other operational events could significantly reduce or eliminate the relevant Registrant's revenue or significantly increase its expenses, thereby
reducing the availability of distributions to BHE. For example, if the relevant Registrant cannot operate its electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event or due to supply constraints, its revenue could decrease and its expenses could increase due to the need to obtain energy from more expensive sources.
The Registrants self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs or other damages. Further, third-party liability insurance coverage may be costly or unavailable as a result of increasing risks associated with catastrophic wildfires as discussed below. The scope, cost and availability of each Registrant's insurance coverage may change, including the portion that is self-insured.
Any
reduction of each Registrant's revenue or increase in its expenses resulting from the risks described above, could adversely affect the relevant Registrant's financial results. Refer also to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding PacifiCorp's wildfire insurance risks.
The Registrants are subject to increasing risks from catastrophic wildfires and may be unable to obtain enough third-party liability insurance coverage at a reasonable cost or at all and insurance coverage on existing wildfire claims could be insufficient to cover all losses, all of which could materially affect the Registrants financial results and liquidity.
The risk of catastrophic and severe wildfires has increased in the western U.S. giving rise to the potential for large
damage claims against utilities for fire-related losses. Catastrophic and severe wildfires can occur in PacifiCorp, Nevada Power and Sierra Pacific's ("Western Domestic Utilities") service territories even when the Western Domestic Utilities effectively implement their wildfire mitigation plans and prudently manage their systems.
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In California, for example, where PacifiCorp operates, "inverse condemnation" currently exposes utilities to potential liability for property damages where the utility's electrical equipment was a substantial cause of the wildfire. California courts have held that utilities can be held liable under inverse condemnation without being found negligent and regardless of fault. California
law also permits inverse condemnation plaintiffs to recover attorney's fees. As a result of inverse condemnation being applied to utilities and wildfire damages, recent losses recorded by insurance companies, and the risk of an increase in the frequency, duration and size of wildfires, insurance for wildfire liabilities may not be available or may be available only at rates that are prohibitively expensive. In addition, even if insurance for wildfire liabilities is available, it may not be available in amounts necessary to cover potential losses. Uninsured losses and increases in the cost of insurance may be challenged when PacifiCorp seeks cost recovery and may not be recoverable in customer rates.
The Western Domestic Utilities monitor weather conditions with specific thresholds for designated high fire consequence areas to help ensure the safe and reliable operation of their systems
during periods of elevated wildfire ignition risk. Should weather conditions become extreme, the Western Domestic Utilities may de-energize certain sections of their transmission and distribution facilities as a last resort to minimize risk to the public. These "public safety power shutoffs" could be subject to increased scrutiny by regulators and policy makers. And, although "public safety power shutoffs" are intended to minimize risk of wildfire ignition, de-energization may cause other damages for which the Western Domestic Utilities could be held liable.
Refer also to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding PacifiCorp's wildfire insurance risks.
Each Registrant is actively pursuing, developing and constructing new or expanded
facilities, the completion and expected costs of which are subject to significant risk, and each Registrant has significant funding needs related to its planned capital expenditures.
Each Registrant actively pursues, develops and constructs new or expanded facilities. Each Registrant expects to incur significant annual capital expenditures over the next several years. Such expenditures may include construction and other costs for new electricity generating facilities, electric transmission or distribution projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline and local distribution systems, and continued maintenance and upgrades of existing assets.
Development and construction of major facilities are subject to substantial risks, including fluctuations
in the price and availability of commodities, manufactured goods, equipment, and the imposition of tariffs thereon when sourced by foreign providers, labor, siting and permitting and changes in environmental and operational compliance matters, load forecasts and other items over a multi-year construction period, as well as counterparty risk and the economic viability of the Registrants' suppliers, customers and contractors. Certain of the Registrants' construction projects are substantially dependent upon a single supplier or contractor and replacement of such supplier or contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in-service and, in extreme cases, the loss of the power purchase agreements or other long-term off-take contracts underlying such projects. Such costs may not be recoverable in the regulated rates or market or contract
prices each Registrant is able to charge its customers. Delays in construction of renewable projects may result in delayed in-service dates which may result in the loss of anticipated revenue or income tax benefits. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or recover any such costs could adversely affect such Registrant's financial results.
Furthermore, each Registrant depends upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If BHE does not provide needed funding to its subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may
need to postpone or cancel planned capital expenditures. Refer to "PacifiCorp Wildfire Litigation and Insurance Risks" above for additional information regarding the impact of wildfire litigation risks on PacifiCorp's capital expenditures.
A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results.
A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results. Factors that could lead to a decrease in market demand include, among
others:
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•a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas;
•an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;
•shifts in competitively priced natural gas supply sources away from the sources connected to the Pipeline Companies' systems, including shale gas sources;
•efforts by customers, legislators and regulators to reduce the consumption of
electricity generated or distributed by each Registrant through various existing laws and regulations, as well as, deregulation, conservation, energy efficiency and private generation measures and programs;
•laws or policy pronouncements mandating or encouraging renewable energy sources, which may decrease the demand for electricity and natural gas or change the market prices of these commodities;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels;
•a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a
result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise;
•a reduction in the state or federal subsidies or tax incentives that are provided to agricultural, industrial or other customers, or a significant sustained change in prices for commodities such as ethanol or corn for ethanol manufacturers; and
•sustained mild weather that reduces heating or cooling needs.
Each Registrant's operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.
In most parts of the U.S. and other markets in which each Registrant operates, demand
for electricity peaks during the summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In other areas, including the western portion of PacifiCorp's service territory, demand for electricity peaks during the winter when heating needs are higher. In addition, demand for natural gas and other fuels generally peaks during the winter. This is especially true in MidAmerican Energy's and Sierra Pacific's retail natural gas businesses. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may negatively impact electricity generation at PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, PacifiCorp and MidAmerican Energy have added substantial wind-powered
generating capacity, and BHE's unregulated subsidiaries are adding solar-powered and wind-powered generating capacity, each of which is also a climate-dependent resource.
As a result, the overall financial results of each Registrant may fluctuate substantially on a seasonal and quarterly basis. Each Registrant has historically provided less service, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect each Registrant's financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase each Registrant's costs to provide services and could adversely affect its financial results. The extent of fluctuation in each Registrant's financial results may change depending on a number of factors related to its regulatory environment and contractual agreements, including its
ability to recover energy costs, the existence of revenue sharing provisions as it relates to MidAmerican Energy, Nevada Power and Sierra Pacific, and terms of its wholesale sale contracts.
Each Registrant is subject to market risk associated with the wholesale energy markets, which could adversely affect its financial results.
In general, each Registrant's primary market risk is adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. The market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity, scheduled and unscheduled outages of generating facilities, prices and
availability of fuel sources for generation, disruptions or constraints to transmission and distribution facilities, weather conditions, demand for electricity, economic growth and changes in technology. Volumetric changes are caused by fluctuations in generation or changes in
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customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations and governmental policies or customer behavior. For example, the Utilities purchase electricity and fuel in the open market as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market prices, the Utilities may incur significantly greater expenses than anticipated. Likewise, if electricity market prices
decline in a period when the Utilities are a net seller of electricity in the wholesale market, the Utilities could earn less revenue. Although the Utilities have ECAMs, the risks associated with changes in market prices may not be fully mitigated due to customer sharing bands as it relates to PacifiCorp and other factors, including potential interjurisdictional allocation constraints and extended recovery periods that negatively impact cash flows.
Certain of BHE's subsidiaries are subject to the risk that customers will not renew their contracts or that BHE's subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect its financial results.
If BHE's subsidiaries are unable to renew, remarket, or find replacements for their customer agreements on favorable
terms, BHE's subsidiaries' sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, BHE cannot assure that the Pipeline Companies will be able to transport natural gas at efficient capacity levels. Substantially all of the Pipeline Companies' revenue is generated under transportation, storage and LNG contracts that periodically must be renegotiated and extended or replaced, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue. Similarly, without long-term power purchase agreements, BHE cannot assure that its unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements, or being required to discount rates significantly upon renewal or replacement, could adversely affect BHE's consolidated financial results. The replacement
of any existing long-term agreements depends on market conditions and other factors that may be beyond BHE's subsidiaries' control.
Each Registrant is subject to counterparty risk, which could adversely affect its financial results.
Each Registrant is subject to counterparty credit risk related to contractual payment obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom each Registrant conducts business could impair the ability of these counterparties to meet their payment obligations. Each Registrant depends on these counterparties to remit payments on a timely basis. Each Registrant monitors the creditworthiness of its wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default.
If strategies used to minimize these risk exposures are ineffective or if a Registrant's wholesale suppliers' or customers' financial condition deteriorates or they otherwise become unable to pay, it could have a significant adverse impact on the Registrant's liquidity and its financial results.
Each Registrant is subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and contractors. Each Registrant relies on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the Utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the Utilities may
be unable to purchase the commodities on terms equivalent to the terms of current contracts.
Each Registrant relies on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require the relevant Registrant to find other customers to take the energy at lower prices than the original customers committed to pay. If each Registrant's wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on its financial results.
The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses with E.ON and British Gas Trading Limited accounting for approximately 19% and 15%, respectively, of distribution revenue in 2023. AltaLink's primary source
of operating revenue is the AESO. Generally, a single customer purchases the energy from BHE's independent power projects in the U.S. pursuant to long-term power purchase agreements. For example, certain of BHE Renewables' solar and wind independent power projects sell all of their electrical production to either PG&E or SCE, respectively. Any material payment or other performance failure by the counterparties in these arrangements could have a significant adverse impact on BHE's consolidated financial results.
Inflation and changes in commodity prices and transportation fuel costs may adversely affect each Registrant's financial results.
Inflation and increases in commodity prices and transportation fuel costs may affect each Registrant by increasing both operating and capital costs. As a result
of existing rate agreements, contractual arrangements or competitive price pressures,
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each Registrant may not be able to pass the inflated costs on to its customers. If a Registrant is unable to manage cost increases or pass them on to its customers, its financial results could be adversely affected.
Physical or cyber attacks, both threatened and actual, could impact each Registrant's operations and could adversely affect its financial results.
Each Registrant relies on technology in virtually all aspects of its business. Like any business, the Registrants' technology systems are a target for computer
viruses, malicious codes, unauthorized access, phishing efforts, denial-of-service attacks and other cyber attacks and each Registrant expects to be subject to attempted attacks in the future and will continue to adapt defensive capabilities as such attacks become more sophisticated and frequent. A significant disruption or failure of its technology systems by cyber or physical attack could result in service interruptions, safety failures, security events, regulatory compliance failures, an inability to protect information and assets against unauthorized users, and other operational difficulties. Attacks perpetrated against each Registrant's systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.
Although the Registrants have taken steps intended to mitigate these risks, a significant disruption or cyber intrusion at
one or more of each Registrant's operations could adversely affect the impacted Registrant's financial results. Cyber attacks could further adversely affect each Registrant's ability to operate facilities, information technology and business systems, or compromise sensitive customer and employee information. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on each Registrant. Additionally, if each Registrant is unable to acquire, develop, implement, adopt or protect rights around new technology, it may suffer a competitive disadvantage.
Much of BHE's growth has been achieved through acquisitions, and any such acquisition may not be successful.
Much of BHE's growth has been achieved through acquisitions. Future acquisitions may range from buying
individual assets to the purchase of entire businesses. BHE will continue to investigate and pursue opportunities for future acquisitions that it believes, but cannot assure, may increase value and expand or complement existing businesses. BHE may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful.
An acquisition could cause an interruption of, or a loss of momentum in, the activities of one or more of BHE's subsidiaries. In addition, the final orders of regulatory authorities approving acquisitions may be subject to appeal by third parties. The diversion of BHE management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect BHE's combined businesses and financial results and could impair its ability to realize
the anticipated benefits of the acquisition.
BHE cannot assure that future acquisitions, if any, or any integration efforts will be successful, or that BHE's ability to repay its obligations will not be adversely affected by any future acquisitions.
Certain Registrants are subject to the unique risks associated with nuclear generation.
The ownership and operation of nuclear generating facilities, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling
and disposal of nuclear materials, compliance with and changes in regulation of nuclear generating facilities, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. Additionally, Constellation Energy, the 75% owner and operator of the facility, may respond to the occurrence of any of these or other risks in a manner that negatively impacts MidAmerican Energy, including closure of Quad Cities Station prior to the expiration of its operating license. The prolonged unavailability, or early closure, of Quad Cities Station due to operational or economic factors could have a materially adverse effect on the relevant Registrant's financial results, particularly when the cost to produce power at the generating facility is significantly less than market wholesale prices. The following are among the more
significant of these risks:
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•Operational Risk - Operations at any nuclear generating facility could degrade to the point where the generating facility would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the generating facility to operation could require significant time and expenses, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the generating facility, the generating facility could be shut down. Furthermore, a shut-down or failure at any other nuclear generating
facility could cause regulators to require a shut-down or reduced availability at Quad Cities Station.
In addition, issues relating to the disposal of nuclear waste material, including the availability, unavailability and expenses of a permanent repository for spent nuclear fuel could adversely impact operations as well as the cost and ability to decommission nuclear generating facilities, including Quad Cities Station, in the future.
•Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with applicable Atomic Energy Act regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase
in capital expenditures or result in increased operating or decommissioning costs.
•Nuclear Accident and Catastrophic Risks - Accidents and other unforeseen catastrophic events have occurred at nuclear facilities other than Quad Cities Station, both in the U.S. and elsewhere, such as at the Fukushima Daiichi nuclear generating facility in Japan as a result of the earthquake and tsunami in March 2011. The consequences of an accident or catastrophic event can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident or catastrophic event could exceed the relevant Registrant's resources, including insurance coverage.
Potential terrorist activities and the impact of military or other actions, including sanctions,
export controls and similar measures, could adversely affect each Registrant's financial results.
The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the U.S. government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Further, the potential or actual outbreak of war or other hostilities and the resulting economic sanctions on aggressor nations, as well as the existing and potential further responses from such aggressors or other countries to such sanctions and military
actions, could adversely affect global and regional economies and financial markets. For instance, a ban on imports of oil, liquefied natural gas and coal to the U.S. could contribute to increases in prices for such commodities in the U.S. and elsewhere which could adversely affect each Registrant's business. Further, each Registrant's business must be conducted in compliance with applicable economic and trade sanctions laws and regulations, including those administered and enforced by the U.S. Department of Treasury's Office of Foreign Assets Control, the U.S. Department of State, the U.S. Department of Commerce, the United Nations Security Council and other relevant governmental authorities in the U.S., Canada, the United Kingdom and European Union, which include sanctions that could potentially restrict or prohibit each Registrant's relationships with certain suppliers and customers. Political, economic, social or financial market instability or damage to or interference
with the operating assets of the Registrants, customers or suppliers, or continued increases in the price of natural gas and other petroleum commodities may result in business interruptions, lost revenue, higher costs, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect BHE's consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.
Each Registrant's business could be adversely affected by epidemics, pandemics or other outbreaks.
Each
Registrant's business could be adversely affected by epidemics, pandemics or other outbreaks generally and more specifically in the markets in which we operate, including, without limitation, if each Registrant's utility customers experience decreases in demand for their products and services or otherwise reduce their consumption of electricity or natural gas that the respective Registrant supplies, or if such Registrant experiences material payment defaults by its customers. In addition, each Registrant's results and financial condition may be adversely affected by federal, state or local and foreign legislation related to such epidemics, pandemics or other outbreaks (or other similar laws, regulations, policies, orders or other governmental or regulatory actions) that would impose a moratorium on terminating electric or natural gas utility services, including related
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assessment
of late fees, due to non-payment or other circumstances. Additionally, HomeServices' real estate businesses could experience a decline (which could be significant) in real estate transactions if potential customers elect to defer purchases in reaction to any epidemic, pandemic or other outbreak or due to general economic uncertainty such as high unemployment levels, in some or all of the real estate markets in which HomeServices operates. The government and regulators could impose other requirements on each Registrant's business that could have an adverse impact on such Registrant's financial results.
Further, epidemics, pandemics or other outbreaks could disrupt supply chains (including supply chains for energy generation, steel or transmission wire) relating to the markets each Registrant serves, which could adversely impact such Registrant's ability to generate or supply power. In
addition, such disruptions to the supply chain could delay certain construction and other capital expenditure projects, including construction and repowering of the Registrants' renewable generation projects. Such disruptions could adversely affect the impacted Registrant's future financial results.
Such declines in demand, any inability to generate or supply power or delays in capital projects could also significantly reduce cash flows at BHE's subsidiaries, thereby reducing the availability of distributions to BHE, which could adversely affect its financial results.
Cyclical fluctuations and competition in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.
The residential
real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:
•rising interest rates or unemployment rates, including a sustained high unemployment rate in the U.S.;
•periods of economic slowdown or recession in the markets served or the adverse effects on market actions as a result of epidemics, pandemics or other outbreaks;
•decreasing
home affordability;
•lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit, which may continue into future periods;
•inadequate home inventory levels;
•sources of new competition; and
•changes in applicable tax law.
BHE owns investments in foreign countries that are exposed to risks related to fluctuations in foreign currency exchange rates and increased economic, regulatory and political risks.
BHE's business operations and investments outside the U.S. increase its risk related to fluctuations
in foreign currency exchange rates, primarily the British pound and the Canadian dollar. BHE's principal reporting currency is the U.S. dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from its foreign operations changes with the fluctuations of the currency in which they transact. BHE may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in, or indexed to, U.S. dollars or a currency freely convertible into U.S. dollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect BHE's consolidated financial results.
In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where BHE has operations or is pursuing investment
opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, pandemics (including potentially in relation to COVID-19 variants), expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. BHE may not choose to or be capable of either fully insuring against or effectively hedging these risks.
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Item 1B.Unresolved
Staff Comments
Not applicable.
Item 1C.Cybersecurity
CYBER RISK MANAGEMENT AND STRATEGY
BHE and its Subsidiary Registrants recognize that maintaining processes for identifying, assessing and managing cybersecurity threats is important in dealing with their significant business risks. As such, BHE has implemented a framework for cybersecurity and cyber-related information management across its businesses. BHE's Chief Security Office ("CSO") drives collective
focus and central coordination of BHE's cyber and physical security programs. The CSO identifies the strategic framework that promotes standardization of business security policies and practices and provides direction in managing security risks. Although the CSO provides oversight, the businesses retain accountability for executing company security objectives, policies and practices within their areas of responsibility.
BHE manages cybersecurity threats through its proactive risk management program and cybersecurity awareness program. BHE's businesses are certified against the ISO 27001 standard. The standard is authored by the International Organization for Standardization ("ISO") of Geneva, Switzerland. To achieve the certification, each business must sustain an information security management system that includes a risk-based framework to identify and manage information security
risks through a continuous improvement cycle. The risks and controls identified in the system must be approved by top management and confirmed through annual internal and external ISO audits prior to certification.
In addition, BHE's compliance requirements include the North American Electric Reliability Corporation Critical Infrastructure Protection Standards, the Transportation Security Administration Pipeline Security Directives and the United Kingdom Center for the Protection of National Infrastructure Standards as applicable to each of the companies. These requirements are audited and assessed as mandated by applicable government agencies.
Each Registrant relies on technology in virtually all aspects of its business. Like any business, the Registrants' technology systems are a target for cyber attacks.
Each Registrant expects to be subject to attempted attacks in the future and will continue to adapt defensive capabilities as such attacks become more sophisticated and frequent. A significant disruption or failure of its technology systems by cyber or physical attack could result in service interruptions, safety failures, security events, regulatory compliance failures, an inability to protect information and assets against unauthorized users, and other operational difficulties. Attacks perpetrated against each Registrant's systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.
In certain circumstances, BHE relies on third-party service providers for a variety of products and services to run its information systems. This dependence exposes BHE, along with others who use these service providers, to the impact of a cyber
attack on its service providers. Cyber attacks at a third-party service provider could have a significant financial, operational, or reputational impact. BHE continuously monitors the risks associated with its service providers.
GOVERNANCE
BHE's Board of Directors has responsibility for oversight of BHE's cybersecurity risk management program.
BHE's CSO is responsible for cyber and physical security across BHE and its Subsidiary Registrants. The CSO reports directly to the Chief Executive Officer of BHE. The CSO is responsible for identifying, assessing and managing cyber risk for BHE and its Subsidiary Registrants. Management has evaluated the expertise of the CSO and determined that it possesses the knowledge and expertise necessary to oversee
BHE's cybersecurity risk management processes.
The CSO provides, at least annually, updates to the Chief Executive Officer and BHE's Board of Directors on:
•Updates on strategic cyber and physical security initiatives
•Current threat and risk landscape impacting the organization
•Security compliance with regulatory requirements
•Compliance with ISO 27001 framework
•Number and impact of incidents reported through the BHE cybersecurity incident reporting process
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A
BHE Cybersecurity Reporting Framework has been adopted so that BHE has a repeatable and timely process to identify, assess and manage any security incidents for materiality reporting. Each BHE business is required to report significant cybersecurity events to BHE. BHE's senior management reviews incident reports to determine whether a cyber incident report should be filed with the SEC.
Item 2.Properties
Each Registrant's energy properties consist of the physical assets necessary to support its electricity and natural gas businesses. Properties of the relevant Registrant's electricity businesses include electric generation, transmission and
distribution facilities, as well as coal mining assets that support certain of PacifiCorp's electric generating facilities. Properties of the relevant Registrant's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, LNG facilities, compressor stations and meter stations. The transmission and distribution assets are primarily within each Registrant's service territories. In addition to these physical assets, the Registrants have rights-of-way, mineral rights and water rights that enable each Registrant to utilize its facilities. It is the opinion of each Registrant's management that the principal depreciable properties owned by it are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the
state of Nevada, AltaLink's transmission properties and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of generation projects are pledged or encumbered to support or otherwise provide the security for the related subsidiary debt. For additional information regarding each Registrant's energy properties, refer to Item 1 of this Form 10-K and Notes 4, 5 and 22 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Nevada Power in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Sierra Pacific in Item 8 of this Form 10-K and Notes 4 and 5 of the Notes
to Consolidated Financial Statements of Eastern Energy Gas in Item 8 of this Form 10-K.
The following table summarizes Berkshire Hathaway Energy's operating electric generating facilities as of December 31, 2023:
Facility
Net
Net Owned
Energy
Capacity
Capacity
Source
Entity
Location by Significance
(MWs)
(MWs)
Wind
PacifiCorp,
MidAmerican Energy, BHE Canada, BHE Montana and BHE Renewables
PacifiCorp, MidAmerican Energy, NV Energy, BHE Canada and BHE Renewables
Nevada, Utah, Iowa, Illinois, Washington, Wyoming, Oregon, Texas, New York, Arizona and Canada
11,250
10,971
Coal
PacifiCorp,
MidAmerican Energy and NV Energy
Iowa, Wyoming, Utah, Nevada, Colorado and Montana
12,174
7,483
Solar
MidAmerican Energy, NV Energy, Northern Powergrid and BHE Renewables
California, Australia, Texas, Arizona, Iowa, Minnesota and Nevada
2,120
1,972
Hydroelectric
PacifiCorp,
MidAmerican Energy and BHE Renewables
Washington, Oregon, Idaho, Utah, Hawaii, Montana, Illinois, California and Wyoming
985
985
Nuclear
MidAmerican Energy
Illinois
1,809
452
Geothermal
PacifiCorp
and BHE Renewables
California and Utah
377
377
Total
41,239
34,764
Additionally, as of December 31, 2023, the Company has electric generating facilities that are under construction in Nevada, Wyoming
and California having total Facility Net Capacity and Net Owned Capacity of 1,284 MWs.
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As of December 31, 2023, the Company also has battery energy storage systems in Nevada having total Facility Net Capacity and Net Owned Capacity in operation of 220 MW and under construction of 100 MW.
The right to construct and operate each Registrant's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through prescription, eminent domain or similar rights. PacifiCorp,
MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas and Kern River in the U.S.; Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc in Great Britain; and AltaLink in Alberta, Canada continue to have the power of eminent domain or similar rights in each of the jurisdictions in which they operate their respective facilities, but the U.S. and Canadian utilities do not have the power of eminent domain with respect to governmental, Native American or Canadian First Nations' tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the U.S. Department of Interior, Bureau of Land Management.
With respect to real property, each of the electric transmission and distribution facilities and interstate natural
gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generating facilities, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) parcels where the interest derives from leases, easements (including prescriptive easements), rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and interstate natural gas pipelines. Each Registrant believes it has satisfactory title or interest to all of the real property making up their respective facilities in all material respects.
Item 3.Legal
Proceedings
BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, including the 2020 Wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life, and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over 500,000 acres in aggregate. Third-party reports for these wildfires indicate over 2,000 structures
destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.
In July 2022, the 2022 McKinney Fire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California located in PacifiCorp's service territory, burning over 60,000 acres. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged; 185 structures destroyed, including residences; 12 injuries; and four fatalities.
As described below, a significant number of complaints and demands alleging similar claims have been filed in Oregon and California related to the 2020 Wildfires. Amounts sought in the complaints and demands filed in Oregon and in certain demands made in California total approximately $8 billion, excluding any doubling
or trebling of damages included in the complaints and those settled. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. The complaints and demands filed in Oregon generally seek doubling of economic damages under Oregon law, which provides for such doubling in the event the wildfire is determined to have occurred as a result of recklessness, gross negligence, willfulness or malice. Additionally, those complaints and demands filed in Oregon that involve damages associated with forestry, trees or shrubbery generally seek trebling of damages claimed under Oregon law, which provides for such trebling in the event the damages are determined to have occurred by willful and intentional acts and without consent. Amounts sought for any doubling or trebling of damages are excluded from the amounts described below.
Multiple complaints have
also been filed in California for the 2022 McKinney Fire for which the damages sought have not been specified.
Investigations into the causes and origins of the Wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part II, Item 8 of this Form 10-K, and PacifiCorp, refer to Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Part II, Item 8 of this Form 10-K.
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2020 Slater Fire California and Oregon Complaints and Demands
As
described below, a significant number of complaints on behalf of plaintiffs associated with the Northern California and Southern Oregon Slater Fire ("Slater Fire") have been filed in Oregon and California. The complaints generally allege: (i) inverse condemnation; (ii) negligence; (iii) trespass; (iv) nuisance; and (v) violation of certain sections of the California Public Utilities Code and the California Health & Safety Code and request a jury trial and seek various damages, generally including: (i) economic damages; (ii) noneconomic damages; (iii) doubling of economic damages; (iv) punitive damages; (v) pre- and post-judgment interest; and (vi) attorneys' fees and other costs. Certain complaints include wrongful death claims as described below.
Hitchcock et al. v. PacifiCorp and Consolidated Slater Fire Cases
On
December 16, 2020, a complaint against PacifiCorp was filed, captioned Hitchcock et al. v. PacifiCorp, Case No. 34-2020-00290833 ("Hitchcock") in California Superior Court, Sacramento County, California by approximately 69 plaintiffs. The Hitchcock case makes similar allegations as those described above for the Slater Fire, includes a wrongful death claim for one of the two Slater Fire decedents and does not specify the amount of damages sought.
The following complaints also filed in California Superior Court, Sacramento County, California have been consolidated into the Hitchcock case: Hillman complaint filed January
29, 2021, approximately 234 plaintiffs; Franklin complaint filed February 17, 2022, approximately 43 plaintiffs; Ormsby complaint filed April 18, 2022, approximately four plaintiffs; Hodges complaint filed August 23, 2022, approximately 26 plaintiffs; Nixon complaint filed August 31, 2022, approximately two plaintiffs; Bleeg complaint filed September 1, 2022, approximately 17 plaintiffs; Sanchez complaint filed September
7, 2022, approximately 10 plaintiffs; Lemon complaint filed September 2, 2022, approximately 186 plaintiffs; and Duval complaint filed September 29, 2022, approximately 24 plaintiffs.
The complaints make similar allegations as those described above for the Slater Fire and do not specify the amount of damages sought.
In 2023, PacifiCorp settled certain claims in the consolidated Hitchcock case for $8 million representing three individual plaintiffs and one commercial timber plaintiff. In January and February 2024, PacifiCorp reached additional settlements totaling
$48 million representing 153 plaintiffs. As a result of the settlements, the Hitchcock case set for trial starting March 4, 2024 through March 29, 2024 was cancelled.
Other Slater Fire Cases
On August 17, 2023, a complaint against PacifiCorp was filed captioned Fernandezet. al v. PacifiCorp, Case No. 23CV007154 in California Superior Court, Sacramento County, California by approximately 51 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount
of damages sought.
On September 8, 2023, a subrogation complaint against PacifiCorp was filed captioned Travelers Commercial Insurance Company et al. v. PacifiCorp, Case No. 23CV008226 in California Superior Court, Sacramento County, California by 4 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought.
On September 7, 2023, a complaint against PacifiCorp was filed captioned Thomasonet. al v. PacifiCorp, Case No. 23CV008033 in California Superior Court, Sacramento County,
California, by approximately 4 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought.
On September 28, 2023, a complaint against PacifiCorp was filed captioned Bledsoeet. al v. PacifiCorp, Case No. 23CV009242 in California Superior Court, Sacramento County, California, by three plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought.
On August 10, 2022, a complaint against PacifiCorp was filed captioned Siskiyou
County v. PacifiCorp, Case No. 34-2022-00324977 by one plaintiff in California Superior Court, Sacramento County. The complaint makes similar allegations as those described above for the Slater Fire and does not specify the amount of damages sought. In April 2023, PacifiCorp received a mediation demand from Siskiyou County for approximately $6 million in damages. A jury trial is scheduled for December 2, 2024.
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On July 12, 2023, a complaint against PacifiCorp was filed captioned Susan Irene Terran et. al v. PacifiCorp, Case No. 23CV27759 in Multnomah County
Circuit Court in Oregon, by approximately six plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and seeks various damages, including economic damages of approximately $10 million based on $1 million for each of the five individual plaintiffs and $5 million for the one non-individual plaintiff. The complaint seeks noneconomic damages to be determined at trial.
Black et al. v. PacifiCorp and Consolidated Slater Fire Cases
On March 10, 2022, a complaint against PacifiCorp was filed, captioned Susan Black et al. v. PacifiCorp, Case No. 22CV08622 ("Black") in Oregon Circuit Court in Multnomah County, Oregon, by approximately
28 plaintiffs. The complaint makes similar allegations as those described above for the Slater Fire and seeks various damages, including economic damages of approximately $44 million based on $1 million for each of the 24 individual plaintiffs and $5 million for each of the four non-individual plaintiffs. The individual plaintiffs also seek unspecified noneconomic damages. A jury trial is scheduled for September 23, 2024, through November 1, 2024.
The following complaints filed in Oregon Circuit Court in Multnomah County have been consolidated into the Black case: Denny complaint filed August 31, 2022, approximately seven plaintiffs and Sparks
amended complaint filed September 7, 2022, approximately five plaintiffs. The complaints make similar allegations as those described above for the Slater Fire and each seek various damages, including economic damages of approximately $16 million based on $1 million for each of the 11 individual plaintiffs and $5 million for the one non-individual plaintiff across both the Denny and Sparks complaints. The individual plaintiffs also seek unspecified noneconomic damages.
United States – Loss and Damages to Federal Lands – Slater Fire
PacifiCorp received a notice of indebtedness from the U.S. Department of Agriculture
Forest Service ("USFS") indicating that PacifiCorp owes the U.S. $356 million for fire suppression costs, natural resource damages and burned area emergency response costs incurred by the USFS associated with the Slater fire in California. The notice further indicates that the alleged amounts owed may not include all environmental damages to which the USFS may be entitled and which the U.S. may seek to recover if further action is taken to resolve the debt. Additional charges for interest, penalties and administrative costs may also be sought associated with amounts considered overdue. In January 2024, PacifiCorp received correspondence from the U.S. Department of Justice ("USDOJ") indicating its intent to litigate the matter due to PacifiCorp not having paid the $356 million. PacifiCorp is actively cooperating with the USDOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution.
2020
Oregon Wildfires, Excluding Slater Fire
As described below, a significant number of complaints on behalf of plaintiffs associated with the 2020 Wildfires have been filed in Oregon in addition to those described above for the Slater Fire. The plaintiffs generally allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; (v) inverse condemnation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The complaints generally assert claims for: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities; (ii) damages for real
and personal property and other economic losses; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of forestry, trees and shrubbery; and (v) double the damages for the costs of litigation and reforestation. Certain complaints include wrongful death claims as described below. The plaintiffs generally demand a trial by jury and reserve their right to further amend their complaints to allege claims for punitive damages.
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Jeanyne James et al. v. PacifiCorp and Consolidated Cases
On September 30, 2020, a class action complaint against
PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885, in Multnomah County Circuit Court, Oregon ("James"). The complaint was filed by Oregon residents and businesses who sought to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain Complex, South Obenchain, 242 and Santiam Canyon fires, as well as to add claims for noneconomic damages. The amended complaint alleged that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September
7, 2020, and that PacifiCorp acted with gross negligence, among other things. The amended complaint seeks damages similar to those described above, including not less than $600 million of economic damages and in excess of $1 billion of noneconomic damages for the plaintiffs and the class.
On April 24, 2023, the jury trial for James with respect to the 17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 named plaintiffs and to the class with respect to the four wildfires. The jury found PacifiCorp's conduct grossly negligent, reckless and willful as to each plaintiff and the entire class. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic damages, $68 million
of noneconomic damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages.
In September 2023, the Multnomah County Circuit Court ordered trial dates for two consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the three damages phase trials will present evidence regarding their damages. The first of these trials addressing nine individual plaintiffs was held in January 2024 while the remaining trials are scheduled at various dates through April 2024.
In January 2024, the Multnomah County Circuit Court entered a limited judgment and money award for the June 2023 James verdict. The limited judgment awards the aforementioned
damages, as well as doubling of the economic damages and offsetting of any insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals.Under ORS 82.010, interest at a rate of 9% per annum will accrue on the judgment commencing at the date the judgment was entered until the entire money award is paid, amended or reversed by an appellate court. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict in James, including whether the case can proceed as a class action and filed a motion to stay further damages phase trials. On February 14, 2024, the Oregon Court of Appeals denied PacifiCorp's
request to stay the damages phase trials. On February 13, 2024, the 17 named plaintiffs filed a notice of cross-appeal as to the January 2024 limited judgment and money award. The appeals process and further actions could take several years.
In January 2024, the jury for the first James damages phase trial awarded nine plaintiffs $62 million of damages, including $6 million of economic damages and $56 million of noneconomic damages. After the jury verdict, the Multnomah County Circuit Court doubled the economic damages to $12 million and added $16 million of punitive damages using the 0.25 multiplier determined by the jury for the June 2023 James verdict. PacifiCorp will request that the Multnomah County Circuit Court judge offset the damage awards
by deducting insurance proceeds received by any of the nine plaintiffs. PacifiCorp intends to appeal the jury's damage awards associated with the January 2024 jury verdict once judgement is entered.
The following cases have been consolidated into the James case:
Amended Salter filed August 20, 2021, in Multnomah County Circuit Court, Oregon by approximately 97 individuals. The complaint seeks damages similar to those described above, including economic damages not to exceed $150 million and noneconomic damages not to exceed $500 million.
Amended Allen
filed September 2, 2021, in Multnomah County Circuit Court, Oregon by approximately five individuals. The Allen case seeks damages similar to those described above, including $8 million in economic and $24 million in noneconomic damages related to the Beachie Creek fire.
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Dietrich filed August 26, 2022, in Multnomah County Circuit Court, Oregon. The complaint, as amended on September 6, 2022, was filed by six Oregon residents individually and on behalf of a class defined to include residents of, business owners
in, real or personal property owners in and any other individuals physically present in specified Oregon counties as of September 7, 2020 who experienced any harm, damage or loss as a result of the Santiam Canyon, Echo Mountain Complex, 242 or South Obenchain fires. The amended complaint seeks $400 million in economic damages and $500 million in noneconomic damages. The Dietrich case is currently stayed due to plaintiffs' motion to consolidate the case into James.
Cady filed April 26,2022, in Multnomah County Circuit Court, Oregon. The Cady case was filed by 21 individuals seeking approximately $105 million in economic damages based on $5 million per each of the 21 individual plaintiffs in connection with the Echo Mountain
Complex fire. The individual plaintiffs also seek noneconomic damages to be determined at trial. A jury trial is scheduled for May 6, 2024, through June 7, 2024.
Logan filed September 2, 2022, in Multnomah County Circuit Court, Oregon. The Logan case was filed by five individuals seeking approximately $35 million in economic damages based on $5 million for each of the four individual plaintiffs and $15 million for the one non-individual plaintiff. A jury trial is scheduled for May 6, 2024, through June 7, 2024.
Bell filed
September 7, 2022, in Multnomah County Circuit Court, Oregon by 59 plaintiffs seeking $35 million in damages, including economic and noneconomic damages.
Freres Timber filed September 1, 2022, in Multnomah County Circuit Court, Oregon. The complaint, as amended on October 18, 2023, was filed by three commercial plaintiffs seeking approximately $7 million in economic damages and $2 million of punitive damages. A jury trial is scheduled for April 22, 2024, through April 30, 2024.
CW Specialty Lumber, Inc. filed
December 6, 2022, in Multnomah County Circuit Court, Oregon. The complaint, as amended on October 17, 2023, was filed by two commercial timber plaintiffs each seeking approximately $10 million in economic damages and $3 million in punitive damages. A jury trial is scheduled for April 22, 2024, through April 30, 2024.
In October 2022, the Multnomah County Circuit Court consolidated 21st Century Centennial Insurance Company, et al. v. PacifiCorp, Case No. 22CV26326 ("21st Century") and Allstate Vehicle and Property Insurance Company, et al. v. PacifiCorp, Case No. 22CV29976 ("Allstate")
into James (described above). The 21st Century and Allstate complaints were each filed in Multnomah County Circuit Court, Oregon by subrogated insurance carriers resulting from the September 2020 Santiam Canyon, Echo Mountain Complex, 242 and South Obenchain fires. The 21st Century case was filed in August 2022 by 177 insurance carriers seeking not less than $20 million in monetary damages. The Allstate case was filed in September 2022 by 11 insurance carriers seeking not less than $40 million in monetary damages. In April 2023, PacifiCorp and the subrogated insurance carriers entered into a settlement agreement. In September 2023, PacifiCorp paid $55 million in settlements associated with the subrogation claims. As a result of the settlement, the 21st Century and Allstate cases have been dismissed.
Roseburg
Resources Co et al. v. PacifiCorp and Consolidated Cases (Archie Creek Fire)
On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22CV09346 ("Roseburg") in Douglas County Circuit Court, Oregon. The complaint was filed by nine businesses and public pension plans that own or operate timberlands or possess property in Douglas County who allege damages, losses and injuries associated with their timberlands as a result of the French Creek, Archie Creek, Susan Creek and Smith Springs Road fires in Douglas County in September 2020. The complaint was amended in September 2023 and seeks economic damages of $195 million; attorney's fees, experts fees and other costs of $105 million;
and pre-judgment interest of $43 million.
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The following complaints were filed in Douglas County Circuit Court, Oregon with substantially similar allegations as those of Roseburg with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral ruling, the Douglas County Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues, along with the above-mentioned Roseburg case; the precise scope of the trial will be determined in a later order. Collectively, these eighteen cases seek economic damages of $531 million and noneconomic damages of
$102 million, inclusive of the $195 million of economic damages in the Roseburg case. Moore filed November 1, 2022, approximately 8 plaintiffs; Blodgett filed November 1, 2022, approximately 11 plaintiffs; Ellis filed November 1, 2022, approximately 10 plaintiffs; Tague filed December 5, 2022, approximately 28 plaintiffs; Long filed December 5, 2022, approximately 33 plaintiffs; Moyers filed December
5, 2022, approximately 41 plaintiffs; Meyer filed January 6, 2023, approximately 11 plaintiffs; Foster filed January 17, 2023, approximately 44 plaintiffs; Hall filed January 17, 2023, approximately 39 plaintiffs; Jones filed January 17, 2023, approximately 47 plaintiffs; Price filed January 17, 2023, approximately 39 plaintiffs; Minott filed January 17, 2023, approximately 33 plaintiffs; Webb
filed January 17, 2023, approximately 30 plaintiffs; Keith filed January 17, 2023, approximately 40 plaintiffs; Kidd filed January 24, 2023, approximately 12 plaintiffs; Parker filed January 24, 2023, approximately 16 plaintiffs; and Diaz filed January 24, 2023, approximately 14 plaintiffs.
On February 14, 2023, the Douglas County Circuit Court ordered that all plaintiffs' claims for inverse condemnation be
dismissed.
In December 2023, PacifiCorp entered into settlement agreements with 463 claimants and 10 companies with commercial timber interests associated with the Archie Creek Fire generally associated with the consolidated Roseburg cases and paid $299 million to the 463 claimants and $250 million to the 10 companies with commercial timber interests. These settlements resolve substantially all claims filed by individual plaintiffs and all claims filed by commercial timber plaintiffs associated with the consolidated Roseburg cases and claims filed by certain of the plaintiffs associated with the Beamer case described below, but do not address related damages claimed by the U.S. or Oregon Departments of Justice also described below. As a result of
the settlement, only the Lee, Beamer and insurance subrogation cases remain active; the Roseburg consolidated cases have been dismissed.
On September 1, 2022, a complaint against PacifiCorp associated with the Archie Creek Fire was filed captioned Leonard Mitchell Lee et. al v. PacifiCorp, Case No. 22CV29685 in Oregon Circuit Court in Multnomah County, Oregon by approximately five plaintiffs, seeking approximately $63 million in economic damages and $63 million in noneconomic damages and makes allegations similar to those described above.
On September
2, 2022, a complaint against PacifiCorp associated with the Archie Creek Fire was filed captioned Beameret. al v. PacifiCorp, Case No. 22CV29851 in Oregon Circuit Court in Douglas County, Oregon by approximately 36 plaintiffs, seeking more than $190 million in economic damages based on $5 million for each of the 35 individual plaintiffs and $15 million for the one non-individual plaintiff and makes allegations similar to those described above. The individual plaintiffs also seek noneconomic damages to be determined at trial. As a result of the December 2023 settlement described above, claims associated with approximately 27 plaintiffs in the Beamer case were resolved.
A group of subrogation insurers that filed complaints against PacifiCorp associated
with the Archie Creek Fire agreed to a mediator's proposal under which PacifiCorp will pay 51.75% of the total claims paid and to be paid by the carriers related to the Archie Creek Fire. In October 2022, PacifiCorp paid $24 million to the subrogation insurers. During 2023 and January 2024, PacifiCorp paid additional amounts to the subrogation insurers and ultimately expects to pay a total of $28 million to the subrogation insurers. While some of the subrogation complaints have been fully dismissed, the following remain active:
The Lexington complaint was filed against PacifiCorp by two insurers in Oregon Circuit Court in Douglas County, Oregon seeking $14 million in damages for negligence associated with the Archie Creek Fire and, as amended on February 3, 2022, make allegations similar to those described
above. The Lexington case was partially dismissed following settlement, but general judgment of dismissal has not yet been entered because certain plaintiffs remain active.
The Certain Underwriters complaint was filed against PacifiCorp by four insurers in Oregon Circuit Court in Douglas County, Oregon on April 28, 2022 by multiple insurers seeking $14 million in damages for negligence associated with the Archie Creek Fire. The Certain Underwriters case remains pending because general judgment of dismissal has not yet been entered because certain plaintiffs remain active.
The Ace American Insurance
Co. complaint was filed against PacifiCorp in Oregon Circuit Court in Douglas County, Oregon on August 25, 2022, by 15 insurers seeking approximately $24 million for negligence. The Ace American
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Insurance case was partially dismissed following settlement, but general judgment of dismissal has not yet been entered because certain plaintiffs remain active.
Ashley Andersen et al. v. PacifiCorp and Consolidated Cases
On November 16, 2021,
a complaint against PacifiCorp was filed in Multnomah County Circuit Court, Oregon, captioned Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen"). The Andersen case was filed by approximately 50 Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The Andersen case as amended on December 6, 2022 makes allegations similar to those described above and seeks economic damages of approximately $83 million and noneconomic damages of approximately $83 million. Multiple complaints have been consolidated into Andersen as described below.
The
following complaints also filed in Multnomah County Circuit Court, Oregon, have been consolidated into the Andersen case each with allegations and damages similar to those described above for the Andersen case and each seek economic damages of approximately $83 million and noneconomic damages of approximately $83 million unless otherwise noted: Klinger filed September 1, 2022, approximately 49 plaintiffs; Bowen filed September 1, 2022, approximately 47 plaintiffs; Weathers filed September 1, 2022, approximately 46 plaintiffs; Barnholdt filed September
6, 2022, approximately 26 plaintiffs; Pratt filed September 7, 2022, approximately 16 plaintiffs; Thompson filed September 7, 2022, approximately 49 plaintiffs; Cohn filed September 7, 2022, approximately 6 plaintiffs, $5 million for a wrongful death claim, $15 million in economic damages and $15 million in noneconomic damages; Sparks filed December 17, 2021 and amended on September 7, 2022, approximately 49 plaintiffs, various damages of approximately $125 million; Russie filed May
13, 2022, approximately 45 plaintiffs, various damages of approximately $125 million.
Judith O'Keefe v. PacifiCorp and Consolidated Cases
On April 23, 2021, a complaint against PacifiCorp was filed, captioned Judith O'Keefe v. PacifiCorp, Case No. 21CV15857 ("O'Keefe") in Multnomah County Circuit Court, Oregon associated with the Beachie Creek
Fire. The complaint, as amended on January 31, 2024, was filed by one individual plaintiff seeking damages similar to those described above, including approximately $1 million in economic damages and $1 million in noneconomic damages. A jury trial is scheduled for November 4, 2024, through November 29, 2024.
The following cases also associated with the Beachie Creek Fire have been consolidated into the O'Keefe case: Macy-Wyngarden filed September 1, 2022, in Multnomah County Circuit Court, Oregon, by approximately 12 plaintiffs seeking economic damages of approximately $83 million and noneconomic
damages of approximately $83 million; Bogle filed September 1, 2022, in Multnomah County Circuit Court, Oregon, by approximately 39 plaintiffs seeking economic damages of approximately $83 million and noneconomic damages of approximately $83 million; Dodge filed September 8, 2022, in Multnomah County Circuit Court, Oregon, by two plaintiffs seeking $3 million in economic damages and $3 million in noneconomic damages.
Other Cases
On October 7, 2021, a complaint against PacifiCorp was filed captioned Estate of Cathy Lynn Cooket. al v. PacifiCorp, Case No. 21CV35076 ("Cook") in Oregon Circuit Court in Multnomah County, Oregon, approximately two plaintiffs, seeking a minor amount of economic damages and approximately $40 million in noneconomic damages associated with the Beachie Creek Fire, makes allegations similar to those described above and includes wrongful death claims. On February 5, 2024, the complaint was amended to add a request for $200 million in punitive damages. The Cook case is set for trial starting July 5, 2024, through July 19, 2024.
On October 7, 2021, a
complaint against PacifiCorp was filed captioned Angela Mossoet. al v. PacifiCorp, Case No. 21CV35069 in Oregon Circuit Court in Multnomah County, Oregon, approximately four plaintiffs, seeking approximately $10 million in economic damages and $90 million in noneconomic damages associated with the Beachie Creek Fire, makes allegations similar to those described above and includes wrongful death claims. On February 5, 2024, the complaint was amended to add a request for $400 million in punitive damages. The Mosso case is set for trial starting August 5, 2024, through August 16, 2024.
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On
June 9, 2023, a complaint against PacifiCorp was filed captioned AnnamarieMilleret. al v. PacifiCorp, Case No. 23CV23104 in Oregon Circuit Court in Multnomah County, Oregon, approximately 10 plaintiffs, seeking approximately $42 million in economic damages and $42 million in noneconomic damages associated with the Echo Mountain Fire and makes allegations similar to those described above.
On November 7, 2023, a complaint against PacifiCorp was filed captioned Cooper Mountain WineryLLC v. PacifiCorp, Case No. 23CV47202 in Oregon Circuit Court in Washington
County, Oregon, seeking approximately $750,000 in economic damages associated with multiple fires and makes allegations similar to those described above.
On January 18, 2024, a complaint against PacifiCorp was filed captioned Sokol Blosser, Ltd.et. al v. PacifiCorp, Case No. 24CV03044 in Oregon Circuit Court in Multnomah County, Oregon, approximately nine plaintiffs, seeking approximately $20 million in economic damages associated with multiple fires and makes allegations similar to those described above.
On July 14, 2023, a complaint against PacifiCorp was filed captioned Elk Cove Vineyards,
Inc. v. PacifiCorp, Case No. 23CV28258 in Oregon Circuit Court in Yamhill County, Oregon, one plaintiff, seeking approximately $3 million in economic damages associated with multiple fires and makes allegations similar to those described above.
On July 14, 2023, a complaint against PacifiCorp was filed captioned Retraite, LLC, et. al v. PacifiCorp, Case No. 23CV28213 in Oregon Circuit Court in Polk County, Oregon, approximately four plaintiffs, seeking approximately $4 million in economic damages associated with multiple fires and makes allegations similar to those described above.
On July 14, 2023, a complaint against PacifiCorp was
filed captioned Brigadoon Vineyards, LLC v. PacifiCorp, Case No. 23CV28149 in Oregon Circuit Court in Lane County, Oregon seeking approximately $100,000 in economic damages associated with multiple fires and makes allegations similar to those described above.
On July 24, 2023, a complaint against PacifiCorp was filed captioned Willamette Valley Vineyards Inc v. PacifiCorp, Case No. 23CV29519 in Oregon Circuit Court in Marion County, Oregon seeking approximately $3 million in economic damages associated with multiple fires and makes allegations similar to those described above.
On September 1, 2022, a complaint against PacifiCorp
was filed captioned Stroh Coastal Holdings LLC, v. PacifiCorp, Case No. 22CV29695 in Oregon Circuit Court in Multnomah County, Oregon, one plaintiff, seeking $1 million in economic damages associated with the Pike Road Fire and makes allegations similar to those described above.
In January 2024, PacifiCorp settled various claims for $3 million with approximately 14 plaintiffs associated with various 2020 Wildfire complaints in Oregon.
United States and State of Oregon – Loss and Damages to Federal and State Lands – Oregon Fires
PacifiCorp received correspondence from the USDOJ, representing the U.S. Department of the Interior, Bureau of Land Management, Bureau of Indian
Affairs, Department of Agriculture and Forest Service, regarding the potential recovery of certain costs and damages alleged to have occurred to federal lands from the September 2020 Archie Creek and Susan Creek fires. The USDOJ estimates for mediation purposes only the costs and damages relating to reforestation, damaged timber and improvements, coordination with hydropower license, suppression costs and other assessment, cleanup and rehabilitation costs and damages at approximately $625 million. The amounts alleged for natural resource damage from these fires do not include intangible environmental and natural resource damages that the U.S. could potentially seek to recover if this matter was fully litigated, nor do they include multipliers which the agencies are allegedly entitled to collect under pertinent federal regulations, under which, for example, minimum damages for trespass to timber managed by the U.S. Department of Interior are twice the fair market value
of the resource at the time of the trespass, or three times if the violation was willful.
PacifiCorp also received correspondence from the Oregon Department of Justice ("ODOJ"), representing the State of Oregon, regarding the potential recovery of losses and damages to state lands from the Archie Creek and Susan Creek fires. The ODOJ estimates for mediation purposes only losses and damages relating to the sheltering of, and assistance to, affected Oregonians, fire control and extinguishment costs, 39 acres of Oregon forestland, losses and damages at the Rock Creek Fish Hatchery, road and highway damages, and other costs, at approximately $109 million.
On October 12, 2023 and December 21, 2023, the
Oregon Department of Forestry sent demand notices for fire suppression costs totaling $2 million for three separate ignition points associated with the 2020 Wildfires.
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PacifiCorp is actively cooperating with both the USDOJ and ODOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution.
2022 McKinney Fire
Numerous complaints associated with the 2022 McKinney Fire have been filed in California Superior Court, Sacramento County, California on behalf of over 300 plaintiffs, including multiple insurers, as described below.
The complaints generally allege: (i) inverse condemnation; (ii) negligence; (iii) trespass; (iv) nuisance; and (v) violation of certain sections of the California Public Utilities Code and the California Health & Safety Code, as well as, in limited cases, wrongful death claims. The complaints do not specify the amount of damages sought.
On August 16, 2022, a complaint against PacifiCorp was filed, captioned Bridges et. al v PacifiCorp, Case No. 34-2022-00325257, in California Superior Court, Sacramento County, California ("Bridges") by approximately five plaintiffs. The following complaints were filed and subsequently consolidated into Bridges: Cogan
filed August 23, 2022, approximately 12 plaintiffs, including a wrongful death claim; Shoopman filed August 26, 2022, approximately 61 plaintiffs, including a wrongful death claim; Lowe filed September 28, 2022, approximately two plaintiffs; Fraser filed November 9, 2022, approximately 180 plaintiffs; Muelrath filed January 18, 2023, approximately two plaintiffs; California Fair Plan Association, filed March 3, 2023, approximately 18 subrogation
insurers; Corrales, filed April 6, 2023, approximately 30 plaintiffs; Murieen, filed April 20, 2023, approximately seven plaintiffs; Hickey, filed May 9, 2023, approximately five plaintiffs; and Volckhausen, filed May 9, 2023, one plaintiff; Huber, filed August 21, 2023, approximately three plaintiffs, including a wrongful death claim; CSAA filed December 21, 2023, one subrogation insurer.
In
November 2023, PacifiCorp settled the Muelrath claims and the trial date was vacated.
On December 21, 2022, a complaint against PacifiCorp was filed, captioned Siskiyou County v. PacifiCorp, Case No. 2:22‑cv‑02278‑DMC, in the U.S. District Court for the Eastern District of California ("Siskiyou County") on behalf of a single plaintiff. A jury trial is scheduled for September 22, 2025.
On January 8, 2024, a complaint against PacifiCorp was filed, captioned Insurance Company
of Hannover v. PacifiCorp, Case No. 24CV000183, in Sacramento Superior Court, California, by one subrogation plaintiff.
BERKSHIRE HATHAWAY ENERGY
HomeServices, a subsidiary of Berkshire Hathaway Energy, is currently defending against eleven antitrust cases, all in federal district courts. In each case, plaintiffs claim HomeServices (or, in one instance, Berkshire Hathaway) and certain of its subsidiaries conspired with co-defendants to artificially inflate real estate commissions by following and enforcing multiple listing service ("MLS") rules that require listing agents to offer a commission split to cooperating agents in order for the property to appear on the MLS ("Cooperative Compensation Rule"). None of the complaints specify damages sought. However, two cases
allege Texas state law deceptive trade practices claims, for which plaintiffs have provided written notice of the damages sought totaling approximately $9 billion by separate notice as required by Texas law. The cases are captioned as follows.
In April 2019, the Burnett (formerly Sitzer) et al. v. HomeServices of America, Inc. et al., Case No. 19CV332, complaint was filed in the U.S. District Court for the Western District of Missouri (the "Burnett case"). This lawsuit, which was certified as a class in April 2022, was originally brought on behalf of named plaintiffs Joshua Sitzer and Amy Winger against the National Association of Realtors ("NAR"), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., RE/MAX, LLC, and Keller Williams Realty, Inc.
HSF Affiliates, LLC and BHH Affiliates, LLC, each a subsidiary of HomeServices, were subsequently added as defendants. Rhonda Burnett became a lead class plaintiff in June 2021. The jury trial commenced on October 16, 2023, and the jury returned a verdict for the plaintiffs on October 31, 2023, finding that the named defendants participated in a conspiracy to follow and enforce the Cooperative Compensation Rule, which conspiracy had the purpose or effect of raising, inflating, or stabilizing broker commission rates paid by home sellers. The jury further found that the class plaintiffs had proved damages in the amount of $1.8 billion. Joint and several liability applies for the co-defendants. Federal law authorizes trebling of damages and the award of pre-judgment interest and attorney fees. Prior to the trial, Anywhere Real Estate (formerly Realogy Holdings Corp.) and
RE/MAX, LLC reached settlement agreements with the plaintiffs, which have not yet been approved by the court. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri. HomeServices intends to vigorously appeal on multiple grounds the jury's findings and damage award in the Burnett case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.
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In March 2019, the Christopher Moehrl v. National Association of Realtors, et al. & Sawbill Strategic, Inc. v. HomeServices of America, Inc. et al., Case Nos. 19CV01610 and 19CV2544
(together "Moehrl") complaint was filed in the U.S. District Court for the Northern District of Illinois. This certified class action lawsuit was brought on behalf of named plaintiff Christopher Moehrl against the NAR, Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC, Long & Foster Companies, Inc. (also a HomeServices subsidiary), RE/MAX, LLC and Keller Williams Realty, Inc.
In December 2020, the Nosalek (formerly Bauman) v. HomeServices of America, Inc. et al., Case No. 20CV1244, complaint was filed in the U.S. District Court for the District of Massachusetts. This putative class action lawsuit was originally filed on behalf of named plaintiffs Gary Bauman, Mary Jane Bauman, and Jennifer Nosalek against the MLS Property Information Network, Inc. (MassPIN),
Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., BHH Affiliates, LLC, HSF Affiliates, LLC, RE/MAX, LLC, Keller Williams Realty, Inc. and additional named defendants. In October 2021, the Baumans voluntarily dismissed themselves from the case, removing them as class representatives.
In January 2021, the Batton (formerly Leeder) v. HomeServices of America, Inc. et al., Case No. 21CV00430, complaint was filed in the U.S. District Court for the Northern District of Illinois. This putative class action lawsuit was originally brought on behalf of former named plaintiff Judah Leeder against the NAR, HomeServices of America, Inc. HSF Affiliates, LLC, BHH Affiliates, LLC, Long & Foster Companies, Inc. (also a HomeServices subsidiary), Anywhere Real Estate (formerly Realogy Holdings Corp.), RE/MAX, LLC and
Keller Williams Realty, Inc. Mya Batton replaced Leeder as class representative in July 2022. This case has been brought on behalf of a putative class of real estate buyers; all other referenced cases have been brought on behalf of real estate sellers. On February 20, 2024, the court entered an order dismissing HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC and Long & Foster Companies, Inc. from the case without prejudice.
In November 2023, the QJ v. HomeServices of America, Inc. et al., Case No. 23CV01013, complaint was filed in the U.S. District Court for the Eastern District of Texas. This putative class action lawsuit was brought on behalf of named plaintiff QJ Team, LLC against the Texas Association of Realtors, Inc., HomeServices of America, Inc., ABA Management,
L.L.C. (a HomeServices subsidiary), Ebby Halliday Real Estate, LLC (a HomeServices subsidiary), Keller Williams Realty, Inc. and additional named defendants.
In December 2023, the Martin v. HomeServices of America, Inc. et al., Case No. 23CV01104, complaint was filed in the U.S. District Court for the Eastern District of Texas. This putative class action lawsuit was brought on behalf of named plaintiff Julie Martin against the Texas Association of Realtors, Inc., HomeServices of America, Inc., ABA Management, L.L.C., Ebby Halliday Real Estate, LLC, Keller Williams Realty, Inc. and additional named defendants.
In December 2023, the Umpa v. HomeServices of America, Inc. et al., Case No. 23CV00945, complaint was
filed in the U.S. District Court for the Western District of Missouri. This putative class action lawsuit was brought on behalf of named plaintiff Daniel Umpa against the NAR, HomeServices of America, Inc., BHH Affiliates, LLC, HSF Affiliates, LLC, Long & Foster Companies, Inc., Keller Williams Realty, Inc. and additional named defendants.
In January 2024, the Masiello v. Roy H. Long Realty, Inc. d/b/a Long Realty et al., Case No. 24CV00045, complaint was filed in the U.S. District Court for the District of Arizona. This putative class action lawsuit was brought on behalf of named plaintiff Joseph Masiello against the Arizona Association of Realtors, Roy H. Long Realty, Inc. d/b/a Long Realty (a HomeServices of America, Inc. subsidiary) and additional named defendants.
In
January 2024, the Fierro v. BHH Affiliates, LLC, et al., Case No. 24CV00449, complaint was filed in the U.S. District Court for the Central District of California. This putative class action lawsuit was brought on behalf of named plaintiffs Gael Fierro and Patrick Thurber against the NAR, Berkshire Hathaway Inc., BHH Affiliates, LLC and additional named defendants.
In January 2024, the Whaley v. Berkshire Hathaway HomeServices Nevada Properties et al., Case No. 24CV00105, amended complaint was filed in the U.S. District Court for the District of Nevada. This putative class action lawsuit was brought on behalf of named plaintiff Nathaniel Whaley against the NAR, Berkshire Hathaway HomeServices Nevada Properties (a HomeServices of America, Inc. subsidiary) and additional named defendants.
In
February 2024, the Jensen v. HomeServices of America, Inc., et al., Case No. 24CV00109, complaint was filed in the U.S. District Court for the District of Utah. The putative class action lawsuit was brought on behalf of named plaintiff Dalton Jensen against the NAR, Anywhere Real Estate, Inc., HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC and additional named defendants.
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In February 2024, the Boykin v. BHH Affiliates, LLC, et al., Case No. 24CV00340, compliant was filed in the U.S. District Court for the District of Nevada. This putative class action lawsuit was brought on behalf of named plaintiff Angela
Boykin against the NAR, BHH Affiliates, LLC and additional named defendants.
Item 4.Mine Safety Disclosures
Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.
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PART
II
Item 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
BERKSHIRE HATHAWAY ENERGY
BHE's common stock is beneficially owned by Berkshire Hathaway and family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. BHE has not declared or paid any cash dividends
to its common shareholders since Berkshire Hathaway acquired an equity ownership interest in BHE in March 2000 and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.
PACIFICORP
All common stock of PacifiCorp is held by its parent company, PPW Holdings LLC, which is a direct, wholly owned subsidiary of BHE. PacifiCorp declared and paid dividends to PPW Holdings LLC of $300 million in 2023, $100 million in 2022 and $150 million in 2021.
MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY
All common stock of MidAmerican Energy is held by its parent company, MHC, which is a direct, wholly
owned subsidiary of MidAmerican Funding. MidAmerican Funding is an Iowa limited liability company whose membership interest is held solely by BHE. MidAmerican Funding declared and paid cash distributions to BHE of $425 million in 2024, $1,025 million in 2023, $69 million in 2022 and $— million in 2021. MidAmerican Energy declared and paid cash dividends to MHC totaling $425 million in 2024, $1,025 million in 2023, $275 million in 2022 and $— million in 2021.
NEVADA POWER
All common stock of Nevada Power is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Nevada Power declared and paid dividends to NV Energy of $50 million in 2023, $— million in 2022 and $213 million in 2021.
SIERRA
PACIFIC
All common stock of Sierra Pacific is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Sierra Pacific declared and paid dividends to NV Energy of $150 million in 2024, $100 million in 2023, $70 million in 2022 and $— million in 2021.
EASTERN ENERGY GAS
Eastern Energy Gas is a Virginia limited liability corporation whose membership interest is held solely by its parent company, BHE GT&S, which is an indirect, wholly owned subsidiary of BHE. Eastern Energy Gas declared and paid dividends to BHE GT&S of $332 million in 2023, $— million in 2022 and $— million in 2021.
EGTS
All
common stock of EGTS is held by its parent company, Eastern Energy Gas, which is an indirect, wholly owned subsidiary of BHE. EGTS declared and paid dividends to Eastern Energy Gas of $158 million in 2023, $215 million million in 2022 and $18 million in 2021.
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Item 6.[Reserved]
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
Berkshire
Hathaway Energy Company and its subsidiaries
Berkshire Hathaway Energy Company and its subsidiaries
Consolidated Financial Section
105
Item 7.Management's
Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with the Company's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform
to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other corporate entities, corporate functions and intersegment eliminations. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been reclassified to reflect this activity in BHE Renewables.
Results of Operations
Overview
Operating
revenue and earnings on common shares for the Company's reportable segments for the years ended December 31 are summarized as follows (in millions):
2023
2022
Change
2022
2021
Change
Operating
revenue:
PacifiCorp
$
5,936
$
5,679
$
257
5
%
$
5,679
$
5,296
$
383
7
%
MidAmerican
Funding
3,393
4,025
(632)
(16)
4,025
3,547
478
13
NV Energy
4,523
3,824
699
18
3,824
3,107
717
23
Northern
Powergrid
1,303
1,365
(62)
(5)
1,365
1,188
177
15
BHE Pipeline Group
3,774
3,844
(70)
(2)
3,844
3,544
300
8
BHE
Transmission
799
732
67
9
732
731
1
—
BHE Renewables
1,710
1,737
(27)
(2)
1,737
1,661
76
5
HomeServices
4,322
5,268
(946)
(18)
5,268
6,215
(947)
(15)
BHE
and Other
(158)
(137)
(21)
15
(137)
(139)
2
(1)
Total operating revenue
$
25,602
$
26,337
$
(735)
(3)
%
$
26,337
$
25,150
$
1,187
5
%
Earnings
on common shares:
PacifiCorp
$
(468)
$
921
$
(1,389)
(151)
%
$
921
$
889
$
32
4
%
MidAmerican
Funding
980
947
33
3
947
883
64
7
NV Energy
394
427
(33)
(8)
427
439
(12)
(3)
Northern
Powergrid
165
385
(220)
(57)
385
247
138
56
BHE Pipeline Group
1,079
1,040
39
4
1,040
807
233
29
BHE
Transmission
246
247
(1)
—
247
247
—
—
BHE Renewables(1)
518
643
(125)
(19)
643
459
184
40
HomeServices
13
100
(87)
(87)
100
387
(287)
(74)
BHE
and Other
59
(2,035)
2,094
*
(2,035)
1,311
(3,346)
*
Total earnings on common shares
$
2,986
$
2,675
$
311
12
%
$
2,675
$
5,669
$
(2,994)
(53)
%
(1)Includes
the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
* Not meaningful.
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Earnings on common shares increased $311 million for 2023 compared to 2022. Included in these results was a pre-tax gain in 2023 of $639 million ($505 million after-tax) compared to a pre-tax loss in 2022 of $1,950 million ($1,540 million after-tax) related to the Company's investment in BYD Company Limited ("BYD"). Excluding the impact of this item, adjusted earnings on common shares in 2023 was $2,481 million, a decrease of $1,734 million, or 41%, compared
to adjusted earnings on common shares in 2022 of $4,215 million.
The increase in earnings on common shares for 2023 compared to 2022 was primarily due to:
•The Utilities' earnings decreased $1,389 million largely due to an increase in wildfire loss accruals, net of expected insurance recoveries, of $1,613 million, higher operations and maintenance expense, increased interest expense and lower electric utility margin. These items were offset by lower depreciation and amortization expense, higher allowances for equity and borrowed funds used during construction, increased interest and dividend income and favorable changes in the cash surrender value of corporate-owned life insurance policies. Electric retail customer volumes decreased 0.8% for 2023 compared to 2022, primarily due to the unfavorable impact of weather, partially
offset by higher customer usage and an increase in the average number of customers;
•Northern Powergrid's earnings decreased $220 million, primarily due to the write-off of gas exploration costs of $92 million, unfavorable operating performance at CE Gas, higher deferred income tax expense, including amounts related to the enactment of a new Energy Profits Levy income tax at the CE Gas business, and increased non-service benefit plan costs. Units distributed declined 3.3% due to the unfavorable impact of weather and lower customer usage;
•BHE Pipeline Group's earnings increased $39 million, primarily due to the impact of a general rate case at Northern Natural Gas and higher earnings from Cove Point, primarily due to the acquisition of DEI's 50% limited partner interests in Cove Point on
September 1, 2023, partially offset by higher operations and maintenance expense;
•BHE Renewables' earnings decreased $125 million, primarily due to lower earnings from wind tax equity investments, mainly due to lower PTCs, lower earnings from the retail energy service business, largely due to unfavorable changes in unrealized positions on derivative contracts, and lower operating revenue from owned renewable energy projects, partially offset by favorable derivative contract valuations and gains on the extinguishment of debt at owned wind projects;
•HomeServices' earnings decreased $87 million, primarily due to lower earnings from brokerage, settlement and mortgage services, reflecting the impact of rising interest rates and a corresponding decline in home sales; and
•BHE
and Other's earnings increased $2,094 million, primarily due to the $2,045 million favorable comparative change in fair value related to the Company's investment in BYD.
Earnings on common shares decreased $2,994 million for 2022 compared to 2021. Included in these results was a pre-tax loss in 2022 of $1,950 million ($1,540 million after-tax) compared to a pre-tax gain in 2021 of $1,796 million ($1,777 million after-tax) related to the Company's investment in BYD. Excluding the impact of this item, adjusted earnings on common shares in 2022 was $4,215 million, an increase of $323 million, or 8%, compared to adjusted earnings on common shares in 2021 of $3,892 million.
The decrease in earnings on common shares for 2022 compared to 2021 was primarily due to:
•The Utilities' earnings
increased $84 million reflecting higher electric utility margin and higher PTCs recognized of $157 million, partially offset by higher operations and maintenance expense and higher depreciation and amortization expense. Electric retail customer volumes increased 2.4% for 2022 compared to 2021, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather;
•Northern Powergrid's earnings increased $138 million, primarily due to a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023 and favorable earnings from new gas and solar projects, partially offset by $41 million from the stronger U.S. dollar;
•BHE Pipeline
Group's earnings increased $233 million due to higher earnings at BHE GT&S from the impacts of the EGTS general rate case, favorable income tax adjustments, lower operations and maintenance expense and higher margin from non-regulated activities;
•BHE Renewables' earnings increased $184 million, primarily due to higher operating revenue from owned renewable energy projects and higher earnings from wind tax equity investments, mainly due to the unfavorable impacts from the February 2021 polar vortex weather event;
107
•HomeServices' earnings decreased $287 million, reflecting lower earnings from brokerage and settlement services largely attributable to a decrease in closed
units at existing companies and lower earnings from mortgage services mainly from a decrease in funded volumes; and
•BHE and Other's earnings decreased $3,346 million, primarily due to the $3,317 million unfavorable comparative change in fair value related to the Company's investment in BYD.
Reportable Segment Results
PacifiCorp
Operating revenue increased $257 million for 2023 compared to 2022, primarily due to higher retail revenues of $350 million, partially offset by lower wholesale and other revenue of $93 million. Retail revenue increased primarily due to price impacts of $389 million from higher average rates, largely due to tariff changes and
sales mix, partially offset by $39 million from lower retail volumes. Retail customer volumes decreased 0.8%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers. Wholesale and other revenue decreased mainly due to lower wholesale volumes, partially offset by higher average wholesale prices.
Earnings decreased $1,389 million for 2023 compared to 2022, primarily due to an increase in wildfire loss accruals, net of expected insurance recoveries, of $1,613 million, higher operations and maintenance expense of $304 million, increased interest expense of $115 million due to debt issuances in December 2022 and May 2023, unfavorable property and other taxes of $20 million and lower utility margin of $10 million. These items were partially offset by higher allowances for equity and borrowed funds used
during construction of $112 million, increased interest and dividend income of $54 million, a favorable income tax benefit from valuation changes on state net operating loss carryforwards of $31 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $10 million. Operations and maintenance expense increased due to increased wildfire mitigation and vegetation management costs, higher insurance premiums, increased general and plant maintenance costs and higher legal expenses. Utility margin decreased primarily due to higher purchased power costs and lower wholesale and retail volumes, partially offset by higher retail rates, favorable deferred net power costs, lower thermal generation costs and higher average wholesale prices.
Operating revenue increased $383 million for 2022 compared to 2021, primarily due to higher retail revenue of $263
million, and higher wholesale and other revenue of $120 million, largely from higher average wholesale prices. Retail revenue increased primarily due to price impacts of $166 million from higher average rates largely due to sales mix and tariff changes and $97 million from higher retail volumes. Retail customer volumes increased 1.6%, primarily due to the favorable impact of weather and an increase in the average number of customers, partially offset by lower customer usage.
Earnings increased $32 million for 2022 compared to 2021, primarily due to higher utility margin of $235 million and higher allowances for equity and borrowed funds used during construction of $28 million, partially offset by higher operations and maintenance expense of $196 million, higher depreciation and amortization expense of $32 million, mainly from additional assets placed in-service, unfavorable changes in
the cash surrender value of corporate-owned life insurance policies and an unfavorable income tax benefit. Utility margin increased primarily due to favorable deferred net power costs, higher retail rates and volumes and higher average wholesale prices, partially offset by higher purchased power and thermal generation costs. Operations and maintenance expense increased mainly due to an increase in wildfire loss accruals, net of expected insurance recoveries of $64 million and higher general and plant maintenance costs. The unfavorable income tax benefit was largely due to state income tax impacts, partially offset by higher PTCs recognized of $21 million.
MidAmerican Funding
Operating revenue decreased $632 million for 2023 compared to 2022, primarily due to lower natural gas operating revenue of $317 million
and lower electric operating revenue of $315 million. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $311 million (fully offset in cost of sales) and the unfavorable impact of weather of $19 million, partially offset by higher average rates of $11 million. Electric operating revenue decreased due to lower wholesale and other revenue of $299 million and lower retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale prices of $203 million and lower wholesale volumes of $94 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $29 million (fully offset in expense, primarily cost of sales), partially offset by $7 million from higher retail volumes and price impacts of $6 million from changes in sales mix. Electric retail customer volumes increased 1.3%, primarily
due to higher customer usage, partially offset by the unfavorable impact of weather.
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Earnings increased $33 million for 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $260 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $39 million, partially offset by lower electric utility margin of $137 million, an unfavorable income tax benefit from the effects of ratemaking of $40 million and lower PTCs recognized of $29 million, increased interest expense of $29 million due to a September 2023 debt issuance and higher operations and maintenance expense of $23 million. Depreciation and amortization
expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Electric utility margin decreased primarily due to lower wholesale and retail revenues, partially offset by lower purchased power and thermal generation costs. Operations and maintenance expense increased mainly due to higher administrative and other costs, increased general and plant maintenance costs and higher property insurance costs.
Operating revenue increased $478 million for 2022 compared to 2021, primarily due to higher electric operating revenue of $459 million and higher natural gas operating revenue of $27 million. Electric operating revenue increased due to higher wholesale and other revenue of $261 million and higher retail revenue of $198 million. Electric wholesale and other revenue increased mainly due to higher
average wholesale prices of $229 million and higher wholesale volumes of $36 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $134 million (fully offset in expense, primarily cost of sales) and higher customer volumes of $62 million. Electric retail customer volumes increased 4.3%, primarily due to higher customer usage and the favorable impact of weather. Natural gas operating revenue increased due to higher customer usage of $9 million, the favorable impact of weather of $9 million and the impacts of tax reform of $5 million.
Earnings increased $64 million for 2022 compared to 2021, primarily due to higher electric utility margin of $319 million, a favorable income tax benefit and higher natural gas utility margin of $25 million, partially offset by higher depreciation and amortization expense of $254 million,
higher operations and maintenance expense of $53 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher non-service benefit plan costs of $17 million. Electric utility margin increased primarily due to higher wholesale and retail revenues, partially offset by higher purchased power and thermal generation costs. The favorable income tax benefit was mainly due to higher PTCs recognized of $136 million, partially offset by state income tax impacts. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service. Operations and maintenance expense increased due to higher general and plant maintenance costs.
NV Energy
Operating revenue increased $699 million for 2023
compared to 2022, primarily due to higher electric operating revenue of $626 million and higher natural gas operating revenue of $69 million largely from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $649 million and increased base tariff general rates of $39 million at Sierra Pacific, partially offset by lower customer volumes of $44 million and lower regulatory-related revenue deferrals of $34 million. Electric retail customer volumes decreased 2.6%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers.
Earnings decreased $33 million for 2023 compared to 2022, primarily due to higher depreciation and amortization expense of $49 million
largely due to additional assets placed in-service, increased interest expense of $38 million due to higher outstanding long-term debt balances and higher average interest rates, higher operations and maintenance expense of $28 million and lower electric utility margin of $23 million, partially offset by higher allowances for equity and borrowed funds of $38 million, increased interest and dividend income of $30 million, mainly from carrying charges on higher deferred energy balances, and favorable changes in the cash surrender value of corporate-owned life insurance policies of $12 million. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs, partially offset by lower earnings sharing accruals at Nevada Power. Electric utility margin decreased primarily due to lower retail customer volumes and lower regulatory-related revenue deferrals, partially offset by higher base tariff
general rates at Sierra Pacific.
Operating revenue increased $717 million for 2022 compared to 2021, primarily due to higher electric operating revenue of $668 million and higher natural gas operating revenue of $51 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of $636 million, higher regulatory-related revenue deferrals of $15 million and higher customer volumes of $6 million. Electric retail customer volumes increased 2.2%, primarily due to an increase in the average number of customers, partially offset by the unfavorable impact of weather.
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Earnings
decreased $12 million for 2022 compared to 2021, primarily due to higher operations and maintenance expense of $24 million, higher depreciation and amortization expense of $17 million, higher interest expense of $15 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher non-service benefit plan costs of $11 million, partially offset by higher interest and dividend income of $36 million from carrying charges on regulatory balances and higher electric utility margin of $32 million. Operations and maintenance expense increased mainly due to higher general and plant maintenance costs and an unfavorable change in earnings sharing at the Nevada Utilities. Depreciation and amortization expense increased mainly from additional assets placed in-service. Electric utility margin increased mainly due to higher regulatory-related revenue deferrals of $15 million and higher electric retail customer volumes.
Northern
Powergrid
Operating revenue decreased $62 million for 2023 compared to 2022, primarily due to lower revenue at CE Gas of $48 million and lower distribution revenue of $48 million, partially offset by higher non-regulated contracting revenue of $18 million and $11 million from the weaker U.S. dollar. CE Gas revenue decreased due to lower gas production volumes and prices from a gas project that commenced commercial operations in March 2022, partially offset by a solar project that commenced commercial operations in July 2022. Distribution revenue decreased primarily due to lower recoveries of Supplier of Last Resort payments of $47 million (largely offset in cost of sales) and a 3.3% decline in units distributed of $9 million, largely due to the unfavorable impact of weather and lower customer usage, partially offset by higher tariff rates of $10 million.
Earnings
decreased $220 million for 2023 compared to 2022, primarily due to the write-off of gas exploration costs of $92 million, unfavorable operating performance at CE Gas of $61 million, higher deferred income tax expense, including amounts related to the enactment of a new Energy Profits Levy income tax at the CE Gas business, increased non-service benefit plan costs of $35 million and higher distribution-related operating and depreciation expenses of $18 million, partially offset by lower interest expense of $14 million. The unfavorable operating performance at CE Gas was largely due to lower gas production volumes and prices from a gas project that commenced commercial operations in March 2022, partially offset by a solar project that commenced commercial operations in July 2022.
Operating revenue increased $177 million for 2022 compared to 2021, primarily due to higher distribution revenue
of $167 million and higher revenue at CE Gas of $158 million, due to a gas project that commenced commercial operation in March 2022 and a solar project that commenced commercial operation in July 2022, partially offset by $155 million from the stronger U.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier of Last Resort payments of $135 million (largely offset in cost of sales) and higher tariff rates of $78 million, partially offset by a 4.6% decline in units distributed of $36 million.
Earnings increased $138 million for 2022 compared to 2021, primarily due to a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, higher distribution tariff rates and improved earnings of $47 million from
the new gas and solar projects, partially offset by $41 million from the stronger U.S. dollar, lower units distributed and higher distribution-related operating and depreciation expenses of $25 million.
BHE Pipeline Group
Operating revenue decreased $70 million for 2023 compared to 2022, primarily due to lower operating revenue of $164 million at BHE GT&S and $29 million at Kern River, largely due to a decline in transportation revenue from lower rates and volumes, partially offset by higher operating revenue of $107 million at Northern Natural Gas. The decrease in operating revenue at BHE GT&S was primarily due to lower non-regulated revenue of $229 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices and lower volumes at EGTS primarily from the expiration
of the Appalachian Gateway Project contracts in August 2022 of $22 million, partially offset by an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $49 million, an increase in variable revenue related to natural gas storage park and loan activity of $17 million at EGTS and higher gas sales of $15 million at EGTS from operational and system balancing activities. The increase in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case of $117 million and higher transportation revenue of $57 million from higher rates, partially offset by lower gas sales of $74 million (largely offset in cost of sales) from system balancing activities.
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Earnings
increased $39 million for 2023 compared to 2022, primarily due to higher earnings of $74 million at Northern Natural Gas, partially offset by lower earnings of $25 million at Kern River, largely due to lower transportation revenue, and lower earnings of $19 million at BHE GT&S. The increase at Northern Natural Gas was primarily due to the impacts of the general rate case of $79 million and higher transportation revenue, partially offset by higher operations and maintenance expense of $34 million, an increase in depreciation and amortization expense of $16 million and unfavorable margin on gas sales from system balancing activities of $16 million. The decrease at BHE GT&S was primarily due to increased cost of gas of $72 million from system balancing activities at EGTS and the unfavorable revaluation of volumes retained at EGTS due to lower natural gas prices and higher operations and maintenance expense of $52 million, partially offset by higher earnings from
Cove Point of $42 million, primarily due to the acquisition of DEI's 50% limited partner interests in Cove Point on September 1, 2023, and a $40 million earnings impact from the rate case settlement at EGTS in 2022. Operations and maintenance expense increased at BHE GT&S mainly due to higher compensation costs and higher technology and related charges.
Operating revenue increased $300 million for 2022 compared to 2021, primarily due to higher operating revenue of $242 million at BHE GT&S and $47 million at Northern Natural Gas. The increase in operating revenue at BHE GT&S was primarily due to higher non-regulated revenue of $109 million (largely offset in cost of sales) from favorable commodity prices, an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of
$101 million and higher LNG revenue of $56 million at Cove Point, largely from favorable variable revenue, partially offset by lower gas sales of $49 million at EGTS from system balancing activities. The increase in operating revenue at Northern Natural Gas was mainly due to higher transportation revenue of $63 million offset by lower gas sales of $14 million from system balancing activities. The variances in transportation revenue and gas sales included favorable impacts recognized of $49 million and $77 million, respectively, from the February 2021 polar vortex weather event. Excluding this item, transportation revenue increased $112 million due to higher volumes and rates and gas sales increased $63 million (largely offset in cost of sales).
Earnings increased $233 million for 2022 compared to 2021, primarily due to higher earnings of $232 million at BHE GT&S. Earnings at BHE GT&S
increased mainly due to the impacts of the EGTS general rate case of $124 million, favorable income tax adjustments, lower operations and maintenance costs and a decrease in property and other tax expense of $30 million, higher margin of $26 million from non-regulated activities and increased earnings at Cove Point of $16 million.
BHE Transmission
Operating revenue increased $67 million for 2023 compared to 2022, primarily due to $69 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $26 million from the stronger U.S. dollar.
Earnings decreased $1 million for 2023 compared to 2022, primarily
due to $7 million from the stronger U.S. dollar, partially offset by the higher non-regulated revenue at BHE Canada.
Operating revenue increased $1 million for 2022 compared to 2021, primarily due to higher non-regulated revenue from wind-powered generating facilities, partially offset by $27 million from the stronger U.S. dollar.
Earnings for 2022 were equal to 2021, primarily due to improved equity earnings from ETT offset by $7 million from the stronger U.S. dollar.
BHE Renewables
Operating revenue decreased $27 million for 2023 compared to 2022, primarily due to lower solar and wind revenues of $78 million, largely from lower generation,
and lower natural gas and electric retail energy services revenue of $56 million, partially offset by favorable changes in the valuations of certain derivative contracts of $76 million and higher natural gas revenue of $34 million from favorable generation and pricing. Retail energy services revenue decreased mainly due to unfavorable natural gas pricing, partially offset by an increase in natural gas volumes.
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Earnings decreased $125 million for 2023 compared to 2022, primarily due to lower earnings from wind tax equity investments of $89 million, primarily due to lower PTCs and higher realized hedge losses, lower earnings of $70 million from the retail services business, largely due to unfavorable changes in unrealized positions
on derivative contracts, lower solar earnings of $40 million from lower generation and lower geothermal and natural gas earnings of $7 million, partially offset by higher earnings at owned wind projects of $88 million. Geothermal and natural gas earnings were lower due to higher geothermal operating and maintenance costs related to storms and outages as well as higher geothermal development costs, partially offset by favorable pricing and generation at the natural gas generating facilities. Earnings from owned wind projects were higher primarily due to favorable derivative contract valuations and from gains on the extinguishment of debt, partially offset by a decrease in operating revenue from lower generation.
Operating revenue increased $76 million for 2022 compared to 2021, primarily due to higher wind, geothermal, and solar revenues of $140 million from higher generation and pricing,
and higher natural gas and electric retail energy services revenue of $64 million due to favorable electric volumes and natural gas pricing, including changes in unrealized positions on derivative contracts, offset by lower electric pricing and natural gas volumes. These items were partially offset by lower natural gas revenues of $72 million from lower generation and pricing, lower hydro revenues of $28 million due to the transfer of the Casecnan generating facility to the Philippine government in December 2021 and $27 million from unfavorable changes in the valuation of certain derivative contracts.
Earnings increased $184 million for 2022 compared to 2021, primarily due to higher wind earnings of $214 million, higher geothermal earnings of $16 million and higher solar earnings of $14 million, partially offset by lower natural gas earnings of $44 million and lower hydro earnings of
$18 million due to the Casecnan generating facility transfer. Wind earnings increased due to higher earnings from tax equity investments of $153 million, largely as a result of the unfavorable impacts recognized in 2021 from the February 2021 polar vortex weather event and higher production tax credits, and higher earnings from owned projects of $61 million.
HomeServices
Operating revenue decreased $946 million for 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $873 million and lower mortgage revenue of $68 million. The decrease in brokerage and settlement services revenue resulted from a 19% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 28% decrease in funded
volume, primarily due to rising interest rates.
Earnings decreased $87 million for 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $78 million and mortgage services of $10 million. Earnings declined due to declines in closed brokerage transaction volume and mortgage funded volume, partially offset by favorable operating expenses primarily due to lower compensation costs.
Operating revenue decreased $947 million for 2022 compared to 2021, primarily due to lower brokerage and settlement services revenue of $637 million and lower mortgage revenue of $305 million. The decrease in brokerage and settlement services revenue resulted from an 11% decrease in closed transaction volume driven by 23% fewer closed units at existing companies resulting from rising interest
rates and a corresponding slowdown in home sales offset by acquisitions and a 7% increase in average sales price. The lower mortgage revenue was due to a 40% decrease in funded volume, primarily due to a decline in refinance activity resulting from rising interest rates.
Earnings decreased $287 million for 2022 compared to 2021, primarily due to lower earnings from brokerage and settlement services of $142 million and mortgage services of $126 million, largely from declines in closed brokerage transaction volume and mortgage funded volume. Earnings at brokerage and settlement services declined due to the decrease in closed units at existing companies, partially offset by favorable operating expense variances.
BHE and Other
Earnings
increased $2,094 million for 2023 compared to 2022, primarily due to the Company's investment in BYD including the $2,045 million favorable comparative change in fair value, favorable changes in the cash surrender value of corporate-owned life insurance policies of $45 million and $12 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway. These items were partially offset by unfavorable consolidated income tax adjustments, largely state related, totaling $48 million and higher BHE corporate interest expense of $52 million from an April 2022 debt issuance.
112
Earnings decreased $3,346 million for 2022 compared to 2021, primarily due to the Company's investment
in BYD, including the $3,317 million unfavorable comparative change in fair value, lower consolidated state income tax benefits, higher BHE corporate interest expense from an April 2022 debt issuance and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by $75 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway and lower corporate costs.
Liquidity and Capital Resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will
be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of December 31, 2023, the Company's total net liquidity was as
follows (in millions):
BHE
Pipeline
MidAmerican
NV
Northern
BHE
Group and
BHE
PacifiCorp
Funding
Energy
Powergrid
Canada
HomeServices
Other
Total
Cash
and cash equivalents
$
166
$
138
$
637
$
58
$
44
$
66
$
280
$
176
$
1,565
Credit
facilities(1)
3,500
2,000
1,509
1,000
346
850
1,500
—
10,705
Less:
Short-term
debt
(1,935)
(1,604)
—
—
(92)
(97)
(420)
—
(4,148)
Tax-exempt bond support and letters of credit
—
(249)
(306)
—
—
(1)
—
—
(556)
Net
credit facilities
1,565
147
1,203
1,000
254
752
1,080
—
6,001
Total
net liquidity(2)
$
1,731
$
285
$
1,840
$
1,058
$
298
$
818
$
1,360
$
176
$
7,566
Credit
facilities:
Maturity dates
2026
2026
2024, 2026
2026
2026
2024,
2026, 2027, 2028
2024
(1) Includes $92 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.
(2) Excludes
$900 million of available liquidity under a delayed draw term loan at PacifiCorp and $700 million from a credit facility at HomeServices that is unavailable due to borrowing restrictions pursuant to the credit agreement.
Refer to Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities, letters of credit, equity commitments and other related items.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2023 and 2022 were $7.1 billion and $9.4 billion, respectively. The decrease was primarily
due to unfavorable operating results, the timing of payments related to fuel and energy costs, a decrease in income tax receipts and changes in working capital.
Net cash flows from operating activities for the years ended December 31, 2022 and 2021 were $9.4 billion and $8.7 billion, respectively. The increase was primarily due to an increase in income tax receipts and improved operating results, partially offset by changes in regulatory assets and working capital.
113
The timing of the Company's income tax cash flows from period to period can be
significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2023 and 2022 were $(5.9) billion and $(7.8) billion, respectively. The change was primarily due to higher proceeds from sales and maturities, net of purchases, of U.S. Treasury Bills totaling $3.0 billion, higher proceeds from sales, net of purchases, of marketable securities of $316 million and lower cash paid for acquisitions, partially offset by higher capital expenditures of $1.6 billion. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net
cash flows from investing activities for the years ended December 31, 2022 and 2021 were $(7.8) billion and $(5.8) billion, respectively. The change was primarily due to the July 2021 receipt of $1.3 billion due to the termination of the second Purchase and Sale Agreement with Dominion Energy Questar Corporation, higher capital expenditures of $894 million and higher cash paid for acquisitions, partially offset by lower funding of tax equity investments. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the year ended December 31, 2023 were $(1.3) billion.
Sources of cash totaled $7.1 billion and consisted of proceeds from subsidiary debt issuances of $4.1 billion and net proceeds from short-term debt totaling $3.0 billion. Uses of cash totaled $8.4 billion and consisted mainly of $3.3 billion for the purchase of Cove Point noncontrolling interest, repayments of subsidiary debt totaling $2.8 billion, repayments of BHE senior debt of $900 million, preferred stock redemptions totaling $850 million and distributions to noncontrolling interests of $395 million.
Net cash flows from financing activities for the year ended December 31, 2022 were $(1.0) billion. Sources of cash totaled $3.9 billion and consisted of proceeds from subsidiary debt issuances of $2.9 billion and proceeds from BHE senior debt issuances of $986 million. Uses of cash totaled $4.9 billion and consisted mainly of repayments
of subsidiary debt totaling $1.5 billion, purchases of common stock of $870 million, net repayments of short-term debt totaling $867 million, preferred stock redemptions totaling $800 million and distributions to noncontrolling interests of $524 million.
Net cash flows from financing activities for the year ended December 31, 2021 were $(3.1) billion. Sources of cash totaled $2.4 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $5.5 billion and consisted mainly of preferred stock redemptions totaling $2.1 billion, repayments of subsidiary debt totaling $2.0 billion, distributions to noncontrolling interests of $488 million, repayments of BHE senior debt totaling $450 million and net repayments of short-term debt totaling $276 million.
Recent
Financing Transactions
In January and February 2024, the Company issued $5.1 billion of term debt with a weighted average interest rate of 5.4% and maturity dates ranging from 2029 to 2055 and repaid short term borrowings of approximately $2.8 billion.
Debt Repurchases
The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Preferred
Stock Redemptions
For the years ended December 31, 2023, 2022 and 2021, BHE redeemed at par 849,982, 800,006 and 2,100,012 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $850 million, $800 million and $2.1 billion.
114
Common Stock Transactions
For the year ended December 31, 2022, BHE purchased 740,961 shares
of its common stock held by Mr. Gregory E. Abel, BHE's Chair, for $870 million. The purchase was pursuant to the terms of BHE's Shareholders Agreement.
There were no common stock repurchases for the years ended December 31, 2023 and 2021.
Future Uses of Cash
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance
of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.
Capital Expenditures
The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers'
rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are as follows (in millions):
Historical
Forecast
2021
2022
2023
2024
2025
2026
PacifiCorp
$
1,513
$
2,166
$
3,226
$
3,577
$
3,545
$
3,492
MidAmerican
Funding
1,912
1,869
1,833
1,880
2,761
2,792
NV Energy
749
1,113
1,797
1,840
2,200
2,945
Northern
Powergrid
742
768
557
872
978
997
BHE Pipeline Group
1,128
1,157
1,294
1,177
1,241
1,038
BHE
Transmission
279
200
206
330
441
447
BHE Renewables
227
140
177
638
197
193
HomeServices
42
48
41
40
43
41
BHE
and Other(1)
19
44
17
24
12
20
Total
$
6,611
$
7,505
$
9,148
$
10,378
$
11,418
$
11,965
(1)BHE
and Other includes intersegment eliminations.
115
Historical
Forecast
2021
2022
2023
2024
2025
2026
Electric
transmission
$
799
$
1,693
$
1,802
$
2,121
$
2,445
$
2,804
Electric distribution
1,620
1,650
2,047
2,293
2,528
2,243
Wind
generation
1,339
774
1,538
1,317
1,909
1,798
Natural gas transmission and storage
1,068
945
997
924
1,014
952
Electric
battery and pumped hydro storage
23
16
371
350
572
1,103
Solar generation
157
422
271
224
584
1,067
Wildfire
mitigation
83
188
352
409
364
368
Other
1,522
1,817
1,770
2,740
2,002
1,630
Total
$
6,611
$
7,505
$
9,148
$
10,378
$
11,418
$
11,965
The
Company's historical and forecast capital expenditures consisted mainly of the following:
•Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦PacifiCorp's transmission investment primarily reflects planned costs for the following major transmission segments: the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho; the 14-mile, 345-kV high-voltage transmission line between the Oquirrh
substation in the Salt Lake Valley and the Terminal substation near the Salt Lake City Airport; and the200-mile, 500-kV high-voltage transmission line between the Anticline substation near Point of Rocks, Wyoming and the Populus substation in Downey, Idaho. Planned spending for major transmission segments that are expected to be placed in-service in 2024 through 2031 totals $694 million in 2024, $325 million in 2025 and $504 million in 2026.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation, near Yerington, Nevada to the Northwest substation, near Las Vegas, Nevada to the Harry Allen substation, near Las Vegas, Nevada; a 235-mile, 525-kV transmission line, known
as Greenlink North, connecting the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Mira Loma substations, near Yerington, Nevada; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada. Planned spending for the expansion program estimated to be placed in-service in 2027 through 2028 totals $281 million in 2024, $584 million in 2025 and $713 million in 2026.
◦Operating expenditures include spending for system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
•Electric
distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, storm damage restoration and repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $608 million for 2023, $72 million for 2022 and $540 million for 2021. MidAmerican Energy placed in-service 200 MWs during 2023 and 294 MWs during 2021. Planned spending for the construction
of additional wind-powered generating facilities totals $515 million in 2024, $1,196 million in 2025 and $998 million in 2026.
116
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $47 million for 2023, $500 million for 2022 and $354 million for 2021. Planned spending for repowering totals $228 million in 2024, $382 million in 2025 and $601 million in 2026. MidAmerican Energy expects its repowered facilities to meet IRS guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service.
◦Construction of new wind-powered generating facilities and construction at existing wind-powered generating
facility sites acquired from third parties at PacifiCorp totaling $735 million for 2023, $23 million for 2022 and $118 million for 2021. PacifiCorp placed in-service 42 MWs at the Foote Creek III and Foote Creek IV wind-powered generating facilities in 2023 and 516 MWs of new wind-powered generating facilities in 2021. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $478 million in 2024, $238 million in 2025 and $95 million in 2026 and is primarily for the Rock River I, Rock Creek I and Rock Creek II wind-powered generating facilities totaling approximately 640 MWs that are expected to be placed in-service in 2024 through 2025.
◦Construction of wind-powered generating facilities at BHE Renewables totaling $155 million for 2021. In May 2021, BHE Renewables completed the asset acquisition of a 54-MW wind-powered generating
facility located in Iowa. In December 2021, BHE Renewables completed asset acquisitions of 158-MW and 200-MW wind-powered generating facilities located in Texas.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $39 million for 2023 and $45 million in 2022. BHE Renewables repowered facilities were placed in-service in the fourth quarter of 2023 and meet IRS guidelines for the re-establishment of PTCs for 10 years.
•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for customer driven expansion projects. Operating expenditures include spending for pipeline integrity projects, automation and controls upgrades, corrosion control, unit exchanges, compressor modifications, projects related to Pipeline and Hazardous
Materials Safety Administration natural gas storage rules and natural gas transmission, storage, LNG terminalling infrastructure needs to serve existing and expected demand and asset modernization programs.
•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:
◦Construction at the Nevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada, with commercial operation expected by early 2024, a 220-MW grid-tied battery energy storage system that was developed on the site of the retired Reid Gardner generating station in Clark County, Nevada with commercial operation being reached in December of 2023, a planned 400-MW battery energy storage system co-located with a 400MW solar photovoltaic
facility that would be developed in Churchill County, Nevada with ownership share between Nevada Power and Sierra Pacific to be approved by the PUCN, with commercial operation expected by early 2026 and other planned electric battery storage systems.
•Solar generation includes growth expenditures, including spending for the following:
◦Construction and operation of solar-powered generating facilities at MidAmerican Energy primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022, with total spend of $13 million in 2023, $119 million in 2022 and $132 million in 2021. Planned spending for the construction and operation of additional solar-powered generating facilities totals $14 million in 2024, $82 million in 2025 and $30 million in 2026.
◦Construction
of solar-powered generating facility at the Nevada Utilities includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada, with commercial operation expected by early 2024. Also included is a planned 400-MW of co-located battery storage that would be developed in Churchill County, Nevada with ownership share between Nevada Power and Sierra Pacific to be approved by the PUCN, with commercial operation expected by early 2027 and other planned solar generating facilities.
◦Construction of solar-powered generating facilities at BHE Renewables' includes expenditures for a 48-MW solar photovoltaic facility with an additional 52 MWs of capacity of co-located battery storage in Kern County, California, with commercial operation expected in the fourth quarter of 2024, with total spend of $60 million
for 2023 and $22 million for 2022. Planned spending totals $139 million in 2024.
117
•Wildfire mitigation includes operating expenditures, including spending for the following:
◦Expenditures at PacifiCorp totaling $325 million in 2023, $159 million in 2022 and $64 million in 2021. Planned spending totals $374 million in 2024, $324 million in 2025 and $319 million in 2026 and is comprised of reducing wildfire risk in the FHCA by conversion of overhead systems to underground, replacing overhead bare wire conductor with covered conductors and deployment of advanced protection devices for faster fault detection. The efforts will also include an expansion of the weather station
network and predictive tools for situational awareness across the entire service territory.
◦Expenditures at the Nevada Utilities totaling $20 million in 2023, $20 million in 2022 and $5 million in 2021. Planned spending totals $25 million in 2024, $31 million in 2025 and $36 million in 2026 is comprised of reducing wildfire risk in Tier 3 HTAs by rebuilding distribution lines with covered conductor, converting overhead distribution lines to underground and copper wire and pole replacement projects.
•Other capital expenditures includes both growth and operating expenditures, including spending for routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of
CCR.
Off-Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments. Certain equity investments are presented on the Consolidated Balance Sheets net of investment tax credits.
As of December 31, 2023, the Company's investments that are accounted
for under the equity method had short- and long-term debt of $2.8 billion, unused revolving credit facilities of $127 million and letters of credit outstanding of $88 million. As of December 31, 2023, the Company's pro-rata share of such short- and long-term debt was $1.4 billion, unused revolving credit facilities was $64 million and outstanding letters of credit was $43 million. The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. The entire amount of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.
Material
Cash Requirements
The Company has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Note 9, 10 and 11), operating and financing leases (refer to Note 6), firm commitments (refer to Note 16), letters of credit (refer to Note 9), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7), uncertain tax positions (refer to Note 12) and AROs (refer to Note 14). Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
The Company has cash requirements relating to interest payments of $39.6 billion on long-term debt, including $2.3 billion due in 2024.
Regulatory
Matters
The Company is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding the Company's general regulatory framework and current regulatory matters.
118
Quad Cities Generating Station Operating Status
Constellation Energy Generation, LLC ("Constellation Energy"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of
which MidAmerican Energy has a 25% ownership interest, receives financial support for continued operation of Quad Cities Station from the zero emission standard enacted by the Illinois legislature in December 2016. The zero emission standard requires the Illinois Power Agency to purchase ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs provide Constellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy does not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided
financial support program like the Illinois zero emission standard, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fueled resources.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC denied rehearing of that order on April 16, 2020. A number of parties,
including Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Seventh Circuit. MidAmerican Energy cannot predict the outcome of this proceeding.
While this litigation is pending, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year in May 2021, which prevented Quad Cities Station from clearing in that capacity auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions with the FERC on July 30, 2021, and, on September 29,
2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR applied in the capacity auction for the 2023-2024 delivery year but did not restrict the offers of Quad Cities Station, which cleared in the capacity auction. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit.
Assuming the continued effectiveness of the Illinois zero emission standard, Constellation Energy no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the
Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC provided no new mechanism for accommodating state-supported resources like Quad Cities Station other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. Depending on the outcome of the proceedings related to the PJM MOPR, the continued effectiveness of the Illinois zero emission standard may be undermined unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.
Environmental
Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and the Company is
unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
119
Collateral and Contingent Features
Debt of BHE and debt and preferred securities of certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating
agency's assessment of the rated company's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
BHE and its subsidiaries have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial
paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31,
2023, the applicable entities' credit ratings from the recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2023, the Company would have been required to post $446 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where BHE's subsidiaries operate have
not had a significant impact on the Company's consolidated financial results. In the U.S. and Canada, the Regulated Businesses operate under cost-of-service based rate-setting structures administered by various state and provincial commissions and the FERC. Under these rate-setting structures, the Regulated Businesses are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the Northern Powergrid Distribution Companies incorporates the rate of inflation in determining rates charged to customers. BHE's subsidiaries attempt to minimize the potential impact of inflation on their operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs
and long-term debt issuances. There can be no assurance that such actions will be successful.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions
that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
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Accounting for the Effects
of Certain Types of Regulation
The Regulated Businesses prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated
rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes its application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $5.6 billion and total regulatory liabilities were $6.8 billion as of December 31,
2023. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Regulated Businesses' regulatory assets and liabilities.
Impairment of Goodwill and Long-Lived Assets
The Company's Consolidated Balance Sheet as of December 31, 2023 includes goodwill of acquired businesses of $11.5 billion. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2023. Additionally, no indicators of impairment were identified as of December 31, 2023. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill
impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings or rate base; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors.
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering
event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As a majority of all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of an asset, for the purposes of impairment analysis, requires the exercise of judgment. Circumstances that could significantly alter the calculation of fair value or the recoverable amount of an asset may include significant changes in
the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset, the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.
Pension and Other Postretirement Benefits
Certain of the Company's subsidiaries sponsor defined benefit pension and other postretirement benefit plans that cover the majority of employees. The Company recognizes the funded status of the defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit
obligation as of the measurement date. As of December 31, 2023, the Company recognized a net asset totaling $302 million for the funded status of the defined benefit pension and other postretirement benefit plans. As of December 31, 2023, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets totaled $282 million and in AOCI totaled $570 million.
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The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including, but not limited
to, discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the key assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2023.
The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds
to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds
to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5.00% by 2028, at which point the rate of increase is assumed to remain constant.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (dollars in millions):
A variety of factors affect the funded status of the plans, including discount rates, asset returns, mortality assumptions, plan changes and the Company's funding policy for each plan.
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Income
Taxes
In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory commissions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements
from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations is not expected to have a material impact on the Company's consolidated financial results. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes.
It is probable the Company's regulated businesses will pass income tax benefit and expense related to the 2017 federal tax rate change from 35% to 21%, certain property-related basis differences and other various
differences on to their customers. As of December 31, 2023, these amounts were recognized as a net regulatory liability of $2.3 billion and will be included in regulated rates when the temporary differences reverse.
The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely; however, the Company periodically evaluates its capital requirements. If circumstances change in the future and a portion of the Company's undistributed foreign earnings were repatriated, the dividends may be subject to taxation in the U.S. but the tax is not expected to be material.
Loss Contingencies
As a
result of certain conditions, situations or circumstances involving uncertainty as to possible loss, including (i) several wildfires that have occurred in the Company's service territory and surrounding areas in the western U.S. and Canada and (ii) antitrust cases at HomeServices, the Company is required to evaluate its exposure to potential loss contingencies arising from claims associated with these items. In determining this exposure, the Company is required to assess whether the likelihood of loss for each of these items is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the outcome of the appeals process, cause and origin of the wildfires, investigations, discovery associated with lawsuits and negotiations with various parties. If deemed reasonably possible, the Company is required to estimate the potential loss or range of potential loss and disclose any material amounts.
If deemed probable, the Company is required to accrue a loss if reasonably estimable based on the bottom end of the range if no amount within the range of estimated loss is any better than another amount. Many assumptions and variables are involved in determining the estimates relative to wildfires, including identifying the various categories of potential loss such as fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages. Within the categories of potential loss, further assumptions are made regarding items such as the types of structures damaged, estimated replacement values associated with those structures, value of personal property, the types of natural resource damage such as timber, the value of that timber, the nature of noneconomic damages such as those arising from personal injuries, other damages the Company may be responsible for
if found negligent such as punitive damages, and the amount of any penalties or fines that may be imposed by governmental entities. Refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's loss contingencies associated with wildfires and the antitrust cases at HomeServices.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates,
equity prices, foreign currency exchange rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. Each of the Company's businesses has established guidelines for credit risk management.
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Commodity Price Risk
The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity
and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage and transmission and transportation constraints. The Company does not engage in a material amount of proprietary trading activities. To manage a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company does not
hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes the Company's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $23 million and $(88) million, respectively, as of December 31, 2023 and 2022, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices with the contracted
or expected volumes. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
The settled cost of certain of the Company's commodity derivative contracts not designated as hedging contracts
is included in regulated rates and, therefore, net unrealized gains and losses associated with interim price movements on commodity derivative contracts do not expose the Company to earnings volatility. Consolidated financial results would be negatively impacted if the costs of wholesale electricity, wholesale natural gas or fuel are higher than what is included in regulated rates, including the impacts of adjustment mechanisms. As of December 31, 2023 and 2022, a net regulatory asset of $166 million and a net regulatory liability of $231 million, respectively, was recorded related to the net derivative liability of $121 million and net derivative asset of $335 million, respectively. For the Company's commodity derivative contracts designated as hedging contracts, net unrealized gains and losses associated with interim price movements on commodity derivative contracts,
to the extent the hedge is considered effective, generally do not expose the Company to earnings volatility.
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Interest Rate Risk
The Company is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt, future debt issuances and mortgage commitments. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the Company's fixed-rate long-term debt does not expose the Company to the risk of loss due to changes in market interest rates.
Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of the Company's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 9, 10, 11, and 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of the Company's short and long-term debt.
As of December 31, 2023 and 2022, the Company had short- and long-term variable-rate obligations totaling $5.0 billion and $3.2 billion, respectively, that
expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on the Company's consolidated annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2023 and 2022.
The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, forward sale commitments or mortgage interest rate lock commitments, to mitigate the Company's exposure to interest rate risk. Changes in fair value of agreements designated as cash flow hedges are reported in AOCI to the extent the hedge is effective until the forecasted transaction
occurs. Changes in fair value of agreements not designated as hedging contracts are recognized in earnings. As of December 31, 2023 and 2022, the Company had variable-to-fixed interest rate swaps with notional amounts of $426 million and $481 million, respectively, Ł163 million and Ł178 million, respectively, and A$161 million and A$167 million, respectively, to protect the Company against an increase in interest rates. Additionally, as of December 31, 2023 and 2022, the Company had mortgage commitments, net, with notional amounts of $406 million and $438 million, respectively, to protect the Company against an increase in interest rates. The fair value of the Company's interest rate derivative contracts was a net derivative asset of $78 million and $108 million as of December 31,
2023 and 2022, respectively. A hypothetical 10 basis point increase and a 10 basis point decrease in interest rates would not have a material impact on the Company.
The Company holds foreign currency swaps with the purpose of hedging the foreign currency exchange rate associated with Euro denominated debt. As of December 31, 2023 and 2022, the Company had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of the Company's foreign currency swaps.
Equity Price Risk
Market
prices for equity securities are subject to fluctuation and consequently the amount realized in the subsequent sale of an investment may significantly differ from the reported market value. Fluctuation in the market price of a security may result from perceived changes in the underlying economic characteristics of the investee, the relative price of alternative investments and general market conditions.
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As of December 31, 2023 and 2022, the Company's investment in BYD Company Limited common stock represented approximately 76% and 86%, respectively, of the total fair value of the Company's equity securities. The majority of the
Company's remaining equity securities are held in a trust related to the decommissioning of nuclear generation assets and the realized and unrealized gains and losses are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. The following table summarizes the Company's investment in BYD Company Limited as of December 31, 2023 and 2022 and the effects of a hypothetical 30% increase and a 30% decrease in market price as of those dates. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).
BHE's business operations and investments outside of the U.S. increase its risk related to fluctuations in foreign currency exchange rates primarily in relation to the British pound and the Canadian dollar. BHE's reporting currency is the U.S. dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from BHE's foreign operations changes with the fluctuations of the currency in which they transact.
Northern Powergrid's functional currency is the British pound. As of December 31, 2023, a 10% devaluation in the British pound to the U.S. dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $840 million cumulative translation adjustment in AOCI.
A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for Northern Powergrid of $16 million in 2023.
BHE Canada's functional currency is the Canadian dollar. As of December 31, 2023, a 10% devaluation in the Canadian dollar to the U.S. dollar would result in the Company's Consolidated Balance Sheet being negatively impacted by a $453 million cumulative translation adjustment in AOCI. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for BHE Canada of $18 million in 2023.
Credit Risk
Domestic Regulated Operations
The
Utilities are exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent the Utilities' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Utilities analyze the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required,
the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2023, PacifiCorp's aggregate credit exposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements, some of which are from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.
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Substantially
all of MidAmerican Energy's electric wholesale sales revenue results from participation in RTOs, including the MISO and the PJM. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. Additionally, as of December 31, 2023, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.
As of December 31, 2023, NV Energy's aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.
BHE GT&S primary customers include electric and natural gas distribution utilities and LNG export, import and storage
customers. Northern Natural Gas' primary customers include utilities in the upper Midwest. Kern River's primary customers are electric and natural gas distribution utilities, major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and financial institutions. As a general policy, collateral is not required for receivables from creditworthy customers. Customers' financial condition and creditworthiness, as defined by the tariff, are regularly evaluated and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of BHE GT&S, Northern Natural Gas' and Kern River's tariffs, the companies have required customers that lack creditworthiness to provide cash deposits, letters of credit or other security until they meet the creditworthiness requirements of the respective tariff.
Northern
Powergrid
The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to supply companies. The supply companies purchase electricity from generators and traders, sell the electricity to end-use customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to the multilateral "Distribution Connection and Use of System Agreement." The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses. During 2023, E.ON and certain of its affiliates and British Gas Trading Limited represented approximately 19% and 15%, respectively, of the total combined distribution revenue of the Northern Powergrid Distribution Companies. The industry operates in accordance with a framework which sets credit limits for each supply business based on its credit rating or
payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided the Northern Powergrid Distribution Companies have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.
BHE Canada
AltaLink's primary source of operating revenue is the AESO, an entity
rated AA- by Standard and Poor's. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations would significantly impair AltaLink's ability to meet its existing and future obligations. Total operating revenue for AltaLink was $666 million for the year ended December 31, 2023.
BHE Renewables
BHE Renewables owns independent power projects that generally have separate project financing agreements. Operating revenue for these projects is derived primarily from long-term power purchase agreements with single customers, primarily utilities, which expire between 2024 and 2043. Because of the dependence generally from a single customer at each project, any material failure of the customer to fulfill its obligations
would significantly impair that project's ability to meet its existing and future obligations. Total operating revenue for BHE Renewables' independent power projects was $1,022 million for the year ended December 31, 2023.
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Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and the shareholders of
Berkshire Hathaway Energy Company
Des Moines, Iowa
Opinion
on the Financial Statements
We have audited the accompanying consolidated balance sheets of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2023, the related notes and the schedule listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022,
and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We
conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any
way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Note 7 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Federal Energy Regulatory Commission as well as certain other regulatory commissions (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where the Company operates. Management
has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation has a pervasive effect on the financial statements.
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Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow the Company an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an effect
on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit the Company's ability to recover its costs.
We identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently
completed plant or plant under construction, and (3) refunds to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of decisions by the Commissions included the following, among others:
•We evaluated the Company's disclosures related to the effects of rate regulation, by testing certain recorded balances and evaluating regulatory developments.
•We read relevant
regulatory orders issued by the Commissions, regulatory statutes, filings made by the Company and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances.
Wildfires — Contingencies — Refer to Note 16 to the financial statements
Critical Audit Matter Description
As
a result of several wildfires that have occurred in the Company's service territory and surrounding areas in Oregon and California, the Company is required to evaluate its exposure to potential loss contingencies arising from claims associated with the 2020 Wildfires and the 2022 McKinney Fire (the "Wildfires"). In determining this exposure, the Company is required to determine whether the likelihood of loss for each of the Wildfires is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the cause and origin of the Wildfires, investigations, discovery associated with lawsuits and negotiations with claimants.
A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. If deemed reasonably possible,
the Company is required to estimate the potential loss or range of potential loss and disclose any material amounts.
Management has recorded estimated liabilities and receivables, which represent its best estimate of probable losses and expected insurance recoveries associated with the Wildfires.
We identified wildfire-related contingencies and the related disclosures as a critical audit matter because of the significant judgments made by management to determine the probability of loss and estimate the probable losses and insurance recoveries. Auditing the reasonableness of management's judgments, estimates and disclosures related to wildfire-related loss contingencies required the application of a high degree of judgment and extensive effort.
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How
the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management's judgments regarding the probability of loss, estimated losses and insurance recoveries, and related disclosures for wildfire-related contingencies included the following, among others:
•We evaluated management's judgments related to whether a loss was probable or reasonably possible for the Wildfires by inquiring of management and the Company's external and internal legal counsel regarding the likelihood and amounts of probable and reasonably possible losses. We also evaluated the potential impact of information gained through the Company and third parties' investigations into the cause of the fires, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict
management's assertions.
•We evaluated the estimation methodology for determining the amount of probable and reasonably possible losses through inquiries with management and external and internal legal counsel and we tested the significant assumptions, including certain settlements, used in the estimates of probable and reasonably possible losses.
•We read legal letters from the Company's external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.
•We evaluated management's judgments related to whether certain insurance recoveries were probable of collection by inquiring of management and the Company's external and internal legal counsel regarding the amounts
of insurance recoveries recorded or disclosed. With the assistance of our insurance specialists, we tested certain significant assumptions used in the determination of collectability, including obtaining and reading relevant insurance policies to determine whether the types of insurance claims are included or excluded from coverage. We compared a sample of subsequent insurance recoveries collected to recorded amounts.
•We evaluated whether the Company's disclosures were appropriate and consistent with the information obtained in our procedures.
Adjustments
to reconcile net income to net cash flows from operating activities:
(Gains) losses on marketable securities, net
(i669)
i2,002
(i1,823)
Depreciation
and amortization
i4,220
i4,286
i3,881
Allowance
for equity funds
(i267)
(i167)
(i126)
Equity
(income) loss, net of distributions
i415
i319
i380
Net
power cost deferrals
(i629)
(i1,290)
(i520)
Amortization
of net power cost deferrals
i354
i357
i107
Other
changes in regulatory assets and liabilities
(i260)
(i146)
(i255)
Deferred
income taxes and investment tax credits, net
(i257)
(i467)
i646
Other,
net
(i46)
i59
(i57)
Changes
in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets
(i134)
i150
i553
Derivative
collateral, net
(i226)
i121
i82
Pension
and other postretirement benefit plans
(i10)
(i27)
(i39)
Accrued
property, income and other taxes, net
(i58)
i397
(i489)
Accounts
payable and other liabilities
i280
i579
i163
Wildfires
insurance receivable
(i253)
(i130)
i—
Wildfires
liability
i1,300
i172
i—
Net
cash flows from operating activities
i7,132
i9,359
i8,692
Cash
flows from investing activities:
Capital expenditures
(i9,148)
(i7,505)
(i6,611)
Acquisitions,
net of cash acquired
i—
(i314)
(i122)
Purchases
of marketable securities
(i314)
(i574)
(i297)
Proceeds
from sales of marketable securities
i2,520
i2,464
i273
Purchases
of U.S. Treasury Bills
(i4,282)
(i1,918)
i—
Proceeds
from sales of U.S. Treasury Bills
i1,809
i—
i—
Proceeds
from maturities of U.S. Treasury Bills
i3,507
i—
i—
Proceeds
from other investments
i4
i6
i1,300
Equity
method investments
(i12)
i119
(i212)
Other,
net
i17
(i28)
(i94)
Net
cash flows from investing activities
(i5,899)
(i7,750)
(i5,763)
Cash
flows from financing activities:
Preferred stock redemptions
(i850)
(i800)
(i2,100)
Preferred
dividends
(i38)
(i50)
(i132)
Common
stock purchases
i—
(i870)
i—
Proceeds
from BHE senior debt
i—
i986
i—
Repayments
of BHE senior debt
(i900)
i—
(i450)
Proceeds
from subsidiary debt
i4,084
i2,887
i2,409
Repayments
of subsidiary debt
(i2,821)
(i1,494)
(i2,024)
Net
proceeds from (repayments of) short-term debt
i3,024
(i867)
(i276)
Purchase
of Cove Point noncontrolling interest
(i3,300)
i—
i—
Distributions
to noncontrolling interests
(i395)
(i524)
(i488)
Other,
net
(i54)
(i274)
(i70)
Net
cash flows from financing activities
(i1,250)
(i1,006)
(i3,131)
Effect
of exchange rate changes
i11
(i30)
i1
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i6)
i573
(i201)
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i1,817
i1,244
i1,445
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i1,811
$
i1,817
$
i1,244
The
accompanying notes are an integral part of these consolidated financial statements.
137
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)iOrganization
and Operations
Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The Company's operations are organized as ieight business segments: PacifiCorp
and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company and its subsidiaries ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC and its subsidiaries ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation and its subsidiaries
("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC and its subsidiaries), BHE Renewables, LLC and its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns ifour utility companies in the U.S. serving customers in i11
states, itwo electricity distribution companies in Great Britain, ifive
interstate natural gas pipeline companies and interests in a liquefied natural gas ("LNG") export, import and storage facility in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the U.S. and ione of the largest residential real estate brokerage franchise networks in the U.S.
(2)iSummary
of Significant Accounting Policies
i
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of BHE and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. The Consolidated Statements of Operations include the revenue and expenses of any acquired entities from the date of acquisition. The Company consolidates variable interest entities ("VIE") in which it possesses both (i) the power to direct
the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Intercompany accounts and transactions have been eliminated.
i
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for loss contingencies and applicable insurance recoveries, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the Wildfires" as discussed in Note 16. Actual results may differ from the
estimates used in preparing the Consolidated Financial Statements.
138
i
Accounting for the Effects of Certain Types of Regulation
PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas, Kern River and AltaLink (the "Regulated Businesses") prepare their financial statements in accordance
with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
i
Fair
Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of
fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
i
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability
is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. iA reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2023 and 2022, as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear
on the Consolidated Balance Sheets (in millions):
Investments
and restricted cash and cash equivalents
i224
i173
Investments
and restricted cash and cash equivalents and investments
i22
i53
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i1,811
$
i1,817
i
Investments
Fixed
Maturity Securities
The Company's management determines the appropriate classification of investments in fixed maturity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments and restricted cash and cash equivalents and investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Consolidated Balance Sheets.
Available-for-sale investments are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on fixed maturity securities in a trust related to the decommissioning of nuclear generation assets are recorded
as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. Trading investments are carried at fair value with changes in fair value recognized in earnings. Held-to-maturity investments are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity. The difference between the original cost and maturity value of a fixed maturity security is amortized to earnings using the interest method.
139
Investment gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired with respect to securities classified as available-for-sale. If the value of a fixed maturity
investment declines to below amortized cost and the decline is deemed other than temporary, the amortized cost of the investment is reduced to fair value, with a corresponding charge to earnings. Any resulting impairment loss is recognized in earnings if the Company intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If the Company does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in other comprehensive income (loss) ("OCI"). For regulated fixed maturity investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.
Equity Securities
Investments
in equity securities are carried at fair value with changes in fair value recognized in earnings as a component of gains (losses) on marketable securities, net. All changes in fair value of equity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates.
Equity Method Investments
The Company utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when the investor possesses more than 20% of the voting interests of the investee. This presumption
may be overcome based on specific facts and circumstances that demonstrate that the ability to exercise significant influence is restricted. In applying the equity method, the Company records the investment at cost and subsequently increases or decreases the carrying value of the investment by the Company's share of the net earnings or losses and OCI of the investee. The Company records dividends or other equity distributions as reductions in the carrying value of the investment. Certain equity investments are presented on the Consolidated Balance Sheets net of related investment tax credits.
i
Allowance
for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on the Company's assessment of the collectability of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, the Company primarily utilizes credit loss history. However, the Company may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. iThe
change in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31 (in millions):
2023
2022
2021
Beginning balance
$
i106
$
i108
$
i77
Charged
to operating costs and expenses, net
i68
i43
i81
Write-offs,
net
(i72)
(i45)
(i50)
Ending
balance
$
i102
$
i106
$
i108
i
Derivatives
The
Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.
140
Commodity
derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of sales on the Consolidated Statements of Operations.
For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For the Company's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as regulatory assets and liabilities, unrealized
gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts; cost of sales and operating expense for purchase contracts and electricity, natural gas and fuel swap contracts; and other, net for interest rate swap derivatives.
For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.
Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax,
until the contract settles and the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.
i
Inventories
Inventories
consist mainly of fuel, which includes coal stocks, stored gas and fuel oil, totaling $i250 million and $i248 million as of December 31, 2023 and 2022,
respectively, and materials and supplies totaling $i1,259 million and $i1,008 million as of December 31, 2023 and 2022, respectively. The cost
of materials and supplies, coal stocks and fuel oil is determined primarily using the average cost method. The cost of stored gas is determined using either the last-in-first-out ("LIFO") method or the lower of average cost or market. With respect to inventories carried at LIFO cost, the replacement cost would be $i4 million and $i22 million
higher as of December 31, 2023 and 2022, respectively.
i
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related materials, direct labor and contract services, as well as indirect construction costs.
Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable to the Regulated Businesses. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Regulated Businesses to determine
the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
141
Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the
original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by the Regulated Businesses as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC") and the Alberta Utilities Commission ("AUC"). After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
i
Asset
Retirement Obligations ("ARO")
The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily related to the decommissioning of nuclear generating facilities and obligations associated with its other generating facilities and offshore natural gas pipelines. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the
ARO liability due to the passage of time. For the Regulated Businesses, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
i
Impairment
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances
indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As a majority of all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
i
Leases
The
Company has non-cancelable operating leases primarily for office space, office equipment, generating facilities, land and rail cars and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company does not include options in its lease calculations unless there is a triggering event indicating the Company is reasonably certain to exercise the option. The Company's
accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
The Company's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily
for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
The Company's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
142
i
Goodwill
Goodwill
represents the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2023. When evaluating goodwill for impairment, the Company estimates the fair value of its reporting units. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the excess is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The determination of fair value incorporates significant unobservable inputs. During 2023, 2022 and 2021, the Company did iiino//t
record any material goodwill impairments.
The Company records goodwill adjustments for changes to the purchase price allocation prior to the end of the measurement period, which is not to exceed one year from the acquisition date.
/
i
Revenue Recognition
Customer
Revenue
The Company uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations. In the event one of the parties to a contract has performed before the other, the Company would recognize a contract asset or contract liability depending on the relationship between the Company's performance and the customer's payment.
Energy Products and Services
A
majority of the Company's energy revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. The Company's energy revenue that is nonregulated primarily relates to the Company's renewable energy business.
Revenue recognized is equal to what the Company has the right to invoice as it generally corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. As of December 31, 2023 and 2022, trade receivables, net on the
Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $i787 million and $i828 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy
products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
Real Estate Services
The Company's HomeServices reportable segment consists of separate brokerage, mortgage and franchise businesses. Rates charged for brokerage, mortgage and franchise real estate services are established through contractual arrangements that establish the transaction price and the allocation of the price amongst the separate performance obligations.
The
full-service residential real estate brokerage business has performance obligations to deliver integrated real estate services including brokerage services, title and closing services, property and casualty insurance, home warranties, relocation services, and other home-related services to customers. All performance obligations related to the full-service residential real estate brokerage business are satisfied in less than one year at the point in time when a real estate transaction is closed or when services are provided. Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title and escrow closing fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing. Payments for amounts billed are generally due from the customer at closing.
/
143
The
franchise business operates a network that has performance obligations to provide the right to use certain brand names and other related service marks as well as to provide orientation programs, training and consultation services, advertising programs and other services to its franchisees. The performance obligations related to the franchise business are satisfied over time or when the services are provided. Franchise royalty fees are sales-based variable consideration and are based on a percentage of commissions earned by franchisees on real estate sales, which are recognized when the sale closes. Meetings and training revenue, referral fees, late fees, service fees and franchise termination fees are earned when services have been completed. Payments for amounts billed are generally due from the franchisee within 30 days of billing.
Other Revenue
Energy
Products and Services
Other revenue consists primarily of revenue related to power purchase agreements not considered Customer Revenue as they are recognized in accordance with ASC 815, "Derivatives and Hedging" and ASC 842, "Leases" and certain non-tariff-based revenue approved by the regulator that is not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers."
Real Estate Service
Mortgage and other revenue consists primarily of revenue related to the mortgage business. Mortgage fee revenue consists of amounts earned related to application and underwriting fees and fees on canceled loans. Fees associated with the origination of mortgage loans are recognized as
earned. These amounts are not considered Customer Revenue as they are recognized in accordance with ASC 815, "Derivatives and Hedging," ASC 825, "Financial Instruments" and ASC 860, "Transfers and Servicing."
i
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
i
Foreign
Currency
The accounts of foreign-based subsidiaries are measured in most instances using the local currency of the subsidiary as the functional currency. Revenue and expenses of these businesses are translated into U.S. dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in equity as a component of AOCI. Gains or losses arising from transactions denominated in a currency other than the functional currency of the entity that is party to the transaction are included in earnings.
i
Income
Taxes
The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated U.S. federal and Iowa state income tax returns and the majority of the Company's U.S. federal income tax is remitted to or received from Berkshire Hathaway.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with income tax benefits and expense for certain
property-related basis differences and other various differences that the Company's regulated businesses deems probable to be passed on to their customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
144
Investment
tax credits are deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions. The Company has not established deferred income taxes on its undistributed foreign earnings that have been determined by management to be reinvested indefinitely.
The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the Consolidated
Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
i
New Accounting Pronouncements
In March 2023, the FASB issued ASU No. 2023-02, amending FASB ASC Topic 323-740, "Investments—Equity Method and Joint Ventures—Income Taxes" which set forth the conditions needed to apply the proportional amortization method. The amendments in this update permit reporting
entities to elect to account for their tax equity investments, regardless of the tax credit program from which the income tax credits are received, using the proportional amortization method if certain conditions are met. This guidance is effective for interim and annual reporting periods beginning after December 15, 2023, with early adoption permitted, and is required to be adopted either using a modified retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption or a retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the earliest fiscal year presented. The Company has elected not to adopt this guidance and therefore this ASU will have no effect on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In
November 2023, the FASB issued ASU No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures
included within Notes to Consolidated Financial Statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial
Statements and disclosures included within Notes to Consolidated Financial Statements.
145
(3) iBusiness Acquisitions
On September
1, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of BHE, completed the acquisition of DECP Holdings, Inc.'s (the "Seller"), an indirect wholly owned subsidiary of Dominion Energy, Inc., i50% limited partner interests in Cove Point LNG, LP ("Cove Point") ("The Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 9, 2023 (the "Purchase
Agreement"), the Buyer paid $i3.3 billion in cash, plus the pro rata portion of the quarterly distribution made by Cove Point for the third fiscal quarter of 2023. BHE funded the Transaction with cash on hand, including cash realized from the liquidation of certain investments, which was contributed to BHE GT&S. The Buyer now owns an aggregate of i75%
of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, continues to own i100% of the general partner interest, of Cove Point. Prior to the Transaction, BHE owned i100%
of the general partner interest and i25% of the limited partner interests in Cove Point. BHE previously determined it has the power to direct the activities that most significantly impact Cove Point's economic performance as well as the obligation to absorb losses and benefits which could be significant to it and accordingly, consolidated Cove Point. Because BHE controls Cove Point both before and after the Transaction, the changes in BHE's ownership interest in Cove Point were accounted for as an equity transaction and no gain or loss was recognized. In connection
with the Transaction, BHE recognized $i120 million of income taxes in equity primarily attributable to the step up in tax basis of the investment in Cove Point of $i144 million,
partially offset by establishing additional regulatory liabilities related to excess deferred income taxes of $i24 million.
Other
In 2022, the Company completed various acquisitions totaling $i314 million,
net of cash acquired. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related to residential real estate brokerage businesses, 300 MWs of long-term transmission rights and 399 MWs of wind-powered generating facilities. As a result of the various acquisitions, the Company acquired assets of $i363 million, assumed liabilities of $i65 million
and recognized goodwill of $i16 million.
In 2021, the Company completed various acquisitions totaling $i122 million, net of cash acquired. The purchase price for each acquisition
was allocated to the assets acquired and liabilities assumed, which related to residential real estate brokerage businesses. As a result of the various acquisitions, the Company acquired assets of $i54 million, assumed liabilities of $i61 million
and recognized goodwill of $i129 million.
146
(4)iProperty,
Plant and Equipment, Net
i
Property, plant and equipment, net consists of the following as of December 31 (in millions):
Depreciable Life
2023
2022
Regulated
assets:
Utility generation, transmission and distribution systems
i5-i80 years
$
i96,195
$
i92,759
Interstate
natural gas pipeline assets
i3-i80 years
i19,226
i18,328
i115,421
i111,087
Accumulated
depreciation and amortization
(i36,365)
(i34,599)
Regulated
assets, net
i79,056
i76,488
Nonregulated
assets:
Independent power plants
i2-i50 years
i8,484
i8,545
Cove
Point LNG facility
i40 years
i3,423
i3,412
Other
assets
i2-i30 years
i2,874
i2,693
i14,781
i14,650
Accumulated
depreciation and amortization
(i3,856)
(i3,452)
Nonregulated
assets, net
i10,925
i11,198
i89,981
i87,686
Construction
work-in-progress
i9,267
i5,357
Property,
plant and equipment, net
$
i99,248
$
i93,043
/
Construction
work-in-progress includes $i8.6 billion and $i4.9 billion as of December 31, 2023 and 2022, respectively, related to the construction of regulated assets.
(5)iJointly
Owned Utility Facilities
Under joint facility ownership agreements, the Domestic Regulated Businesses, as tenants in common, have undivided interests in jointly owned generation, transmission, distribution and pipeline common facilities. The Company accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include the Company's share of the expenses of these facilities.
147
i
The
amounts shown in the table below represent the Company's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2023 (dollars in millions):
Accumulated
Construction
Company
Facility
In
Depreciation and
Work-in-
Share
Service
Amortization
Progress
PacifiCorp:
Jim Bridger Nos. 1-4
i67
%
$
i1,596
$
i996
$
i26
Hunter
No. 1
i94
i510
i237
i4
Hunter
No. 2
i60
i316
i151
i2
Wyodak
i80
i491
i285
i—
Colstrip
Nos. 3 and 4
i10
i262
i199
i—
Hermiston
i50
i191
i111
i3
Craig
Nos. 1 and 2
i19
i372
i341
i—
Hayden
No. 1
i25
i77
i55
i—
Hayden
No. 2
i13
i45
i32
i—
Transmission
and distribution facilities
Various
i900
i283
i192
Total
PacifiCorp
i4,760
i2,690
i227
MidAmerican
Energy:
Louisa No. 1
i88
%
i983
i531
i5
Quad
Cities Nos. 1 and 2(1)
i25
i737
i496
i11
Walter
Scott, Jr. No. 3
i79
i1,017
i888
i14
Walter
Scott, Jr. No. 4(2)
i60
i170
i123
i8
George
Neal No. 4
i41
i330
i191
i6
Ottumwa
No. 1(2)
i52
i433
i299
i8
George
Neal No. 3
i72
i557
i375
i20
Transmission
facilities
Various
i274
i100
i3
Total
MidAmerican Energy
i4,501
i3,003
i75
NV
Energy:
Navajo
i11
%
i—
i2
i—
Valmy
i50
i405
i351
i4
On
Line Transmission Line
i25
i172
i42
i1
Transmission
facilities
Various
i64
i30
i6
Total
NV Energy
i641
i425
i11
BHE
Pipeline Group:
Ellisburg Pool
i39
%
i33
i12
i—
Ellisburg
Station
i50
i29
i9
i2
Harrison
i50
i56
i19
i1
Leidy
i50
i148
i49
i2
Oakford
i50
i216
i73
i4
Common
Facilities
Various
i275
i179
i—
Total
BHE Pipeline Group
i757
i341
i9
Total
$
i10,659
$
i6,459
$
i322
(1)Includes
amounts related to nuclear fuel.
/
(2)Facility in-service and accumulated depreciation and amortization amounts are net of credits applied under Iowa regulatory arrangements totaling $i891 million and $i183
million, respectively.
148
(6) iiLeases
/
i
The following table summarizes the Company's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
2023
2022
Right-of-use
assets:
Operating leases
$
i501
$
i545
Finance
leases
i399
i418
Total right-of-use assets
$
i900
$
i963
Lease
liabilities:
Operating leases
$
i555
$
i605
Finance
leases
i413
i432
Total lease liabilities
$
i968
$
i1,037
/
i
The
following table summarizes the Company's lease costs for the years ended December 31 (in millions):
2023
2022
2021
Variable
$
i439
$
i552
$
i611
Operating
i136
i136
i161
Finance:
Amortization
i21
i20
i23
Interest
i35
i36
i38
Short-term
i46
i44
i15
Total
lease costs
$
i677
$
i788
$
i848
Weighted-average
remaining lease term (years):
Operating leases
i7.4
i7.4
i7.6
Finance
leases
i27.5
i28.1
i28.1
Weighted-average
discount rate:
Operating leases
i4.5
%
i4.1
%
i4.3
%
Finance
leases
i8.6
%
i8.6
%
i8.6
%
/
i
The
following table summarizes the Company's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
2023
2022
2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating
cash flows from operating leases
$
(i138)
$
(i141)
$
(i163)
Operating
cash flows from finance leases
(i35)
(i36)
(i38)
Financing
cash flows from finance leases
(i27)
(i25)
(i28)
Right-of-use
assets obtained in exchange for lease liabilities:
Operating leases
$
i71
$
i131
$
i119
Finance
leases
i6
i3
i2
/
149
i
The
Company has the following remaining lease commitments as of December 31, 2023 (in millions):
Operating
Finance
Total
2024
$
i148
$
i63
$
i211
2025
i122
i62
i184
2026
i97
i62
i159
2027
i71
i58
i129
2028
i45
i52
i97
Thereafter
i170
i512
i682
Total
undiscounted lease payments
i653
i809
i1,462
Less
- amounts representing interest
(i98)
(i396)
(i494)
Lease
liabilities
$
i555
$
i413
$
i968
/
(7)iRegulatory
Matters
Regulatory Assets
i
Regulatory assets represent costs that are expected to be recovered in future regulated rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining Life
2023
2022
Deferred net power costs
i2
years
$
i1,769
$
i1,478
Asset
retirement obligations
i17 years
i930
i835
Deferred
income taxes(1)
Various
i435
i373
Employee
benefit plans(2)
i14 years
i414
i490
Demand
side management
i10 years
i245
i224
Unrealized
losses on regulated derivative contracts
i1 year
i173
i112
Levelized
depreciation
i28 years
i167
i151
Cost
of removal
i26 years
i143
i—
Environmental
costs
i30 years
i139
i111
Asset
disposition costs
Various
i135
i231
Wildfire mitigation and vegetation management
costs
Various
i114
i111
Other
Various
i901
i946
Total
regulatory assets
$
i5,565
$
i5,062
Reflected
as:
Current assets
$
i1,398
$
i1,319
Noncurrent
assets
i4,167
i3,743
Total
regulatory assets
$
i5,565
$
i5,062
(1)Amounts
primarily represent income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Includes amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
/
The Company had regulatory assets not earning a return on investment of $i3.2
billion and $i2.3 billion as of December 31, 2023 and 2022, respectively.
150
Regulatory Liabilities
Regulatory
liabilities represent income to be recognized or amounts to be returned to customers in future periods. iThe Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Cost of removal(1)
i26 years
$
i2,741
$
i2,578
Deferred
income taxes(2)
Various
i2,733
i2,901
Asset
retirement obligations
i30 years
i364
i250
Revenue
sharing mechanisms
Various
i243
i426
Levelized depreciation
i27
years
i230
i245
Employee benefit plans(3)
Various
i211
i180
Unrealized
gains on regulated derivative contracts
i1 year
i7
i343
Other
Various
i289
i446
Total
regulatory liabilities
$
i6,818
$
i7,369
Reflected
as:
Current liabilities
$
i174
$
i299
Noncurrent
liabilities
i6,644
i7,070
Total
regulatory liabilities
$
i6,818
$
i7,369
(1)Amounts
represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)Amounts primarily represent income tax liabilities related to the 2017 federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(3)Includes amounts not yet recognized as a component of net periodic benefit cost that are expected to be returned to customers in future periods when recognized.
151
(8)iInvestments
and Restricted Cash and Cash Equivalents and Investments
i
Investments and restricted cash and cash equivalents and investments consists of the following as of December 31 (in millions):
2023
2022
Investments:
BYD
Company Limited common stock
$
i2,218
$
i3,763
U.S.
Treasury Bills
i996
i1,931
Rabbi trusts
i487
i433
Other
i338
i335
Total
investments
i4,039
i6,462
Equity
method investments:
BHE Renewables tax equity investments
i4,058
i4,535
Electric
Transmission Texas, LLC
i673
i623
Iroquois Gas Transmission System, L.P.
i599
i600
Other
i381
i304
Total
equity method investments
i5,711
i6,062
Restricted
cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds
i767
i664
Other
restricted cash and cash equivalents
i246
i226
Total restricted cash and cash equivalents and investments
i1,013
i890
Total
investments and restricted cash and cash equivalents and investments
$
i10,763
$
i13,414
Reflected
as:
Other current assets
$
i1,253
$
i2,141
Noncurrent
assets
i9,510
i11,273
Total
investments and restricted cash and cash equivalents and investments
$
i10,763
$
i13,414
/
Investments
BHE's
investment in BYD Company Limited common stock is accounted for as a marketable security with changes in fair value recognized in net income.
Rabbi trusts primarily hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were established to hold investments used to fund the obligations of various nonqualified executive and director compensation plans and to pay the costs of the trusts. The amount represents the cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value.
i
Gains
(losses) on marketable securities, net recognized during the period consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Unrealized gains (losses) recognized on marketable securities held at the reporting date
$
i252
$
(i1,487)
$
i1,819
Net
gains (losses) recognized on marketable securities sold during the period
i417
(i515)
i4
Gains
(losses) on marketable securities, net
$
i669
$
(i2,002)
$
i1,823
/
152
Equity
Method Investments
The Company has invested in wind projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company made iino/
contributions in 2023 and 2022 and 2021. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
BHE, through separate subsidiaries, owns (i) i50% of Electric Transmission Texas, LLC, which owns and operates electric transmission assets in the Electric Reliability Council of Texas footprint; (ii) i50%
of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut; (iii) i50% of JAX LNG, LLC, which is an LNG supplier in Florida serving the growing marine and truck LNG markets; and (iv) i66.67% of Bridger
Coal Company ("Bridger Coal"), which is a coal mining joint venture that supplies coal to PacifiCorp's Jim Bridger Nos. 1-4 generating facility. Bridger Coal is being accounted for under the equity method of accounting as the power to direct the activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. Coal purchases from Bridger Coal for the years ended December 31, 2023, 2022 and 2021 totaled $i115 million,
$i100 million and $i132 million, respectively.
Restricted Investments
MidAmerican
Energy has established a trust for the investment of funds for decommissioning the Quad Cities Nuclear Station Units 1 and 2 ("Quad Cities Station"). The debt and equity securities in the trust are reported at fair value. Funds are invested in the trust in accordance with applicable federal and state investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station, which are currently licensed for operation until December 2032.
(9)iShort-term
Debt and Credit Facilities
i
The following table summarizes BHE's and its subsidiaries' availability under their credit facilities as of December 31 (in millions):
MidAmerican
NV
Northern
BHE
BHE
PacifiCorp
Funding
Energy
Powergrid
Canada
HomeServices
Total(1)
2023:
Credit
facilities(2)(3)
$
i3,500
$
i2,000
$
i1,509
$
i1,000
$
i346
$
i850
$
i1,500
$
i10,705
Less:
Short-term
debt
(i1,935)
(i1,604)
i—
i—
(i92)
(i97)
(i420)
(i4,148)
Tax-exempt
bond support and letters of credit
i—
(i249)
(i306)
i—
i—
(i1)
i—
(i556)
Net
credit facilities
$
i1,565
$
i147
$
i1,203
$
i1,000
$
i254
$
i752
$
i1,080
$
i6,001
2022:
Credit
facilities(2)
$
i3,500
$
i1,200
$
i1,509
$
i650
$
i296
$
i793
$
i2,925
$
i10,873
Less:
Short-term
debt
(i245)
i—
i—
i—
(i120)
(i197)
(i557)
(i1,119)
Tax-exempt
bond support and letters of credit
i—
(i249)
(i370)
i—
i—
(i1)
i—
(i620)
Net
credit facilities
$
i3,255
$
i951
$
i1,139
$
i650
$
i176
$
i595
$
i2,368
$
i9,134
(1)The
table does not include unused credit facilities and letters of credit for investments that are accounted for under the equity method.
(2)Includes $i92 million and $i55 million, respectively, drawn on capital expenditure and other uncommitted credit
facilities at Northern Powergrid as of December 31, 2023 and 2022.
(3)Excludes $i700 million from a credit facility at HomeServices that is unavailable due to borrowing restrictions pursuant to the credit agreement.
/
As
of December 31, 2023, the Company was in compliance with the covenants of its credit facilities and letter of credit arrangements.
153
BHE
BHE has a $i3.5 billion unsecured credit facility expiring
in June 2026 with an unlimited number of maturity extension options, subject to lender consent. This credit facility, which is for general corporate purposes, supports BHE's commercial paper program and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate ("SOFR") or a base rate, at BHE's option, plus a spread that varies based on BHE's credit ratings for its senior unsecured long-term debt securities.
As of December 31, 2023 and 2022, BHE had $i1,935
million and $i245 million of commercial paper borrowings outstanding at a weighted average interest rate of i5.59% and i4.55%,
respectively. The credit facility requires that BHE's ratio of consolidated debt, including current maturities, to total capitalization not exceed i0.70 to 1.0 as of the last day of each quarter.
As of December 31, 2023 and 2022, BHE had $i300 million
and $i450 million, respectively, of letter of credit capacity under its $i3.5 billion unsecured credit facility, of which iino/
amounts were outstanding. Additionally, as of December 31, 2023 and 2022, BHE had $i105 million and $i101 million, respectively,
of letters of credit outstanding outside of its $i3.5 billion unsecured credit facility, which primarily support power purchase agreements and debt service requirements at certain subsidiaries of BHE Renewables, LLC expiring through December 2024 and have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
PacifiCorp
PacifiCorp
has a $i2 billion unsecured credit facility expiring in June 2026 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on SOFR or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.
As
of December 31, 2023, PacifiCorp had $i1.6 billion of short-term debt outstanding at a weighted average rate of i6.16%, which was subsequently repaid in January 2024. As of December 31, 2022, PacifiCorp
had ino short-term debt outstanding.
The credit facility and the delayed draw term loan facility described in Note 11 require that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed i0.65
to 1.0 as of the last day of each quarter.
As of December 31, 2023, PacifiCorp had $i255 million of letter of credit capacity under its $i2.0
billion revolving credit facility of which $i31 million was outstanding and was utilized as a standby letter of credit, and $i168 million of letter of credit capacity outside of its $i2.0 billion
revolving credit facility, of which $i55 million was outstanding and was utilized in support of certain transactions required by third parties.
As of December 31, 2022, PacifiCorp had $i219 million
of letter of credit capacity under the $i1.2 billion revolving credit facility that was in place at that time, of which $i31 million was outstanding and was utilized as a standby letter of credit, and
$i7 million of letters of credit outstanding under committed arrangements outside of the facility in support of certain transactions required by third parties.
MidAmerican Funding
As of December 31, 2023, MidAmerican Energy has a $i1.5
billion unsecured credit facility expiring in June 2026 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on SOFR or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities.
As of December 31, 2023 and 2022, MidAmerican Energy had iino/
commercial paper borrowings outstanding. The $i1.5 billion credit facility requires that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed i0.65 to 1.0 as of the last day of any quarter.
154
As
of December 31, 2023 and 2022, MidAmerican Energy had $i345 million and $i371 million,
respectively, of letter of credit capacity under its $i1.5 billion unsecured credit facility, of which iino/
amounts were outstanding. Additionally, as of December 31, 2023 and 2022, MidAmerican Energy had $i55 million and $i34 million, respectively,
of letters of credit outstanding outside of its $i1.5 billion unsecured credit facility in support of certain transactions required by third parties that generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
NV Energy
Nevada Power has a $i600
million secured credit facility expiring in June 2026 and Sierra Pacific has a $i400 million secured credit facility expiring in June 2026 each with an unlimited number of maturity extension options, subject to lender consent. These credit facilities, which are for general corporate purposes and provide for the issuance of letters of credit, have a variable interest rate based on SOFR or a base rate, at each of the Nevada Utilities' option, plus a spread that varies based on each of the Nevada Utilities' credit ratings for its senior secured long‑term debt securities.
As of December 31, 2023 and 2022, the Nevada Utilities had iiiino///
borrowings outstanding under the credit facility. Amounts due under each credit facility are collateralized by each of the Nevada Utilities' general and refunding mortgage bonds. These credit facilities require that each of the Nevada Utilities' ratio of consolidated debt, including current maturities, to total capitalization not exceed ii0.65/
to 1.0 as of the last day of each quarter.
As of December 31, 2023, Nevada Power had $i50 million of letter of credit capacity under its $i600
million secured credit facility and Sierra Pacific had $i50 million of letter of credit capacity under its $i400 million secured credit facility, of which iino/
amounts were outstanding.
As of December 31, 2022, Nevada Power had $i100 million of letter of credit capacity under its $i400 million
secured credit facility and Sierra Pacific had $i75 million of letter of credit capacity under its $i250 million secured credit facility, of which iino/
amounts were outstanding.
Northern Powergrid
Northern Powergrid has a Łi200 million unsecured credit facility expiring in December 2026. The credit facility has a variable interest rate based on Sterling Overnight Index Average plus a spread that varies based on Northern Powergrid's credit ratings and a credit adjustment spread that varies based on the tenor of any borrowings. The credit facility requires
that the ratio of consolidated senior total net debt, including current maturities, to regulated asset value not exceed i0.8 to 1.0 at Northern Powergrid and i0.65 to 1.0 at each of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc as of June 30 and December 31. Northern Powergrid's interest coverage ratio shall not be less
than i2.5 to 1.0.
As of December 31, 2023 and 2022, Northern Powergrid had $i— million and $i65 million
outstanding under this facility at a weighted average interest rate of i—% and i3.56%, respectively.
BHE Canada
BHE
Canada has a C$i50 million unsecured revolving term credit facility expiring in December 2027 with a recurring ione-year extension option subject to lender consent. The credit facility, which may be used for general corporate purposes and letters of credit, has a variable
interest rate based on the Canadian bank prime lending rate, or a spread above the Canadian Overnight Repo Rate Average ("CORRA"), at BHE Canada's option, based on BHE Canada's senior unsecured credit rating. The credit facility requires the ratio of consolidated total debt to consolidated total capitalization not exceed i0.75 to 1.0 measured as of the last day of each quarter. In addition, BHE Canada is required to maintain a ratio of unconsolidated earnings before interest, taxes, depreciation and amortization to interest expense of not less than i2.25
to 1.00 measured as of the last day of each quarter.
As of December 31, 2023, BHE Canada had ino borrowings outstanding under the credit facility.
As of December 31, 2023, BHE Canada had C$i50 million
of letter of credit capacity under its C$i50 million unsecured revolving term credit facility, of which ino amount was outstanding.
155
AltaLink
AltaLink
has a C$i500 million secured revolving term credit facility expiring in December 2028 with a recurring ione-year extension option subject to lender consent. The credit facility, which supports AltaLink's commercial paper program and may also be used for general corporate
purposes, has a variable interest rate based on the Canadian bank prime lending rate or a spread above CORRA, at AltaLink's option, based on AltaLink's senior secured credit rating.
As of December 31, 2023 and 2022, AltaLink had $i97 million and $i89
million outstanding under the facility at a weighted average interest rate of i5.24% and i4.59%, respectively. The credit facility requires the ratio of consolidated indebtedness to total capitalization not exceed i0.75
to 1.0 measured as of the last day of each quarter.
AltaLink also has a C$i75 million secured revolving term credit facility expiring in December 2028 with a recurring ione-year extension
option subject to lender consent. The credit facility, which may be used for general corporate purposes and letters of credit, has a variable interest rate based on the Canadian bank prime lending rate, or a spread above CORRA, at AltaLink's option, based on AltaLink's senior secured credit rating.
As of December 31, 2023 and 2022, AltaLink had iino/
borrowings outstanding under the facility. The credit facility requires the ratio of consolidated indebtedness to total capitalization not exceed i0.75 to 1.0 measured as of the last day of each quarter.
As of December 31, 2023 and 2022, AltaLink had C$ii75/ million
of letter of credit capacity under its C$i75 million secured revolving term credit facility, of which C$i1 million and C$i—
million were outstanding.
AltaLink Investments, L.P. has a C$i300 million unsecured revolving term credit facility expiring in December 2026 with a recurring ione-year extension option
subject to lender consent. The credit facility, which may be used for general corporate purposes and letters of credit, has a variable interest rate based on the Canadian bank prime lending rate, or a spread above the Bankers' Acceptance rate, at AltaLink Investments, L.P.'s option, based on AltaLink Investments, L.P.'s senior unsecured credit rating.
AltaLink Investments, L.P. also has a C$i200 million revolving term credit facility. The credit facility, which may be used for general corporate
purposes and letters of credit, has a variable interest rate based on the Canadian bank prime lending rate, or a spread above CORRA, at AltaLink Investments, L.P.'s option, based on AltaLink Investments, L.P.'s credit ratings for its senior unsecured credit rating. This facility was terminated on January 8, 2024.
As of December 31, 2023 and 2022, AltaLink Investments, L.P. had $i— million and $i108
million outstanding under these facilities at a weighted average interest rate of i—% and i5.71%, respectively. The credit facilities require the ratio of consolidated total debt to capitalization not exceed i0.8
to 1.0 and earnings before interest, taxes, depreciation and amortization to interest expense for the four fiscal quarters ended not be less than i2.25 to 1.0 measured as of the last day of each quarter.
As of December 31, 2023 and 2022, AltaLink Investments, L.P. had C$ii10/ million
of letter of credit capacity under its C$i300 million unsecured revolving term credit facility, of which iino/
amounts were outstanding.
As of December 31, 2023 and 2022, AltaLink Investments, L.P. had C$ii10/ million
of letter of credit capacity under its C$i200 million revolving term credit facility, of which iino/
amounts were outstanding.
HomeServices
HomeServices has a $i700 million unsecured credit facility expiring in September 2026. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on SOFR or a base rate, at HomeServices' option, plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of
each quarter. As of December 31, 2023 and 2022, HomeServices had $i— million and $i115 million, respectively, outstanding under its credit facility with a weighted average interest rate of i—%
and i5.17%, respectively. The credit facility is unavailable due to borrowing restrictions pursuant to the credit agreement.
156
Through its subsidiaries, HomeServices maintains mortgage lines of credit totaling $i1.5
billion and $i2.2 billion as of December 31, 2023 and 2022, respectively, used for mortgage banking activities that expire beginning in March 2024 through July 2024. The mortgage lines of credit have variable rates based on SOFR, plus a spread. Collateral for these credit facilities is comprised of residential property being financed and is equal to the loans funded with the facilities. As of December 31, 2023 and 2022,
HomeServices had $i420 million and $i442 million, respectively, outstanding under these mortgage lines of credit at a weighted average interest rate of i6.92%
and i6.09%, respectively.
BHE Renewables Letters of Credit
As of December 31, 2023 and 2022, certain renewable projects collectively have letters of credit outstanding of $i311 million
and $i309 million, respectively, primarily in support of the power purchase agreements and large generator interconnection agreements associated with the projects.
(10)iBHE
Debt
Senior Debt
BHE senior debt represents unsecured senior obligations of BHE that are redeemable in whole or in part at any time generally with make whole premiums. iBHE senior debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (in millions):
Par
Value
2023
2022
i2.80% Senior Notes, due 2023
$
i—
$
i—
$
i400
i3.75%
Senior Notes, due 2023
i—
i—
i500
i3.50%
Senior Notes, due 2025
i400
i399
i398
i4.05%
Senior Notes, due 2025
i1,250
i1,248
i1,245
i3.25%
Senior Notes, due 2028
i600
i593
i594
i8.48%
Senior Notes, due 2028
i256
i264
i266
i3.70%
Senior Notes, due 2030
i1,100
i1,096
i1,095
i1.65%
Senior Notes, due 2031
i500
i498
i497
i6.125%
Senior Bonds, due 2036
i1,670
i1,663
i1,661
i5.95%
Senior Bonds, due 2037
i550
i548
i548
i6.50%
Senior Bonds, due 2037
i225
i223
i223
i5.15%
Senior Notes, due 2043
i750
i741
i740
i4.50%
Senior Notes, due 2045
i750
i739
i738
i3.80%
Senior Notes, due 2048
i750
i736
i738
i4.45%
Senior Notes, due 2049
i1,000
i990
i990
i4.25%
Senior Notes, due 2050
i900
i889
i889
i2.85%
Senior Notes, due 2051
i1,500
i1,488
i1,487
i4.60%
Senior Notes, due 2053
i1,000
i986
i987
Total
BHE Senior Debt
$
i13,201
$
i13,101
$
i13,996
Reflected
as:
Current liabilities
$
i—
$
i900
Noncurrent
liabilities
i13,101
i13,096
Total
BHE Senior Debt
$
i13,101
$
i13,996
Junior
Subordinated Debentures
BHE junior subordinated debentures consists of the following as of December 31 (in millions):
157
Par Value
2023
2022
i5.00%
Junior subordinated debentures, due 2057
i100
i100
i100
Total
BHE junior subordinated debentures - noncurrent
$
i100
$
i100
$
i100
The
junior subordinated debentures are held by a minority shareholder and are redeemable at BHE's option at any time from and after June 15, 2037, at par plus accrued and unpaid interest. Interest expense to the minority shareholder was $iii5//
million for each of the years ended December 31, 2023, 2022 and 2021.
(11)iSubsidiary Debt
BHE's direct and indirect subsidiaries are organized as legal entities separate and apart from BHE
and its other subsidiaries. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties; the equity interest of MidAmerican Funding's subsidiary; MidAmerican Energy's electric utility properties in the state of Iowa; substantially all of Nevada Power's and Sierra Pacific's properties in the state of Nevada; AltaLink's transmission properties; and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of wind and solar generation projects are pledged or encumbered to support or otherwise provide the security for their related subsidiary debt. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements
for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The long-term debt of BHE's subsidiaries may include provisions that allow BHE's subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums.
Distributions at these separate legal entities are limited by various covenants including, among others, leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2023, all subsidiaries were in compliance with their long-term debt covenants.
Long-term debt of subsidiaries consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as
of December 31 (in millions):
Par Value
2023
2022
PacifiCorp
$
i10,493
$
i10,410
$
i9,666
MidAmerican
Funding
i9,115
i8,992
i7,954
NV
Energy
i4,736
i4,695
i4,354
Northern
Powergrid
i3,497
i3,465
i3,054
BHE
Pipeline Group
i4,876
i5,154
i5,849
BHE
Transmission
i3,591
i3,574
i3,495
BHE
Renewables
i2,571
i2,548
i3,027
HomeServices
i133
i133
i140
Total
subsidiary debt
$
i39,012
$
i38,971
$
i37,539
Reflected
as:
Current liabilities
$
i2,740
$
i2,301
Noncurrent
liabilities
i36,231
i35,238
Total
subsidiary debt
$
i38,971
$
i37,539
158
PacifiCorp
PacifiCorp's
long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs as of December 31 (dollars in millions):
Par Value
2023
2022
First mortgage bonds:
i2.95%
to i8.23%, due through 2026
$
i775
$
i774
$
i1,223
i2.70%
to i7.70%, due 2029 to 2031
i1,100
i1,096
i1,095
i5.25%
to i6.35%, due 2034 to 2038
i2,350
i2,341
i2,340
i4.10%
to i6.00%, due 2039 to 2042
i950
i942
i941
i2.90%
to i5.50%, due 2049 to 2054
i5,100
i5,039
i3,849
Variable-rate
series, tax-exempt bond obligations (2023-i4.60% to i5.60%; 2022-i3.75%
to i4.10%):
Due 2025
i25
i25
i25
Due
2024 to 2025(1)
i193
i193
i193
Total
PacifiCorp
$
i10,493
$
i10,410
$
i9,666
(1)Secured
by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations.
In December 2023, PacifiCorp entered into a $i900 million unsecured delayed draw term loan facility expiring in June 2025. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at PacifiCorp's option, plus a pricing margin. Subject to regulatory authority to issue long-term
debt, PacifiCorp may draw all or none of the unused commitment up to three times through June 2025. As of December 31, 2023, PacifiCorp had no term loans drawn from the facility and currently has no authority to issue additional long-term debt until additional filings occur with the Oregon Public Utility Commission ("OPUC") and the Idaho Public Utilities Commission ("IPUC") and are approved as described below.
In January 2024, PacifiCorp issued $i500 million of its i5.10%
First Mortgage Bonds due February 2029, $i700 million of its i5.30% First Mortgage Bonds due February 2031, $i1.1 billion
of its i5.45% First Mortgage Bonds due February 2034 and $i1.5 billion of its i5.80%
First Mortgage Bonds due January 2055 for a total of $i3.8 billion. PacifiCorp initially used a portion of the net proceeds to repay outstanding short-term debt and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.
Following PacifiCorp's January 2024 First Mortgage Bond issuances, PacifiCorp currently has no remaining regulatory authority from the OPUC and the IPUC to issue additional long-term debt. PacifiCorp must apply for additional issuance authority from the OPUC and IPUC
and make a notice filing with the Washington Utilities and Transportation Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the U.S. Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds through September 2026.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $i36 billion of PacifiCorp's eligible property
(based on original cost) was subject to the lien of the mortgage as of December 31, 2023.
159
MidAmerican Funding
MidAmerican Funding's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par
Value
2023
2022
MidAmerican Funding:
i6.927% Senior Bonds, due 2029
$
i239
$
i240
$
i240
Fair
value adjustment
—
(i14)
(i15)
MidAmerican
Funding, net of fair value adjustments
i239
i226
i225
MidAmerican
Energy:
First Mortgage Bonds:
i3.70%, due 2023
i—
i—
i250
i3.50%,
due 2024
i500
i500
i500
i3.10%,
due 2027
i375
i374
i374
i3.65%,
due 2029
i850
i858
i859
i4.80%,
due 2043
i350
i347
i347
i4.40%,
due 2044
i400
i396
i395
i4.25%,
due 2046
i450
i446
i446
i3.95%,
due 2047
i475
i471
i471
i3.65%,
due 2048
i700
i690
i689
i4.25%,
due 2049
i900
i876
i875
i3.15%,
due 2050
i600
i592
i592
i2.70%,
due 2052
i500
i492
i492
i5.35%,
due 2034
i350
i347
i—
i5.85%,
due 2054
i1,000
i989
i—
Notes:
i6.75%
Series, due 2031
i400
i398
i397
i5.75%
Series, due 2035
i300
i299
i298
i5.80%
Series, due 2036
i350
i348
i348
Transmission
upgrade obligation, i3.24% to i7.84%, due 2036 to 2043
i70
i39
i27
Tax-exempt
bond obligations -
Variable-rate tax-exempt bond obligation series: (weighted average interest rate - 2023-i4.81%, 2022-i3.83%),
due 2023-2047
i306
i304
i369
Total
MidAmerican Energy
i8,876
i8,766
i7,729
Total
MidAmerican Funding
$
i9,115
$
i8,992
$
i7,954
In
January 2024, MidAmerican Energy issued $i600 million of its i5.30% First Mortgage Bonds due February 2055. MidAmerican Energy intends, within i24
months of the issuance date, to allocate an amount equal to the net proceeds to finance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.
Pursuant to MidAmerican Energy's mortgage dated September 9, 2013, MidAmerican Energy's first mortgage bonds, currently and from time to time outstanding, are secured by a first mortgage lien on substantially all of its electric generating, transmission and distribution property within the state of Iowa, subject to certain exceptions and permitted encumbrances. Approximately $i24
billion of MidAmerican Energy's eligible property, based on original cost, was subject to the lien of the mortgage as of December 31, 2023. Additionally, MidAmerican Energy's senior notes outstanding are equally and ratably secured with the first mortgage bonds as required by the indentures under which the senior notes were issued.
160
MidAmerican Energy's variable-rate tax-exempt obligations bear interest at rates that are periodically established through remarketing of the bonds in the short-term tax-exempt market. MidAmerican Energy, at its option, may change the mode of interest calculation for these bonds by selecting from among several floating or fixed rate alternatives.
The interest rates shown in the table above are the weighted average interest rates as of December 31, 2023 and 2022. MidAmerican Energy maintains revolving credit facility agreements to provide liquidity for holders of these issues. Additionally, MidAmerican Energy's obligations associated with $i30 million and $i150
million of the variable rate, tax-exempt bond obligations due 2046 and 2047, respectively, are secured by an equal amount of first mortgage bonds pursuant to MidAmerican Energy's mortgage dated September 9, 2013, as supplemented and amended.
NV Energy
NV Energy's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par
Value
2023
2022
Nevada Power:
General and refunding mortgage securities:
i3.700%
Series CC, due 2029
$
i500
$
i498
$
i497
i2.400%
Series DD, due 2030
i425
i423
i422
i6.650%
Series N, due 2036
i367
i360
i360
i6.750%
Series R, due 2037
i349
i346
i346
i5.375%
Series X, due 2040
i250
i248
i248
i5.450%
Series Y, due 2041
i250
i240
i239
i3.125%
Series EE, due 2050
i300
i298
i298
i5.900%
Series GG, due 2053
i400
i394
i394
i6.000%
Series 2023A, due 2054
i500
i494
i—
Tax-exempt
refunding revenue bond obligations:
Fixed-rate series:
i4.125% Pollution Control Bonds Series 2017A, due 2032(1)
i40
i39
i39
i3.750%
Pollution Control Bonds Series 2017, due 2036(1)
i40
i39
i39
i3.750%
Pollution Control Bonds Series 2017B, due 2039(1)
i13
i13
i13
Variable-rate
i4.821% Term Loan, due 2024(2)
i—
i—
i300
Total
Nevada Power
i3,434
i3,392
i3,195
Fair
value adjustments
—
i9
i10
Total
Nevada Power, net of fair value adjustments
i3,434
i3,401
i3,205
Sierra
Pacific:
General and refunding mortgage securities:
i3.375% Series T, due 2023
i—
i—
i249
i2.600%
Series U, due 2026
i400
i398
i397
i6.750%
Series P, due 2037
i252
i254
i254
i4.710%
Series W, due 2052
i250
i248
i248
i5.900%
Series 2023A, due 2054
i400
i393
i—
Total
Sierra Pacific
i1,302
i1,293
i1,148
Fair
value adjustments
—
i1
i1
Total
Sierra Pacific, net of fair value adjustment
i1,302
i1,294
i1,149
Total
NV Energy
$
i4,736
$
i4,695
$
i4,354
(1) Subject
to mandatory purchase by Nevada Power in March 2026 at which date the interest rate may be adjusted.
(2) Amounts borrowed under the facility bear interest at variable rates based on SOFR or a base rate, at Nevada Power's option, plus a pricing margin.
161
In February 2024, Sierra Pacific entered into a re-offering of the following series of fixed-rate tax exempt bonds: $i75 million
of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $i60 million of Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds, Series 2016B, due 2036; $i30 million of Humboldt County, Nevada Pollution Control Refunding
Revenue Bonds, Series 2016B, due 2029; $i30 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $i20 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016A due 2029; and $i20 million
of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Humboldt County Series 2016A and Series 2016B bonds were offered at a term rate of ii3.550/%.
The Washoe County Series 2016B and Series 2016G bonds were offered at a fixed rate of ii3.625/% and the Washoe County
Series 2016C and Series 2016F bonds were offered at a fixed rate of ii4.125/%. Sierra Pacific previously purchased
the bonds as required by the bond indentures. Sierra Pacific used the net proceeds of the re-offering for general corporate purposes.
The issuance of General and Refunding Mortgage Securities by the Nevada Utilities are subject to PUCN approval and are limited by available property and other provisions of the mortgage indentures for each of Nevada Power and Sierra Pacific. As of December 31, 2023, approximately $i10 billion of Nevada Power's and $i5
billion of Sierra Pacific's (based on original cost) property was subject to the liens of the mortgages.
Northern Powergrid
Northern Powergrid and its subsidiaries' long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par Value(1)
2023
2022
i2.50%
Bonds, due 2025
$
i191
$
i191
$
i181
i2.073%
European Investment Bank loan, due 2025
i64
i65
i62
i2.564%
European Investment Bank loans, due 2027
i318
i317
i301
i7.25%
Bonds, due 2028
i236
i238
i227
i4.375%
Bonds, due 2032
i191
i189
i179
i5.625%
Bonds, due 2033
i318
i314
i—
i5.125%
Bonds, due 2035
i255
i252
i240
i5.125%
Bonds, due 2035
i191
i189
i180
i2.75%
Bonds, due 2049
i191
i188
i178
i3.25%
Bonds, due 2052
i445
i442
i419
i2.25%
Bonds, due 2059
i382
i374
i355
i1.875%
Bonds, due 2062
i382
i375
i356
Variable-rate
loan, due 2025(2)
i158
i158
i164
Variable-rate
loan, due 2026(3)
i175
i173
i212
Total
Northern Powergrid
$
i3,497
$
i3,465
$
i3,054
(1)The
par values for these debt instruments are denominated in sterling.
(2)Amortizes quarterly and the loan is i70% floating and i30% fixed. The Company has entered into an interest rate swap that fixes
the interest rate on i100% of the floating rate portion. The variable interest rate as of December 31, 2023, was i6.41% (including i2.00%
margin) and the average fixed interest rate was i3.08% (including i2.00% margin).
(3)Amortizes semiannually and the Company has entered
into an interest rate swap that fixes the interest rate on i80% of the outstanding debt. The variable interest rate as of December 31, 2023 was i6.74% (including i1.55%
margin) and the fixed interest rate was i2.45% (including i1.55% margin), resulting in a blended rate of i3.30%.
162
BHE
Pipeline Group
BHE Pipeline Group's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par Value
2023
2022
Eastern Energy Gas:
i2.875%
Senior Notes, due 2023
$
i—
$
i—
$
i250
i3.55%
Senior Notes, due 2023
i—
i—
i399
i2.50%
Senior Notes, due 2024
i600
i600
i598
i3.60%
Senior Notes, due 2024
i339
i339
i338
i3.32%
Senior Notes, due 2026 (€i250)(1)
i276
i274
i267
i3.00%
Senior Notes, due 2029
i174
i173
i173
i3.80%
Senior Notes, due 2031
i150
i150
i150
i4.80%
Senior Notes, due 2043
i54
i53
i53
i4.60%
Senior Notes, due 2044
i56
i56
i56
i3.90%
Senior Notes, due 2049
i27
i26
i26
EGTS:
i3.60%
Senior Notes, due 2024
i111
i111
i110
i3.00%
Senior Notes, due 2029
i426
i422
i422
i4.80%
Senior Notes, due 2043
i346
i342
i342
i4.60%
Senior Notes, due 2044
i444
i437
i437
i3.90%
Senior Notes, due 2049
i273
i271
i271
Total
Eastern Energy Gas
i3,276
i3,254
i3,892
Fair
value adjustments
—
i312
i368
Total
Eastern Energy Gas, net of fair value adjustments
i3,276
i3,566
i4,260
Northern
Natural Gas:
i5.80% Senior Bonds, due 2037
i150
i149
i149
i4.10%
Senior Bonds, due 2042
i250
i248
i248
i4.30%
Senior Bonds, due 2049
i650
i651
i652
i3.40%
Senior Bonds, due 2051
i550
i540
i540
Total
Northern Natural Gas
i1,600
i1,588
i1,589
Total
BHE Pipeline Group
$
i4,876
$
i5,154
$
i5,849
(1) The
senior notes are denominated in Euros with an outstanding principal balance of €i250 million and a fixed interest rate of i1.45%. Eastern Energy Gas has entered into cross currency swaps that fix USD payments for i100%
of the notes. The fixed USD outstanding principal when combined with the swaps is $ii280/ million,
with fixed interest rates at both December 31, 2023 and 2022 that averaged ii3.32/%.
In
January 2024, Northern Natural Gas issued $i500 million of its i5.625% Senior Bonds due February 2054. Northern Natural Gas intends to use the net proceeds from the sale of the bonds for general corporate purposes, including to fund capital expenditures.
163
BHE
Transmission
BHE Transmission's long-term debt consists of the following, including fair value adjustments and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par Value(1)
2023
2022
AltaLink,
L.P.:
Series 2013-4 Notes, i3.668%, due 2023
$
i—
$
i—
$
i369
Series
2014-1 Notes, i3.399%, due 2024
i264
i264
i258
Series
2016-1 Notes, i2.747%, due 2026
i264
i264
i258
Series
2020-1 Notes, i1.509%, due 2030
i170
i169
i165
Series
2022-1 Notes, i4.692%, due 2032
i208
i207
i202
Series
2006-1 Notes, i5.249%, due 2036
i113
i113
i111
Series
2010-1 Notes, i5.381%, due 2040
i94
i94
i92
Series
2010-2 Notes, i4.872%, due 2040
i113
i113
i110
Series
2011-1 Notes, i4.462%, due 2041
i208
i207
i202
Series
2012-1 Notes, i3.990%, due 2042
i396
i391
i383
Series
2013-3 Notes, i4.922%, due 2043
i264
i263
i258
Series
2014-3 Notes, i4.054%, due 2044
i223
i222
i216
Series
2015-1 Notes, i4.090%, due 2045
i264
i263
i257
Series
2016-2 Notes, i3.717%, due 2046
i340
i338
i330
Series
2013-1 Notes, i4.446%, due 2053
i189
i188
i184
Series
2023-1 Notes, i5.463%, due 2055
i378
i375
i—
Series
2014-2 Notes, i4.274%, due 2064
i98
i98
i95
Total
AltaLink, L.P.
i3,586
i3,569
i3,490
Other:
Construction
Loan, i5.620%, due 2024
i5
i5
i5
Total
BHE Transmission
$
i3,591
$
i3,574
$
i3,495
(1)The
par values for these debt instruments are denominated in Canadian dollars.
164
BHE Renewables
BHE Renewables' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par
Value
2023
2022
Fixed-rate(1):
Bishop Hill Holdings Senior Notes, i5.125%, due 2032
$
i51
$
i50
$
i56
Solar
Star Funding Senior Notes, i3.950%, due 2035
i230
i228
i242
Solar
Star Funding Senior Notes, i5.375%, due 2035
i744
i739
i781
Grande
Prairie Wind Senior Notes, i3.860%, due 2037
i236
i234
i267
Topaz
Solar Farms Senior Notes, i5.750%, due 2039
i541
i536
i568
Topaz
Solar Farms Senior Notes, i4.875%, due 2039
i152
i151
i160
Alamo
6 Senior Notes, i4.170%, due 2042
i181
i179
i188
Variable-rate(1):
TX
Jumbo Road Term Loan, due 2025(2)
i73
i72
i96
Marshall
Wind Term Loan, due 2026(2)
i49
i49
i56
Flat
Top Wind I Term Loan, due 2028(2)
i—
i—
i99
Mariah
Del Norte Term Loan, due 2028(2)
i—
i—
i54
Mariah
Del Norte Term Loan, due 2032(2)
i—
i—
i138
Pinyon
Pines I and II Term Loans, due 2034(2)
i314
i310
i322
Total
BHE Renewables
$
i2,571
$
i2,548
$
i3,027
(1)Amortizes
quarterly or semiannually.
(2)The term loans have variable interest rates based on SOFR plus a margin that varies during the terms of the agreements. The Company has entered into interest rate swaps that fix the interest rate on i100% of the TX Jumbo Road, Marshall Wind and Pinyon Pines outstanding debt. The fixed interest rates as of December 31, 2023 and 2022 ranged from ii3.23/%
to ii3.88/%. The variable interest rate on the Flat Top Wind I and Mariah Del Norte outstanding
debt was i9.82% as of December 31, 2022.
HomeServices
HomeServices' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par
Value
2023
2022
Variable-rate:
Variable-rate term loan (2023 - i6.27%, 2022 - i5.242%),
due 2026(1)
$
i133
$
i133
$
i140
(1)Term
loan amortizes quarterly and variable-rate resets monthly.
165
Annual Repayments of Long-Term Debt
i
The annual repayments of BHE and subsidiary debt for the years beginning January 1, 2024 and thereafter, excluding fair value adjustments and unamortized premiums, discounts and
debt issuance costs, are as follows (in millions):
2029
and
2024
2025
2026
2027
2028
Thereafter
Total
BHE
senior notes
$
i—
$
i1,650
$
i—
$
i—
$
i856
$
i10,695
$
i13,201
BHE
junior subordinated debentures
i—
i—
i—
i—
i—
i100
i100
PacifiCorp
i591
i302
i100
i—
i—
i9,500
i10,493
MidAmerican
Funding
i539
i17
i4
i379
i4
i8,172
i9,115
NV
Energy
i—
i—
i400
i—
i—
i4,336
i4,736
Northern
Powergrid
i62
i449
i79
i318
i236
i2,353
i3,497
BHE
Pipeline Group
i1,050
i—
i276
i—
i—
i3,550
i4,876
BHE
Transmission
i269
i—
i264
i—
i—
i3,058
i3,591
BHE
Renewables
i220
i241
i218
i168
i175
i1,549
i2,571
HomeServices
i9
i15
i109
i—
i—
i—
i133
Totals
$
i2,740
$
i2,674
$
i1,450
$
i865
$
i1,271
$
i43,313
$
i52,313
/
(12)iIncome
Taxes
The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated U.S. federal and Iowa state income tax returns and the majority of the Company's U.S. federal income tax is remitted to or received from Berkshire Hathaway. The Company had a current income tax receivable from Berkshire Hathaway of $i96 million and a current income tax payable to Berkshire Hathaway of $i113 million
for federal income tax as of December 31, 2023 and 2022, respectively. In July 2022, the Company amended its tax allocation agreement with Berkshire Hathaway, which changed how state tax attributes will be settled with respect to state income tax returns that Berkshire Hathaway includes the Company. As a result, the Company no longer expects to receive the cash benefits from the state of Iowa net operating loss carryforward previously recorded as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity, and recognized a noncash distribution of $i744 million
to retained earnings.
i
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Current:
Federal
$
(i1,650)
$
(i1,463)
$
(i1,701)
State
i118
(i65)
(i177)
Foreign
i90
i79
i100
(i1,442)
(i1,449)
(i1,778)
Deferred:
Federal
(i114)
(i408)
i1,037
State
(i275)
(i49)
(i476)
Foreign
i33
(i5)
i89
(i356)
(i462)
i650
Investment
tax credits
i99
(i5)
(i4)
Total
$
(i1,699)
$
(i1,916)
$
(i1,132)
/
166
i
A
reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense (benefit) is as follows for the years ended December 31:
2023
2022
2021
Federal
statutory income tax rate
i21
%
i21
%
i21
%
Income
tax credits
(i85)
(i124)
(i27)
Effects
of ratemaking
(i11)
(i16)
(i4)
State
income tax, net of federal income tax benefit
(i6)
(i6)
(i10)
Non-controlling
interest
(i4)
(i6)
(i2)
Income
tax effect of foreign income
(i1)
(i4)
(i1)
Tax
rate change - deferred (foreign)
i2
i—
i2
Equity
loss
(i3)
(i3)
(i1)
Other,
net
i—
i2
i1
Effective
income tax rate
(i87)
%
(i136)
%
(i21)
%
/
Income
tax credits relate primarily to production tax credits ("PTC") from wind- and solar-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind- and solar-powered generating facilities are eligible for the credits for i10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the years ended December 31,
2023, 2022 and 2021 totaled $i1.7 billion, $i1.7 billion, and $i1.4
billion, respectively.
Tax rate change - deferred (foreign) includes a deferred income tax charge of $i45 million in 2023, related to the United Kingdom's Energy Profits Levy. The Energy Profits Levy increased from 25% to 35%, effective January 1, 2023. It also includes a deferred income tax charge of $i105 million
in 2021, related to the United Kingdom's corporate income tax rate. The United Kingdom's rate increased from 19% to 25%, effective April 1, 2023, through legislation enacted in June 2021.
i
The net deferred income tax liability consists of the following as of December 31 (in millions):
2023
2022
Deferred
income tax assets:
Regulatory liabilities
$
i1,248
$
i1,323
Federal,
state and foreign carryforwards
i774
i812
AROs
i318
i283
Loss
contingency
i431
i109
Other
i629
i632
Total
deferred income tax assets
i3,400
i3,159
Valuation
allowances
(i142)
(i187)
Total deferred income tax assets, net
i3,258
i2,972
Deferred
income tax liabilities:
Property-related items
(i12,596)
(i12,244)
Investments
(i1,574)
(i1,998)
Regulatory
assets
(i1,034)
(i898)
Other
(i491)
(i510)
Total
deferred income tax liabilities
(i15,695)
(i15,650)
Net
deferred income tax liability
$
(i12,437)
$
(i12,678)
/
167
i
The
following table provides, without regard to valuation allowances, the Company's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2023 (in millions):
Federal
State
Foreign
Total
Net
operating loss carryforwards(1)
$
i119
$
i9,850
$
i688
$
i10,657
Deferred
income taxes on net operating loss carryforwards
i25
i547
i158
i730
Expiration
dates
2024 - indefinite
2024 - indefinite
2028 - 2043
Tax credits
$
i15
$
i29
$
i—
$
i44
Expiration
dates
2024 - 2034
2024 - indefinite
(1)The federal net operating loss carryforwards relate principally to net operating loss carryforwards of subsidiaries that are tax residents in both the U.S. and the United Kingdom. The federal net operating loss carryforwards were generated prior to Berkshire Hathaway Inc.'s ownership and began to expire in 2022.
/
The
U.S. Internal Revenue Service has closed or effectively settled its examination of the Company's income tax returns through December 31, 2013. The statute of limitations for the Company's income tax returns have expired for certain states through December 31, 2011, and for other states through December 31, 2019, except for the impact of any federal audit adjustments. The closure of examinations, or the expiration of the statute of limitations, for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
i
A
reconciliation of the beginning and ending balances of the Company's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
2023
2022
Beginning balance
$
i68
$
i97
Additions
based on tax positions related to the current year
i10
i15
Additions
for tax positions of prior years
i1
i—
Reductions
based on tax positions related to the current year
(i6)
(i12)
Reductions
for tax positions of prior years
i—
(i23)
Statute
of limitations
(i1)
i—
Interest
and penalties
i1
(i9)
Ending
balance
$
i73
$
i68
/
As
of December 31, 2023 and 2022, the Company had unrecognized tax benefits totaling $i88 million and $i79 million,
respectively, that if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company's effective income tax rate.
168
(13)iEmployee
Benefit Plans
Defined Benefit Plans
Domestic Operations
PacifiCorp, MidAmerican Energy and NV Energy sponsor defined benefit pension plans that cover a majority of all employees of BHE and its domestic energy subsidiaries. These pension plans include noncontributory defined benefit pension plans, supplemental executive retirement plans ("SERP") and restoration plans. PacifiCorp, MidAmerican Energy and NV Energy also provide certain postretirement healthcare and life insurance benefits through various plans to eligible retirees.
Net Periodic Benefit Cost
For
purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is generally calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.
i
Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):
Pension
Other
Postretirement
2023
2022
2021
2023
2022
2021
Service cost
$
i15
$
i22
$
i30
$
i8
$
i11
$
i12
Interest
cost
i110
i83
i78
i30
i20
i19
Expected
return on plan assets
(i123)
(i108)
(i134)
(i33)
(i29)
(i22)
Curtailment
i—
(i10)
i—
i—
i—
i—
Settlement
(i3)
i17
i3
i—
i—
i—
Net
amortization
i14
i19
i25
(i2)
(i1)
(i3)
Net
periodic benefit cost
$
i13
$
i23
$
i2
$
i3
$
i1
$
i6
/
Funded
Status
i
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
Pension
Other
Postretirement
2023
2022
2023
2022
Plan assets at fair value, beginning of year
$
i2,013
$
i2,795
$
i614
$
i769
Employer
contributions
i14
i14
i6
i8
Participant
contributions
i—
i—
i8
i8
Actual
return on plan assets
i219
(i491)
i86
(i122)
Settlement
i—
(i164)
i—
i—
Benefits
paid
(i177)
(i141)
(i49)
(i49)
Plan
assets at fair value, end of year
$
i2,069
$
i2,013
$
i665
$
i614
/
169
i
The
following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension
Other Postretirement
2023
2022
2023
2022
Benefit
obligation, beginning of year
$
i2,040
$
i2,777
$
i569
$
i714
Service
cost
i15
i22
i8
i11
Interest
cost
i110
i83
i30
i20
Participant
contributions
i—
i—
i8
i8
Actuarial
loss (gain)
i62
(i524)
(i1)
(i155)
Amendment
i—
(i3)
i—
i20
Curtailment
i—
(i10)
i—
i—
Settlement
i—
(i164)
i—
i—
Benefits
paid
(i177)
(i141)
(i49)
(i49)
Benefit
obligation, end of year
$
i2,050
$
i2,040
$
i565
$
i569
Accumulated
benefit obligation, end of year
$
i2,013
$
i2,003
/
i
The
funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
Pension
Other Postretirement
2023
2022
2023
2022
Plan
assets at fair value, end of year
$
i2,069
$
i2,013
$
i665
$
i614
Benefit
obligation, end of year
i2,050
i2,040
i565
i569
Funded
status
$
i19
$
(i27)
$
i100
$
i45
Amounts
recognized on the Consolidated Balance Sheets:
Other assets
$
i160
$
i125
$
i104
$
i52
Other
current liabilities
(i13)
(i13)
i—
i—
Other
long-term liabilities
(i128)
(i139)
(i4)
(i7)
Amounts
recognized
$
i19
$
(i27)
$
i100
$
i45
/
The
SERPs and restoration plan have no plan assets; however, the Company has Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERPs and restoration plan. The cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $i341 million and $i300
million as of December 31, 2023 and 2022, respectively. These assets are not included in the plan assets in the above table, but are reflected in noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets.
170
i
The
fair value of plan assets, projected benefit obligation and accumulated benefit obligation for (1) pension and other postretirement benefit plans with a projected benefit obligation in excess of the fair value of plan assets and (2) pension plans with an accumulated benefit obligation in excess of the fair value of plan assets as of December 31 are as follows (in millions):
Pension
Other
Postretirement
2023
2022
2023
2022
Fair value of plan assets
$
i—
$
i490
$
i—
$
i240
Projected
benefit obligation
$
i141
$
i643
$
i4
$
i247
Fair
value of plan assets
$
i—
$
i—
Accumulated
benefit obligation
$
i141
$
i142
/
Unrecognized
Amounts
i
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
Pension
Other
Postretirement
2023
2022
2023
2022
Net loss (gain)
$
i325
$
i365
$
(i88)
$
(i38)
Prior
service (credit) cost
(i3)
(i4)
i20
i21
Regulatory
deferrals
i22
i29
i—
i1
Total
$
i344
$
i390
$
(i68)
$
(i16)
A
reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2023 and 2022 is as follows (in millions):
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension
Other
Postretirement
2023
2022
2021
2023
2022
2021
Benefit obligations as of December 31:
Discount
rate
i5.36
%
i5.65
%
i2.98
%
i5.35
%
i4.54
%
i2.95
%
Rate
of compensation increase
i3.00
%
i3.00
%
i2.75
%
N/A
N/A
N/A
Interest
crediting rates for cash balance plan
2021
N/A
N/A
i2.45
%
N/A
N/A
N/A
2022
N/A
i3.25
%
i2.56
%
N/A
N/A
N/A
2023
i4.19
%
i4.25
%
i2.56
%
N/A
N/A
N/A
2024
i4.58
%
i4.25
%
i2.83
%
N/A
N/A
N/A
2025
i4.58
%
i3.65
%
i2.83
%
N/A
N/A
N/A
2026
and beyond
i3.73
%
i3.65
%
i2.83
%
N/A
N/A
N/A
Net
periodic benefit cost for the years ended December 31:
Discount rate
i5.65
%
i2.98
%
i2.60
%
i5.58
%
i2.95
%
i2.59
%
Expected
return on plan assets
i6.10
%
i4.30
%
i5.39
%
i5.84
%
i4.20
%
i3.35
%
Rate
of compensation increase
i3.00
%
i2.75
%
i2.75
%
N/A
N/A
N/A
Interest
crediting rate for cash balance plan
i4.19
%
i3.25
%
i2.45
%
N/A
N/A
N/A
In
establishing its assumption as to the expected return on plan assets, the Company utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
2023
2022
Assumed healthcare cost trend rates as of December 31:
Healthcare cost trend rate assumed for next year
i6.44
%
i6.50
%
Rate
that the cost trend rate gradually declines to
i5.00
%
i5.00
%
Year
that the rate reaches the rate it is assumed to remain at
2028
2028
/
172
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $i13
million and $i5 million, respectively, during 2024. Funding to the established pension trusts is based upon the actuarially determined costs of the plans and the requirements of the IRC, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act of 2006, as amended. The Company considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the Pension Protection Act of 2006, as amended. The Company evaluates a variety of factors, including funded
status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plans.
i
The expected benefit payments to participants in the Company's pension and other postretirement benefit plans for 2024 through 2028 and for the five years thereafter are summarized below (in millions):
Projected
Benefit
Payments
Other
Pension
Postretirement
2024
$
i187
$
i54
2025
i183
i54
2026
i181
i53
2027
i175
i54
2028
i169
i52
2029-2033
i774
i231
/
Plan
Assets
Investment Policy and Asset Allocations
The Company's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment consultants to advise on plan investments within the parameters outlined by the Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
173
i
The
target allocations (percentage of plan assets) for the Company's pension and other postretirement benefit plan assets are as follows as of December 31, 2023:
Other
Pension
Postretirement
%
%
PacifiCorp:
Debt
securities(1)
i73
i79
Equity
securities(1)
i22
i21
Limited
partnership interests
i5
0
MidAmerican Energy:
Debt
securities(1)
i40-i60
i25-i35
Equity
securities(1)
i30-i60
i65-i75
Other
0-i15
0-i5
NV
Energy:
Debt securities(1)
i65-i80
i68-i88
Equity
securities(1)
i20-i35
i12-i32
(1)For
purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.
/
174
Fair Value Measurements
i
The
following table presents the fair value of plan assets, by major category, for the Company's defined benefit pension plans (in millions):
Limited partnership interests(3) measured at net asset value
i32
Total
assets measured at fair value
$
i2,013
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment
funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately i51% and i49%, respectively, for 2023 and i53%
and i47%, respectively, for 2022. Additionally, these funds are invested in U.S. and international securities of approximately i94% and i6%,
respectively, for 2023 and i95% and i5%, respectively, for 2022.
(3)Limited partnership interests include several funds
that invest primarily in real estate, buyout, growth equity and venture capital.
/
175
The following table presents the fair value of plan assets, by major category, for the Company's defined benefit other postretirement plans (in millions):
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual
funds and collective trust funds. These funds consist of equity and debt securities of approximately i55% and i45%, respectively, for 2023 and i55%
and i45%, respectively, for 2022. Additionally, these funds are invested in U.S. and international securities of approximately i88% and i12%,
respectively, for 2023 and i88% and i12%, respectively, for 2022.
For level 1 investments, a readily observable
quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
176
Foreign Operations
Certain wholly-owned
subsidiaries of Northern Powergrid participate in the Northern Powergrid group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the "UK Plan"), which provides pension and other related defined benefits, based on final pensionable pay, to the employees of Northern Powergrid. The UK Plan is closed to employees hired after July 23, 1997. Employees hired after that date are covered by a defined contribution plan sponsored by a wholly-owned subsidiary of Northern Powergrid.
Net Periodic Benefit Cost
For purposes of calculating the expected return on pension plan assets, a market-related value is used. The market-related value of plan assets is calculated by including the difference between expected and actual investment returns
after the first year in which they occur.
Net periodic benefit cost (credit) for the UK Plan included the following components for the years ended December 31 (in millions):
2023
2022
2021
Service
cost
$
i6
$
i14
$
i16
Interest
cost
i57
i35
i31
Expected
return on plan assets
(i80)
(i92)
(i111)
Settlement
i—
i—
i10
Net
amortization
i26
i24
i55
Net
periodic benefit cost (credit)
$
i9
$
(i19)
$
i1
Funded
Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
2023
2022
Plan assets at fair value, beginning of year
$
i1,363
$
i2,363
Employer
contributions
i13
i15
Participant contributions
i1
i1
Actual
return on plan assets
i52
(i671)
Benefits
paid
(i97)
(i109)
Foreign currency exchange
rate changes
i70
(i236)
Plan
assets at fair value, end of year
$
i1,402
$
i1,363
177
The
following table is a reconciliation of the benefit obligation for the years ended December 31 (in millions):
2023
2022
Benefit obligation, beginning of year
$
i1,175
$
i2,003
Service
cost
i6
i14
Interest cost
i57
i35
Participant
contributions
i1
i1
Actuarial
loss (gain)
i1
(i596)
Amendment
i16
i27
Benefits
paid
(i97)
(i109)
Foreign
currency exchange rate changes
i60
(i200)
Benefit
obligation, end of year
$
i1,219
$
i1,175
Accumulated
benefit obligation, end of year
$
i1,103
$
i1,060
The
funded status of the UK Plan and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
2023
2022
Plan assets at fair value, end of year
$
i1,402
$
i1,363
Benefit
obligation, end of year
i1,219
i1,175
Funded
status
$
i183
$
i188
Amounts
recognized on the Consolidated Balance Sheets:
Other assets
$
i183
$
i188
Unrecognized
Amounts
The portion of the funded status of the UK Plan not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
2023
2022
Net loss
$
i532
$
i499
Prior
service cost
i44
i30
Total
$
i576
$
i529
A
reconciliation of the amounts not yet recognized as components of net periodic benefit cost, which are included in accumulated other comprehensive loss on the Consolidated Balance Sheets, for the years ended December 31 is as follows (in millions):
2023
2022
Balance, beginning of year
$
i529
$
i405
Net
loss arising during the year
i29
i167
Net
prior service cost arising during the year
i16
i27
Net
amortization
(i26)
(i24)
Foreign
currency exchange rate changes
i28
(i46)
Total
i47
i124
Balance,
end of year
$
i576
$
i529
178
Plan
Assumptions
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
2023
2022
2021
Benefit
obligations as of December 31:
Discount rate
i4.55
%
i4.80
%
i1.95
%
Rate
of compensation increase
i3.00
%
i3.20
%
i3.45
%
Rate
of future price inflation
i2.75
%
i2.95
%
i2.95
%
Net
periodic benefit cost for the years ended December 31:
Discount rate
i4.80
%
i1.95
%
i1.40
%
Expected
return on plan assets
i6.00
%
i4.40
%
i4.85
%
Rate
of compensation increase
i3.20
%
i3.45
%
i3.05
%
Rate
of future price inflation
i2.95
%
i2.95
%
i2.55
%
Contributions
and Benefit Payments
Employer contributions to the UK Plan are expected to be Łi9 million during 2024. The expected benefit payments to participants in the UK Plan for 2024 through 2028 and for the five years thereafter, excluding lump sum settlement elections and using the foreign currency exchange rate as of December 31, 2023, are summarized below (in millions):
2024
$
i74
2025
i76
2026
i78
2027
i79
2028
i81
2029-2033
i437
Plan
Assets
Investment Policy and Asset Allocations
The investment policy for the UK Plan is to balance risk and return through a diversified portfolio of debt securities, equity securities, real estate and other asset classes. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The UK Plan retains outside investment advisors to manage plan investments within the parameters set by the trustees of the UK Plan in consultation with Northern Powergrid. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments. The return on assets assumption is based on a weighted-average of the expected historical performance for the types of assets in which the UK Plan invests.
The
target allocations (percentage of plan assets) for the UK Plan assets are as follows as of December 31, 2023:
%
Debt securities(1)
i60-i70
Equity
securities(1)
i10-i20
Real estate funds
and other
i15-i25
(1)For
purposes of target allocation percentages and consistent with the plans' investment policy, investment funds have been allocated based on the underlying investments in debt and equity securities.
179
Fair Value Measurements
The following table presents the fair value of the UK Plan assets, by major category (in millions):
(1)Refer
to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately i14% and i86%,
respectively, for 2023 and i25% and i75%, respectively, for 2022.
The fair value of the UK Plan's assets are determined similar to the plan
assets of the domestic plans as previously discussed.
i
The following table reconciles the beginning and ending balances of the UK Plan assets measured at fair valueusing significant Level 3 inputs for the years ended December 31 (in millions):
Real
Estate Funds
2023
2022
2021
Beginning balance
$
i214
$
i269
$
i237
Actual
return on plan assets still held at period end
(i87)
(i27)
i35
Foreign
currency exchange rate changes
i9
(i28)
(i3)
Ending
balance
$
i136
$
i214
$
i269
/
Defined
Contribution Plans
The Company sponsors various defined contribution plans covering substantially all employees. The Company's contributions vary depending on the plan, but matching contributions are based on each participant's level of contribution, and certain participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. The Company's contributions to these plans were $i177 million, $i159 million
and $i137 million for the years ended December 31, 2023, 2022 and 2021, respectively.
180
(14)iAsset
Retirement Obligations
The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
The Company does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts
are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $i2.7 billion and $i2.6 billion as of December 31,
2023 and 2022, respectively.
i
The following table presents the Company's ARO liabilities by asset type as of December 31 (in millions):
2023
2022
Wind-powered
generating facilities
$
i452
$
i353
Quad Cities
Station
i407
i417
Fossil-fueled generating facilities
i402
i396
Solar-powered
generating facilities
i36
i30
Offshore pipeline facilities
i15
i14
Other
i116
i118
Total
asset retirement obligations
$
i1,428
$
i1,328
Quad
Cities Station nuclear decommissioning trust funds
$
i767
$
i664
/
i
The
following table reconciles the beginning and ending balances of the Company's ARO liabilities for the years ended December 31 (in millions):
2023
2022
Beginning balance
$
i1,328
$
i1,340
Change
in estimated costs
i54
i2
Acquisitions
i—
i29
Additions
i56
i32
Retirements
(i64)
(i122)
Accretion
i54
i47
Ending
balance
$
i1,428
$
i1,328
Reflected
as:
Other current liabilities
$
i34
$
i76
Other
long-term liabilities
i1,394
i1,252
Total
ARO liability
$
i1,428
$
i1,328
/
The
Nuclear Regulatory Commission regulates the decommissioning of nuclear generating facilities, which includes the planning and funding for the decommissioning. In accordance with these regulations, MidAmerican Energy submits a biennial report to the Nuclear Regulatory Commission providing reasonable assurance that funds will be available to pay for its share of the Quad Cities Station decommissioning.
181
Certain of the Company's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites, and as such, each subsidiary is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary
may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. The Company's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.
(15)iFair Value Measurements
The carrying value of the Company's cash,
certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities
in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.
The following table presents the Company's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
(1)Represents
netting under master netting arrangements and a net cash collateral receivable of $i27 million and payable of $i87
million as of December 31, 2023 and 2022, respectively.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price
quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative
contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.
183
The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available,
a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
i
The following table reconciles the beginning and ending balances of
the Company's financial assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions). Transfers out of Level 3 occur primarily due to increased price observability.
Commodity
Derivatives
Interest Rate Derivatives
2023
2022
2021
2023
2022
2021
Beginning
balance
$
(i59)
$
(i151)
$
i116
$
i6
$
i19
$
i62
Changes
included in earnings(1)
i9
(i85)
(i43)
i1
(i13)
(i43)
Changes
in fair value recognized in OCI
(i3)
i9
(i13)
i—
i—
i—
Changes
in fair value recognized in net regulatory assets
(i256)
(i52)
(i118)
i—
i—
i—
Purchases
i2
i3
(i76)
i—
i—
i—
Settlements
i216
i171
(i34)
i—
i—
i—
Transfers
out of Level 3 into Level 2
i—
i46
i17
i—
i—
i—
Ending
balance
$
(i91)
$
(i59)
$
(i151)
$
i7
$
i6
$
i19
(1)Changes
included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.
/
The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Financial Statements. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term
debt approximates fair value because of the frequent repricing of these instruments at market rates. iThe following table presents the carrying value and estimated fair value of the Company's long-term debt as of December 31 (in millions):
2023
2022
Carrying
Fair
Carrying
Fair
Value
Value
Value
Value
Long-term
debt
$
i52,172
$
i48,624
$
i51,635
$
i46,906
(16)iCommitments
and Contingencies
Commitments
i
The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2023 are as follows (in millions):
2029
and
2024
2025
2026
2027
2028
Thereafter
Total
Contract type:
Fuel,
capacity and transmission contract commitments
$
i2,360
$
i1,666
$
i1,351
$
i1,305
$
i1,189
$
i12,055
$
i19,926
Construction
commitments
i1,883
i475
i388
i67
i22
i28
i2,863
Easements
i84
i82
i82
i82
i85
i3,213
i3,628
Maintenance,
service and other contracts
i482
i459
i452
i323
i258
i1,325
i3,299
$
i4,809
$
i2,682
$
i2,273
$
i1,777
$
i1,554
$
i16,621
$
i29,716
/
184
Fuel,
Capacity and Transmission Contract Commitments
The Utilities have fuel supply and related transportation and lime contracts for their coal- and natural gas-fueled generating facilities. The Utilities expect to supplement these contracts with additional contracts and spot market purchases to fulfill their future fossil fuel needs. The Utilities acquire a portion of their electricity through long-term purchases and exchange agreements. The Utilities have several power purchase agreements with renewable generating facilities that are not included in the table above as the payments are based on the amount of energy generated and there are no minimum payments. The Utilities also have contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to their customers.
MidAmerican
Energy has long-term rail transportation contracts with BNSF Railway Company ("BNSF"), an affiliate company, and Union Pacific Railroad Company for the transportation of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities. For the years ended December 31, 2023, 2022 and 2021, $i109 million, $i100
million and $i76 million, respectively, were incurred for coal transportation services, the majority of which was related to the BNSF agreement.
Construction Commitments
The Company's firm construction commitments reflected in the table above include the following major construction projects:
•PacifiCorp's costs associated with certain generating plant, transmission, and distribution
projects.
•MidAmerican Energy's firm construction commitments primarily consisting of contracts for the repowering and construction of wind- and solar-powered generating facilities and the settlement of AROs.
•Nevada Utilities' firm construction commitments consisting of costs associated with a planned 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada, the planned Greenlink Nevada transmission expansion program that will be developed in western and northern Nevada, a planned 444 MWs of peaking combustion turbines that will be developed at the Silverhawk generating facility in Clark County, Nevada, costs associated with one additional solar photovoltaic facility project and certain other generation plant projects. The solar project, pending PUCN approval,
is a 400-MW solar photovoltaic facility with an additional 400 MWs of co-located battery storage that would be developed in Churchill County, Nevada.
•AltaLink's investments in directly assigned transmission projects from the AESO.
Easements
The Company has non-cancelable easements for land on which certain of its assets, primarily wind- and solar-powered generating facilities, are located.
Maintenance, Service and Other Contracts
The Company has entered into service agreements related to its nonregulated wind-powered and solar-powered projects with third parties to operate
and maintain the projects under fixed-fee operating and maintenance agreements. Additionally, the Company has various non-cancelable maintenance, service and other contracts primarily related to turbine and equipment maintenance and various other service agreements.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact the its current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.
185
Lower
Klamath Hydroelectric Project
PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $i200 million
plus $i250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with
the FERC to transfer the license for the four mainstem Klamath hydroelectric dams comprising the Lower Klamath Project (FERC Project No. 14803) from PacifiCorp to the KRRC. The FERC approved the partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application to remove PacifiCorp from the license for the Lower Klamath Project and add the States and KRRC as co-licensees for the purposes of surrender. In addition, the MOA provides for additional contingency
funding of $i45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $i450 million
in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved the transfer of the Lower Klamath Project dams from PacifiCorp to the KRRC and the States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. In August 2022, the FERC staff issued a final environmental impact statement for the project, concluding that dam removal is the preferred action. In November 2022, the FERC issued a license surrender order for the project, which was accepted by the KRRC and the States in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer
owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility was completed in November 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1, and Iron Gate) is anticipated to be completed in 2024.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses and settlement agreements contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities, which are estimated to be approximately $i314 million
over the next i10 years.
Legal Matters
The Company is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may seek to impose fines, penalties and other costs.
Pursuant to ASC 450, "Contingencies," a provision for a
loss contingency is recorded when it is probable a liability is likely to occur and the amount of loss can be reasonably estimated. The Company evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.
Wildfires
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may
contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could be found liable for all damages.
186
2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple
counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over i500,000 acres in aggregate. Third-party reports for these wildfires indicate over i2,000
structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.
Investigations into the cause and origin of each wildfire are complex and ongoing and have been or are being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, a significant number of complaints and demands alleging similar claims related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint in Oregon for which two jury verdicts were issued in June 2023 and January 2024 as described below. The plaintiffs seek damages for economic
losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned complaints. Additionally, the U.S. and Oregon Departments of Justice have informed PacifiCorp that they are contemplating filing actions against PacifiCorp in connection with certain of the Oregon 2020 Wildfires. PacifiCorp is actively cooperating with the U.S. and Oregon Departments of Justice on resolving these alleged claims, including through the pursuit of alternative dispute resolution.
Amounts sought in the complaints and demands filed in Oregon and in certain demands made in California total approximately $i8 billion,
excluding any doubling or trebling of damages included in the complaints. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. For class actions, amounts specified by the plaintiffs in the complaints include amounts based on estimates of the potential class size, which ultimately may be significantly greater than estimated. Additionally, damages are not limited to the amounts specified in the initially filed complaints as plaintiffs are frequently allowed to amend their complaints to add additional damages and amounts awarded in a court proceeding may be significantly greater than the damages specified. Oregon law provides for doubling of economic and property damages in the event the defendant is found to have acted with gross negligence, recklessness, willfulness or malice. Oregon law provides for trebling of the damages associated with timber, shrubs and produce in the event the defendant is determined to have
willfully and intentionally trespassed. Based on available information to date, PacifiCorp believes it is probable that losses will be incurred associated with the 2020 Wildfires. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.
The James Case
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon ("James"). The complaint was filed
by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain Complex, South Obenchain and 242 wildfires. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated the James case with several other cases. While PacifiCorp's pre-trial request for immediate appeal of the class certification was denied, it subsequently filed to appeal the class issues as described below.
In April 2023, the jury trial for James
with respect to i17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the i17 named plaintiffs and to the class with respect to the ifour
wildfires. The jury found PacifiCorp's conduct grossly negligent, reckless and willful as to each plaintiff and the entire class. The jury awarded the i17 named plaintiffs $i90 million of damages, including $i4 million
of economic damages, $i68 million of noneconomic damages and $i18 million of punitive damages based on a i0.25
multiplier of the economic and noneconomic damages.
187
In September 2023, the Multnomah County Circuit Court ordered trial dates for itwo consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the ithree
damages phase trials will present evidence regarding their damages. The first of these trials addressing nine individual plaintiffs was held in January 2024 while the remaining trials are scheduled at various dates through April 2024.
In January 2024, the Multnomah County Circuit Court entered a limited judgment and money award for the June 2023 James verdict. The limited judgment awards the aforementioned damages, as well as doubling of the economic damages and offsetting of any insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals.Under ORS 82.010, interest at a rate of i9%
per annum will accrue on the judgment commencing at the date the judgment was entered until the entire money award is paid, amended or reversed by an appellate court. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict in James, including whether the case can proceed as a class action and filed a motion to stay further damages phase trials. On February 14, 2024, the Oregon Court of Appeals denied PacifiCorp's request to stay the damages phase trials. On February 13, 2024, the i17
named plaintiffs filed a notice of cross-appeal as to the January 2024 limited judgment and money award. The appeals process and further actions could take several years.
In January 2024, the jury for the first James damages phase trial awarded inine plaintiffs $i62 million
of damages, including $i6 million of economic damages and $i56 million of noneconomic damages. After the jury verdict, the Multnomah County Circuit Court doubled the economic damages to $i12 million
and added $i16 million of punitive damages using the i0.25 multiplier determined by the jury for the June 2023 James verdict. PacifiCorp will request that the Multnomah County Circuit Court judge offset the
damage awards by deducting insurance proceeds received by any of the inine plaintiffs. PacifiCorp intends to appeal the jury's damage awards associated with the January 2024 jury verdict once judgement is entered.
2022 McKinney Fire
According to the California Department of Forestry and Fire Protection, on July 29, 2022, the 2022 McKinney Fire began in the Oak Knoll Ranger District of the Klamath
National Forest in Siskiyou County, California located in PacifiCorp's service territory, burning over 60,000 acres. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged; 185 structures destroyed, including residences; 12 injuries; and four fatalities. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service, the California Public Utilities Commission, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, multiple complaints have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees, but the amount of damages sought is not specified.
Based
on available information to date, PacifiCorp believes it is probable a loss will be incurred associated with the 2022 McKinney Fire. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes.
Estimated Losses for and Settlements Associated with the Wildfires
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, including (i) ongoing cause and origin investigations; (ii) ongoing settlement and mediation discussions; (iii) other litigation matters and upcoming legal proceedings; and (iv) the status of the James case, PacifiCorp increased its accrual by $i1,930 million
during the year ended December 31, 2023, bringing its cumulative estimated probable losses associated with the Wildfires to $i2,407 million through December 31, 2023. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages and noneconomic damages such as personal injury damages and loss of life damages that it is reasonably able to estimate at this time and which is subject to change as
additional relevant information becomes available.
188
Through December 31, 2023, PacifiCorp paid $i684 million in settlements associated with the 2020 Wildfires, including $i299 million
to i463 claimants and $i250 million to i10
companies with commercial timber interests associated with the Archie Creek, French Creek, Susan Creek and Smith Springs Road fires (collectively, the "Archie Creek Complex Fire") in Douglas County, Oregon. The Archie Creek Complex Fire settlements resolve substantially all claims filed by individual plaintiffs and all claims filed by commercial timber plaintiffs associated with the Archie Creek Complex Fire, but do not address related damages claimed by the U.S. or Oregon Departments of Justice. In January 2024 through February 23, 2024, PacifiCorp entered into additional settlements associated with the 2020 Wildfires totaling $i51
million with i167 plaintiffs.
i
The following table presents changes in PacifiCorp's liability for estimated losses associated with the Wildfires for the years ended December 31 (in millions):
2023
2022
2021
Beginning
balance
$
i424
$
i252
$
i252
Accrued
losses
i1,930
i225
i—
Payments(1)
(i631)
(i53)
i—
Ending balance
$
i1,723
$
i424
$
i252
(1)Amounts
represent payments made to settle certain claims associated with the 2020 Wildfires, including $i549 million in December 2023 resulting from the above-described settlement agreements reached in December 2023 associated with the Archie Creek Complex Fire.
/
As of December 31, 2023 and 2022,
$i4 million and $i24 million of PacifiCorp's liability for estimated losses associated with the Wildfires was included in Other current liabilities on the Consolidated Balance Sheets.
Until
such time that settlement terms or other conclusions are reached to indicate that payments are expected to occur in the short-term, PacifiCorp's liability for estimated losses associated with the Wildfires is classified as a noncurrent liability captioned Wildfires liabilities on the Consolidated Balance Sheets.
The following table presents changes in PacifiCorp's receivable for expected insurance recoveries associated with the Wildfires for the years ended December 31 (in millions):
2023
2022
2021
Beginning
balance
$
i246
$
i116
$
i116
Accruals
i253
i161
i—
Payments
received
i—
(i31)
i—
Ending balance
$
i499
$
i246
$
i116
As
of December 31, 2023, $i350 million of PacifiCorp's receivable for expected insurance recoveries was included in Other receivables, net while the remaining $i149 million was included
in Other assets on the Consolidated Balance Sheets. As of December 31, 2022, the $i246 million was included in Other assets on the Consolidated Balance Sheets. In January and February 2024, PacifiCorp received $i338
million of insurance proceeds related to the 2020 Wildfires.
During the years ended December 31, 2023, 2022 and 2021, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $i1,677 million, $i64 million and
$i— million, respectively. No additional insurance recoveries beyond those accrued to date are expected to be available.
It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued for the Wildfires that could have a material adverse effect on PacifiCorp's financial condition. PacifiCorp is currently unable to reasonably estimate a specific range of possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the class to the
James case, the variation in the types of properties and damages and the ultimate outcome of legal actions.
189
HomeServices Antitrust Cases
HomeServices is currently defending against ieleven antitrust cases, all in federal district courts. In each case, plaintiffs
claim HomeServices (or, in one instance, Berkshire Hathaway) and certain of its subsidiaries conspired with co-defendants to artificially inflate real estate commissions by following and enforcing multiple listing service ("MLS") rules that require listing agents to offer a commission split to cooperating agents in order for the property to appear on the MLS ("Cooperative Compensation Rule"). None of the complaints specify damages sought. However, itwo cases allege Texas state law deceptive trade practices claims, for which plaintiffs have provided written notice of the damages sought totaling approximately
$i9 billion by separate notice as required by Texas law.
In April 2019, the Burnett (formerly Sitzer) et al. v. HomeServices of America, Inc. et al. complaint was filed in the U.S. District Court for the Western District of Missouri (the "Burnett case"). This lawsuit, which was certified as a class in April 2022, was originally brought on behalf of named plaintiffs Joshua Sitzer and Amy Winger against the National Association of Realtors ("NAR"), Anywhere Real Estate
(formerly Realogy Holdings Corp.), HomeServices of America, Inc., RE/MAX, LLC, and Keller Williams Realty, Inc. HSF Affiliates, LLC and BHH Affiliates, LLC, each a subsidiary of HomeServices, were subsequently added as defendants. Rhonda Burnett became a lead class plaintiff in June 2021. The jury trial commenced on October 16, 2023, and the jury returned a verdict for the plaintiffs on October 31, 2023, finding that the named defendants participated in a conspiracy to follow and enforce the Cooperative Compensation Rule, which had the purpose or effect of raising, inflating, or stabilizing broker commission rates paid by home sellers. The jury further found that the class plaintiffs had proved damages in the amount of $i1.8 billion.
Federal law authorizes trebling of damages and the award of pre-judgment interest and attorney fees. Joint and several liability applies for the co-defendants. Prior to the trial, Anywhere Real Estate (formerly Realogy Holdings Corp.) and RE/MAX, LLC reached settlement agreements with the plaintiffs, which have not yet received final approval from the court. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri. HomeServices intends to vigorously appeal on multiple grounds the jury's findings and damage award in the Burnett case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.
Based on available information to date, HomeServices believes losses are likely to occur as a result of the jury verdict in the Burnett case and that such damages could be up to $i5.4 billion,
excluding attorneys' fees, prejudgment interest and other costs subject to determination by the court. Under the current circumstances, HomeServices is currently unable to reasonably estimate such loss due to, among other reasons, the joint and several nature of the liability and the early stage of the appeals process; therefore, no loss has been accrued as of the date of this filing. While HomeServices intends to appeal any final judgment, the outcome of such appeals, if adverse, could have a material adverse effect on HomeServices' financial condition.
It is also reasonably possible HomeServices will incur losses from the iten
remaining antitrust cases that could have a material adverse effect on HomeServices' financial condition. HomeServices is currently unable to reasonably estimate a specific range of possible losses that could be incurred due to, among other reasons, the lack of information about the size of the plaintiff class and potential damages, as well as the joint and several nature of potential liability of the defendants.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
190
(17) iRevenue
from Contracts with Customers
Energy Products and Services
i
The following table summarizes the Company's energy products and services Customer Revenue by regulated energy and nonregulated energy, with further disaggregation of regulated energy by line of business, including a reconciliation to the Company's reportable segment information included in Note 22, for the years ended December 31 (in millions):
2023
PacifiCorp
MidAmerican
Funding
NV Energy
Northern Powergrid
BHE Pipeline Group
BHE Transmission
BHE Renewables(1)
BHE and
Other(2)
Total
Customer Revenue:
Regulated:
Retail
Electric
$
i5,462
$
i2,309
$
i4,121
$
i—
$
i—
$
i—
$
i—
$
(i1)
$
i11,891
Retail
Gas
i—
i638
i235
i—
i—
i—
i—
i—
i873
Wholesale
i165
i303
i64
i—
i22
i—
i—
(i1)
i553
Transmission
and distribution
i151
i54
i77
i1,041
i—
i660
i—
i—
i1,983
Interstate
pipeline
i—
i—
i—
i—
i2,700
i—
i—
(i155)
i2,545
Other
i129
i—
i2
i—
i5
i—
i—
i—
i136
Total
Regulated
i5,907
i3,304
i4,499
i1,041
i2,727
i660
i—
(i157)
i17,981
Nonregulated
i—
i7
i4
i142
i984
i142
i1,436
(i1)
i2,714
Total
Customer Revenue
i5,907
i3,311
i4,503
i1,183
i3,711
i802
i1,436
(i158)
i20,695
Other
revenue
i29
i82
i20
i120
i63
(i3)
i274
i—
i585
Total
$
i5,936
$
i3,393
$
i4,523
$
i1,303
$
i3,774
$
i799
$
i1,710
$
(i158)
$
i21,280
2022
PacifiCorp
MidAmerican
Funding
NV Energy
Northern Powergrid
BHE Pipeline Group
BHE Transmission
BHE Renewables(1)
BHE and
Other(2)
Total
Customer Revenue:
Regulated:
Retail
Electric
$
i5,099
$
i2,320
$
i3,465
$
i—
$
i—
$
i—
$
i—
$
i—
$
i10,884
Retail
Gas
i—
i855
i167
i—
i—
i—
i—
i—
i1,022
Wholesale
i260
i668
i92
i—
i8
i—
i—
(i4)
i1,024
Transmission
and distribution
i166
i61
i76
i1,081
i—
i683
i—
i—
i2,067
Interstate
pipeline
i—
i—
i—
i—
i2,603
i—
i—
(i127)
i2,476
Other
i102
i—
i2
i—
i3
i—
i—
(i2)
i105
Total
Regulated
i5,627
i3,904
i3,802
i1,081
i2,614
i683
i—
(i133)
i17,578
Nonregulated
i—
i7
i—
i169
i1,076
i70
i1,465
(i2)
i2,785
Total
Customer Revenue
i5,627
i3,911
i3,802
i1,250
i3,690
i753
i1,465
(i135)
i20,363
Other
revenue
i52
i114
i22
i115
i154
(i21)
i272
(i2)
i706
Total
$
i5,679
$
i4,025
$
i3,824
$
i1,365
$
i3,844
$
i732
$
i1,737
$
(i137)
$
i21,069
/
191
2021
PacifiCorp
MidAmerican
Funding
NV Energy
Northern Powergrid
BHE Pipeline Group
BHE Transmission
BHE Renewables(1)
BHE and
Other(2)
Total
Customer Revenue:
Regulated:
Retail
Electric
$
i4,847
$
i2,128
$
i2,828
$
i—
$
i—
$
i—
$
i—
$
(i2)
$
i9,801
Retail
Gas
i—
i859
i115
i—
i—
i—
i—
i—
i974
Wholesale
i157
i454
i62
i—
i57
i—
i—
(i3)
i727
Transmission
and distribution
i143
i58
i74
i1,023
i—
i702
i—
i—
i2,000
Interstate
pipeline
i—
i—
i—
i—
i2,404
i—
i—
(i131)
i2,273
Other
i108
i—
i1
i—
(i1)
i—
i—
i1
i109
Total
Regulated
i5,255
i3,499
i3,080
i1,023
i2,460
i702
i—
(i135)
i15,884
Nonregulated
i—
i15
i3
i43
i956
i35
i1,374
(i2)
i2,424
Total
Customer Revenue
i5,255
i3,514
i3,083
i1,066
i3,416
i737
i1,374
(i137)
i18,308
Other
revenue
i41
i33
i24
i122
i128
(i6)
i287
(i2)
i627
Total
$
i5,296
$
i3,547
$
i3,107
$
i1,188
$
i3,544
$
i731
$
i1,661
$
(i139)
$
i18,935
(1)Effective
January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been reclassified to reflect this activity in BHE Renewables.
(2)The BHE and Other reportable segment represents amounts related principally to other corporate entities, corporate functions and intersegment eliminations.
Real Estate Services
The following table summarizes the Company's real estate services Customer Revenue by line of business for the years ended December 31 (in millions):
HomeServices
2023
2022
2021
Customer
Revenue:
Brokerage
$
i4,000
$
i4,867
$
i5,498
Franchise
i55
i66
i85
Total
Customer Revenue
i4,055
i4,933
i5,583
Mortgage
and other revenue
i267
i335
i632
Total
$
i4,322
$
i5,268
$
i6,215
Remaining
Performance Obligations
i
The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2023, by reportable segment (in millions):
Performance
obligations expected to be satisfied
Less than 12 months
More than 12 months
Total
BHE
Pipeline Group
$
i2,984
$
i20,019
$
i23,003
/
192
(18)iBHE
Shareholders' Equity
Preferred Stock
As of December 31 2022, BHE had i849,982 shares outstanding of its Perpetual Preferred Stock (the "i4%
Perpetual Preferred Stock") issued to certain subsidiaries of Berkshire Hathaway Inc. The i4% Perpetual Preferred Stock had a liquidation preference of $i1,000 per share and paid a i4.00%
dividend per share on the liquidation preference. Dividends accrued and accumulated daily, were cumulative, compounded semi-annually and, if declared, were payable in cash semi-annually in arrears on May 15 and November 15 of each year. If dividends were not declared and paid, any accumulating dividends would continue to accumulate and compound. BHE would not make any dividends on shares of any other class or series of its capital stock (other than for dividends on shares of common stock payable in shares of common stock, unless the holders of the then outstanding i4% Perpetual Preferred Stock should first receive, or simultaneously
have received, a dividend in an amount at least equivalent to the amount accumulated and not previously paid. BHE would not declare or pay any dividends on shares of the i4% Perpetual Preferred Stock if such declaration or payment would constitute an event of default on BHE's senior indebtedness (as defined). BHE may, at its option, redeem the i4%
Perpetual Preferred Stock in whole or in part at any time at a price per share equal to the liquidation preference.
Common Stock
On March 14, 2000, and as amended on December 7, 2005, BHE's shareholders entered into a Shareholder Agreement that provides specific rights to certain shareholders. One of these rights allows certain shareholders the ability to put their common shares to BHE at the then-current fair value dependent on certain circumstances controlled by BHE.
In June 2022, BHE purchased i740,961
shares of its common stock held by Mr. Gregory E. Abel, BHE's Chair, for $i870 million. The purchase was pursuant to the terms of BHE's Shareholders Agreement.
Restricted Net Assets
BHE has maximum debt-to-total capitalization percentage restrictions imposed by its senior unsecured credit facilities expiring in June 2026 which, in
certain circumstances, limit BHE's ability to make cash dividends or distributions. As a result of this restriction, BHE has restricted net assets of $i23.2 billion as of December 31, 2023.
Certain of BHE's subsidiaries have restrictions on their ability to dividend, loan or advance funds to BHE due to specific legal or regulatory restrictions, including, but not limited to, maximum debt-to-total capitalization percentages and commitments made to state commissions. As a result of these restrictions, BHE's
subsidiaries had restricted net assets of $i21.8 billion as of December 31, 2023.
193
(19)iComponents
of Accumulated Other Comprehensive Loss, Net
i
The following table shows the change in accumulated other comprehensive loss attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income taxes, for the year ended December 31 (in millions):
Reclassifications
from AOCI to net income for the years ended December 31, 2023, 2022 and 2021 were insignificant. Additionally, refer to the "Foreign Operations" discussion in Note 13 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.
(20)iVariable
Interest Entities and Noncontrolling Interests
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both (i) the power to direct the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
As of December 31, 2022, BHE owned an indirect i25%
economic interest in Cove Point, consisting of i100% of the general partner interest and i25% of the total limited partner interests. As described in Note 3, on September 1, 2023, BHE completed its acquisition of
i50% of the limited partner interest in Cove Point from DEI, and accordingly, owns an aggregate i75% of the limited partner interest and
continues to own i100% of the general partner interest of Cove Point. BHE concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. BHE is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Included in noncontrolling interests on the Consolidated Balance Sheets are (i) Brookfield Super-Core
Infrastructure Partner's i25% interest in Cove Point and (ii) preferred securities of subsidiaries of $ii58/ million
as of December 31, 2023 and 2022, consisting of $ii56/
million of ii8.061/%
cumulative preferred securities of Northern Electric plc, a subsidiary of Northern Powergrid, which are redeemable in the event of the revocation of Northern Electric plc's electricity distribution license by the Secretary of State, and $i2 million of nonredeemable preferred stock of PacifiCorp.
194
(21)iSupplemental
Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2023
2022
2021
Supplemental disclosure of cash flow information:
Interest
paid, net of amounts capitalized
$
i2,109
$
i2,071
$
i2,041
Income
taxes received, net(1)
$
i1,370
$
i1,863
$
i1,309
Supplemental
disclosure of non-cash investing and financing transactions:
Accruals related to property, plant and equipment additions
$
i1,494
$
i1,049
$
i834
(1)Includes
$i1,479 million, $i1,961 million and $i1,441
million of income taxes received from Berkshire Hathaway in 2023, 2022 and 2021, respectively.
(22)iSegment Information
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, and BHE Transmission,
whose business includes operations in Canada. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been reclassified to reflect this activity in BHE Renewables. iInformation related to the Company's reportable segments is shown below (in millions):
Total
property, plant and equipment, net by country
$
i99,248
$
i93,043
$
i89,816
(1)The
differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate to other corporate entities, corporate functions and intersegment eliminations.
(2)Income tax (benefit) expense includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
198
i
The
following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2023 and 2022 (in millions):
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This
discussion should be read in conjunction with PacifiCorp's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. PacifiCorp's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net loss for the year ended December 31, 2023, was $468 million, a decrease of $1,388 million, compared to 2022 net income of $920 million. The decrease in net income was primarily due to an increase in estimated
losses of $1,613 million associated with the 2020 Wildfires and the 2022 McKinney Fire, net of expected insurance recoveries, higher operations and maintenance expense, higher property and other taxes and lower utility margin, partially offset by higher income tax benefit and lower other expense. Utility margin decreased primarily due to higher purchased electricity costs from higher volumes and prices, lower wholesale volumes, higher coal-fueled generation prices, higher natural gas-fueled generation volumes and lower retail volumes, partially offset by higher retail rates, higher net power cost deferrals, lower coal-fueled generation volumes, lower natural gas-fueled generation prices and higher average wholesale prices. Retail customer volumes decreased 0.8% primarily due to unfavorable impacts of weather and lower industrial, irrigation and residential customer usage, partially offset by higher commercial customer usage and an increase in the average number of customers.
Energy generated decreased 6,762 gigawatt-hours, or 13%, primarily due to lower coal-fueled and wind-powered volumes, partially offset by higher natural gas-fueled and hydroelectric-powered volumes. Wholesale electricity sales volumes decreased 40% and purchased electricity volumes increased 32%.
Net income for the year ended December 31, 2022, was $920 million, an increase of $32 million, or 4%, compared to 2021, primarily due to higher utility margin, lower other expense, including higher allowance for equity and borrowed funds used during construction and lower property and other taxes, partially offset by higher operations and maintenance expense, largely due to higher general and plant maintenance costs and an increase in estimated losses of $64 million associated with the 2020 Wildfires, net of expected insurance recoveries, higher
depreciation and amortization expense, and lower income tax benefit. Utility margin increased primarily due to higher net power cost deferrals, higher retail prices and volumes, higher average wholesale prices, lower coal-fueled generation volumes and higher net wheeling revenues, partially offset by higher natural gas-fueled generation prices and volumes, higher purchased electricity costs from higher volumes and prices, higher coal-fueled generation prices, lower wind-based ancillary revenues, and lower wholesale volumes. Retail customer volumes increased 1.6% due to an increase in the average number of customers, favorable impacts of weather and an increase in commercial customer usage, partially offset by a decrease in residential and industrial customer usage. Energy generated decreased 4% for 2022 compared to 2021 primarily due to lower coal-fueled generation, partially offset by higher wind-powered, natural gas-fueled and hydroelectric-powered generation. Wholesale
electricity sales volumes decreased 5% and purchased electricity volumes increased 20%.
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Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
PacifiCorp's cost of fuel and energy is generally recovered from its retail customers through regulatory recovery
mechanisms and, as a result, changes in PacifiCorp's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
2023
2022
Change
2022
2021
Change
Utility
margin:
Operating revenue
$
5,936
$
5,679
$
257
5
%
$
5,679
$
5,296
$
383
7
%
Cost
of fuel and energy
2,246
1,979
267
13
1,979
1,831
148
8
Utility margin
3,690
3,700
(10)
—
3,700
3,465
235
7
Operations
and maintenance
1,469
1,163
306
26
1,163
1,031
132
13
Wildfires losses, net
1,677
64
1,613
*
64
—
64
*
Depreciation
and amortization
1,126
1,120
6
1
1,120
1,088
32
3
Property and other taxes
215
195
20
10
195
213
(18)
(8)
Operating
income
$
(797)
$
1,158
$
(1,955)
(169)
%
$
1,158
$
1,133
$
25
2
%
* Not
meaningful
202
Utility Margin
A comparison of key operating results related to utility margin is as follows for the years ended December 31:
2023
2022
Change
2022
2021
Change
Utility
margin (in millions):
Operating revenue
$
5,936
$
5,679
$
257
5
%
$
5,679
$
5,296
$
383
7
%
Cost
of fuel and energy
2,246
1,979
267
13
1,979
1,831
148
8
Utility margin
$
3,690
$
3,700
$
(10)
—
%
$
3,700
$
3,465
$
235
7
%
Sales
(GWhs):
Residential
18,159
18,425
(266)
(1)
%
18,425
17,905
520
3
%
Commercial(1)
20,491
19,570
921
5
19,570
18,839
731
4
Industrial(1)
16,705
17,622
(917)
(5)
17,622
17,909
(287)
(2)
Other(1)
1,341
1,547
(206)
(13)
1,547
1,621
(74)
(5)
Total
retail
56,696
57,164
(468)
(1)
57,164
56,274
890
2
Wholesale
2,911
4,836
(1,925)
(40)
4,836
5,113
(277)
(5)
Total
sales
59,607
62,000
(2,393)
(4)
%
62,000
61,387
613
1
%
Average
number of retail customers
(in thousands)
2,069
2,037
32
2
%
2,037
2,003
34
2
%
Average
revenue per MWh:
Retail
$
96.25
$
89.33
$
6.92
8
%
$
89.33
$
86.08
$
3.25
4
%
Wholesale
$
66.04
$
61.39
$
4.65
8
%
$
61.39
$
37.90
$
23.49
62
%
Heating
degree days
10,415
10,767
(352)
(3)
%
10,767
9,914
853
9
%
Cooling degree days
2,183
2,451
(268)
(11)
%
2,451
2,431
20
1
%
Sources
of energy (GWhs)(1):
Coal
21,950
28,390
(6,440)
(23)
%
28,390
31,566
(3,176)
(10)
%
Natural
gas
14,050
13,686
364
3
13,686
13,323
363
3
Wind(2)
6,500
7,238
(738)
(10)
7,238
6,686
552
8
Hydroelectric
and other(2)
3,258
3,206
52
2
3,206
3,010
196
7
Total energy generated
45,758
52,520
(6,762)
(13)
52,520
54,585
(2,065)
(4)
Energy
purchased
18,404
13,968
4,436
32
13,968
11,601
2,367
20
Total
64,162
66,488
(2,326)
(3)
%
66,488
66,186
302
—
%
Average
cost of energy per MWh:
Energy generated(3)
$
24.65
$
22.86
$
1.79
8
%
$
22.86
$
18.05
$
4.81
27
%
Energy
purchased
$
80.38
$
71.15
$
9.23
13
%
$
71.15
$
66.93
$
4.22
6
%
(1) GWh
amounts are net of energy used by the related generating facilities.
(2)All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
Utility margin decreased $10 million for 2023 compared to 2022 primarily due to:
•$485 million of higher purchased electricity costs from higher volumes and prices;
•$105 million of lower wholesale revenue primarily due to lower volumes, partially offset by higher average prices; and
•$18 million of lower net wheeling revenue.
The decreases above were partially offset by:
•$350 million of higher retail revenue primarily due to higher average prices, partially offset by lower volumes. Retail customer volumes decreased 0.8%, primarily due to lower
industrial customer usage across the service territory, lower residential customer usage across the western states, primarily in Oregon, lower irrigation customer usage across the service territory and unfavorable residential and commercial weather related impacts across the service territory, partially offset by higher commercial and residential customer usage across the eastern states, primarily in Utah, higher Oregon commercial customer usage and an increase in the average number of residential and commercial customers across the service territory;
•$147 million from higher deferred net power costs in accordance with established adjustment mechanisms;
•$54 million of lower natural gas-fueled generation costs primarily due to lower average prices, partially offset by higher volumes;
•$21
million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices;
•$12 million associated with the recognition of California greenhouse gas allowances related revenues driven by timing of customer credits (offset in retail revenue);
•$8 million of higher other revenue due to the reestablishment of customer late fees assessments; and
•$5 million of higher REC sales.
Wildfires losses, net increased $1,613 million for 2023 compared to 2022 due to an increase in estimated losses associated with the 2020 Wildfires and the 2022 McKinney Fire, net of expected insurance recoveries.
Operations
and maintenance increased $306 million, or 26%, for 2023 compared to 2022 primarily due to:
•$114 million increase in vegetation management and wildfire mitigation costs due to higher costs of $19 million, lower current year regulatory deferrals of $70 million and higher amortization of prior regulatory deferrals of $25 million;
•$42 million increase in insurance premiums due to higher cost of third-party liability insurance coverage resulting from the impact of industry-wide catastrophic wildfires;
•$41 million increase in plant operations and maintenance costs;
•$33 million of higher legal fees primarily related to wildfires matters;
•$25
million increase in DSM amortization expense driven by higher spend in Oregon, Washington, Utah and Idaho (offset in retail revenue);
•$17 million of higher bad debt expense;
•$15 million increase from higher write-offs of construction work-in-progress balances resulting from changes in planned spending for certain growth projects;
•$14 million higher labor and employee-related expenses;
•$9 million increase in amortization of various regulatory balances (offset in other revenue); and
•$6 million increase in general injuries and damages accruals.
204
The
decreases above were partially offset by:
•$9 million of operations and maintenance expense related to regulatory deferrals resulting from the December 2023 California general rate case order.
Depreciation and amortization increased $6 million, or 1%, for 2023 compared to 2022 primarily due to higher plant in-service balances in the current year and prior year Oregon deferral associated with the depreciation of certain wind-powered generating facilities compounded by current year amortization, partially offset by decreases mainly due to the extension of Jim Bridger Units 1 and 2 lives in Oregon as a result of the planned gas conversion and lower amortization of certain Klamath related deferrals in the eastern states that became fully amortized in the prior year.
Property
and other taxes increased $20 million, or 10%, for 2023 compared to 2022 primarily due to prior year favorable Utah property tax appeal settlement.
Interest expense increased$115 million, or27%, for 2023 compared to 2022 primarily due to higher average long- and short-term debt balances, higher interest rates, and higher interest expense on transmission readiness, security and network deposits due to higher average deposits on hand.
Allowance for borrowed and equity funds increased $112 million for 2023 compared to 2022 primarily due to higher qualified
construction work-in-progress balances, partially offset by lower rates.
Interest and dividend income increased $54 million for 2023 compared to 2022 primarily due to higher deferred net power cost regulatory asset balances and higher investment income primarily from higher average interest rates.
Other, net increased$25 million for 2023 compared to 2022 primarily due to an increase in cash surrender values of corporate-owned life insurance policies, lower pension costs and favorable change in the long-term incentive plan primarily due to market movements (offset in operations and maintenance expense).
Income tax benefit
increased $491 million for 2023 compared to 2022. The effective tax rate was 54% and (7)% for 2023 and 2022, respectively. The $491 million increase is primarily due to the increase in the accruals, net of expected insurance recoveries for the 2020 Wildfires and the 2022 McKinney Fire, a decrease to the valuation allowance for state net operating losses and higher benefit from the effects of ratemaking, partially offset by lower PTCs from PacifiCorp's wind-powered generating facilities.
Utility margin increased $235 million, or 7% for 2022 compared to 2021 primarily due to:
•$290
million from higher deferred net power costs in accordance with established adjustment mechanisms;
•$263 million of higher retail revenue primarily due to higher average prices and higher volumes. Retail customer volumes increased 1.6% primarily due to an increase in the average number of customers, favorable impacts of weather and an increase in commercial customer usage, partially offset by a decrease in residential and industrial customer usage;
•$103 million of higher wholesale revenue primarily due to higher average prices, partially offset by lower volumes;
•$44 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices; and
•$19 million of favorable
wheeling activities.
The increases above were partially offset by:
•$259 million of higher natural gas-fueled generation costs primarily due to higher average prices and higher volumes;
•$217 million of higher purchased electricity costs from higher volumes and prices; and
•$10 million of lower wind-based ancillary revenue.
Wildfires losses, net increased $64 million for 2022 compared to 2021 due to an increase in estimated losses associated with the 2020 Wildfires, net of expected insurance recoveries.
Operations and maintenance
increased $132 million, or 13%, for 2022 compared to 2021 primarily due to:
205
•$38 million of higher plant maintenance costs;
•$37 million of higher consumption of materials, chemical and start-up fuel costs;
•$27 million of higher DSM amortization expense driven by higher spend in Oregon, Utah, Wyoming and Washington (offset in retail revenue);
•$25 million of changes in the prior year in how obligations associated with the implementation of the Klamath Hydroelectric Settlement Agreement will be met; and
•$17
million of higher insurance premiums due to higher cost of third-party liability insurance coverage resulting from the impact of industry-wide catastrophic wildfires.
The increases above were partially offset by:
•$22 million of deferrals of vegetation management costs in Oregon and Utah, net of higher vegetation management and wildfire mitigation costs.
Depreciation and amortization increased $32 million, or 3%, for 2022 compared to 2021 primarily due to higher plant-in-service balances in the current year and prior year deferral of the 2018 depreciation study in Idaho compared to current year amortization, partially offset by current year allocation adjustment for Oregon incremental depreciation of certain coal units and Oregon deferral associated
with the depreciation of certain wind-powered generating facilities.
Property and other taxes decreased $18 million, or 8%, for 2022 compared to 2021 primarily due to lower property tax rates in Utah.
Allowance for borrowed and equity funds increased $28 million, or 38%, for 2022 compared to 2021 primarily due to higher qualified construction work-in-progress balances and higher rates.
Interest and dividend income increased $20 million, or 83%, for 2022 compared to 2021 primarily due to the recording of interest on the 2021 Oregon PCAM deferral and higher investment income due to higher average interest rates.
Other,
net decreased $23 million for 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies driven by market declines, unfavorable change in deferred compensation and the long-term incentive plan primarily due to market movements (offset in operations and maintenance expense) and higher pension costs primarily due to lower expected return on net assets.
Income tax benefit decreased $17 million, or 22% for 2022 compared to 2021. The effective tax rate was (7)% and (10)% for 2022 and 2021, respectively. The effective tax rate increased primarily as a result of lower effects of ratemaking associated with excess deferred income tax amortization and an increase to the valuation allowance for state net operating losses, partially offset by increased PTCs from PacifiCorp's wind-powered generating facilities
in the current year.
Liquidity and Capital Resources
Overview
PacifiCorp's liquidity has been materially impacted by the Wildfires, and it may be unable to maintain sufficient levels of cash or obtain necessary short- and long-term financing to fund its operations, implement its business strategy, make interest payments, make scheduled repayments of long-term debt, finance its capital investments and fund potential future settlements associated with the Wildfires. To help mitigate PacifiCorp's liquidity pressures, BHE has indicated that it will suspend dividends for the next several years in order to
allow PacifiCorp to accumulate cash that may be necessary in the event of additional future settlements associated with the Wildfires.
Additionally, to the extent PacifiCorp is unable to obtain additional surety bonds in the event of further unfavorable trial verdicts associated with the Wildfires, it may be required to post letters of credit or cash to secure such judgments. Such requirements would further reduce PacifiCorp's liquidity and availability under its revolving credit facility as described below under "Credit Facility" and "Letters of Credit." Refer also to additional potential restrictions related to PacifiCorp's First Mortgage Bonds and credit facilities described below under "Financing Activities."
206
As
of December 31, 2023, PacifiCorp's issuer credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade. While PacifiCorp's credit ratings remain investment grade, additional unfavorable wildfire litigation outcomes could result in additional pressure on the credit ratings. Further declines in PacifiCorp's credit ratings could limit investors' ability to purchase PacifiCorp's First Mortgage Bonds, as well as trigger investors to be required to sell PacifiCorp First Mortgage Bonds they currently hold. Additionally, in the event PacifiCorp's credit ratings decline to below investment grade, it would be required to post additional collateral associated with commodity agreements as a result of credit-risk-related contingent features in those contracts and counterparties could demand "adequate assurance" if there is
a material adverse change in PacifiCorp's creditworthiness. Refer to additional information below under "Collateral and Contingent Features."Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities and commercial paper, and long-term debt costs.
Refer to Item 1A. Risk Factors of this Form 10-K for additional information regarding the risks associated with the changes in PacifiCorp's credit ratings, the litigation risk associated with the Wildfires and the increasing cost of third-party liability insurance coverage, all of which are expected to materially impact PacifiCorp's liquidity.
For more information about the risks that could materially affect PacifiCorp's financial condition, results of operations, liquidity,
and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors of this Form 10-K. This report contains forward-looking statements that are subject to various risks and uncertainties. These statements reflect management's judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. See "Forward-Looking Statements" above for a list of some of the factors that may cause actual results to differ materially.
Net Liquidity
As of December 31, 2023, PacifiCorp's total net liquidity was as follows (in millions):
Cash
and cash equivalents
$
138
Credit facility(1)
2,000
Less:
Short-term debt
(1,604)
Tax-exempt bond support and letters of credit
(249)
Net
credit facility
147
Total net liquidity(2)
$
285
Credit facility:
Maturity date
2026
(1)Refer
to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K and "Credit Facility" below for further discussion regarding PacifiCorp's credit facilities.
(2)Excludes $900 million of available liquidity under a delayed draw term loan.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2023 and 2022 were $700 million and $1.82 billion, respectively. The decrease is primarily due to higher wildfire liability settlement payments, higher wholesale purchases and collateral returned to counterparties, partially offset by higher collections from retail customers.
Net
cash flows from operating activities for the years ended December 31, 2022 and 2021 were $1.82 billion and $1.80 billion, respectively. The increase is primarily due to higher collections from retail customers, collateral received from counterparties, transmission deposits and cash received for income taxes, partially offset by higher fuel, wholesale and material and supplies purchases.
The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
207
Investing
Activities
Net cash flows from investing activities for the years ended December 31, 2023 and 2022 were $(3.22) billion and $(2.16) billion, respectively. The increase in net cash outflows from investing activities is mainly due to an increase in capital expenditures of $1.06 billion.
Net cash flows from investing activities for the years ended December 31, 2022 and 2021 were $(2.16) billion and $(1.50) billion, respectively. The increase in net cash outflows from investing activities is mainly due to an increase in capital expenditures of $653 million.
Financing
Activities
Mortgage
PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31, 2023, PacifiCorp estimated it would be able to issue up to $7.2 billion of new first mortgage bonds under the most restrictive issuance test in the mortgage. Any issuances are subject to market conditions and amounts are further limited by regulatory authorizations or commitments or by covenants and tests contained in other financing agreements,
as described below. PacifiCorp also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
Debt Authorizations, Restrictions and Debt Covenants
Following PacifiCorp's January 2024 First Mortgage Bond issuances, PacifiCorp currently has no remaining regulatory authority from the OPUC and the IPUC to issue additional long-term debt. PacifiCorp must apply for additional issuance authority from the OPUC and IPUC and make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the SEC to issue an indeterminate amount of first mortgage bonds through September 2026.
PacifiCorp
currently has regulatory authority from the OPUC, the WUTC, the IPUC and the FERC to issue $2.0 billion of short-term debt.
While PacifiCorp's current revolving credit facility is unsecured, upon future renewal, PacifiCorp may be required to secure the facility, which could further limit the amount of First Mortgage Bonds PacifiCorp can issue.
The credit facility and term loan require that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter. As of December 31, 2023, PacifiCorp's debt to total capitalization ratio was 0.55 to 1.0.
As
of December 31, 2023, PacifiCorp was in compliance with all financial covenants that affect access to capital.
Short-term Debt
As of December 31, 2023, PacifiCorp had $1.6 billion of short-term debt outstanding at a weighted average rate of 6.16%, which was subsequently repaid in January 2024. As of December 31, 2022, PacifiCorp had no short-term debt outstanding. For further discussion, refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Long-term
Debt
In May 2023, PacifiCorp issued $1.2 billion of its 5.500% First Mortgage Bonds due May 2054. PacifiCorp intends within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.
208
In December 2023, PacifiCorp entered into a $900 million unsecured delayed draw term loan facility expiring in June 2025. Amounts borrowed under the facility bear interest at variable
rates based on the Secured Overnight Financing Rate or a base rate, at PacifiCorp's option, plus a pricing margin. Subject to regulatory authority to issue long-term debt, PacifiCorp may draw all or none of the unused commitment up to three times through June 2025. As of December 31, 2023, PacifiCorp had no term loans drawn from the facility and currently has no authority to issue additional long-term debt until additional filings occur with the OPUC and the IPUC and are approved as described above.
In January 2024, PacifiCorp issued $500 million of its 5.10% First Mortgage Bonds due February 2029, $700 million of its 5.30% First Mortgage Bonds due February 2031, $1.1 billion of its 5.45% First Mortgage Bonds due February 2034 and $1.5 billion of its 5.80% First Mortgage Bonds due January 2055 for a total of $3.8 billion. PacifiCorp initially
used a portion of the net proceeds to repay outstanding short-term debt and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.
PacifiCorp made repayments on long-term debt totaling $449 million and $155 million during the years ended December 31, 2023 and 2022, respectively.
Credit Facility
In June 2023, PacifiCorp amended and restated its existing $1.2 billion unsecured credit facility expiring in June 2024. The amendment increased the lender commitment to $2.0 billion and extended the expiration date to June 2026. Additionally, in June 2023, PacifiCorp terminated
its existing $800 million 364-day unsecured credit facility expiring in January 2024.
Preferred Stock
As of December 31, 2023 and 2022, PacifiCorp had non-redeemable preferred stock outstanding with an aggregate stated value of $2 million.
Common Shareholder's Equity
In 2023 and 2022, PacifiCorp declared and paid dividends of $300 million and $100 million, respectively, to PPW Holdings LLC.
Capitalization
PacifiCorp
manages its capitalization and liquidity position to maintain a prudent capital structure with the objective of retaining strong investment grade credit ratings, which is expected to facilitate continuing access to flexible borrowing arrangements at favorable costs and rates. This objective, subject to periodic review and revision, attempts to balance the interests of all shareholders, customers and creditors and provide a competitive cost of capital and predictable capital market access.
Under existing or prospective authoritative accounting guidance, such as guidance pertaining to consolidations and leases, it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing arrangements may be accounted for as lease obligations on PacifiCorp's financial statements. While PacifiCorp has successfully amended covenants in financing arrangements
that may be impacted, it may be more difficult for PacifiCorp to comply with its capitalization targets or regulatory commitments concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers under financing agreements and from regulators, delay or reduce dividends or spending programs, seek additional new equity contributions from its indirect parent company, BHE, or take other actions.
Future Uses of Cash
PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, bank loans, capital contributions and other sources.
These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility industry.
209
Capital Expenditures
PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews,
which may consider, among other factors, impacts to customer rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings, including regulatory filings for Certificates of Public Convenience and Necessity; outcomes of legal actions associated with the Wildfires; changes in income tax laws; general business conditions; new customer requests; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
Historical
Forecast
2021
2022
2023
2024
2025
2026
Wind
generation
$
131
$
37
$
755
$
502
$
273
$
137
Electric distribution
554
543
673
718
779
523
Electric
transmission
315
1,184
1,189
1,172
1,096
1,314
Solar generation
—
—
2
—
47
61
Electric
battery and pumped hydro storage
5
8
4
59
241
308
Wildfire mitigation
64
159
325
374
324
319
Other
444
235
278
752
785
830
Total
$
1,513
$
2,166
$
3,226
$
3,577
$
3,545
$
3,492
PacifiCorp's
IRP is a roadmap for PacifiCorp's energy transition to renewable and carbon free generation resources, coal-to-natural gas conversion of certain coal-fueled units, energy storage, associated transmission, load forecast and resource adequacy. PacifiCorp anticipates that the additional new renewable and carbon free generation and energy storage will be a mixture of owned and contracted resources. PacifiCorp has included estimates for these new renewable and carbon free generation and energy storage resources, conversion of certain coal-fueled units to natural-gas fueled units, energy storage assets and associated transmission assets in its forecast capital expenditures for 2024 through 2026. These estimates are likely to change as a result of the IRP update and RFP process. PacifiCorp's historical and forecast capital expenditures include the following:
•Wind generation
includes both growth projects and operating expenditures. Growth projects include construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties totaling $735 million for 2023, $23 million for 2022 and $118 million for 2021. PacifiCorp placed in-service 42 MWs at the Foote Creek III and Foote Creek IV wind-powered generating facilities in 2023 and 516 MWs of new wind-powered generating facilities in 2021. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $478 million in 2024, $238 million in 2025 and $95 million in 2026 and is primarily for the Rock River I, Rock Creek I and Rock Creek II wind-powered generating facilities totaling approximately 640 MWs that are expected to be placed in-service in 2024 through 2025.
•Electric distribution includes
both growth projects and operating expenditures. Growth expenditures include spending on new customer connections totaling $264 million in 2023, $182 million in 2022 and $177 million in 2021. Planned spending for new customer connections totals $359 million in 2024, $423 million in 2025 and $224 million in 2026. The remaining investments primarily relate to expenditures for distribution operations.
•Electric transmission includes both growth projects and operating expenditures. Transmission growth investments primarily reflects costs associated with major transmission projects. Expenditures for these projects totaled $799 million for 2023, $944 million for 2022 and $94 million for 2021. Forecast expenditures for major transmission projects include planned costs for the following segments:
•416-mile, 500-kV high-voltage transmission line
between the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah;
•59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation;
•290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho;
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•14-mile, 345-kV high-voltage transmission line between the Oquirrh substation in the Salt Lake Valley and the Terminal substation near the Salt Lake City Airport; and
•200-mile,
500-kV high-voltage transmission line between the Anticline substation near Point of Rocks, Wyoming and the Populus substation in Downey, Idaho.
Planned spending for major transmission segments that are expected to be placed in-service in 2024 through 2031 totals $694 million in 2024, $325 million in 2025 and $504 million in 2026. The remaining investments primarily relate to expenditures for transmission operations, generation interconnection requests and other transmission segments.
•Solar generation includes growth projects that are for planned spending for projects that are expected to be placed in-service beyond 2026.
•Electric battery and pumped hydro storage includes growth projects that are for planned spending on projects that are expected to be placed in-service beyond 2026.
•Wildfire
mitigation includes operating expenditures previously included in electric distribution and electric transmission. Expenditures for these items totaled $325 million in 2023, $159 million in 2022 and $64 million in 2021. Planned spending through 2026 is comprised of reducing wildfire risk in the FHCA by conversion of overhead systems to underground, replacing overhead bare wire conductor with covered conductors and deployment of advanced protection devices for faster fault detection. The efforts will also include an expansion of the weather station network and predictive tools for situational awareness across the entire service territory.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $179 million in 2023, $155 million in 2022 and $108 million for 2021. Planned information technology spending totals
$202 million in 2024, $248 million in 2025 and $271 million in 2026. The remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.
Off-Balance Sheet Arrangements
From time to time, PacifiCorp enters into arrangements in the normal course of business to facilitate commercial transactions with third parties that involve guarantees or similar arrangements. PacifiCorp currently has indemnification obligations in connection with the sale or transfer of certain assets. In addition, PacifiCorp evaluates potential obligations that arise out of variable interests in unconsolidated
entities, determined in accordance with authoritative accounting guidance. PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these obligations is remote. Refer to Notes 11 and 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K for more information on these obligations and arrangements.
Material Cash Requirements
PacifiCorp has cash requirements that may affect its consolidated financial condition that arise primarily from long-term debt (refer to Note 8); certain commitments and contingencies, including those associated with the Wildfires (refer to Note 14); and cost of removal
and AROs (refer to Notes 6 and 11). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
PacifiCorp has cash requirements relating to interest payments of $9.5 billion on long-term debt, including $496 million due in 2024.
Regulatory Matters
PacifiCorp is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding PacifiCorp's general regulatory framework and current regulatory matters.
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Environmental
Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict
the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral and Contingent Features
Debt and preferred securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is
no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2023, PacifiCorp's issuer credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future
cost of commercial paper, short- and long-term debt issuances or new credit facilities. Certain authorizations or exemptions by regulatory commissions for the issuance of securities are valid as long as PacifiCorp maintains investment grade ratings on senior secured debt. A downgrade below that level would necessitate new regulatory applications and approvals.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features"). These agreements and
other agreements that do not refer to specified rating-dependent thresholds may provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2023, PacifiCorp would have been required to post $267 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, outstanding accounts payable and receivable or other factors. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a discussion of PacifiCorp's collateral requirements specific
to PacifiCorp's derivative contracts.
Inflation
PacifiCorp operates under a cost-of-service based rate-setting structure administered by various state commissions and the FERC. Under this rate-setting structure, PacifiCorp is allowed to include prudent costs in its rates, including the impact of inflation. PacifiCorp seeks to minimize the potential impact of inflation on its operations through the use of energy and other cost adjustment clauses and tariff riders, by employing prudent risk management and hedging strategies and entering into contracts with fixed pricing where possible by considering, among other areas, its impact on purchases of energy, operating expenses, materials and
equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
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Critical
Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by PacifiCorp's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with PacifiCorp's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting
for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as
a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit PacifiCorp's ability to recover its costs. PacifiCorp believes its application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $2.6 billion and total regulatory liabilities were $2.6 billion as of December 31, 2023. Refer to Note 6 of Notes to Consolidated Financial Statements in
Item 8 of this Form 10-K for additional information regarding PacifiCorp's regulatory assets and liabilities.
Pension and Other Postretirement Benefits
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans as described in Note 10. PacifiCorp recognizes the funded status of these defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2023, PacifiCorp recognized a net asset totaling $80 million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31,
2023, amounts not yet recognized as a component of net periodic benefit cost included in net regulatory assets and accumulated other comprehensive loss totaled $237 million and $13 million, respectively.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including, but not limited to, discount rate and expected long-term rate of return on plan assets. These key assumptions are reviewed annually and modified as appropriate. PacifiCorp believes that the key assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 10 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about PacifiCorp's defined
benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2023.
PacifiCorp chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date with cash flows aligning to the expected timing and amount of plan liabilities.
In establishing its assumption as to the expected long-term rate of return on plan assets, PacifiCorp evaluates the investment allocation between return-seeking investment and fixed income securities based on the funded status of the plan and utilizes the asset allocation and return assumptions for each asset class based on forward-looking
views of the financial markets and historical performance. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. PacifiCorp regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
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The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (in millions):
A
variety of factors affect the funded status of the plans, including discount rates, asset returns, mortality assumptions, plan changes and PacifiCorp's funding policy for each plan.
Income Taxes
In determining PacifiCorp's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by PacifiCorp's various regulatory commissions. PacifiCorp's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. PacifiCorp recognizes the tax benefit from an
uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal, state and local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations is not expected to have a material impact on PacifiCorp's consolidated financial results. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's income taxes.
It
is probable that PacifiCorp will pass income tax benefit and expense related to the 2017 federal tax rate change from 35% to 21%, certain property-related basis differences and other various differences on to customers in certain state jurisdictions. As of December 31, 2023, these amounts were recognized as a net regulatory liability of $1.0 billion and will primarily be included in regulated rates over the estimated useful lives of the related properties.
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Wildfire Loss Contingencies
As a result of several wildfires that have occurred in PacifiCorp's service territory and surrounding areas in the western
U.S., PacifiCorp is required to evaluate its exposure to potential loss contingencies arising from claims associated with the wildfires. In determining this exposure, PacifiCorp is required to assess whether the likelihood of loss for each of the wildfires and lawsuits is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the cause and origin of the wildfires, investigations, discovery associated with lawsuits and negotiations with various parties. If deemed reasonably possible, PacifiCorp is required to estimate the potential loss or range of potential loss and disclose any material amounts. If deemed probable, PacifiCorp is required to accrue a loss if reasonably estimable based on the bottom end of the range if no amount within the range of estimated loss is any better than another amount. Many assumptions and variables are involved in determining these estimates, including
identifying the various categories of potential loss such as fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages. Within the categories of potential loss, further assumptions are made regarding items such as the types of structures damaged, estimated replacement values associated with those structures, value of personal property, the types of natural resource damage such as timber, the value of that timber, the nature of noneconomic damages such as those arising from personal injuries, other damages PacifiCorp may be responsible for if found negligent such as punitive damages, and the amount of any penalties or fines that may be imposed by governmental entities. Refer to Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's loss contingencies associated with the
2020 Wildfires and the 2022 McKinney fire.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
PacifiCorp's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. PacifiCorp's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which PacifiCorp transacts. The following discussion addresses the significant market risks associated with PacifiCorp's business activities. PacifiCorp has established guidelines for credit risk management. Refer to Notes 2 and 12 of Notes to Consolidated
Financial Statements in Item 8 of this Form 10-K for additional information regarding PacifiCorp's contracts accounted for as derivatives.
PacifiCorp has a risk management committee that is responsible for the oversight of market and credit risk relating to the commodity transactions of PacifiCorp. To limit PacifiCorp's exposure to market and credit risk, the risk management committee recommends, and executive management establishes, policies, limits and approved products, which are reviewed frequently to respond to changing market conditions.
Risk is an inherent part of PacifiCorp's business and activities. PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved
in its business. The risk management policy governs energy transactions and is designed for hedging PacifiCorp's existing energy and asset exposures, and to a limited extent, the policy permits arbitrage and trading activities to take advantage of market inefficiencies. The policy also governs the types of transactions authorized for use and establishes guidelines for credit risk management and management information systems required to effectively monitor such transactions. PacifiCorp's risk management policy provides for the use of only those contracts that have a similar volume or price relationship to its portfolio of assets, liabilities or anticipated transactions.
Commodity Price Risk
PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation
to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. PacifiCorp does not engage in a material amount of proprietary trading activities. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp does not hedge all of its commodity price
risk, thereby exposing the unhedged portion to changes in market prices. PacifiCorp's exposure to commodity price risk is generally limited by its ability to include commodity costs in rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
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PacifiCorp measures, monitors and manages the market risk in its electricity and natural gas portfolio in comparison to established thresholds and measures its open positions subject to price risk in terms of quantity at each delivery location for each forward time period. PacifiCorp has a risk management policy that
requires increasing volumes of hedge transactions over a three-year position management and hedging horizon to reduce market risk of its electricity and natural gas portfolio.
PacifiCorp maintained compliance with its risk management policy and limit procedures during the year ended December 31, 2023.
The table that follows summarizes PacifiCorp's price risk on commodity contracts accounted for as derivatives, excluding net collateral receivable of $10 million and net collateral payable of $78 million as of December 31, 2023 and 2022, respectively, and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes
for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions):
PacifiCorp's commodity derivative contracts are generally recoverable from customers in rates; therefore, net unrealized gains and losses associated with interim price movements on commodity derivative
contracts do not expose PacifiCorp to earnings volatility. As of December 31, 2023 and 2022, a regulatory liability of $76 million and a regulatory asset of $270 million, respectively, was recorded related to the net derivative liability of $76 million and net derivative asset $270 million, respectively.
Interest Rate Risk
PacifiCorp is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, PacifiCorp's fixed-rate
long-term debt does not expose PacifiCorp to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity. PacifiCorp has the ability to enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. The nature and amount of PacifiCorp's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7, 8 and 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of PacifiCorp's short- and long-term debt.
As
of December 31, 2023 and 2022, PacifiCorp had long-term variable-rate obligations totaling $218 million that expose PacifiCorp to the risk of increased interest expense in the event of increases in short-term interest rates. The market risk related to PacifiCorp's long-term variable-rate debt as of December 31, 2023 is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on PacifiCorp's consolidated annual interest expense. The carrying value of the long-term variable-rate obligations approximates fair value as of December 31, 2023 and 2022. While PacifiCorp had $1.6 billion of short-term variable rate debt outstanding as of December
31, 2023, it was repaid in January 2024.
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Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be
extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2023, PacifiCorp's aggregate credit exposure with wholesale energy supply and marketing counterparties included counterparties having non-investment grade, internally rated credit ratings. Substantially all of these non-investment grade, internally rated counterparties are associated with long-duration solar and wind power purchase agreements,
some of which are from facilities that have not yet achieved commercial operation and for which PacifiCorp has no obligation should the facilities not achieve commercial operation.
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Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of PacifiCorp
Opinion on the Financial Statements
We
have audited the accompanying consolidated balance sheets of PacifiCorp and subsidiaries ("PacifiCorp") as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive (loss) income, changes in shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of PacifiCorp as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December
31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of PacifiCorp's management. Our responsibility is to express an opinion on PacifiCorp's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. PacifiCorp is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of PacifiCorp's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also
included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical
audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Note 6 to the financial statements
Critical Audit Matter Description
PacifiCorp is subject to rate regulation by the Federal Energy Regulatory Commission as well as certain other regulatory commissions (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where PacifiCorp operates. Management has determined its regulated operations meet the requirements
under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation has a pervasive effect on the financial statements.
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Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow PacifiCorp an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an effect on the recovery of costs, the rate of return earned on investment,
and the timing and amount of assets to be recovered by rates. While PacifiCorp has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit PacifiCorp's ability to recover its costs.
We identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant
under construction, and (3) refunds to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of decisions by the Commissions included the following, among others:
•We evaluated PacifiCorp's disclosures related to the effects of rate regulation by testing certain recorded balances and evaluating regulatory developments.
•We
read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by PacifiCorp and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected PacifiCorp's filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances.
Wildfires — Contingencies — Refer to Note 14 to the financial statements
Critical Audit Matter Description
As
a result of several wildfires that have occurred in PacifiCorp's service territory and surrounding areas in Oregon and California, PacifiCorp is required to evaluate its exposure to potential loss contingencies arising from claims associated with the 2020 Wildfires and the 2022 McKinney Fire (the "Wildfires"). In determining this exposure, PacifiCorp is required to determine whether the likelihood of loss for each of the Wildfires is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the cause and origin of the Wildfires, investigations, discovery associated with lawsuits and negotiations with claimants.
A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. If deemed reasonably possible, PacifiCorp
is required to estimate the potential loss or range of potential loss and disclose any material amounts.
Management has recorded estimated liabilities and receivables which represent its best estimate of probable losses and expected insurance recoveries associated with the Wildfires.
We identified wildfire-related contingencies and the related disclosures as a critical audit matter because of the significant judgments made by management to determine the probability of loss and estimate the probable losses and insurance recoveries. Auditing the reasonableness of management's judgments, estimates and disclosures related to wildfire-related loss contingencies required the application of a high degree of judgment and extensive effort.
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How
the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management's judgments regarding the probability of loss, estimated losses and insurance recoveries, and related disclosures for wildfire-related contingencies included the following, among others:
•We evaluated management's judgments related to whether a loss was probable or reasonably possible for the Wildfires by inquiring of management and PacifiCorp's external and internal legal counsel regarding the likelihood and amounts of probable and reasonably possible losses. We also evaluated the potential impact of information gained through PacifiCorp and third-parties' investigations into the cause
of the fires, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management's assertions.
•We evaluated the estimation methodology for determining the amount of probable and reasonably possible losses through inquiries with management and external and internal legal counsel, and we tested the significant assumptions, including certain settlements, used in the estimates of probable and reasonably possible losses.
•We read legal letters from PacifiCorp's external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.
•We
evaluated management's judgments related to whether certain insurance recoveries were probable of collection by inquiring of management and PacifiCorp's external and internal legal counsel regarding the amounts of insurance recoveries recorded or disclosed. With the assistance of our insurance specialists, we tested certain significant assumptions used in the determination of collectability, including obtaining and reading relevant insurance policies to determine whether the types of insurance claims are included or excluded from coverage. We compared a sample of subsequent insurance recoveries collected to recorded amounts.
•We evaluated whether PacifiCorp's disclosures were appropriate and consistent with the information obtained in our procedures.
Adjustments
to reconcile net (loss) income to net cash flows from operating activities:
Depreciation and amortization
i1,126
i1,120
i1,088
Allowance
for equity funds
(i144)
(i71)
(i50)
Net
power cost deferrals
(i760)
(i482)
(i159)
Amortization
of net power cost deferrals
i231
i100
i67
Other
changes in regulatory assets and liabilities
(i161)
(i162)
(i97)
Deferred
income taxes and amortization of investment tax credits
(i224)
i157
i64
Other, net
i11
i13
(i5)
Changes
in other operating assets and liabilities:
Trade receivables, other receivables and other assets
(i38)
(i88)
i15
Inventories
(i58)
i—
i8
Prepaid
expenses
(i91)
(i46)
i2
Derivative
collateral, net
(i100)
i95
i19
Accrued
property, income and other taxes, net
(i40)
(i46)
(i37)
Accounts
payable and other liabilities
i370
i267
i1
Wildfires
insurance receivable
(i253)
(i130)
i—
Wildfires
liability
i1,299
i172
i—
Net
cash flows from operating activities
i700
i1,819
i1,804
Cash
flows from investing activities:
Capital expenditures
(i3,226)
(i2,166)
(i1,513)
Other,
net
i5
i5
i12
Net
cash flows from investing activities
(i3,221)
(i2,161)
(i1,501)
Cash
flows from financing activities:
Proceeds from long-term debt
i1,189
i1,087
i984
Repayments
of long-term debt
(i449)
(i155)
(i870)
Net
proceeds from (repayments of) short-term debt
i1,604
i—
(i93)
Dividends
paid
(i300)
(i100)
(i150)
Other,
net
(i5)
(i2)
(i7)
Net
cash flows from financing activities
i2,039
i830
(i136)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i482)
i488
i167
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i674
i186
i19
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i192
$
i674
$
i186
The
accompanying notes are an integral part of these consolidated financial statements.
227
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)iOrganization
and Operations
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a U.S. regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company
("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2)iSummary of Significant Accounting Policies
i
Basis
of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of PacifiCorp and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.
i
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally
accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for loss contingencies and applicable insurance recoveries, including those related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the
Wildfires" as discussed in Note 14. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
i
Accounting for the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there
will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in rates occur.
If it becomes no longer probable that the deferred costs or income will be included in future rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
i
Fair
Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair
value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
228
i
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds,
U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing vendor retention, nuclear decommissioning and custodial funds. iA reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2023 and 2022 as
presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Total cash
and cash equivalents and restricted cash and cash equivalents
$
i192
$
i674
i
Investments
Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. As of December 31, 2023 and 2022, PacifiCorp had iino/
unrealized gains and losses on available-for-sale securities. Trading securities are carried at fair value with realized and unrealized gains and losses recognized in earnings.
Equity Method Investments
PacifiCorp utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when an investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate that the ability to exercise significant influence is restricted. In applying the equity method, PacifiCorp records the investment at cost and subsequently
increases or decreases the carrying value of the investment by PacifiCorp's proportionate share of the net earnings or losses and other comprehensive income (loss) ("OCI") of the investee. PacifiCorp records dividends or other equity distributions as reductions in the carrying value of the investment.
/
i
Allowance for Credit Losses
Trade receivables
are primarily short-term in nature with stated collection terms of less than one year from the date of origination, and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on PacifiCorp's assessment of the collectability of amounts owed to PacifiCorp by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, PacifiCorp primarily utilizes credit loss history. However, PacifiCorp may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. iThe
change in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31 (in millions):
2023
2022
2021
Beginning
balance
$
i19
$
i18
$
i17
Charged
to operating costs and expenses, net
i34
i18
i13
Write-offs,
net
(i23)
(i17)
(i12)
Ending
balance
$
i30
$
i19
$
i18
229
i
Derivatives
PacifiCorp
employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled
amounts are recognized as operating revenue or cost of fuel and energy on the Consolidated Statements of Operations.
For PacifiCorp's derivative contracts, the settled amount is generally included in rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in rates are recorded as regulatory liabilities or assets. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
i
Inventories
Inventories
consist mainly of materials, supplies and fuel stocks and are stated at the lower of average cost or net realizable value.
i
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. PacifiCorp capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs, which include debt and equity allowance for funds used during
construction ("AFUDC"). The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.
Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by PacifiCorp's various regulatory authorities or over the assets' estimated useful lives. Depreciation studies are completed periodically to determine the appropriate composite asset class lives, net salvage and depreciation rates. These studies are reviewed and rates are ultimately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability
or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when PacifiCorp retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of property, plant and equipment, is capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set
forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, PacifiCorp is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
230
i
Asset Retirement Obligations
PacifiCorp recognizes AROs when
it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
i
Impairment
PacifiCorp
evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. Substantially all property, plant and equipment supports PacifiCorp's regulated operations, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
i
Leases
PacifiCorp
has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's
accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Right-of-use assets will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
PacifiCorp's leases of generating facilities generally are in the form of long-term purchases of electricity, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements
are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
PacifiCorp's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
i
Revenue Recognition
PacifiCorp uses a single five-step model to identify and recognize
revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or services. PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of PacifiCorp's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided.
231
Revenue
recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp's performance to date and includes billed and unbilled amounts. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
The determination of customer billings is based on a systematic reading of meters. At the end of each month, energy provided to customers since the date of the last meter
reading is estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the subsequent meter readings.
As of December 31, 2023 and 2022, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $i296 million
and $i301 million, respectively.
i
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized
over the term of the related financing using the effective interest method.
i
Income Taxes
Berkshire Hathaway includes PacifiCorp in its consolidated U.S. federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income
tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with certain property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to
income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Investment tax credits are deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.
PacifiCorp recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate
settlement. PacifiCorp's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
i
Segment Information
PacifiCorp currently has ione
segment, which includes its regulated electric utility operations.
/
232
i
New Accounting Pronouncements
In November 2023, the FASB issued ASU No. 2023-07,
Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial
Statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes
to Consolidated Financial Statements.
(3)iProperty, Plant and Equipment, Net
i
Property,
plant and equipment, net consists of the following as of December 31 (in millions):
Depreciable Life
2023
2022
Utility Plant:
Generation
i15
- i59 years
$
i13,904
$
i13,726
Transmission
i60
- i90 years
i8,216
i8,051
Distribution
i20
- i75 years
i9,060
i8,477
Intangible
plant(1) and other
i5 - i75 years
i2,833
i2,755
Utility
plant in-service
i34,013
i33,009
Accumulated
depreciation and amortization
(i11,725)
(i11,093)
Utility
plant in-service, net
i22,288
i21,916
Nonregulated,
net of accumulated depreciation and amortization
i14 - i95 years
i18
i18
i22,306
i21,934
Construction
work-in-progress
i4,745
i2,496
Property,
plant and equipment, net
$
i27,051
$
i24,430
(1)Computer
software costs included in intangible plant are initially assigned a depreciable life of i5 to i10 years.
/
The
average depreciation and amortization rate applied to depreciable property, plant and equipment was i3.4%, i3.5%
and i3.5% for the years ended December 31, 2023, 2022 and 2021, respectively.
Unallocated Acquisition Adjustments
PacifiCorp has unallocated acquisition adjustments that represent the excess
of costs of the acquired interests in property, plant and equipment purchased from the entity that first dedicated the assets to utility service over their net book value in those assets. These unallocated acquisition adjustments included in other property, plant and equipment had an original cost of $ii156/ million
as of December 31, 2023 and 2022, and accumulated depreciation of $i145 million and $i144 million
as of December 31, 2023 and 2022, respectively.
233
(4)iJointly Owned Utility Facilities
Under
joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include PacifiCorp's share of the expenses of these facilities.
i
The
amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2023 (dollars in millions):
Facility
Accumulated
Construction
PacifiCorp
in
Depreciation
and
Work-in-
Share
Service
Amortization
Progress
Jim Bridger Nos. 1 - 4
i67
%
$
i1,596
$
i996
$
i26
Hunter
No. 1
i94
i510
i237
i4
Hunter
No. 2
i60
i316
i151
i2
Wyodak
i80
i491
i285
i—
Colstrip
Nos. 3 and 4
i10
i262
i199
i—
Hermiston
i50
i191
i111
i3
Craig
Nos. 1 and 2
i19
i372
i341
i—
Hayden
No. 1
i25
i77
i55
i—
Hayden
No. 2
i13
i45
i32
i—
Transmission
and distribution facilities
Various
i900
i283
i192
Total
$
i4,760
$
i2,690
$
i227
/
(5) iiLeases/
i
The
following table summarizes PacifiCorp's leases recorded on the Consolidated Balance Sheets as of December 31 (in millions):
2023
2022
Right-of-use assets:
Operating leases
$
i12
$
i11
Finance
leases
i10
i9
Total right-of-use assets
$
i22
$
i20
Lease
liabilities:
Operating leases
$
i12
$
i11
Finance
leases
i12
i11
Total lease liabilities
$
i24
$
i22
/
234
i
The
following table summarizes PacifiCorp's lease costs for the years ended December 31 (in millions):
2023
2022
2021
Variable
$
i57
$
i61
$
i56
Operating
i4
i3
i3
Finance:
Amortization
i1
i1
i5
Interest
i1
i1
i2
Short-term
i6
i5
i3
Total
lease costs
$
i69
$
i71
$
i69
Weighted-average
remaining lease term (years):
Operating leases
i12.3
i11.4
i12.7
Finance
leases
i8.8
i9.7
i10.1
Weighted-average
discount rate:
Operating leases
i3.8
%
i3.9
%
i3.7
%
Finance
leases
i10.6
%
i11.4
%
i11.1
%
/
Cash
payments associated with operating and finance lease liabilities approximated lease cost for the years ended December 31, 2023, 2022 and 2021.
i
PacifiCorp has the following remaining lease commitments as of December 31, 2023 (in millions):
Operating
Finance
Total
2024
$
i3
$
i2
$
i5
2025
i2
i2
i4
2026
i2
i2
i4
2027
i1
i2
i3
2028
i1
i2
i3
Thereafter
i7
i8
i15
Total
undiscounted lease payments
i16
i18
i34
Less
- amounts representing interest
(i4)
(i6)
(i10)
Lease
liabilities
$
i12
$
i12
$
i24
/
235
(6)iRegulatory
Matters
Regulatory Assets
i
Regulatory assets represent costs that are expected to be recovered in future rates. PacifiCorp's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Employee
benefit plans(1)
i16 years
$
i279
$
i290
Utah
mine disposition(2)
Various
i79
i115
Deferred
net power costs
i2 years
i1,117
i546
Unrealized
loss on derivative contracts
i1 year
i76
i—
Environmental
costs
i30 years
i139
i111
Asset
retirement obligation
i28 years
i300
i275
Demand
side management (DSM)
i10 years
i245
i224
Wildfire
mitigation and vegetation management costs
Various
i114
i111
Other
Various
i224
i208
Total
regulatory assets
$
i2,573
$
i1,880
Reflected
as:
Current assets
$
i631
$
i275
Noncurrent
assets
i1,942
i1,605
Total
regulatory assets
$
i2,573
$
i1,880
(1)Represents
amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognized.
(2)Amounts represent regulatory assets established as a result of the Utah mine disposition in 2015 for the United Mine Workers of America ("UMWA") 1974 Pension Plan withdrawal and closure costs incurred to date considered probable of recovery. Refer to Note 10 for additional information.
/
PacifiCorp had regulatory assets not earning a return on investment of $i1,852
million and $i1,200 million as of December 31, 2023 and 2022, respectively.
236
Regulatory Liabilities
i
Regulatory
liabilities represent income to be recognized or amounts to be returned to customers in future periods. PacifiCorp's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Cost
of removal(1)
i26 years
$
i1,456
$
i1,332
Deferred
income taxes(2)
Various
i1,006
i1,164
Unrealized
gain on regulated derivatives
N/A
i—
i270
Other
Various
i148
i173
Total
regulatory liabilities
$
i2,610
$
i2,939
Reflected
as:
Current liabilities
$
i70
$
i96
Noncurrent
liabilities
i2,540
i2,843
Total
regulatory liabilities
$
i2,610
$
i2,939
(1)Amounts
represent estimated costs, as generally accrued through depreciation rates, of removing property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable of being passed on to customers, partially offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
/
(7)iShort-term
Debt and Credit Facilities
PacifiCorp has a $i2.0 billion unsecured credit facility expiring in June 2026 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate or a base rate, at PacifiCorp's option, plus
a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.
i
The following table summarizes PacifiCorp's availability under its unsecured credit facility as of December 31 (in millions):
2023:
Credit
facility
$
i2,000
Less:
Short-term debt
(i1,604)
Tax-exempt
bond support and letters of credit
(i249)
Net credit facility
$
i147
2022:
Credit
facility
$
i1,200
Less:
Tax-exempt bond support and letters of credit
(i249)
Net
credit facility
$
i951
/
As of December 31, 2023, PacifiCorp was in compliance with all financial covenants that affect access to capital.
As
of December 31, 2023, PacifiCorp had $i1.6 billion of short-term debt outstanding at a weighted average rate of i6.16%, which was subsequently repaid in January 2024. As of December 31, 2022, PacifiCorp
had ino short-term debt outstanding.
237
The credit facility and the delayed draw term loan facility described in Note 8 require that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed i0.65
to 1.0 as of the last day of each quarter. As of December 31, 2023, PacifiCorp's debt to total capitalization ratio was 0.55 to 1.0. Refer to Note 8 for discussion of PacifiCorp's January 2024 issuance of First Mortgage Bonds.
As of December 31, 2023, PacifiCorp had $i255 million of letter of credit
capacity under its $i2.0 billion revolving credit facility of which $i31 million was outstanding and was utilized as a standby letter of credit, and $i168 million
of letter of credit capacity outside of its $i2.0 billion revolving credit facility, of which $i55 million was outstanding and was utilized in support of certain transactions required by third parties.
As
of December 31, 2022, PacifiCorp had $i219 million of letter of credit capacity under the $i1.2 billion revolving credit facility
that was in place at that time, of which $i31 million was outstanding and was utilized as a standby letter of credit, and $i7 million of letters of credit outstanding under committed arrangements outside of the facility in support
of certain transactions required by third parties.
(8)iLong-term Debt
i
PacifiCorp's
long-term debt was as follows as of December 31 (dollars in millions):
2023
2022
Average
Average
Principal
Carrying
Interest
Carrying
Interest
Amount
Value
Rate
Value
Rate
First
mortgage bonds:
i2.95% to i8.23%,
due through 2026
$
i775
$
i774
i3.92
%
$
i1,223
i4.07
%
i2.70%
to i7.70%, due 2029 to 2031
i1,100
i1,096
i4.35
i1,095
i4.35
i5.25%
to i6.35%, due 2034 to 2038
i2,350
i2,341
i5.96
i2,340
i5.96
i4.10%
to i6.00%, due 2039 to 2042
i950
i942
i5.40
i941
i5.40
i2.90%
to i5.50%, due 2049 to 2054
i5,100
i5,039
i4.38
i3,849
i4.03
Variable-rate
series, tax-exempt bond obligations (2023-i4.60% to i5.60%; 2022-i3.75%
to i4.10%):
Due 2025
i25
i25
i4.60
i25
i4.10
Due
2024 to 2025(1)
i193
i193
i5.51
i193
i3.81
Total
long-term debt
$
i10,493
$
i10,410
$
i9,666
Reflected
as:
2023
2022
Current portion of long-term debt
$
i591
$
i449
Long-term
debt
i9,819
i9,217
Total
long-term debt
$
i10,410
$
i9,666
(1)Secured
by pledged first mortgage bonds registered to and held by the tax-exempt bond trustee generally with the same interest rates, maturity dates and redemption provisions as the tax-exempt bond obligations.
/
In May 2023, PacifiCorp issued $i1.2 billion of its i5.50%
First Mortgage Bonds due May 2054. PacifiCorp intends within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.
238
In December 2023, PacifiCorp entered into a $i900 million
unsecured delayed draw term loan facility expiring in June 2025. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at PacifiCorp's option, plus a pricing margin. Subject to regulatory authority to issue long-term debt, PacifiCorp may draw all or none of the unused commitment up to three times through June 2025. As of December 31, 2023, PacifiCorp had no term loans drawn from the facility and currently has no authority to issue additional long-term debt until additional filings occur with the Oregon Public Utility Commission ("OPUC") and the Idaho Public Utilities Commission ("IPUC") and are approved as described below. As described in Note 7, the delayed draw term loan facility requires certain ratios to be maintained.
In January 2024, PacifiCorp issued
$i500 million of its i5.10% First Mortgage Bonds due February 2029, $i700 million
of its i5.30% First Mortgage Bonds due February 2031, $i1.1 billion of its i5.45%
First Mortgage Bonds due February 2034 and $i1.5 billion of its i5.80% First Mortgage Bonds due January 2055 for a total of $i3.8 billion.
PacifiCorp initially used a portion of the net proceeds to repay outstanding short-term debt and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.
PacifiCorp's long-term debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in part at any time through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generally redeemable at par value.
Following PacifiCorp's January 2024 First Mortgage Bond issuances, PacifiCorp currently has no remaining regulatory authority from the OPUC and the IPUC to issue additional long-term debt. PacifiCorp must apply for additional issuance authority from the OPUC and IPUC and make a notice filing with the Washington Utilities and Transportation
Commission prior to any future issuance. PacifiCorp currently has an effective shelf registration statement filed with the U.S. Securities and Exchange Commission to issue an indeterminate amount of first mortgage bonds through September 2026.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's mortgage. Approximately $i36 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 31, 2023.
i
As of December 31, 2023, the annual principal maturities of long-term debt for 2024 and thereafter are as follows (in millions):
Long-term
Debt
2024
$
i591
2025
i302
2026
i100
2027
i—
2028
i—
Thereafter
i9,500
Total
i10,493
Unamortized
discount and debt issuance costs
(i83)
Total
$
i10,410
/
(9)iIncome
Taxes
The effective tax rate for the year ended December 31, 2023, is i54% and results from a $i553 million
income tax benefit associated with a $i1,021 million pre-tax loss primarily related to a $i1,677 million
increase in wildfire loss accruals, net of expected insurance recoveries as described in Note 14. The $i553 million income tax benefit is primarily comprised of a $i214 million
benefit, or i21%, from the application of the federal statutory income tax rate to the pre-tax loss, a $i180 million benefit, or i18%,
from federal income tax credits, a $i111 million benefit, or i11%, from effects of ratemaking and a $i41 million
benefit, or i4%, from state income tax.
239
i
Income
tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Current:
Federal
$
(i324)
$
(i216)
$
(i150)
State
(i5)
(i3)
i7
Total
(i329)
(i219)
(i143)
Deferred:
Federal
(i172)
i90
i26
State
(i51)
i71
i40
Total
(i223)
i161
i66
Investment
tax credits
(i1)
(i4)
(i2)
Total
income tax expense (benefit)
$
(i553)
$
(i62)
$
(i79)
/
i
A
reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income (loss) before income tax expense (benefit) is as follows for the years ended December 31:
2023
2022
2021
Federal statutory income tax rate
i21
%
i21
%
i21
%
State
income taxes, net of federal income tax benefit
i4
i3
i3
Effects
of ratemaking(1)
i11
(i12)
(i14)
Federal
income tax credits
i18
(i22)
(i20)
Valuation
allowance
i1
i2
i—
Other
(i1)
i1
i—
Effective
income tax rate
i54
%
(i7)
%
(i10)
%
/
(1)
Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
Income tax credits relate primarily to production tax credits ("PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for i10 years from the date the
qualifying generating facilities are placed in-service. PTCs for the years ended December 31, 2023, 2022 and 2021 totaled $i180 million, $i185 million
and $i164 million, respectively.
240
i
The
net deferred income tax liability consists of the following as of December 31 (in millions):
2023
2022
Deferred income tax assets:
Regulatory liabilities
$
i643
$
i724
Employee
benefits
i51
i59
State
carryforwards
i84
i73
Loss
contingencies
i429
i107
AROs
i85
i79
Other
i117
i80
Total
deferred income tax assets
i1,409
i1,122
Valuation
allowances
(i24)
(i35)
Total deferred income tax assets, net
i1,385
i1,087
Deferred
income tax liabilities:
Property-related items
(i3,704)
(i3,612)
Regulatory
assets
(i632)
(i462)
Other
(i134)
(i165)
Total
deferred income tax liabilities
(i4,470)
(i4,239)
Net
deferred income tax liability
$
(i3,085)
$
(i3,152)
/
i
The
following table provides, without regard to valuation allowances, PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31, 2023 (in millions):
State
Net operating loss carryforwards
$
i1,427
Deferred
income taxes on net operating loss carryforwards
$
i64
Expiration dates
2026 - indefinite
Tax credit carryforwards
$
i20
Expiration
dates
2024 - indefinite
/
The U.S. Internal Revenue Service has closed or effectively settled its examination of PacifiCorp's income tax returns through December 31, 2013. The statute of limitations for PacifiCorp's income tax returns have expired for certain states through December 31, 2011, and for Idaho through December 31, 2019, except for the impact of any federal audit adjustments. The closure of examinations, or the expiration of the statute of limitations, for state
filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
(10) iEmployee Benefit Plans
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover certain of its employees, as well
as a defined contribution 401(k) employee savings plan ("401(k) Plan"). In addition, PacifiCorp contributes to a joint trustee pension plan and a subsidiary previously contributed to a multiemployer pension plan for benefits offered to certain bargaining units.
241
Defined Benefit Plans
PacifiCorp's pension plans include non-contributory defined benefit pension plans, the PacifiCorp Retirement Plan ("Retirement Plan"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union employees hired after January 1, 2008. All non-union Retirement
Plan participants hired prior to January 1, 2008 that did not elect to receive equivalent fixed contributions to the 401(k) Plan effective January 1, 2009 earned benefits based on a cash balance formula through December 31, 2016. Effective January 1, 2017, non-union employee participants with a cash balance benefit in the Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general for union employees, benefits under the Retirement Plan were frozen at various dates from December 31, 2007 through December 31, 2011 as they are now being provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants
continue to earn benefits under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to new participants as of March 21, 2006 and froze future accruals for active participants as of December 31, 2014.
PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.
Pension Settlement
Pension settlement accounting was triggered in 2022 and 2021 as a result of the amount of lump sum distributions in the Retirement Plan exceeding the service and interest cost threshold. The 2021 pension settlement accounting included
an interim July 31, 2021 remeasurement of the pension plan assets and projected benefit obligation. As a result of the settlement accounting, PacifiCorp recognized settlement losses of $ii6/ million,
net of regulatory deferrals during each of the years ended December 31, 2022 and 2021.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the first year in which they occur.
i
Net
periodic benefit cost (credit) for the plans included the following components for the years ended December 31 (in millions):
Pension
Other Postretirement
2023
2022
2021
2023
2022
2021
Service
cost
$
i—
$
i—
$
i—
$
i1
$
i2
$
i2
Interest
cost
i39
i29
i29
i11
i8
i7
Expected
return on plan assets
(i49)
(i42)
(i51)
(i13)
(i11)
(i9)
Settlement(1)
i—
i6
i6
i—
i—
i—
Net
amortization
i12
i16
i21
(i2)
i1
i1
Net
periodic benefit cost (credit)
$
i2
$
i9
$
i5
$
(i3)
$
i—
$
i1
/
(1)Pension
amounts represent settlement losses of $i— million, $i24
million and $i15 million net of deferrals of $i— million,
$i18 million and $i9 million
during the years ended December 31, 2023, 2022 and 2021.
242
Funded Status
i
The following table is a reconciliation of the fair value of plan assets for the years ended December 31
(in millions):
Pension
Other Postretirement
2023
2022
2023
2022
Plan
assets at fair value, beginning of year
$
i758
$
i1,058
$
i264
$
i324
Employer
contributions(1)
i4
i4
i—
i—
Participant
contributions
i—
i—
i4
i5
Actual
(loss) return on plan assets
i73
(i172)
i25
(i42)
Settlement(2)
i—
(i67)
i—
i—
Benefits
paid
(i71)
(i65)
(i22)
(i23)
Plan
assets at fair value, end of year
$
i764
$
i758
$
i271
$
i264
(1)Pension
amounts represent employer contributions to the SERP.
(2)Benefits paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
/
i
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension
Other
Postretirement
2023
2022
2023
2022
Benefit obligation, beginning of year
$
i746
$
i1,048
$
i219
$
i288
Service
cost
i—
i—
i1
i2
Interest
cost
i39
i29
i11
i8
Participant
contributions
i—
i—
i4
i5
Actuarial
gain (loss)
i26
(i199)
i2
(i61)
Settlement(1)
i—
(i67)
i—
i—
Benefits
paid
(i71)
(i65)
(i22)
(i23)
Benefit
obligation, end of year
$
i740
$
i746
$
i215
$
i219
Accumulated
benefit obligation, end of year
$
i740
$
i746
(1)Benefits
paid in the form of lump sum distributions that gave rise to the settlement accounting described above.
/
i
The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
Pension
Other
Postretirement
2023
2022
2023
2022
Plan assets at fair value, end of year
$
i764
$
i758
$
i271
$
i264
Less
- Benefit obligation, end of year
i740
i746
i215
i219
Funded
status
$
i24
$
i12
$
i56
$
i45
Amounts
recognized on the Consolidated Balance Sheets:
Other assets
$
i65
$
i53
$
i56
$
i45
Accrued
employee expenses
(i4)
(i4)
i—
i—
Other
long-term liabilities
(i37)
(i37)
i—
i—
Amounts
recognized
$
i24
$
i12
$
i56
$
i45
/
243
The
SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $i68 million and $i61 million
as of December 31, 2023 and 2022, respectively. These assets are not included in the plan assets in the above table, but are reflected in noncurrent other assets as of December 31, 2023 and 2022, respectively, on the Consolidated Balance Sheets. The projected and accumulated benefit obligations for the SERP were $i41 million and $i42 million
at December 31, 2023 and 2022, respectively.
As of December 31, 2023, the fair value of the plan assets for the Retirement Plan was in excess of both the projected benefit obligation and the accumulated benefit obligation.
Unrecognized Amounts
i
The
portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
Pension
Other Postretirement
2023
2022
2023
2022
Net
loss (gain)
$
i270
$
i273
$
(i42)
$
(i36)
Regulatory
deferrals(1)
i22
i29
i—
i1
Total
$
i292
$
i302
$
(i42)
$
(i35)
(1)Pension
amounts represent the unamortized portion of deferred settlement losses.
/
244
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2023 and 2022 is as follows (in millions):
Assumptions
used to determine benefit obligations and net periodic benefit cost were as follows:
Pension
Other Postretirement
2023
2022
2021
2023
2022
2021
Benefit
obligations as of December 31:
Discount rate
i5.20
%
i5.55
%
i2.90
%
i5.20
%
i5.50
%
i2.90
%
Interest
crediting rates for cash balance plan - non-union
2021
N/A
N/A
i0.82
%
N/A
N/A
N/A
2022
N/A
i0.88
%
i0.88
%
N/A
N/A
N/A
2023
i4.73
%
i4.73
%
i0.88
%
N/A
N/A
N/A
2024
i5.98
%
i4.73
%
i1.90
%
N/A
N/A
N/A
2025
i5.98
%
i2.60
%
i1.90
%
N/A
N/A
N/A
2026
and beyond
i3.10
%
i2.60
%
i1.90
%
N/A
N/A
N/A
Interest
crediting rates for cash balance plan - union
2021
N/A
N/A
i1.42
%
N/A
N/A
N/A
2022
N/A
i1.94
%
i1.94
%
N/A
N/A
N/A
2023
i3.55
%
i3.55
%
i1.94
%
N/A
N/A
N/A
2024
i4.47
%
i3.55
%
i2.30
%
N/A
N/A
N/A
2025
i4.47
%
i2.40
%
i2.30
%
N/A
N/A
N/A
2026
and beyond
i2.70
%
i2.40
%
i2.30
%
N/A
N/A
N/A
Net
periodic benefit cost for the years ended December 31:
Discount rate
i5.55
%
i2.90
%
i2.50
%
i5.50
%
i2.90
%
i2.50
%
Expected
return on plan assets
i6.00
i4.70
i6.00
i4.78
i3.44
i2.90
/
In
establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
As a result of a plan amendment effective on January 1, 2017, the benefit obligation for the Retirement Plan is no longer affected by future increases in compensation. As a result of a labor settlement reached with UMWA in December 2014, the benefit obligation for the other postretirement plan is no longer affected by healthcare cost trends.
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit
plans are expected to be $i4 million and $i— million, respectively, during
2024. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ("ERISA") and the Pension Protection Act of 2006, as amended ("PPA of 2006"). PacifiCorp considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the PPA of 2006. PacifiCorp evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plan.
246
i
The
expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2024 through 2028 and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension
Other Postretirement
2024
$
i76
$
i22
2025
i72
i22
2026
i70
i21
2027
i66
i20
2028
i63
i19
2029-2033
i273
i81
/
Plan
Assets
Investment Policy and Asset Allocations
PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment consultants to advise on plan investments within the parameters outlined by the Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
In 2020, the assets of the PacifiCorp Master Retirement Trust
were transferred into the BHE Master Retirement Trust.
i
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows as of December 31, 2023:
Pension(1)
Other
Postretirement(1)
%
%
Debt securities(2)
i73
i79
Equity
securities(2)
i22
i21
Other
i5
0
(1)The trust in which the PacifiCorp Retirement Plan is invested includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association ("VEBA") trusts, each of which has its own investment allocation strategies. Target allocations for the other postretirement benefit plan include the separate account of the Retirement Plan trust and the VEBA trusts.
(2)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying
investments in debt and equity securities.
/
247
Fair Value Measurements
i
The
following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in millions):
Limited partnership interests(3) measured at net asset value
i32
Investments
at fair value
$
i758
(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are
substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately i41% and i59%, respectively, for 2023 and i50%
and i50%, respectively, for 2022, and are invested in U.S. and international securities of approximately i88% and i12%,
respectively, for 2023 and i90% and i10%, respectively, for 2022.
(3)Limited partnership interests include several funds
that invest primarily in real estate.
/
248
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan (in millions):
(1)Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are
substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately i38% and i62%, respectively, for 2023 and i41%
and i59%, respectively, for 2022, and are invested in U.S. and international securities of approximately i89% and i11%,
respectively, for 2023 and i91% and i9%, respectively, for 2022.
For level 1 investments, a readily observable
quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Multiemployer and Joint Trustee Pension Plans
PacifiCorp contributes to the PacifiCorp/IBEW Local 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number 001) and its subsidiary,
Energy West Mining Company, previously contributed to the UMWA 1974 Pension Plan (plan number 002). Contributions to these pension plans are based on the terms of collective bargaining agreements.
249
As a result of the Utah Mine Disposition and UMWA labor settlement, PacifiCorp's subsidiary, Energy West Mining Company, triggered involuntary withdrawal from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp recorded its estimate of the withdrawal obligation in December 2014 when withdrawal was considered probable and deferred the portion of the obligation considered probable of recovery to a regulatory asset. PacifiCorp has subsequently revised its estimate due
to changes in facts and circumstances for a withdrawal occurring by July 2015. As communicated in a letter received in August 2016, the plan trustees determined a withdrawal liability of $i115 million. Energy West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to settle the withdrawal obligation. In January 2024, the withdrawal liability was recalculated by the plan's actuary to be $i80 million
as a result of arbitration efforts regarding the interest rate used to compute the obligation. The ultimate amount paid by Energy West Mining Company to settle the obligation is dependent on a variety of factors, including the results of ongoing efforts with the plan trustees and the recent arbitration activities.
The Local 57 Trust Fund is a joint trustee plan such that the board of trustees is represented by an equal number of trustees from PacifiCorp and the union. The Local 57 Trust Fund was established pursuant to the provisions of the Taft-Hartley Act and although formed with the ability for other employers to participate in the plan, there are no other employers that participate in this plan.
The risk of participating in multiemployer pension plans generally differs from single-employer plans in
that assets are pooled such that contributions by one employer may be used to provide benefits to employees of other participating employers and plan assets cannot revert to employers. If an employer ceases participation in the plan, the employer may be obligated to pay a withdrawal liability based on the participants' unfunded, vested benefits in the plan. If participating employers withdraw from a multiemployer plan, the unfunded obligations of the plan may be borne by the remaining participating employers.
i
The following table presents PacifiCorp's participation in individually significant
joint trustee and multiemployer pension plans for the years ended December 31 (dollars in millions):
PPA
of 2006 zone status or plan funded status percentage for plan years beginning July 1,
Contributions
Plan name
Employer Identification Number
2023
2022
2021
Funding improvement plan
Surcharge imposed under
PPA of 2006
2023
2022
2021
Year contributions to plan exceeded more than 5% of total contributions
Local 57 Trust Fund
87-0640888
At least
i80%
At
least i80%
At least i80%
None
None
$
i5
$
i6
$
i6
2023,
2022, 2021
/
PacifiCorp's minimum contributions to the Local 57 Trust Fund are based on the amount of wages paid to employees covered by the Local 57 Trust Fund collective bargaining agreements, subject to ERISA minimum funding requirements. The collective bargaining agreements governing the Local 57 Trust Fund that were due to expire in 2023 were extended to 2028 in December 2022.
Defined Contribution Plan
PacifiCorp's 401(k) Plan covers substantially all employees. PacifiCorp's matching contributions are based on each participant's level of contribution
and, as of January 1, 2023, all participants receive contributions based on eligible pre-tax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. PacifiCorp's contributions to the 401(k) Plan were $i48 million, $i44
million and $i40 million for the years ended December 31, 2023, 2022 and 2021, respectively.
(11)iAsset
Retirement Obligations
PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
PacifiCorp does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized
on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. Cost of removal regulatory liabilities totaled $i1,456 million and $i1,332 million
as of December 31, 2023 and 2022, respectively.
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i
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31 (in millions):
2023
2022
Beginning
balance
$
i331
$
i304
Change in estimated costs
(i4)
i20
Additions
i27
i3
Retirements
(i9)
(i6)
Accretion
i11
i10
Ending
balance
$
i356
$
i331
Reflected
as:
Other current liabilities
$
i9
$
i11
Other
long-term liabilities
i347
i320
$
i356
$
i331
/
Certain
of PacifiCorp's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites. PacifiCorp is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, PacifiCorp may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. PacifiCorp's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities.
(12)iRisk
Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt
and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.
PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp has the ability to enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's
exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
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i
The
following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
(1)PacifiCorp's
commodity derivatives are generally included in rates. As of December 31, 2023 a regulatory asset of $i76 million was recorded related to the net derivative liability of $i76 million.
As of December 31, 2022 regulatory liability of $i270 million was recorded related to the net derivative asset of $i270 million.
(2)As of December 31, 2022, PacifiCorp had an additional $i12 million cash collateral payable that was not required to be netted against total derivatives.
/
i
The
following table reconciles the beginning and ending balances of PacifiCorp's net regulatory (liabilities) assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory (liabilities) assets, as well as amounts reclassified to earnings for the years ended December 31 (in millions):
2023
2022
2021
Beginning
balance
$
(i270)
$
(i53)
$
i17
Changes
in fair value recognized in regulatory (liabilities) assets
i206
(i513)
(i171)
Net
(losses) gains reclassified to operating revenue
(i8)
(i13)
(i23)
Net
gains (losses) reclassified to cost of fuel and energy
i148
i309
i124
Ending balance
$
i76
$
(i270)
$
(i53)
/
252
Derivative
Contract Volumes
i
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
Unit of
Measure
2023
2022
Electricity purchases,
net
Megawatt hours
i2
i2
Natural gas purchases
Decatherms
i153
i127
/
Credit
Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements
and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features"). These agreements and other agreements that do not refer
to specified rating-dependent thresholds may provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2023, PacifiCorp's issuer credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $i108 million
and $i48 million as of December 31, 2023 and 2022, respectively, for which PacifiCorp had posted collateral of $i12 million
and $i— million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of December 31, 2023 and 2022, PacifiCorp would have been required to post $i84 million
and $i3 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
253
(13)iFair
Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement
date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.
The following table presents PacifiCorp's financial assets and
liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
(1)Represents
netting under master netting arrangements and a net cash collateral receivable of $i10 million and a net cash collateral payable of $i78 million
as of December 31, 2023 and 2022, respectively. As of December 31, 2022, PacifiCorp had an additional $i12 million cash collateral payable that was not required to be netted against total derivatives.
254
Derivative
contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. A discounted cash flow valuation method was used to estimate fair value. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market
price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates,
related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 12 for further discussion regarding PacifiCorp's risk management and hedging activities.
PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's
long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. iThe following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt as of December 31 (in millions):
2023
2022
Carrying
Fair
Carrying
Fair
Value
Value
Value
Value
Long-term
debt
$
i10,410
$
i9,722
$
i9,666
$
i9,045
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(14)iCommitments
and Contingencies
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Certain commitments are with related parties. Refer to Note 21 for transactions associated with these related party contracts. iMinimum payments as of December 31, 2023 are as follows (in millions):
The table above reflects purchased electricity contracts with expiration dates ranging from 2024 through 2052. As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange agreements. PacifiCorp has many long-term PPAs primarily with solar-powered or wind-powered generating facilities that are not included in the table above due to there being no minimum payments generally due to being dependent on wind and solar conditions. The PPAs generally range from i10 to i30
years in duration, with certain of the PPAs extending through 2046. Future payments associated with these PPAs are expected to be material. Certain of these PPAs qualify as leases as described in Note 2. Refer to Note 5 for variable lease costs associated with these lease commitments.
Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several hydroelectric systems under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service" basis for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are included in energy costs on the Consolidated Statements of Operations. PacifiCorp is required to pay its portion of operating costs and its portion of the debt service, whether or not any electricity is produced.
These arrangements accounted for less than iii5//%
of PacifiCorp's 2023, 2022 and 2021 energy sources.
PacifiCorp has many long-term PPAs with facilities that have not yet achieved commercial operation, primarily related to wind-powered and solar-powered generated facilities and including with facilities that are not included in the table above due to there being no minimum payments generally due to being dependent on wind and solar conditions. The PPAs generally range from i10 to i30
years in duration, with certain of the PPAs extending through 2054. Future payments associated with these arrangements are expected to be material. The table above reflects capacity payments through 2046 for a 400 MW battery storage agreement associated with a purchased electricity contract for a 400 MW solar generating facility. To the extent these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparties.
Fuel Contracts
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments. In January and February 2024, PacifiCorp entered into new and amended coal supply agreements aggregating approximately $i1.9 billion
of additional commitments through 2030.
256
Construction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with certain generating plant, transmission, and distribution projects.
Transmission
PacifiCorp has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's customers.
Easements
PacifiCorp
has easements for land on which certain of its assets, primarily wind-powered generating facilities, are located.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, wildfire prevention and mitigation and other environmental matters that have the potential to impact its current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Lower Klamath Hydroelectric Project
PacifiCorp is a party to the 2016 amended Klamath Hydroelectric
Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $i200 million plus $i250 million
in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath hydroelectric dams comprising the Lower Klamath Project (FERC Project No. 14803) from PacifiCorp to the KRRC. The FERC approved the partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender
and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application to remove PacifiCorp from the license for the Lower Klamath Project and add the States and KRRC as co-licensees for the purposes of surrender. In addition, the MOA provides for additional contingency funding of $i45 million,
equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $i450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved the transfer of the Lower Klamath Project dams from PacifiCorp to the KRRC and the States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally
approved the required property transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. In August 2022, the FERC staff issued a final environmental impact statement for the project, concluding that dam removal is the preferred action. In November 2022, the FERC issued a license surrender order for the project, which was accepted by the KRRC and the States in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility was completed in November 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1, and Iron Gate) is anticipated to be completed in 2024.
257
Hydroelectric
Commitments
Certain of PacifiCorp's hydroelectric licenses and settlement agreements contain requirements for PacifiCorp to make certain capital and operating expenditures related to its hydroelectric facilities, which are estimated to be approximately $i314 million over the next i10
years.
Legal Matters
PacifiCorp is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may seek to impose fines, penalties and other costs.
Pursuant to ASC 450, "Contingencies," a provision for a loss contingency is recorded when it is probable a liability is likely to occur and the amount of loss can be reasonably estimated. PacifiCorp evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.
Wildfires
In
California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could be found liable for all damages.
2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to
several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over i500,000 acres in aggregate. Third-party reports for these wildfires indicate over i2,000
structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.
Investigations into the cause and origin of each wildfire are complex and ongoing and have been or are being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, a significant number of complaints and demands alleging similar claims related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint in Oregon for which two jury verdicts were issued in June 2023 and January 2024 as described below. The plaintiffs seek damages for economic
losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned complaints. Additionally, the U.S. and Oregon Departments of Justice have informed PacifiCorp that they are contemplating filing actions against PacifiCorp in connection with certain of the Oregon 2020 Wildfires. PacifiCorp is actively cooperating with the U.S. and Oregon Departments of Justice on resolving these alleged claims, including through the pursuit of alternative dispute resolution.
258
Amounts sought in the complaints
and demands filed in Oregon and in certain demands made in California total approximately $i8 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the complaints filed in California do not specify damages sought and are excluded from this amount. For class actions, amounts specified by the plaintiffs in the complaints include amounts based on estimates of the potential class size, which ultimately may be significantly greater than estimated. Additionally, damages are not limited to the amounts specified in the initially filed complaints as plaintiffs are
frequently allowed to amend their complaints to add additional damages and amounts awarded in a court proceeding may be significantly greater than the damages specified. Oregon law provides for doubling of economic and property damages in the event the defendant is found to have acted with gross negligence, recklessness, willfulness or malice. Oregon law provides for trebling of the damages associated with timber, shrubs and produce in the event the defendant is determined to have willfully and intentionally trespassed. Based on available information to date, PacifiCorp believes it is probable that losses will be incurred associated with the 2020 Wildfires. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.
The
James Case
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon ("James"). The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain Complex, South Obenchain and 242 wildfires. In May 2022, the Multnomah County Circuit Court
granted issue class certification and consolidated the James case with several other cases. While PacifiCorp's pre-trial request for immediate appeal of the class certification was denied, it subsequently filed to appeal the class issues as described below.
In April 2023, the jury trial for James with respect to i17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the i17
named plaintiffs and to the class with respect to the ifour wildfires. The jury found PacifiCorp's conduct grossly negligent, reckless and willful as to each plaintiff and the entire class. The jury awarded the i17 named plaintiffs $i90 million
of damages, including $i4 million of economic damages, $i68 million of noneconomic damages and $i18 million
of punitive damages based on a i0.25 multiplier of the economic and noneconomic damages.
In September 2023, the Multnomah County Circuit Court ordered trial dates for itwo consolidated jury trials including
approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the ithree damages phase trials will present evidence regarding their damages. The first of these trials addressing nine individual plaintiffs was held in January 2024 while the remaining trials are scheduled at various dates through April 2024.
In January 2024, the Multnomah County Circuit Court entered a limited judgment and money award for the June 2023 James verdict. The limited
judgment awards the aforementioned damages, as well as doubling of the economic damages and offsetting of any insurance proceeds received by plaintiffs. The limited judgment created a lien against PacifiCorp, attaching a debt for the money awards. PacifiCorp posted a supersedeas bond, which stays any effort to seek payment of the judgment pending final resolution of any appeals.Under ORS 82.010, interest at a rate of i9% per annum will accrue on the judgment commencing at the date the judgment was entered until the entire money award is paid, amended or reversed by an appellate
court. In January 2024, PacifiCorp filed a notice of appeal associated with the June 2023 verdict in James, including whether the case can proceed as a class action and filed a motion to stay further damages phase trials. On February 14, 2024, the Oregon Court of Appeals denied PacifiCorp's request to stay the damages phase trials. On February 13, 2024, the i17 named plaintiffs filed a notice of cross-appeal as to the January 2024 limited judgment and money award. The appeals process
and further actions could take several years.
In January 2024, the jury for the first James damages phase trial awarded inine plaintiffs $i62 million
of damages, including $i6 million of economic damages and $i56 million of noneconomic damages. After the jury verdict, the Multnomah County Circuit Court doubled the economic damages to $i12 million
and added $i16 million of punitive damages using the i0.25 multiplier determined by the jury for the June 2023 James verdict. PacifiCorp will request that the Multnomah County Circuit Court judge offset the
damage awards by deducting insurance proceeds received by any of the inine plaintiffs. PacifiCorp intends to appeal the jury's damage awards associated with the January 2024 jury verdict once judgement is entered.
259
2022 McKinney Fire
According to the California Department of Forestry
and Fire Protection, on July 29, 2022, the 2022 McKinney Fire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California located in PacifiCorp's service territory, burning over 60,000 acres. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged; 185 structures destroyed, including residences; 12 injuries; and four fatalities. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service, the California Public Utilities Commission, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, multiple complaints have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering,
emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees, but the amount of damages sought is not specified.
Based on available information to date, PacifiCorp believes it is probable a loss will be incurred associated with the 2022 McKinney Fire. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes.
Estimated Losses for and Settlements Associated with the Wildfires
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, including (i) ongoing cause and origin investigations; (ii) ongoing settlement and mediation discussions; (iii) other litigation
matters and upcoming legal proceedings; and (iv) the status of the James case, PacifiCorp increased its accrual by $i1,930 million during the year ended December 31, 2023, bringing its cumulative estimated probable losses associated with the Wildfires to $i2,407 million
through December 31, 2023. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages and noneconomic damages such as personal injury damages and loss of life damages that it is reasonably able to estimate at this time and which is subject to change as additional relevant information becomes available.
Through December 31, 2023, PacifiCorp paid $i684 million
in settlements associated with the 2020 Wildfires, including $i299 million to i463 claimants and $i250 million
to i10 companies with commercial timber interests associated with the Archie Creek, French Creek, Susan Creek and Smith Springs Road fires (collectively, the "Archie Creek Complex Fire") in Douglas County, Oregon. The Archie Creek Complex Fire settlements resolve substantially all claims filed by individual plaintiffs and all claims filed by commercial timber plaintiffs associated with the Archie Creek Complex Fire, but do not address related damages claimed by the U.S. or Oregon Departments of Justice. In January 2024 through February 23, 2024, PacifiCorp entered into additional
settlements associated with the 2020 Wildfires totaling $i51 million with i167 plaintiffs.
i
The
following table presents changes in PacifiCorp's liability for estimated losses associated with the Wildfires for the years ended December 31 (in millions):
2023
2022
2021
Beginning
balance
$
i424
$
i252
$
i252
Accrued
losses
i1,930
i225
i—
Payments(1)
(i631)
(i53)
i—
Ending balance
$
i1,723
$
i424
$
i252
(1)Amounts
represent payments made to settle certain claims associated with the 2020 Wildfires, including $i549 million in December 2023 resulting from the above-described settlement agreements reached in December 2023 associated with the Archie Creek Complex Fire.
/
As of December 31, 2023 and 2022,
$i4 million and $i24 million of PacifiCorp's liability for estimated losses associated with the Wildfires was included in Other current liabilities on the Consolidated Balance Sheets.
Until
such time that settlement terms or other conclusions are reached to indicate that payments are expected to occur in the short-term, PacifiCorp's liability for estimated losses associated with the Wildfires is classified as a noncurrent liability captioned Wildfires liabilities on the Consolidated Balance Sheets.
260
The following table presents changes in PacifiCorp's receivable for expected insurance recoveries associated with the Wildfires for the years ended December 31 (in millions):
2023
2022
2021
Beginning
balance
$
i246
$
i116
$
i116
Accruals
i253
i161
i—
Payments
received
i—
(i31)
i—
Ending balance
$
i499
$
i246
$
i116
As
of December 31, 2023, $i350 million of PacifiCorp's receivable for expected insurance recoveries was included in Other receivables, net while the remaining $i149 million was included
in Other assets on the Consolidated Balance Sheets. As of December 31, 2022, the $i246 million was included in Other assets on the Consolidated Balance Sheets. In January and February 2024, PacifiCorp received $i338
million of insurance proceeds related to the 2020 Wildfires.
During the years ended December 31, 2023, 2022 and 2021, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $i1,677 million, $i64 million and
$i— million, respectively. No additional insurance recoveries beyond those accrued to date are expected to be available.
It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued for the Wildfires that could have a material adverse effect on PacifiCorp's financial condition. PacifiCorp is currently unable to reasonably estimate a specific range of possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the class to the
James case, the variation in the types of properties and damages and the ultimate outcome of legal actions.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.
(15)iRevenue
from Contracts with Customers
i
The following table summarizes PacifiCorp's Customer Revenue by line of business, with further disaggregation of retail by customer class, for the years ended December 31 (in millions):
2023
2022
2021
Customer
Revenue:
Retail:
Residential
$
i2,156
$
i2,013
$
i1,914
Commercial
i1,829
i1,645
i1,559
Industrial
i1,179
i1,163
i1,125
Other
retail
i298
i278
i249
Total
retail
i5,462
i5,099
i4,847
Wholesale
i165
i260
i157
Transmission
i151
i166
i143
Other
Customer Revenue
i129
i102
i108
Total
Customer Revenue
i5,907
i5,627
i5,255
Other
revenue
i29
i52
i41
Total
operating revenue
$
i5,936
$
i5,679
$
i5,296
/
261
(16)iPreferred
Stock
PacifiCorp has ii3,500/
thousand shares of Serial Preferred Stock authorized at the stated value of $ii100/ per share. PacifiCorp had iiii24/// thousand
shares of Serial Preferred Stock issued and outstanding as of December 31, 2023 and 2022. The outstanding preferred stock series are non-redeemable and have annual dividend rates of i6.00% and i7.00%.
In
the event of voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in default in an amount equal to ifour full quarterly
payments.
PacifiCorp also has ii16/ million
shares of No Par Serial Preferred Stock and ii127/ thousand shares of ii5/%
Preferred Stock authorized, but iiiino///
shares were issued or outstanding as of December 31, 2023 and 2022.
(17)iCommon Shareholder's Equity
Through PPW Holdings, BHE is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that
authorized BHE's acquisition of PacifiCorp contain restrictions on PacifiCorp's ability to pay dividends to the extent that they would reduce PacifiCorp's common equity below specified percentages of defined capitalization. As of December 31, 2023, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to PPW Holdings or BHE without prior state regulatory approval to the extent that it would reduce PacifiCorp's common equity below i44% of its total capitalization, excluding short-term debt and current maturities of long-term debt.
As of December 31, 2023, PacifiCorp's actual common equity percentage, as calculated under this measure, was i50%.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or BHE if PacifiCorp's senior unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings, or Baa3 or lower by Moody's Investor Service, as indicated by two of the three
rating services. As of December 31, 2023, PacifiCorp met these minimum required senior unsecured debt ratings.
PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various financing agreements as further discussed in Note 7.
(18) iComponents of Accumulated Other Comprehensive Loss, Net
Accumulated
other comprehensive loss, net consists of unrecognized amounts on retirement benefits, net of tax, of $i10 million and $i9 million
as of December 31, 2023 and 2022, respectively.
(19)iVariable Interest Entities
PacifiCorp holds a i66.67%
interest in Bridger Coal Company ("Bridger Coal"), which supplies coal to the Jim Bridger generating facility that is owned i66.67% by PacifiCorp and i33.33% by PacifiCorp's joint venture partner in Bridger Coal. PacifiCorp purchases i66.67%
of the coal produced by Bridger Coal, while the joint venture partner purchases the remaining i33.33% of the coal produced. The power to direct the activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. Each joint venture partner is jointly and severally liable for the obligations of Bridger Coal. Bridger Coal's necessary working capital to carry out its mining operations is financed by contributions from PacifiCorp and its joint venture partner. PacifiCorp's equity investment in Bridger Coal was $i48 million
and $i28 million as of December 31, 2023 and 2022, respectively. Refer to Note 21 for information regarding related party transactions with Bridger Coal.
262
(20)iSupplemental
Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2023
2022
2021
Supplemental disclosure
of cash flow information:
Interest paid, net of amounts capitalized
$
i432
$
i380
$
i395
Income
taxes received, net
$
i292
$
i185
$
i120
Supplemental
disclosure of non-cash investing and financing activities:
Accruals related to property, plant and equipment additions
$
i862
$
i558
$
i254
(21)iRelated
Party Transactions
PacifiCorp has an intercompany administrative services agreement and a mutual assistance agreement with BHE and its subsidiaries. Amounts charged to PacifiCorp by BHE and its subsidiaries under these agreements totaled $i168 million, $i123 million
and $i70 million during the years ended December 31, 2023, 2022 and 2021, respectively. Amounts charged to PacifiCorp in 2023 and 2022 were primarily reflected in construction work in progress on the Consolidated Balance Sheets as of December 31, 2023 and 2022. Payables associated with the charges were $i15 million
and $i16 million as of December 31, 2023 and 2022, respectively. Amounts charged by PacifiCorp to BHE and its subsidiaries under these agreements totaled $i44 million, $i23 million
and $i8 million during the years ended December 31, 2023, 2022 and 2021, respectively. Receivables associated with the charges were $i8 million and
$i3 million as of December 31, 2023 and 2022, respectively. Such amounts primarily relate to information technology projects and other costs managed at a consolidated level and allocated or passed through to affiliates.
PacifiCorp also engages in various transactions with several subsidiaries of BHE in the ordinary course of business. Services provided by these subsidiaries in the ordinary course of business and charged to PacifiCorp
primarily relate to wholesale electricity purchases and transmission of electricity, transportation of natural gas and employee relocation services. These expenses totaled $i6 million, $i8 million
and $i6 million during the years ended December 31, 2023, 2022 and 2021, respectively.
PacifiCorp has long-term transportation contracts with BNSF Railway Company, an indirect wholly owned subsidiary of Berkshire Hathaway, PacifiCorp's ultimate parent company. Transportation costs under these contracts were $i24 million,
$i21 million and $i19 million during the years ended December 31, 2023, 2022
and 2021, respectively.
PacifiCorp has a long-term master materials supply contract with Marmon Utility, LLC, an indirect wholly owned subsidiary of a holding company in which Berkshire Hathaway holds a majority interest. Materials and supplies purchased under this contract were $i17 million, $i8 million and
$i2 million during the years ended December 31, 2023, 2022 and 2021, respectively.
PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated U.S. federal income tax return. Federal and state income taxes receivable from BHE were $i114 million
and $i84 million as of December 31, 2023 and 2022, respectively. For the years ended December 31, 2023, 2022 and 2021, cash refunded from BHE for federal and state income taxes totaled $i292 million,
$i185 million and $i120 million.
PacifiCorp transacts
with its equity investees, Bridger Coal and Trapper Mining Inc. Services provided by equity investees to PacifiCorp primarily relate to coal purchases. During the years ended December 31, 2023, 2022 and 2021, coal purchases from PacifiCorp's equity investees totaled $i139 million, $i119 million
and $i148 million, respectively. Payables to PacifiCorp's equity investees were $i34 million and $i10
million as of December 31, 2023 and 2022, respectively.
263
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
264
Item 7.Management's
Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify
information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with MidAmerican Funding's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical Financial Statements and Notes to Financial Statements each in Item 8 of this Form 10-K. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
MidAmerican
Energy -
MidAmerican Energy's net income for 2023 was $982 million, an increase of $21 million, or 2%, compared to 2022 primarily due to lower depreciation and amortization expense, favorable changes in the cash surrender value of corporate-owned life insurance policies and higher AFUDC, partially offset by lower electric utility margin, an unfavorable income tax benefit, higher interest expense, higher operations and maintenance expense, higher property and other taxes and lower natural gas utility margin. Depreciation and amortization decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Electric utility margin decreased due to lower wholesale utility margin from lower margin per unit and lower wholesale customer volumes of 15.8%, offset by
higher retail utility margin, largely from higher retail customer volumes. Retail customer volumes increased 1.3% primarily due to higher customer usage for certain industrial customers, partially offset by the unfavorable impact of weather. Energy generated decreased 6% primarily due to lower wind-powered generation, partially offset by higher natural gas-fueled generation, and energy purchased increased 4%. The unfavorable income tax benefit was mainly due to lower PTCs recognized from lower wind- and solar-powered generation, higher pretax income and the timing of state income tax benefits.
MidAmerican Energy's net income for 2022 was $961 million, an increase of $67 million, or 7%, compared to 2021 primarily due to higher electric utility margin, a favorable income tax benefit, higher natural gas utility margin
and higher AFUDC, partially offset by higher depreciation and amortization expense, higher operations and maintenance expense, unfavorable changes in the cash surrender value of corporate-owned life insurance policies, higher non-service benefit plan costs and higher interest expense. Electric utility margin increased due to higher wholesale utility margin from higher margin per unit and higher wholesale customer volumes of 12.2% and higher retail utility margin, largely from higher retail customer volumes. Retail customer volumes increased 4.3% due to higher customer usage, reflecting the favorable impact of weather and an increase in certain industrial customer usage. Energy generated increased 6% primarily due to higher wind-powered generation, partially offset by lower coal-fueled generation, and energy purchased increased 19%. The favorable income tax benefit was mainly due to higher PTCs recognized
from higher wind- and solar-powered generation, partially offset by the timing of state income tax benefits. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service.
MidAmerican Funding -
MidAmerican Funding's net income for 2023 was $980 million, an increase of $33 million, or 3%, compared to 2022. MidAmerican Funding's net income for 2022 was $947 million, an increase of $64 million, or 7%, compared to 2021. The increases were primarily due to the changes in MidAmerican Energy's earnings discussed above and a one-time gain on the sale of an investment of $10 million.
265
Non-GAAP
Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.
MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally
recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in MidAmerican Energy's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to managing the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the
most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
2023
2022
Change
2022
2021
Change
Electric
utility margin:
Operating revenue
$
2,673
$
2,988
$
(315)
(11)
%
$
2,988
$
2,529
$
459
18
%
Cost
of fuel and energy
501
679
(178)
(26)
679
539
140
26
Electric utility margin
2,172
2,309
(137)
(6)
%
2,309
1,990
319
16
%
Natural
gas utility margin:
Operating revenue
713
1,030
(317)
(31)
%
1,030
1,003
27
3
%
Natural
gas purchased for resale
451
762
(311)
(41)
762
760
2
—
%
Natural gas utility margin
262
268
(6)
(2)
%
268
243
25
10
%
Utility
margin
$
2,434
$
2,577
$
(143)
(6)
%
$
2,577
$
2,233
$
344
15
%
Other
operating revenue
7
7
—
—
%
7
15
(8)
(53)
%
Other cost of sales
—
1
(1)
(100)
1
1
—
—
Operations
and maintenance
851
828
23
3
828
775
53
7
Depreciation and amortization
908
1,168
(260)
(22)
1,168
914
254
28
Property
and other taxes
161
149
12
8
149
142
7
5
Operating
income
$
521
$
438
$
83
19
%
$
438
$
416
$
22
5
%
* Not
meaningful.
266
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows for the years ended December 31:
2023
2022
Change
2022
2021
Change
Utility
margin (in millions):
Operating revenue
$
2,673
$
2,988
$
(315)
(11)
%
$
2,988
$
2,529
$
459
18
%
Cost
of fuel and energy
501
679
(178)
(26)
679
539
140
26
Utility margin
$
2,172
$
2,309
$
(137)
(6)
%
$
2,309
$
1,990
$
319
16
%
Sales
(GWhs):
Residential
6,759
7,006
(247)
(4)
%
7,006
6,718
288
4
%
Commercial
3,992
4,017
(25)
(1)
4,017
3,841
176
5
Industrial
17,307
16,646
661
4
16,646
15,944
702
4
Other
1,617
1,621
(4)
—
1,621
1,571
50
3
Total
retail
29,675
29,290
385
1
29,290
28,074
1,216
4
Wholesale
15,129
17,964
(2,835)
(16)
17,964
16,011
1,953
12
Total
sales
44,804
47,254
(2,450)
(5)
%
47,254
44,085
3,169
7
%
Average
number of retail customers (in thousands)
820
813
7
1
%
813
804
9
1
%
Average
revenue per MWh:
Retail
$
77.82
$
79.23
$
(1.41)
(2)
%
$
79.23
$
75.84
$
3.39
4
%
Wholesale
$
17.92
$
31.07
$
(13.15)
(42)
%
$
31.07
$
18.92
$
12.15
64
%
Heating
degree days
5,371
6,449
(1,078)
(17)
%
6,449
5,704
745
13
%
Cooling degree days
1,255
1,274
(19)
(1)
%
1,274
1,331
(57)
(4)
%
Sources
of energy (GWhs)(1):
Wind and other(2)
24,877
28,129
(3,252)
(12)
%
28,129
23,374
4,755
20
%
Coal
9,961
10,078
(117)
(1)
10,078
12,313
(2,235)
(18)
Nuclear
3,790
3,782
8
—
3,782
3,934
(152)
(4)
Natural
gas
2,184
1,504
680
45
1,504
1,398
106
8
Total energy generated
40,812
43,493
(2,681)
(6)
43,493
41,019
2,474
6
Energy
purchased
4,772
4,594
178
4
4,594
3,865
729
19
Total
45,584
48,087
(2,503)
(5)
%
48,087
44,884
3,203
7
%
Average
cost of energy per MWh:
Energy generated(3)
$
6.80
$
7.42
$
(0.62)
(8)
%
$
7.42
$
7.12
$
0.30
4
%
Energy
purchased
$
46.86
$
77.59
$
(30.73)
(40)
%
$
77.59
$
64.04
$
13.55
21%
* Not
meaningful.
(1) GWh amounts are net of energy used by the related generating facilities.
(2) All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
267
Natural Gas Utility Margin
A comparison
of key operating results related to natural gas utility margin is as follows for the years ended December 31:
2023
2022
Change
2022
2021
Change
Utility
margin (in millions):
Operating revenue
$
713
$
1,030
$
(317)
(31)
%
$
1,030
$
1,003
$
27
3
%
Natural
gas purchased for resale
451
762
(311)
(41)
762
760
2
—
Utility margin
$
262
$
268
$
(6)
(2)
%
$
268
$
243
$
25
10
%
Throughput
(000's Dths):
Residential
47,558
56,100
(8,542)
(15)
%
56,100
48,984
7,116
15
%
Commercial
22,715
26,298
(3,583)
(14)
26,298
23,240
3,058
13
Industrial
5,799
6,039
(240)
(4)
6,039
5,287
752
14
Other
76
75
1
1
75
68
7
10
Total
retail sales
76,148
88,512
(12,364)
(14)
88,512
77,579
10,933
14
Wholesale sales
30,764
30,996
(232)
(1)
30,996
34,337
(3,341)
(10)
Total
sales
106,912
119,508
(12,596)
(11)
119,508
111,916
7,592
7
Natural gas transportation service
106,422
102,827
3,595
3
102,827
112,631
(9,804)
(9)
Total
throughput
213,334
222,335
(9,001)
(4)
%
222,335
224,547
(2,212)
(1)
%
Average
number of retail customers (in thousands)
796
789
7
1
%
789
781
8
1
%
Average revenue per retail Dth sold
$
7.80
$
9.19
$
(1.39)
(15)
%
$
9.19
$
10.59
$
(1.40)
(13)
%
Heating
degree days
5,668
6,810
(1,142)
(17)
%
6,810
6,000
810
14
%
Average
cost of natural gas per retail Dth sold
$
4.98
$
6.66
$
(1.68)
(25)
%
$
6.66
$
7.95
$
(1.29)
(16)%
Combined
retail and wholesale average cost of natural gas per Dth sold
Electric utility margin decreased $137 million, or 6%, for 2023 compared to 2022 primarily due to:
•a $223 million decrease in wholesale utility margin due to lower margin per unit of $158 million, reflecting lower market prices, and lower volumes of $65 million or 15.8%; and
•a $7 million decrease in Multi-Value Projects ("MVP") transmission
revenue; partially offset by
•a $93 million increase in retail utility margin primarily due to $75 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit), $30 million from higher customer usage, $6 million due to price impacts from changes in sales mix and $5 million from higher wind-turbine performance settlements, partially offset by $23 million from the unfavorable impact of weather. Retail customer volumes increased 1.3%.
Natural gas utility margin decreased $6 million, or 2%, for 2023 compared to 2022 primarily due to:
•an $8 million decrease in customer usage, including $19 million from the unfavorable impact of weather; and
•a
$2 million decrease from lower refunds related to amortization of excess accumulated deferred income taxes arising from 2017 tax reform (offset in income tax benefit); partially offset by
•a $3 million increase in natural gas transportation margin, reflecting higher prices.
268
Operations and maintenance increased $23 million, or 3%, for 2023 compared to 2022 primarily due to higher technology costs of $11 million, higher nuclear power generation costs of $8 million, higher employee costs of $5 million, higher steam power generation costs of $4 million, higher other power generation costs of $4 million, higher property insurance costs of $4 million and higher nonregulated operating
costs of $2 million, partially offset by lower electric distribution costs of $15 million and lower transmission costs from MISO of $4 million.
Depreciation and amortization decreased $260 million, or 22%, for 2023 compared to 2022 primarily due to $267 million from lower Iowa revenue sharing accruals and $45 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $39 million related to new and repowered wind-powered generating facilities and other plant placed in-service and $12 million from lower depreciation expense deferrals in 2023.
Property and other taxes increased $12 million, or 8%, for 2023 compared to 2022 primarily due to $9 million from higher wind
turbine property taxes and $3 million from higher replacement taxes.
Interest expense increased $33 million, or 11%, for 2023 compared to 2022 primarily due to higher interest expense from a September 2023 long-term debt issuance and higher interest rates on variable rate long-term debt.
Allowance for borrowed and equity funds increased $12 million, or 18%, for 2023 compared to 2022 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation projects.
Other, net increased $36 million, or 100%, for 2023 compared to 2022 primarily due to higher cash surrender values of corporate-owned life insurance policies
of $39 million and higher interest income of $16 million, partially offset by higher non-service costs of postretirement employee benefit plans.
Income tax benefit decreased $77 million, or 10%, for 2023 compared to 2022, and the effective tax rate was (240)% for 2023 and (403)% for 2022. The change in the effective tax rate was substantially due to a decrease of $29 million in PTCs, partially offset by state income tax impacts.
Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-powered generating facilities is produced and sold and are based on a prescribed per-kilowatt rate pursuant to the applicable federal income tax law. Qualifying generating facilities are eligible for the credits for 10 years from the date the facilities are placed in-service.
Beginning in late 2014, some of MidAmerican Energy's wind-powered generating facilities surpassed the 10-year eligibility period for earning the credits. Most of those facilities have since been repowered, and under IRS rules, qualifying repowered facilities are eligible for the available credits, for 10 years from the date they are returned to service. Refer to "Capital Expenditures" in Liquidity and Capital Resources for additional information about repowering and new wind- and solar-powered generation placed in-service. PTC's totaled $681 million, $710 million and $574 million in 2023, 2022 and 2021, respectively.
MidAmerican Funding -
Income tax benefit for MidAmerican Funding decreased $81 million, or 10%, for 2023 compared to 2022, and the effective tax rate was (244)%
for 2023 and (454)% for 2022. The change in effective tax rates was due principally to the factors discussed for MidAmerican Energy and higher pretax income from a one-time gain on the sale of an investment.
Electric utility margin increased $319 million, or 16%, for 2022 compared to 2021 primarily due to:
•a
$250 million increase in wholesale utility margin due to higher margin per unit of $237 million, reflecting higher market prices and lower energy costs, and higher volumes of 12.2%;
•a $66 million increase in retail utility margin primarily due to $62 million from higher customer usage, including $7 million from the favorable impact of weather; and $9 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); partially offset by $6 million in 2021 from liquidated damages related to a wind-powered generation project. Retail customer volumes increased 4.3%; and
•a $3 million increase in Multi-Value Projects ("MVP") transmission revenue.
Natural gas utility margin increased $25 million,
or 10%, for 2022 compared to 2021 primarily due to:
•an $18 million increase in customer usage, including $9 million from the favorable impact of weather;
•a $5 million increase from higher refunds related to amortization of excess accumulated deferred income taxes arising from 2017 tax reform (offset in income tax benefit); and
•a $3 million increase in natural gas transportation margin, reflecting higher prices.
Operations and maintenance increased $53 million, or 7%, for 2022 compared to 2021 primarily due to higher other power generation costs of $21 million from additional wind turbines and easements, higher electric distribution costs of $17 million reflecting greater tree-trimming efforts, higher
steam generation costs of $13 million and higher transmission costs from MISO of $6 million, partially offset by lower gas distribution costs of $6 million.
Depreciation and amortization increased $254 million, or 28%, for 2022 compared to 2021 primarily due to $181 million from higher Iowa revenue sharing accruals, $40 million related to new and repowered wind-powered generating facilities and other plant placed in-service and $31 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects.
Property and other taxes increased $7 million, or 5%, for 2022 compared to 2021 primarily due to higher wind turbine property taxes.
Interest
expense increased $11 million, or 4%, for 2022 compared to 2021 primarily due to a higher average long-term debt balance and higher variable interest rates.
Allowance for borrowed and equity funds increased $14 million, or 27%, for 2022 compared to 2021 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation projects.
Other, net decreased $53 million, or 100%, for 2022 compared to 2021 primarily due to lower cash surrender values of corporate-owned life insurance policies of $37 million, higher non-service costs of postretirement employee benefit plans of $17 million and lower other investment values, partially offset by higher interest income.
Income
tax benefit increased $95 million, or 14%, for 2022 compared to 2021, and the effective tax rate was (403)% for 2022 and (308)% for 2021. The change in the effective tax rate was substantially due to an increase of $136 million in PTCs, partially offset by state income tax impacts.
MidAmerican Funding -
Income tax benefit for MidAmerican Funding increased $96 million, or 14%, for 2022 compared to 2021, and the effective tax rate was (454)% for 2022 and (335)% for 2021. The change in effective tax rates was due principally to the factors discussed for MidAmerican Energy.
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Liquidity
and Capital Resources
As of December 31, 2023, MidAmerican Energy's and MidAmerican Funding's total net liquidity were as follows (in millions):
MidAmerican Energy:
Cash and cash equivalents
$
636
Credit
facilities, maturing 2024 and 2026
1,505
Less:
Tax-exempt bond support
(306)
Net credit facilities
1,199
MidAmerican Energy total net liquidity
$
1,835
MidAmerican
Funding:
MidAmerican Energy total net liquidity
$
1,835
Cash and cash equivalents
1
MHC, Inc. credit facility, maturing 2024
4
MidAmerican Funding total net liquidity
$
1,840
Operating
Activities
MidAmerican Energy's net cash flows from operating activities were $2,217 million, $2,174 million and $1,617 million for 2023, 2022 and 2021, respectively. MidAmerican Funding's net cash flows from operating activities were $2,203 million, $2,161 million and $1,605 million for 2023, 2022 and 2021, respectively. Cash flows from operating activities increased for 2023 compared to 2022 primarily due to lower asset retirement obligation settlements, higher utility margin for MidAmerican Energy's regulated electric business and higher income tax receipts, partially offset by higher payments to vendors and lower utility margin for MidAmerican Energy's regulated natural gas business. Cash flows from operating activities increased for 2022 compared to 2021 primarily due to higher utility margins for MidAmerican Energy's regulated electric and natural gas businesses, higher income tax
receipts and lower payments to vendors. Higher utility margins are partially attributable to timing of the recovery of higher natural gas costs caused by the February 2021 polar vortex weather event.
The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
MidAmerican Energy's net cash flows from investing activities were $(1,837) million, $(1,867) million and $(1,911) million for 2023, 2022 and 2021, respectively. MidAmerican Funding's net cash flows from investing activities were $(1,825) million, $(1,868) million and $(1,912) million for 2023,
2022 and 2021, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures. Purchases and proceeds related to marketable securities primarily consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments.
Financing Activities
MidAmerican Energy's net cash flows from financing activities were $(6) million, $(278) million and $488 million for 2023, 2022 and 2021, respectively. MidAmerican Funding's net cash flows from financing activities were $(6) million, $(262) million and $501 million for 2023, 2022 and 2021, respectively. Proceeds from long-term debt reflect MidAmerican Energy's issuance in September 2023 of $350 million of its 5.350% First
Mortgage Bonds due January 2034 and $1 billion of its 5.850% First Mortgage Bonds due September 2054. In July 2021, MidAmerican Energy issued $500 million of its 2.70% First Mortgage Bonds due August 2052. In 2023 and 2022, MidAmerican Energy paid $1,025 million and $275 million in cash dividends to its parent company, MHC Inc. In 2023 and 2022, MidAmerican Funding paid $1,025 million and $69 million, respectively, in cash distributions to its sole member, BHE. MidAmerican Funding paid $189 million in 2022 and received $12 million in 2021, respectively, through its note payable with BHE.
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In January 2024, MidAmerican Energy issued $600 million of its 5.30% First Mortgage Bonds due February 2055. MidAmerican Energy intends,
within 24 months of the issuance date, to allocate an amount equal to the net proceeds to finance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.
Debt Authorizations and Related Matters
Short-term Debt
MidAmerican Energy has authority from the FERC to issue, through April 2, 2024, commercial paper and bank notes aggregating $1.5 billion. MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 2026. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of
letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
Long-term Debt and Preferred Stock
MidAmerican Energy currently has an effective shelf registration statement with the SEC to issue an additional $1.3 billion of long-term debt securities and preferred stock through March 10, 2026. MidAmerican Energy has authorization from the FERC to issue, through June 30, 2025, long-term debt securities up to an aggregate of $1.05 billion and preferred
stock up to an aggregate of $500 million. MidAmerican Energy has authorization from the ICC through May 25, 2025, to issue long-term debt securities up to an aggregate of $1.05 billion and preferred stock up to an aggregate of $500 million.
MidAmerican Energy's mortgage dated September 9, 2013, creates a lien on most of MidAmerican Energy's electric utility property within the state of Iowa, allowing the issuance of bonds based on a percentage of eligible utility property additions, bond credits arising from retirement of previously outstanding bonds or deposits of cash. As of December 31, 2023, MidAmerican Energy estimated it would be able to issue up to $8.3 billion of new first mortgage bonds under the mortgage. Any issuances are subject
to market conditions, and amounts are further limited by regulatory authorizations and commitments, as well as any more restrictive requirements of covenants and tests contained in other financing agreements. MidAmerican Energy also has the ability to release property from the lien of the mortgage on the basis of property additions, bond credits or deposits of cash.
MidAmerican Funding or one of its subsidiaries, including MidAmerican Energy, may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by MidAmerican Funding or one of its subsidiaries may be reissued or resold by MidAmerican Funding or one of its subsidiaries from time to time and will depend on prevailing market conditions, the issuing company's liquidity requirements, contractual restrictions
and other factors. The amounts involved may be material.
Future Uses of Cash
MidAmerican Energy and MidAmerican Funding have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors,
including their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
MidAmerican Energy has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
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MidAmerican
Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ended December 31 are as follows (in millions):
Historical
Forecast
2021
2022
2023
2024
2025
2026
Wind
generation
$
964
$
685
$
744
$
815
$
1,636
$
1,661
Electric distribution
257
311
369
314
304
308
Electric
transmission
199
145
205
235
306
338
Solar generation
132
119
13
14
82
30
Other
360
609
502
502
433
455
Total
$
1,912
$
1,869
$
1,833
$
1,880
$
2,761
$
2,792
MidAmerican
Energy's capital expenditures provided above consist of the following:
•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction of wind-powered generating facilities totaled $608 million for 2023, $72 million for 2022 and $540 million for 2021. MidAmerican Energy placed in-service 200 MWs during 2023 and 294 MWs during 2021. Planned spending for the construction of additional wind-powered generating facilities totals $515 million, $1,196 million and $998 million for 2024, 2025 and 2026, respectively.
◦Repowering of wind-powered generating facilities totaled $47 million for 2023, $500 million for 2022 and $354 million for 2021. Planned spending for repowering totals $228 million,
$382 million and $601 million in 2024, 2025 and 2026, respectively. MidAmerican Energy expects its repowered facilities to meet IRS guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service.
•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.
•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.
•Solar generation includes the construction and operation of solar-powered generating facilities, primarily consisting of 141 MWs of small- and utility-scale solar
generation, all of which were placed in-service in 2022, with total spend of $13 million in 2023, $119 million in 2022 and $132 million in 2021. Planned spending for the construction and operation of additional solar-powered generating facilities totals $14 million, $82 million and $30 million for 2024, 2025 and 2026, respectively.
•Remaining expenditures primarily relate to routine projects for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.
Material Cash Requirements
MidAmerican Energy and MidAmerican Funding have cash requirements that may
affect their financial condition that arise primarily from long- and short-term debt (refer to Notes 7 and 8), firm commitments (refer to Note 13) and construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7) and AROs (refer to Note 11). Refer, where applicable, to the respective referenced note in Notes to Financial Statements in Item 8 of this Form 10-K for additional information.
MidAmerican Energy has cash requirements relating to interest payments of $7.3 billion on long-term debt, including $385 million due in 2024. Additionally, MidAmerican Funding has cash requirements relating to interest payments on its long-term debt of $91 million, including $17 million due in 2024.
Regulatory
Matters
MidAmerican Energy is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding MidAmerican Energy's general regulatory framework and current regulatory matters.
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Quad Cities Generating Station Operating Status
Constellation Energy Generation, LLC ("Constellation Energy"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, receives financial support for continued operation of Quad Cities Station from the zero emission
standard enacted by the Illinois legislature in December 2016. The zero emission standard requires the Illinois Power Agency to purchase ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs provide Constellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy does not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided financial support program like the Illinois zero emission standard, resulting in a higher offer that may not clear the capacity market. Prior to December 19,
2019, the PJM MOPR applied only to certain new gas-fueled resources.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC denied rehearing of that order on April 16, 2020. A number of parties, including Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Seventh Circuit. MidAmerican Energy cannot
predict the outcome of this proceeding.
While this litigation is pending, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year in May 2021, which prevented Quad Cities Station from clearing in that capacity auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions with the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR applied in the capacity
auction for the 2023-2024 delivery year but did not restrict the offers of Quad Cities Station, which cleared in the capacity auction. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit.
Assuming the continued effectiveness of the Illinois zero emission standard, Constellation Energy no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement.
The FERC provided no new mechanism for accommodating state-supported resources like Quad Cities Station other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. Depending on the outcome of the proceedings related to the PJM MOPR, the continued effectiveness of the Illinois zero emission standard may be undermined unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance
standards, water quality, coal ash disposal and other environmental matters that have the potential to impact MidAmerican Energy's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and financial results.
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Refer
to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral and Contingent Features
Debt securities of MidAmerican Energy are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of MidAmerican Energy's ability to, in general, meet the obligations of its issued debt securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2023, MidAmerican Energy's
credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade. As a result of the issuance of first mortgage bonds by MidAmerican Energy in September 2013, its then outstanding senior unsecured debt was equally and ratably secured with such first mortgage bonds. Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K for a discussion of MidAmerican Energy's first mortgage bonds.
MidAmerican Funding and MidAmerican Energy have no credit rating downgrade triggers that would accelerate the maturity dates of its outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. MidAmerican Energy's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order
to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base MidAmerican Energy's collateral requirements on its credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties
to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in MidAmerican Energy's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2023, MidAmerican Energy would have been required to post $85 million of additional collateral. MidAmerican Energy's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically,
overall inflation and changing prices in the economies where MidAmerican Energy operates have not had a significant impact on its financial results. MidAmerican Energy operates under cost-of-service based rate-setting structures administered by various state commissions and the FERC. Under these rate-setting structures, MidAmerican Energy is allowed to include prudent costs in its rates, including the impact of inflation. MidAmerican Energy attempts to minimize the potential impact of inflation on its operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, inflation's impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs, and long-term debt issuances. There can be no assurance that such actions will be successful.
New
Accounting Pronouncements
For a discussion of new accounting pronouncements affecting MidAmerican Energy and MidAmerican Funding, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
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Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve
numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by MidAmerican Energy's methods, judgments and assumptions used in the preparation of the Financial Statements and should be read in conjunction with MidAmerican Energy's Summary of Significant Accounting Policies included in Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
MidAmerican Energy prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, MidAmerican Energy
defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
MidAmerican Energy continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition, that could limit MidAmerican Energy's ability to recover its costs. MidAmerican Energy believes its application of
the guidance for regulated operations is appropriate, and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as AOCI. Total regulatory assets were $600 million and total regulatory liabilities were $1,079 million as of December 31, 2023. Refer to Note 5 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding regulatory assets and liabilities.
Impairment of Goodwill
MidAmerican
Funding's Consolidated Balance Sheet as of December 31, 2023, includes goodwill from the acquisition of MHC totaling $1.3 billion. Goodwill is allocated to each reporting unit. MidAmerican Funding evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2023. Additionally, no indicators of impairment were identified as of December 31, 2023. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. MidAmerican Funding uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash
flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, MidAmerican Funding incorporates current market information, as well as historical factors.
Pension and Other Postretirement Benefits
MidAmerican Energy sponsors defined benefit pension and other postretirement benefit plans that cover the majority of the employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy Inc. MidAmerican Energy recognizes the funded status of its defined benefit pension and other postretirement benefit plans on the Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31,
2023, MidAmerican Energy recognized a net liability totaling $45 million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31, 2023, amounts not yet recognized as a component of net periodic benefit cost that were included in regulatory assets and regulatory liabilities totaled $16 million and $16 million, respectively.
276
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including, but not limited to, discount rates, expected long-term rate of return on plan assets
and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. MidAmerican Energy believes that the key assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 10 of Notes to Financial Statements in Item 8 of this Form 10-K for disclosures about MidAmerican Energy's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2023.
MidAmerican Energy chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to cash flows over the expected benefit period. The
pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, MidAmerican Energy utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. MidAmerican Energy regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
MidAmerican Energy chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected
benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5.00% by 2028 at which point the rate of increase is assumed to remain constant.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and funded status. If changes were to occur for the following key assumptions, the approximate effect on the Financial Statements of the total plan before allocations to affiliates would be as follows (in millions):
A
variety of factors affect the funded status of the plans, including discount rates, asset returns, plan changes and MidAmerican Energy's funding policy for each plan.
Income Taxes
In determining MidAmerican Funding's and MidAmerican Energy's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by MidAmerican Energy's various regulatory commissions. MidAmerican Funding's and MidAmerican Energy's income tax returns are subject to continuous examinations by federal, state and local tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters
are resolved. MidAmerican Funding and MidAmerican Energy recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of their federal, state and local tax examinations is uncertain, each company believes it has made adequate provisions for its income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations is not expected to have a material impact on its consolidated financial results. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding income taxes.
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It
is probable that MidAmerican Energy will either refund to, or recover from its customers in certain state jurisdiction income tax benefits and expense related to the 2017 federal tax rate change from 35% to 21%, certain property-related basis differences, and other various differences. As of December 31, 2023, these amounts were recognized as a net regulatory liability of $102 million and will be included in regulated rates when the temporary differences reverse.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
MidAmerican Energy's Balance Sheets include assets and liabilities
with fair values that are subject to market risks. MidAmerican Energy's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which it transacts. The following discussion addresses the significant market risks associated with MidAmerican Energy's business activities. MidAmerican Energy has established guidelines for credit risk management. Refer to Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's contracts accounted for as derivatives.
Commodity Price Risk
MidAmerican Energy is exposed to the impact of market fluctuations in commodity prices and interest rates. MidAmerican Energy is principally exposed to electricity, natural gas, coal and fuel oil commodity
price risk as it has an obligation to serve retail customer load in its regulated service territory. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather; market liquidity; generating facility availability; customer usage; storage; and transmission and transportation constraints. Commodity price risk for MidAmerican Energy's regulated retail electricity and natural gas operations is significantly mitigated by the inclusion of energy costs in energy cost rider mechanisms, which permit the current recovery of such costs from its retail customers. MidAmerican Energy uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements to mitigate price volatility on behalf of its customers. MidAmerican Energy does not engage in a material amount of proprietary trading activities.
Interest
Rate Risk
MidAmerican Energy and MidAmerican Funding are exposed to interest rate risk on their outstanding variable-rate short- and long-term debt and future debt issuances. MidAmerican Energy and MidAmerican Funding manage interest rate risk by limiting their exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, the fixed-rate long-term debt does not expose MidAmerican Energy or MidAmerican Funding to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if MidAmerican Energy or MidAmerican Funding were to reacquire all or a portion of these instruments prior to their maturity.
MidAmerican Energy or MidAmerican Funding may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate their exposure to interest rate risk. The nature and amount of their short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7, 8 and 12 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-K for additional discussion of MidAmerican Energy's and MidAmerican Funding's short- and long-term debt.
As of December 31, 2023 and 2022, MidAmerican Energy had short- and long-term variable-rate obligations totaling $306 million that expose MidAmerican Energy to the risk of increased interest expense in the event
of increases in short-term interest rates. The market risk related to MidAmerican Energy's variable-rate debt as of December 31, 2023, is not hedged. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on MidAmerican Energy's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2023 and 2022.
278
Credit Risk
MidAmerican Energy is exposed to counterparty credit risk associated with wholesale energy supply and marketing
activities with other utilities, energy marketing companies, financial institutions and other market participants. Additionally, MidAmerican Energy participates in the RTO markets and has indirect credit exposure related to other participants, although RTO credit policies are designed to limit exposure to credit losses from individual participants. Credit risk may be concentrated to the extent MidAmerican Energy's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MidAmerican Energy analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty, and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, MidAmerican Energy enters into netting and collateral arrangements
that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, MidAmerican Energy exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Substantially all of MidAmerican Energy's electric wholesale sales revenue results from participation in RTOs, including the MISO and the PJM. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. Additionally, as of December 31, 2023, MidAmerican Energy's aggregate direct credit exposure from electric wholesale marketing counterparties was not material.
279
Item 8.Financial
Statements and Supplementary Data
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
MidAmerican Energy Company
Des Moines, Iowa
Opinion on the Financial Statements
We have audited the accompanying balance sheets of MidAmerican Energy Company ("MidAmerican Energy") as of December 31, 2023 and 2022, the related statements of operations, changes in shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes
(collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of MidAmerican Energy as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of MidAmerican Energy's management. Our responsibility is to express an opinion on MidAmerican Energy's financial statements based on our audits. We are a
public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to MidAmerican Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. MidAmerican Energy is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the
effectiveness of MidAmerican Energy's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical
audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Note 5 to the financial statements
Critical Audit Matter Description
MidAmerican
Energy is subject to rate regulation by state public service commissions as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where MidAmerican Energy operates. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation has a pervasive effect on the financial statements.
281
Regulated rates are
subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow MidAmerican Energy an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an effect on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While MidAmerican Energy has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit MidAmerican Energy's ability to recover its costs.
We identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made by management
to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included
the following, among others:
•We evaluated MidAmerican Energy's disclosures related to the effects of rate regulation by testing recorded balances and evaluating regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by MidAmerican Energy and interveners, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected MidAmerican Energy's filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment
of similar costs under similar circumstances.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i908
i1,168
i914
Amortization
of utility plant to other operating expenses
i34
i35
i34
Allowance
for equity funds
(i59)
(i51)
(i39)
Deferred
income taxes and amortization of investment tax credits
i90
i33
i153
Settlements
of asset retirement obligations
(i21)
(i85)
(i103)
Other,
net
i46
i51
i21
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i254
(i11)
(i293)
Inventories
(i87)
(i43)
i44
Pension
and other postretirement benefit plans, net
i3
i8
(i4)
Accrued
property, income and other taxes, net
i76
i40
(i71)
Accounts
payable and other liabilities
(i9)
i68
i67
Net
cash flows from operating activities
i2,217
i2,174
i1,617
Cash
flows from investing activities:
Capital expenditures
(i1,833)
(i1,869)
(i1,912)
Purchases
of marketable securities
(i243)
(i499)
(i213)
Proceeds
from sales of marketable securities
i227
i492
i207
Other,
net
i12
i9
i7
Net
cash flows from investing activities
(i1,837)
(i1,867)
(i1,911)
Cash
flows from financing activities:
Common stock dividends
(i1,025)
(i275)
i—
Proceeds
from long-term debt
i1,338
i—
i492
Repayments
of long-term debt
(i317)
(i2)
(i1)
Other,
net
(i2)
(i1)
(i3)
Net
cash flows from financing activities
(i6)
(i278)
i488
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i374
i29
i194
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of year
i268
i239
i45
Cash
and cash equivalents and restricted cash and cash equivalents at end of year
$
i642
$
i268
$
i239
The
accompanying notes are an integral part of these financial statements.
287
MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(1)iOrganization
and Operations
MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2)iSummary
of Significant Accounting Policies
i
Basis ofPresentation
The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2023, 2022 and 2021.
i
Use
of Estimates in Preparation of Financial Statements
The preparation of the Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Financial Statements.
i
Accounting
for the Effects of Certain Types of Regulation
MidAmerican Energy's utility operations are subject to the regulation of the Iowa Utilities Board ("IUB"), the Illinois Commerce Commission ("ICC"), the South Dakota Public Utilities Commission, and the Federal Energy Regulatory Commission ("FERC"). MidAmerican Energy's accounting policies and the accompanying Financial Statements conform to GAAP applicable to rate-regulated enterprises and reflect the effects of the ratemaking process.
MidAmerican Energy prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, MidAmerican Energy defers the recognition of certain costs or income if it is probable that, through the ratemaking process,
there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
i
Fair Value Measurements
As
defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts
that could be realized in a current or future market exchange.
288
i
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents
exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for wildlife preservation. iA reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2023 and 2022 as presented on the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
Restricted
cash and cash equivalents in other current assets
i6
i10
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i642
$
i268
i
Investments
Fixed
Maturity Securities
MidAmerican Energy's management determines the appropriate classification of investments in fixed maturity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Balance Sheets.
Available-for-sale investments are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on fixed maturity securities in a trust related to the decommissioning of the Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") are recorded as
a net regulatory liability because MidAmerican Energy expects to refund to customers any decommissioning funds in excess of costs for these activities through regulated rates. Trading investments are carried at fair value with changes in fair value recognized in earnings. Held-to-maturity securities are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity. The difference between the original cost and maturity value of a fixed maturity security is amortized to earnings using the interest method.
Investments gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired with respect to securities classified as available-for-sale. If the value of a fixed maturity investment declines to below amortized cost and the decline is deemed other than temporary, the amortized cost
of the investment is reduced to fair value, with a corresponding charge to earnings. Any resulting impairment loss is recognized in earnings if MidAmerican Energy intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If MidAmerican Energy does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in other comprehensive income (loss) ("OCI"). For regulated investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.
Equity Securities
All changes in fair
value of equity securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since MidAmerican Energy expects to refund to customers any decommissioning funds in excess of costs for these activities through regulated rates.
289
i
Allowance for Credit Losses
Trade
receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on MidAmerican Energy's assessment of the collectability of amounts owed to it by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, MidAmerican Energy primarily utilizes credit loss history. However, it may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. iThe
change in the balance of the allowance for credit losses, which is included in trade receivables, net on the Balance Sheets, is summarized as follows for the years ended December 31 (in millions):
2023
2022
2021
Beginning balance
$
i14
$
i12
$
i12
Charged
to operating costs and expenses, net
i8
i11
i10
Write-offs,
net
(i10)
(i9)
(i10)
Ending
balance
$
i12
$
i14
$
i12
i
Derivatives
MidAmerican
Energy employs a number of different derivative contracts, including forwards, futures, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities, and interest rate risk. Derivative contracts are recorded on the Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Balance Sheets.
Commodity derivatives used in normal business operations that are settled by physical
delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked to market, and settled amounts are recognized as operating revenue or cost of sales on the Statements of Operations.
For MidAmerican Energy's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.
i
Inventories
Inventories
consist mainly of materials and supplies, totaling $i240 million and $i175 million as of December 31, 2023 and 2022, respectively, coal stocks,
totaling $i89 million and $i68 million as of December 31, 2023 and 2022, respectively, and natural gas in storage, totaling $i29 million
and $i27 million as of December 31, 2023 and 2022, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined using the average cost method. The cost of stored natural gas is determined using the last-in-first-out method. With respect to stored natural gas, the replacement cost would be $i4 million
and $i22 million higher as of December 31, 2023 and 2022, respectively.
i
Property,
Plant and Equipment, Net
General
Additions to utility plant are recorded at cost. MidAmerican Energy capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC") and equity AFUDC. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds and retail energy benefits associated with certain wind-powered generation.
Amounts expensed under these arrangements are included as a component of depreciation and amortization.
290
Depreciation and amortization for MidAmerican Energy's utility operations are computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by its various regulatory authorities. Depreciation studies are completed by MidAmerican Energy to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through
approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally, when MidAmerican Energy retires or sells a component of utility plant, it charges the original cost, net of any proceeds from the disposition to accumulated depreciation. Any gain or loss on disposals of nonregulated assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of its regulated facilities, is capitalized by MidAmerican Energy as a component of utility plant, with offsetting credits
to the Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, MidAmerican Energy is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
i
Asset Retirement Obligations
MidAmerican Energy recognizes AROs when it has a legal obligation to perform decommissioning or removal activities upon retirement of an asset. MidAmerican Energy's AROs
are primarily related to decommissioning of the Quad Cities Station and obligations associated with its other generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to utility plant) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in utility plant, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
i
Impairment
MidAmerican
Energy evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. Additionally, when evaluating the carrying value of regulated assets, MidAmerican Energy considers the impact of regulation on recoverability. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Statements of Operations.
i
Revenue
Recognition
MidAmerican Energy uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which MidAmerican Energy expects to be entitled in exchange for those goods and services. MidAmerican Energy records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Statements of Operations.
A majority of MidAmerican Energy's energy revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations
to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided.
Revenue from electric and natural gas customers is recognized as electricity or natural gas is delivered or services are provided. Revenue recognized includes billed and unbilled amounts. As of December 31, 2023 and 2022, unbilled revenue was $i97 million and $i102 million,
respectively, and is included in trade receivables, net on the Balance Sheets.
/
291
The determination of customer billings is based on a systematic reading of customer meters and applicable rates. At the end of each month, amounts of energy provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled revenue include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses and composition of customer classes. Unbilled revenue is reversed
in the following month and billed revenue is recorded based on the subsequent meter readings.
All of MidAmerican Energy's regulated retail electric and natural gas sales are subject to energy adjustment clauses. MidAmerican Energy also has costs that are recovered, at least in part, through bill riders, including demand-side management and certain transmission costs. The clauses and riders allow MidAmerican Energy to adjust the amounts charged for electric and natural gas service as the related costs change. The costs recovered in revenue through use of the adjustment clauses and bill riders are charged to expense in the same year the related revenue is recognized. At any given time, these costs may be over or under collected from customers. The total under collection included in trade receivables, net at December 31, 2023 and 2022,
was $i29 million and $i156 million, respectively.
i
Unamortized
Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
i
Income Taxes
Berkshire Hathaway includes MidAmerican Funding and MidAmerican Energy in its consolidated U.S. federal and Iowa state income tax returns. MidAmerican Funding's and MidAmerican Energy's provisions for income taxes
have been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with certain property-related basis differences and other various differences that MidAmerican Energy deems probable to be passed on to its customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted
income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Investment tax credits are deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory commissions.
MidAmerican Funding and MidAmerican Energy recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based
on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. MidAmerican Funding's and MidAmerican Energy's unrecognized tax benefits are primarily included in taxes accrued and other long-term liabilities on their respective Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
292
i
New
Accounting Pronouncements
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. MidAmerican Energy
is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. MidAmerican
Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.
(3)iProperty, Plant and Equipment, Net
i
Property,
plant and equipment, net consists of the following as of December 31 (in millions):
Depreciable Life
2023
2022
Utility plant:
Generation
i20-i62
years
$
i18,129
$
i18,582
Transmission
i55-i80
years
i2,834
i2,662
Electric
distribution
i15-i80 years
i5,288
i4,931
Natural
gas distribution
i30-i75 years
i2,294
i2,144
Utility
plant in-service
i28,545
i28,319
Accumulated
depreciation and amortization
(i7,841)
(i8,024)
Utility
plant in-service, net
i20,704
i20,295
Nonregulated
property, net of accumulated depreciation and amortization
i20-i50 years
i6
i6
i20,710
i20,301
Construction
work-in-progress
i1,260
i790
Property,
plant and equipment, net
$
i21,970
$
i21,091
/
Nonregulated
property, net consists primarily of land not recoverable for regulated utility purposes.
i
The average depreciation and amortization rates applied to depreciable utility plant for the years ended December 31 were as follows:
2023
2022
2021
Electric
i3.3
%
i3.2
%
i3.3
%
Natural
gas
i2.8
%
i2.9
%
i2.8
%
/
Under
a revenue sharing arrangement in Iowa, MidAmerican Energy accrues throughout the year a regulatory liability based on the extent to which its anticipated annual equity return exceeds specified thresholds, with an equal amount recorded in depreciation and amortization expense. The annual regulatory liability accrual reduces utility plant upon final determination of the amount. For the years ended December 31, 2023, 2022 and 2021, $i29 million, $i296 million,
and $i115 million, respectively, is reflected in depreciation and amortization expense on the Statements of Operations.
293
(4)iJointly
Owned Utility Facilities
Under joint facility ownership agreements with other utilities, MidAmerican Energy, as a tenant in common, has undivided interests in jointly owned generation and transmission facilities. MidAmerican Energy accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating expenses on the Statements of Operations include MidAmerican Energy's share of the expenses of these facilities.
i
The
amounts shown in the table below represent MidAmerican Energy's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2023 (dollars in millions):
Accumulated
Construction
Company
Plant
in
Depreciation and
Work-in-
Share
Service
Amortization
Progress
Louisa Unit No. 1
i88
%
$
i983
$
i531
$
i5
Quad
Cities Unit Nos. 1 & 2(1)
i25
i737
i496
i11
Walter
Scott, Jr. Unit No. 3
i79
i1,017
i888
i14
Walter
Scott, Jr. Unit No. 4(2)
i60
i170
i123
i8
George
Neal Unit No. 4
i41
i330
i191
i6
Ottumwa
Unit No. 1(2)
i52
i433
i299
i8
George
Neal Unit No. 3
i72
i557
i375
i20
Transmission
facilities
Various
i274
i100
i3
Total
$
i4,501
$
i3,003
$
i75
(1)Includes
amounts related to nuclear fuel.
(2)Plant in-service and accumulated depreciation and amortization amounts are net of credits applied under Iowa regulatory arrangements totaling $i891 million and $i183
million, respectively.
/
(5) iRegulatory Matters
Regulatory Assets
i
Regulatory
assets represent costs that are expected to be recovered in future regulated rates. MidAmerican Energy's regulatory assets reflected on the Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Asset retirement obligations(1)
i12
years
$
i541
$
i469
Employee
benefit plans(2)
i9 years
i16
i47
Unrealized
loss on regulated derivative contracts
i1 year
i11
i—
Other
Various
i32
i34
Total
$
i600
$
i550
(1)Amount
predominantly relates to AROs for fossil-fueled and wind-powered generating facilities. Refer to Note 11 for a discussion of AROs.
(2)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
/
MidAmerican Energy had regulatory assets not earning a return on investment of $i598 million and
$i548 million as of December 31, 2023 and 2022, respectively.
294
Regulatory Liabilities
i
Regulatory
liabilities represent amounts expected to be returned to customers in future periods. MidAmerican Energy's regulatory liabilities reflected on the Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Cost of removal(1)
i28 years
$
i411
$
i392
Asset
retirement obligations(2)
i30 years
i360
i247
Iowa
electric revenue sharing(3)
Various
i127
i312
Deferred
income taxes(4)
Various
i102
i72
Pre-funded
AFUDC on transmission MVPs(5)
i56 years
i32
i34
Employee
benefit plans(6)
N/A
i16
i—
Unrealized
gain on regulated derivative contracts
i1 year
i—
i31
Other
Various
i31
i31
Total
$
i1,079
$
i1,119
(1)Amounts
represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing utility plant in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)Amount represents the excess of nuclear decommission trust assets over the related ARO. Refer to Note 11 for a discussion of AROs.
(3)Represents accruals associated with a regulatory arrangement in Iowa in which equity returns exceeding specified thresholds reduce utility plant and retail electric energy cost recoveries as required.
(4)Amounts primarily represent income tax liabilities primarily related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax
benefits related to state accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(5)Represents AFUDC accrued on transmission MVPs that is deducted from rate base as a result of the inclusion of related construction work-in-progress in rate base.
(6)Represents amounts not yet recognized as a component of net periodic benefit cost that are to be returned to customers in future periods when recognized.
/
(6)iInvestments
and Restricted Investments
i
Investments and restricted investments consists of the following amounts as of December 31 (in millions):
2023
2022
Nuclear
decommissioning trust
$
i767
$
i664
Rabbi
trusts
i239
i215
Other
i24
i23
Total
$
i1,030
$
i902
/
MidAmerican
Energy has established a trust for the investment of funds for decommissioning the Quad Cities Station. The debt and equity securities in the trust are reported at fair value. Funds are invested in the trust in accordance with applicable federal and state investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station, which is currently licensed for operation until December 2032. As of December 31, 2023 and 2022, the fair value of the trust's funds was invested as follows: i56%
and i54%, respectively, in domestic common equity securities, i33% and i32%,
respectively, in U.S. government securities, i9% and i11%, respectively, in domestic corporate debt securities and i2%
and i3%, respectively, in other securities.
Rabbi trusts primarily hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were established to hold investments used to fund the obligations of various nonqualified executive and director compensation plans and to pay the costs of the trusts. The amount represents the cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value. Changes in the cash
surrender value of the policies are reflected in other income (expense) - other, net on the Statements of Operations.
295
(7)iShort-term Debt and Credit Facilities
Interim financing
of working capital needs and the construction program is obtained from unaffiliated parties through the sale of commercial paper or short-term borrowing from banks. iThe following table summarizes MidAmerican Energy's availability under its unsecured revolving credit facilities as of December 31 (in millions):
2023
2022
Credit
facilities
$
i1,505
$
i1,505
Less:
Variable-rate
tax-exempt bond support
(i306)
(i370)
Net credit facilities
$
i1,199
$
i1,135
As
of December 31, 2023, MidAmerican Energy has a $i1.5 billion unsecured credit facility expiring in June 2026 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate ("SOFR") or a base rate, at MidAmerican Energy's option, plus a spread
that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $i5 million unsecured credit facility, which expires June 2024 and has a variable interest rate based on SOFR, plus a spread.
MidAmerican Energy had iino/
commercial paper borrowings outstanding of as of December 31, 2023 and 2022. The $i1.5 billion credit facility requires that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed i0.65
to 1.0 as of the last day of any quarter.
As of December 31, 2023, MidAmerican Energy was in compliance with the covenants of its credit facilities. MidAmerican Energy has authority from the FERC to issue commercial paper and bank notes aggregating $i1.5 billion through April 2, 2024.
As of December
31, 2023 and 2022, MidAmerican Energy had $i345 million and $i371 million, respectively, of letter of credit capacity under
its $i1.5 billion unsecured credit facility, of which iino/
amounts were outstanding. Additionally, as of December 31, 2023 and 2022, MidAmerican Energy had $i55 million and $i34 million, respectively,
of letters of credit outstanding outside of its $i1.5 billion unsecured credit facility in support of certain transactions required by third parties that generally have provisions that automatically extend the annual expiration dates for an additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
296
(8)iLong-term
Debt
MidAmerican Energy's long-term debt consists of the following, including amounts maturing within one year and unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par Value
2023
2022
First mortgage bonds:
i3.70%,
due 2023
$
i—
$
i—
$
i250
i3.50%,
due 2024
i500
i500
i500
i3.10%,
due 2027
i375
i374
i374
i3.65%,
due 2029
i850
i858
i859
i4.80%,
due 2043
i350
i347
i347
i4.40%,
due 2044
i400
i396
i395
i4.25%,
due 2046
i450
i446
i446
i3.95%,
due 2047
i475
i471
i471
i3.65%,
due 2048
i700
i690
i689
i4.25%,
due 2049
i900
i876
i875
i3.15%,
due 2050
i600
i592
i592
i2.70%,
due 2052
i500
i492
i492
i5.35%,
due 2034
i350
i347
i—
i5.85%,
due 2054
i1,000
i989
i—
Notes:
i6.75%
Series, due 2031
i400
i398
i397
i5.75%
Series, due 2035
i300
i299
i298
i5.80%
Series, due 2036
i350
i348
i348
Transmission
upgrade obligations, i3.24% to i7.84%, due 2036 to 2043
i70
i39
i27
Variable-rate
tax-exempt bond obligation series: (weighted average interest rate- 2023-i4.81%, 2022-i3.83%):
Due
2023, issued in 1993
i—
i—
i7
Due
2023, issued in 2008
i—
i—
i57
Due
2024
i35
i35
i35
Due
2025
i13
i13
i13
Due
2036
i33
i33
i33
Due
2038
i45
i45
i45
Due
2046
i30
i29
i30
Due
2047
i150
i149
i149
Total
long-term debt
$
i8,876
$
i8,766
$
i7,729
Reflected
as:
2023
2022
Current portion of long-term debt
$
i539
$
i317
Long-term
debt
i8,227
i7,412
Total
long-term debt
$
i8,766
$
i7,729
297
i
The
annual repayments of MidAmerican Energy's long-term debt for the years beginning January 1, 2024, and thereafter, excluding unamortized premiums, discounts and debt issuance costs, are as follows (in millions):
2024
$
i539
2025
i17
2026
i4
2027
i379
2028
i4
2029
and thereafter
i7,933
/
In January 2024, MidAmerican Energy issued $i600 million
of its i5.30% First Mortgage Bonds due February 2055. MidAmerican Energy intends, within i24 months of the issuance date, to allocate an amount equal to the net proceeds to finance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green
Financing Framework.
Pursuant to MidAmerican Energy's mortgage dated September 9, 2013, MidAmerican Energy's first mortgage bonds, currently and from time to time outstanding, are secured by a first mortgage lien on substantially all of its electric generating, transmission and distribution property within the state of Iowa, subject to certain exceptions and permitted encumbrances. Approximately $i24 billion of MidAmerican Energy's eligible property, based
on original cost, was subject to the lien of the mortgage as of December 31, 2023. Additionally, MidAmerican Energy's senior notes outstanding are equally and ratably secured with the first mortgage bonds as required by the indentures under which the senior notes were issued.
MidAmerican Energy's variable-rate tax-exempt bond obligations bear interest at rates that are periodically established through remarketing of the bonds in the short-term tax-exempt market. MidAmerican Energy, at its option, may change the mode of interest calculation for these bonds by selecting from among several floating or fixed rate alternatives. The interest rates shown in the table above are the weighted average interest rates as of December 31, 2023 and 2022.
MidAmerican Energy maintains revolving credit facility agreements to provide liquidity for holders of these issues. Additionally, MidAmerican Energy's obligations associated with the $i30 million and $i150 million variable rate, tax-exempt bond obligations due 2046
and 2047, respectively, are secured by an equal amount of first mortgage bonds pursuant to MidAmerican Energy's mortgage dated September 9, 2013, as supplemented and amended.
As of December 31, 2023, MidAmerican Energy was in compliance with all of its applicable long-term debt covenants.
In March 1999, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above i42%
of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below i39% of total capitalization. MidAmerican Energy must seek the approval from the IUB of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below i42%
of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy's equity level decreases to below i39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy. As of December 31, 2023, MidAmerican Energy's common equity ratio was i55%
computed on a basis consistent with its commitment. As a result of its regulatory commitment to maintain its common equity level above certain thresholds, MidAmerican Energy could dividend $i3.6 billion as of December 31, 2023, without falling below i42%.
298
(9)iIncome
Taxes
i
MidAmerican Energy's income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Current:
Federal
$
(i755)
$
(i769)
$
(i736)
State
(i28)
(i34)
(i92)
(i783)
(i803)
(i828)
Deferred:
Federal
i109
i77
i189
State
(i18)
(i43)
(i35)
i91
i34
i154
Investment
tax credits
(i1)
(i1)
(i1)
Total
$
(i693)
$
(i770)
$
(i675)
/
i
A
reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax expense (benefit) is as follows for the years ended December 31:
2023
2022
2021
Federal
statutory income tax rate
i21
%
i21
%
i21
%
Income
tax credits
(i236)
(i372)
(i262)
State
income tax, net of federal income tax impacts
(i12)
(i32)
(i46)
Effects
of ratemaking
(i12)
(i23)
(i20)
Other,
net
(i1)
i3
(i1)
Effective
income tax rate
(i240)
%
(i403)
%
(i308)
%
/
Income
tax credits relate primarily to production tax credits ("PTC") earned by MidAmerican Energy's wind- and solar-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind- and solar-powered generating facilities are eligible for the credits for i10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the years ended December 31, 2023,
2022 and 2021 totaled $i681 million, $i710 million and $i574
million, respectively.
299
i
MidAmerican Energy's net deferred income tax liability consists of the following as of December 31 (in millions):
2023
2022
Deferred
income tax assets:
Regulatory liabilities
$
i218
$
i194
Asset
retirement obligations
i204
i191
State
carryforwards
i68
i61
Revenue
sharing
i34
i87
Employee benefits
i25
i37
Other
i68
i24
Total
deferred income tax assets
i617
i594
Valuation allowances
(i2)
(i2)
Total
deferred income tax assets, net
i615
i592
Deferred
income tax liabilities:
Property-related items
(i3,972)
(i3,895)
Regulatory
assets
(i134)
(i128)
Other
(i3)
(i2)
Total
deferred income tax liabilities
(i4,109)
(i4,025)
Net
deferred income tax liability
$
(i3,494)
$
(i3,433)
/
As
of December 31, 2023, MidAmerican Energy's state tax carryforwards, principally related to $i1 billion of net operating losses, expire at various intervals between 2024 and 2042.
The U.S. Internal Revenue Service has closed or effectively settled its examination of MidAmerican Energy's income tax returns through December 31, 2013. The statute of limitations for MidAmerican Energy's income tax returns have expired for certain states
through December 31, 2011, and for other states through December 31, 2019, except for the impact of any federal audit adjustments. The closure of examinations, or the expiration of the statute of limitations, for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
i
A reconciliation of the beginning and ending balances of MidAmerican Energy's net unrecognized
tax benefits is as follows for the years ended December 31 (in millions):
2023
2022
Beginning balance
$
i16
$
i13
Additions
based on tax positions related to the current year
i10
i15
Interest
i1
i—
Reductions
based on tax positions related to the current year
(i5)
(i12)
Ending
balance
$
i22
$
i16
/
As
of December 31, 2023, MidAmerican Energy had unrecognized tax benefits totaling $i48 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect MidAmerican Energy's effective income tax rate.
300
(10)iEmployee
Benefit Plans
Defined Benefit Plan
MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. Benefit obligations under the plan are based on a cash balance arrangement for salaried employees and most union employees and final average pay formulas for other union employees. MidAmerican Energy also maintains noncontributory, nonqualified defined benefit supplemental executive retirement plans ("SERP") for certain active and retired participants. For the years ended December 31, 2023 and 2022, the defined benefit pension plan recorded a settlement gain of
$i3 million and a settlement loss of $i4 million, respectively, for previously unrecognized
gains and losses as a result of excess lump sum distributions over the defined threshold. In 2022, the defined benefit pension plan recorded a curtailment gain of $i10 million as a result of certain plan amendments.
MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. Under the plans, a
majority of all employees of the participating companies may become eligible for these benefits if they reach retirement age. New employees are not eligible for benefits under the plans. MidAmerican Energy has been allowed to recover accrued pension and other postretirement benefit costs in its electric and gas service rates.
Net Periodic Benefit Cost
For purposes of calculating the expected return on pension plan assets, a market-related value is used. The market-related value of plan assets is calculated by spreading the difference between expected and actual investment returns on equity investments over a five-year period beginning after the first year in which they occur.
MidAmerican Energy bills to and is reimbursed
currently for affiliates' share of the net periodic benefit costs from all plans in which such affiliates participate. In 2023, 2022 and 2021, MidAmerican Energy's share of the pension net periodic benefit credit was $(i5) million, $(i2) million
and $(i20) million, respectively. MidAmerican Energy's share of the other postretirement net periodic benefit cost (credit) in 2023, 2022 and 2021 totaled $i2 million, $(i2) million
and $i1 million, respectively.
i
Net periodic benefit cost for the plans of MidAmerican Energy and the aforementioned affiliates included the following components for the years ended December 31 (in
millions):
Pension
Other Postretirement
2023
2022
2021
2023
2022
2021
Service
cost
$
i10
$
i15
$
i20
$
i5
$
i8
$
i9
Interest
cost
i32
i23
i22
i13
i8
i8
Expected
return on plan assets
(i30)
(i27)
(i37)
(i14)
(i14)
(i10)
Curtailment
i—
(i10)
i—
i—
i—
i—
Settlement
(i3)
i4
(i5)
i—
i—
i—
Net
amortization
i—
i1
i1
i—
(i2)
(i4)
Net
periodic benefit cost
$
i9
$
i6
$
i1
$
i4
$
i—
$
i3
/
301
Funded
Status
i
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
Pension
Other
Postretirement
2023
2022
2023
2022
Plan assets at fair value, beginning of year
$
i490
$
i704
$
i240
$
i308
Employer
contributions
i7
i7
i3
i3
Participant
contributions
i—
i—
i1
i1
Actual
return on plan assets
i64
(i130)
i51
(i58)
Settlement
i—
(i57)
i—
i—
Benefits
paid
(i45)
(i34)
(i17)
(i14)
Plan
assets at fair value, end of year
$
i516
$
i490
$
i278
$
i240
/
i
The
following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension
Other Postretirement
2023
2022
2023
2022
Benefit
obligation, beginning of year
$
i586
$
i781
$
i243
$
i285
Service
cost
i10
i15
i5
i8
Interest
cost
i32
i23
i13
i8
Participant
contributions
i—
i—
i1
i1
Actuarial
loss (gain)
i15
(i129)
(i4)
(i64)
Amendment
i—
(i3)
i—
i19
Curtailment
i—
(i10)
i—
i—
Settlement
i—
(i57)
i—
i—
Benefits
paid
(i45)
(i34)
(i17)
(i14)
Benefit
obligation, end of year
$
i598
$
i586
$
i241
$
i243
Accumulated
benefit obligation, end of year
$
i564
$
i551
/
i
The
funded status of the plans and the amounts recognized on the Balance Sheets as of December 31 are as follows (in millions):
Pension
Other Postretirement
2023
2022
2023
2022
Plan
assets at fair value, end of year
$
i516
$
i490
$
i278
$
i240
Less
- Benefit obligation, end of year
i598
i586
i241
i243
Funded
status
$
(i82)
$
(i96)
$
i37
$
(i3)
Amounts
recognized on the Balance Sheets:
Other assets
$
i3
$
i—
$
i37
$
i—
Other
current liabilities
(i8)
(i8)
i—
i—
Other
long-term liabilities
(i77)
(i88)
i—
(i3)
Amounts
recognized
$
(i82)
$
(i96)
$
i37
$
(i3)
/
302
The
SERP has no plan assets; however, MidAmerican Energy and BHE have Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in MidAmerican Energy's Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $i149 million and $i134 million
as of December 31, 2023 and 2022, respectively. These assets are not included in the plan assets in the above table, but are reflected in investments and restricted investments on the Balance Sheets. For each of the years ended December 31, 2023 and 2022, the accumulated benefit obligation and projected benefit obligation for the SERP was $ii85/ million
and $ii85/ million, respectively.
Unrecognized
Amounts
i
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
Pension
Other
Postretirement
2023
2022
2023
2022
Net loss (gain)
$
(i19)
$
(i4)
$
(i30)
$
i11
Prior
service cost (credit)
(i3)
(i3)
i18
i19
Total
$
(i22)
$
(i7)
$
(i12)
$
i30
/
MidAmerican
Energy sponsors pension and other postretirement benefit plans on behalf of certain of its affiliates in addition to itself, and therefore, the portion of the funded status of the respective plans that has not yet been recognized in net periodic benefit cost is attributable to multiple entities. Additionally, substantially all of MidAmerican Energy's portion of such amounts is either refundable to or recoverable from its customers and is reflected as regulatory liabilities and regulatory assets.
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2023 and 2022 is as follows (in millions):
Assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension
Other
Postretirement
2023
2022
2021
2023
2022
2021
Benefit obligations as of December 31:
Discount
rate
i5.45
%
i5.70
%
i3.05
%
i5.45
%
i5.60
%
i2.95
%
Rate
of compensation increase
i3.00
%
i3.00
%
i2.75
%
N/A
N/A
N/A
Interest
crediting rates for cash balance plan
2021
N/A
N/A
i1.19
%
N/A
N/A
N/A
2022
N/A
i3.74
%
i1.19
%
N/A
N/A
N/A
2023
i3.50
%
i3.74
%
i1.19
%
N/A
N/A
N/A
2024
i3.50
%
i3.74
%
i1.19
%
N/A
N/A
N/A
2025
i3.50
%
i3.74
%
i1.19
%
N/A
N/A
N/A
2026
and beyond
i3.50
%
i3.74
%
i1.19
%
N/A
N/A
N/A
Net
periodic benefit cost for the years ended December 31:
Discount rate
i5.70
%
i3.05
%
i2.75
%
i5.60
%
i2.95
%
i2.65
%
Expected
return on plan assets(1)
i6.35
%
i4.30
%
i5.60
%
i6.80
%
i5.30
%
i4.00
%
Rate
of compensation increase
i3.00
%
i2.75
%
i2.75
%
N/A
N/A
N/A
Interest
crediting rates for cash balance plan
i3.50
%
i3.74
%
i1.19
%
N/A
N/A
N/A
(1)Amounts
reflected are pretax values. Assumed after-tax returns for a taxable, non-union other postretirement plan were i5.52% for 2023, i4.21%
for 2022 and i2.39% for 2021.
In establishing its assumption as to the expected return on plan assets, MidAmerican Energy utilizes the asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets.
2023
2022
Assumed
healthcare cost trend rates as of December 31:
Healthcare cost trend rate assumed for next year
i6.20
%
i6.50
%
Rate
that the cost trend rate gradually declines to
i5.00
%
i5.00
%
Year
that the rate reaches the rate it is assumed to remain at
i2028
i2028
/
304
Contributions
and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $i8 million and $i2
million, respectively, during 2024. Funding to MidAmerican Energy's qualified pension benefit plan trust is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 and the Pension Protection Act of 2006, as amended. MidAmerican Energy considers contributing additional amounts from time to time in order to achieve certain funding levels specified under the Pension Protection Act of 2006, as amended. MidAmerican Energy evaluates a variety of factors, including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit plans.
i
Net
periodic benefit costs assigned to MidAmerican Energy affiliates are reimbursed currently in accordance with its intercompany administrative services agreement. The expected benefit payments to participants in MidAmerican Energy's pension and other postretirement benefit plans for 2024 through 2028 and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension
Other Postretirement
2024
$
i54
$
i22
2025
i54
i23
2026
i53
i23
2027
i52
i24
2028
i49
i23
2029-2033
i226
i107
/
Plan
Assets
Investment Policy and Asset Allocations
MidAmerican Energy's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified portfolio of debt securities, equity securities and other alternative investments. Maturities for debt securities are managed to targets consistent with prudent risk tolerances. The plans retain outside investment consultants to advise on plan investments within the parameters outlined by the Berkshire Hathaway Energy Company Investment Committee. The investment portfolio is managed in line with the investment policy with sufficient liquidity to meet near-term benefit payments.
i
The
target allocations (percentage of plan assets) for MidAmerican Energy's pension and other postretirement benefit plan assets are as follows as of December 31, 2023:
Pension
Other
Postretirement
%
%
Debt securities(1)
i40-i60
i25-i35
Equity
securities(1)
i30-i60
i65-i75
Other
0-i15
0-i5
(1)For
purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying investments in debt and equity securities.
/
305
Fair Value Measurements
i
The
following table presents the fair value of plan assets, by major category, for MidAmerican Energy's defined benefit pension plan (in millions):
(1)Refer to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective
trust funds. These funds consist of equity and debt securities of approximately i68% and i32%, respectively, for 2023 and i55%
and i45%, respectively, for 2022. Additionally, these funds are invested in U.S. and international securities of approximately i93% and i7%,
respectively, for 2023 and i97% and i3%, respectively, for 2022.
/
306
The
following table presents the fair value of plan assets, by major category, for MidAmerican Energy's defined benefit other postretirement plans (in millions):
(1)Refer
to Note 12 for additional discussion regarding the three levels of the fair value hierarchy.
(2)Investment funds are comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately i83% and i17%,
respectively, for 2023 and i82% and i18%, respectively, for 2022. Additionally, these funds are invested in U.S. and international securities of approximately i83%
and i17%, respectively, for 2023 and i82% and i18%,
respectively, for 2022.
For level 1 investments, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Defined Contribution Plan
MidAmerican Energy
sponsors a defined contribution plan ("401(k) plan") covering substantially all employees. MidAmerican Energy's matching contributions are based on each participant's level of contribution, and certain participants receive contributions based on eligible pretax annual compensation. Contributions cannot exceed the maximum allowable for tax purposes. Certain participants now receive enhanced benefits in the 401(k) plan and no longer accrue benefits in the noncontributory defined benefit pension plans. MidAmerican Energy's contributions to the plan were $i34 million, $i33
million, and $i27 million for the years ended December 31, 2023, 2022 and 2021, respectively.
307
(11)iAsset
Retirement Obligations
MidAmerican Energy estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work. The change in estimated costs for 2023 was primarily the result of an updated decommissioning estimate for its wind-powered generating facilities, which is a non-cash investing activity and reflects changes in the projected removal costs per turbine.
MidAmerican Energy does not recognize liabilities
for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $i411 million and $i392 million
as of December 31, 2023 and 2022, respectively.
i
The following table presents MidAmerican Energy's ARO liabilities by asset type as of December 31 (in millions):
2023
2022
Quad
Cities Station
$
i407
$
i417
Fossil-fueled generating
facilities
i62
i76
Wind-powered generating facilities
i305
i210
Solar-powered
generating facilities and other
i4
i4
Total asset retirement obligations
$
i778
$
i707
Quad
Cities Station nuclear decommissioning trust funds(1)
$
i767
$
i664
(1)Refer
to Note 6 for a discussion of the Quad Cities Station nuclear decommissioning trust funds.
/
i
The following table reconciles the beginning and ending balances of MidAmerican Energy's ARO liabilities for the years ended December 31 (in millions):
2023
2022
Beginning
balance
$
i707
$
i787
Change in estimated costs
i56
(i27)
Additions
i3
i2
Retirements
(i21)
(i85)
Accretion
i33
i30
Ending
balance
$
i778
$
i707
Reflected
as:
Other current liabilities
$
i10
$
i24
Asset
retirement obligations
i768
i683
$
i778
$
i707
/
Retirements
in 2023 and 2022 relate to settlements of MidAmerican Energy's coal combustion residuals ARO liabilities.
308
(12)iFair Value Measurements
The carrying value of MidAmerican Energy's
cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or
liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.
309
The following table presents MidAmerican Energy's financial
assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
(1)Represents
netting under master netting arrangements and a net cash collateral receivable of $i12 million and $i— million
as of December 31, 2023 and 2022, respectively.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
310
i
The
following table reconciles the beginning and ending balances of MidAmerican Energy's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
2023
2022
2021
Beginning balance
$
i5
$
(i5)
$
i2
Changes
in fair value recognized in net regulatory assets
(i40)
i37
(i2)
Settlements
i24
(i27)
(i5)
Ending
balance
$
(i11)
$
i5
$
(i5)
/
MidAmerican
Energy's long-term debt is carried at cost on the Financial Statements. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. iThe following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt
as of December 31 (in millions):
2023
2022
Carrying
Value
Fair Value
Carrying
Value
Fair
Value
Long-term debt
$
i8,766
$
i8,252
$
i7,729
$
i6,964
(13)iCommitments
and Contingencies
Commitments
i
MidAmerican Energy had the following firm commitments that are not reflected on the Balance Sheet. Minimum payments as of December 31, 2023, are as follows (in millions):
2029
and
2024
2025
2026
2027
2028
Thereafter
Total
Contract type:
Coal
and natural gas for generation
$
i123
$
i66
$
i36
$
i36
$
i6
$
i—
$
i267
Electric
capacity and transmission
i29
i29
i28
i17
i7
i—
i110
Natural
gas contracts for gas operations
i178
i102
i91
i64
i23
i14
i472
Construction
commitments
i399
i10
i5
i18
i11
i—
i443
Easements
i45
i46
i47
i47
i48
i1,618
i1,851
Maintenance,
services and other
i159
i153
i148
i126
i89
i81
i756
$
i933
$
i406
$
i355
$
i308
$
i184
$
i1,713
$
i3,899
/
Coal,
Natural Gas, Electric Capacity and Transmission Commitments
MidAmerican Energy has coal supply and related transportation and lime contracts for its coal-fueled generating facilities. MidAmerican Energy expects to supplement the coal contracts with additional contracts and spot market purchases to fulfill its future coal supply needs. Additionally, MidAmerican Energy has a natural gas transportation contract for a natural gas-fueled generating facility. The contracts have minimum payment commitments ranging through 2028.
MidAmerican Energy has various natural gas supply and transportation contracts for its regulated natural gas operations that have minimum payment commitments ranging through 2037.
MidAmerican Energy has
contracts to purchase electric capacity that have minimum payment commitments ranging through 2028. MidAmerican Energy also has contracts for the right to transmit electricity over other entities' transmission lines with minimum payment commitments ranging through 2027.
311
Construction Commitments
MidAmerican Energy's firm construction commitments reflected in the table above consist primarily of contracts for the repowering and construction of wind- and solar-powered generating facilities and the settlement of AROs.
Easements
MidAmerican
Energy has non-cancelable easements with minimum payment commitments ranging through 2061 for land in Iowa on which certain of its assets, primarily wind- and solar-powered generating facilities, are located.
Maintenance, Services and Other Contracts
MidAmerican Energy has other non-cancelable contracts primarily related to maintenance and services for various generating facilities with minimum payment commitments ranging through 2035.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal
ash disposal and other environmental matters that have the potential to impact its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Legal Matters
MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.
Transmission Rates
MidAmerican Energy's wholesale transmission rates are set annually using formula rates approved by the FERC subject to true-up for actual cost of service. In November
2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the base return on equity ("ROE") used to determine rates in effect prior to September 2016 no longer be found just and reasonable and sought to reduce the base ROE. In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion vacating all orders related to the complaints and remanding them back to the FERC. MidAmerican Energy cannot predict the ultimate outcome of these matters or the amount of refunds, if any, and accordingly, has reversed its previously accrued liability for potential refunds of amounts collected under the higher ROE during the periods covered by the complaints.
312
(14) iRevenue
from Contracts with Customers
MidAmerican Energy uses a single five-step model to identify and recognize Customer Revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. iThe following table summarizes MidAmerican Energy's revenue by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 19, (in millions):
In 2023 and 2022, MidAmerican Energy paid $i1,025 million and $i275 million, respectively, in cash dividends to its parent company, MHC. In
February 2024, MidAmerican Energy paid $i425 million in a cash dividend to its parent company, MHC.
(16)iOther
Income (Expense)
i
Other, net, as shown on the Statements of Operations, includes the following other income (expense) items for the years ended December 31 (in millions):
2023
2022
2021
Corporate-owned
life insurance income (loss)
$
i23
$
(i16)
$
i21
Non-service
cost components of postretirement employee benefit plans
i8
i9
i26
Interest
income and other, net
i5
i7
i6
Total
$
i36
$
i—
$
i53
/
(17)iSupplemental
Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ending December 31 is as follows (in millions):
2023
2022
2021
Supplemental disclosure of cash flow information:
Interest
paid, net of amounts capitalized
$
i300
$
i292
$
i279
Income
taxes received, net
$
i852
$
i840
$
i746
Supplemental
disclosure of non-cash investing transactions:
Accruals related to property, plant and equipment additions
$
i193
$
i168
$
i257
314
(18)iRelated
Party Transactions
The companies identified as affiliates of MidAmerican Energy are Berkshire Hathaway and its subsidiaries, including BHE and its subsidiaries. The basis for the following transactions is provided for in service agreements between MidAmerican Energy and the affiliates.
MidAmerican Energy is reimbursed for charges incurred on behalf of its affiliates. The majority of these reimbursed expenses are for general costs, such as insurance and building rent, and for employee wages, benefits and costs related to corporate functions such as information technology, human resources, treasury, legal and accounting. The amount of such reimbursements was $i94 million,
$i78 million and $i66 million for 2023, 2022 and 2021, respectively.
MidAmerican Energy reimbursed BHE in the amount
of $i123 million, $i79 million and $i72 million
in 2023, 2022 and 2021, respectively, for its share of technology costs, corporate expenses and other costs. Amounts charged to MidAmerican Energy in 2023 and 2022 were primarily reflected in construction work-in-progress on the Balance Sheets as of December 31, 2023 and 2022.
MidAmerican Energy purchases, in the normal course of business at either tariffed or market prices, natural gas transportation and storage capacity services from Northern Natural Gas Company, a wholly owned subsidiary of BHE, and coal transportation services from BNSF Railway Company, an indirect wholly owned subsidiary of Berkshire Hathaway. These purchases totaled $i141 million,
$i141 million and $i132 million in 2023, 2022 and 2021, respectively.
MidAmerican
Energy had accounts receivable from affiliates of $i9 million and $i9 million as of December 31, 2023 and 2022, respectively, that are included in other current assets on the Balance Sheets.
MidAmerican Energy also had accounts payable to affiliates of $i32 million and $i22 million as of December 31, 2023 and 2022, respectively, that are included in accounts payable
on the Balance Sheets.
MidAmerican Energy is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated U.S. federal income tax return. For current federal and state income taxes, MidAmerican Energy had a net payable to BHE of $i21 million and a receivable from BHE of $i42 million
as of December 31, 2023 and 2022, respectively. MidAmerican Energy received net cash payments for federal and state income taxes from BHE totaling $i852 million, $i840 million
and $i746 million for the years ended December 31, 2023, 2022 and 2021, respectively.
MidAmerican Energy recognizes the full amount of the funded status for its pension and postretirement plans, and amounts attributable to MidAmerican Energy's affiliates that have not previously been recognized through income are recognized as an
intercompany balance with such affiliates. MidAmerican Energy adjusts these balances when changes to the funded status of the respective plans are recognized and does not intend to settle the balances currently. Amounts receivable from affiliates attributable to the funded status of employee benefit plans totaled $i82 million and $i79 million
as of December 31, 2023 and 2022, respectively, and are included in other assets on the Balance Sheets. Similar amounts payable to affiliates totaled $i55 million and $i40 million
as of December 31, 2023 and 2022, respectively, and are included in other long-term liabilities on the Balance Sheets. See Note 10 for further information pertaining to pension and postretirement accounting.
(19)iSegment Information
MidAmerican
Energy has identified itwo reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales
are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. Refer to Note 9 for a discussion of items affecting income tax expense (benefit) for the regulated electric and natural gas operating segments.
315
i
The
following tables provide information on a reportable segment basis (in millions):
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers and Member of
MidAmerican Funding, LLC
Des Moines, Iowa
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in member's equity, and cash flows for each of the three years in the period ended December 31,
2023, the related notes and the schedule listed in the Index at Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of MidAmerican Funding as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of MidAmerican Funding's management. Our responsibility is to express an
opinion on MidAmerican Funding's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. MidAmerican Funding is not required to have, nor were we engaged to perform, an audit of its internal control over financial
reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of MidAmerican Funding's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical
Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Note 5 to the financial statements
Critical
Audit Matter Description
MidAmerican Funding is subject to rate regulation by state public service commissions as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where MidAmerican Funding operates. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation has a pervasive effect on the financial statements.
318
Regulated
rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow MidAmerican Funding an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an effect on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While MidAmerican Funding has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit MidAmerican Funding's ability to recover its costs.
We identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made
by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the
Commissions included the following, among others:
•We evaluated MidAmerican Funding's disclosures related to the effects of rate regulation by testing recorded balances and evaluating regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by MidAmerican Funding and interveners, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected MidAmerican Funding's filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the
Commissions' treatment of similar costs under similar circumstances.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i908
i1,168
i914
Amortization
of utility plant to other operating expenses
i34
i35
i34
Allowance
for equity funds
(i59)
(i51)
(i39)
Deferred
income taxes and amortization of investment tax credits
i90
i33
i153
Settlements
of asset retirement obligations
(i21)
(i85)
(i103)
Other,
net
i33
i52
i21
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i254
(i11)
(i293)
Inventories
(i87)
(i43)
i44
Pension
and other postretirement benefit plans, net
i3
i8
(i4)
Accrued
property, income and other taxes, net
i77
i40
(i71)
Accounts
payable and other liabilities
(i9)
i68
i66
Net
cash flows from operating activities
i2,203
i2,161
i1,605
Cash
flows from investing activities:
Capital expenditures
(i1,833)
(i1,869)
(i1,912)
Purchases
of marketable securities
(i243)
(i499)
(i213)
Proceeds
from sales of marketable securities
i227
i492
i207
Proceeds
from sales of other investments
i12
i—
i—
Other,
net
i12
i8
i6
Net
cash flows from investing activities
(i1,825)
(i1,868)
(i1,912)
Cash
flows from financing activities:
Distributions to member
(i1,025)
(i69)
i—
Proceeds
from long-term debt
i1,338
i—
i492
Repayments
of long-term debt
(i317)
(i2)
(i1)
Net
change in note payable to affiliate
i—
(i189)
i12
Other,
net
(i2)
(i2)
(i2)
Net
cash flows from financing activities
(i6)
(i262)
i501
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i372
i31
i194
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of year
i271
i240
i46
Cash
and cash equivalents and restricted cash and cash equivalents at end of year
$
i643
$
i271
$
i240
The
accompanying notes are an integral part of these consolidated financial statements.
324
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)iOrganization
and Operations
MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct, wholly
owned nonregulated subsidiary is Midwest Capital Group, Inc. ("Midwest Capital Group").
(2) iSummary of Significant Accounting Policies
In addition to the following significant accounting policies, refer to Note 2 of MidAmerican Energy's Notes to Financial Statements for significant accounting policies of MidAmerican Funding.
i
Basis
ofConsolidation and Presentation
The Consolidated Financial Statements include the accounts of MidAmerican Funding and its subsidiaries in which it held a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated, other than those between rate-regulated operations. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2023, 2022 and 2021.
i
Cash
and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for wildlife preservation. iA reconciliation of cash and cash
equivalents and restricted cash and cash equivalents as of December 31, 2023 and 2022 as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Restricted
cash and cash equivalents in other current assets
i6
i10
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i643
$
i271
i
Goodwill
Goodwill
represents the excess of the purchase price over the fair value of identifiable net assets acquired when MidAmerican Funding purchased MHC. MidAmerican Funding evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2023. When evaluating goodwill for impairment, MidAmerican Funding estimates the fair value of its reporting units. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment
is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The determination of fair value incorporates significant unobservable inputs. During 2023, 2022 and 2021, MidAmerican Funding did iiino//t
record any goodwill impairments.
/
325
New Accounting Pronouncements
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as
incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. MidAmerican Funding is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated
information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. MidAmerican Funding is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
(3) iProperty,
Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had nonregulated property gross of $i1 million and $i1 million
as of December 31, 2023 and 2022, respectively.
(4)iJointly Owned Utility Facilities
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
(5)iRegulatory
Matters
Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.
(6)iInvestments and Restricted Investments
Refer to Note 6 of MidAmerican
Energy's Notes to Financial Statements. In addition to MidAmerican Energy's investments and restricted investments, MHC had corporate-owned life insurance policies in a Rabbi trust owned by MHC with a total cash surrender value of $ii2/
million as of December 31, 2023 and 2022.
(7)iShort-term Debt and Credit Facilities
Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's credit facilities, MHC has a $i4 million
unsecured credit facility, which expires in June 2024 and has a variable interest rate based on the Secured Overnight Financing Rate, plus a spread. As of December 31, 2023 and 2022, there were iino/
borrowings outstanding under this credit facility. As of December 31, 2023, MHC was in compliance with the covenants of its credit facility.
(8)iLong-term Debt
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements for detail and a discussion of its long-term debt. In addition to MidAmerican
Energy's annual repayments of long-term debt, MidAmerican Funding parent company has $i239 million of i6.927% Senior Bonds due in 2029, with a carrying value of $ii240/ million
as of December 31, 2023 and 2022.
The MidAmerican Funding parent company bonds are the direct senior secured obligations of MidAmerican Funding and effectively rank junior to all indebtedness and other liabilities of the direct and indirect subsidiaries of MidAmerican Funding, to the extent of the assets of these subsidiaries. MidAmerican Funding may redeem the bonds in whole or in part at any time at a redemption price equal to the sum of any accrued and unpaid interest to the date of redemption and the greater of (1) 100% of the principal amount of the bonds or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the bonds, discounted to the date of redemption on a semiannual basis at the treasury yield plus 25 basis points.
326
MidAmerican
Funding parent company long-term debt is secured by a pledge of the common stock of MHC, which is not publicly traded. In the event of any triggering event under the related debt indenture, the common stock of MHC would be available to satisfy the applicable debt obligations. Triggering events include, among other specified circumstances, (1) default on the payment of interest for 30 days or principal for three days; (2) a material default in the performance of any material covenants or obligations in the indenture continuing for a period of 90 days after written notice in accordance with the indenture; or (3) the failure generally of MidAmerican Funding or any significant subsidiary to pay its debts when due.
Subsidiaries of MidAmerican Funding must make payments on their own indebtedness before making distributions to MidAmerican Funding. Refer to Note 8 of MidAmerican Energy's Notes
to Financial Statements for a discussion of utility regulatory restrictions affecting distributions from MidAmerican Energy. As a result of the utility regulatory restrictions agreed to by MidAmerican Energy in March 1999, MidAmerican Funding had restricted net assets of $i6 billion as of December 31, 2023.
As of December 31, 2023, MidAmerican Funding was in compliance with all of its applicable long-term debt covenants.
Each
of MidAmerican Funding's direct or indirect subsidiaries is organized as a legal entity separate and apart from MidAmerican Funding and its other subsidiaries. It should not be assumed that any asset of any subsidiary of MidAmerican Funding will be available to satisfy the obligations of MidAmerican Funding or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MidAmerican Funding, one of its subsidiaries or affiliates thereof.
(9)iIncome
Taxes
i
MidAmerican Funding's income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Current:
Federal
$
(i756)
$
(i773)
$
(i739)
State
(i29)
(i36)
(i94)
(i785)
(i809)
(i833)
Deferred:
Federal
i109
i77
i189
State
(i18)
(i43)
(i35)
i91
i34
i154
Investment
tax credits
(i1)
(i1)
(i1)
Total
$
(i695)
$
(i776)
$
(i680)
/
i
A
reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax expense (benefit) is as follows for the years ended December 31:
2023
2022
2021
Federal
statutory income tax rate
i21
%
i21
%
i21
%
Income
tax credits
(i239)
(i416)
(i283)
State
income tax, net of federal income tax impacts
(i13)
(i36)
(i50)
Effects
of ratemaking
(i12)
(i26)
(i21)
Other,
net
(i1)
i3
(i2)
Effective
income tax rate
(i244)
%
(i454)
%
(i335)
%
/
327
Income
tax credits relate primarily to production tax credits ("PTC") earned by MidAmerican Energy's wind- and solar-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind- and solar-powered generating facilities are eligible for the credits for i10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the years ended December 31, 2023,
2022 and 2021 totaled $i681 million, $i710 million and $i574
million, respectively.
i
MidAmerican Funding's net deferred income tax liability consists of the following as of December 31 (in millions):
2023
2022
Deferred
income tax assets:
Regulatory liabilities
$
i218
$
i194
Asset
retirement obligations
i204
i192
State
carryforwards
i68
i61
Revenue
sharing
i34
i87
Employee benefits
i25
i37
Other
i69
i24
Total
deferred income tax assets
i618
i595
Valuation allowances
(i2)
(i2)
Total
deferred income tax assets, net
i616
i593
Deferred
income tax liabilities:
Property-related items
(i3,972)
(i3,895)
Regulatory
assets
(i134)
(i128)
Other
(i2)
(i1)
Total
deferred income tax liabilities
(i4,108)
(i4,024)
Net
deferred income tax liability
$
(i3,492)
$
(i3,431)
/
As
of December 31, 2023, MidAmerican Funding's state tax carryforwards, principally related to $i1 billion of net operating losses, expire at various intervals between 2024 and 2042.
The U.S. Internal Revenue Service has closed or effectively settled its examination of MidAmerican Funding's income tax returns through December 31, 2013. The statute of limitations for MidAmerican Funding's income tax returns have expired for certain states
through December 31, 2011, and for other states through December 31, 2019, except for the impact of any federal audit adjustments. The closure of examinations, or the expiration of the statute of limitations, for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
i
A reconciliation of the beginning and ending balances of MidAmerican
Funding's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
2023
2022
Beginning balance
$
i16
$
i13
Additions
based on tax positions related to the current year
i10
i15
Interest
i1
i—
Reductions
based on tax positions related to the current year
(i5)
(i12)
Ending
balance
$
i22
$
i16
/
As
of December 31, 2023, MidAmerican Funding had unrecognized tax benefits totaling $i48 million that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect MidAmerican Funding's effective income tax rate.
328
(10)iEmployee
Benefit Plans
Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements for additional information regarding MidAmerican Funding's pension, supplemental retirement and postretirement benefit plans.
i
Pension and postretirement costs allocated by MidAmerican Funding to its parent and other affiliates in each of the years ended December 31, were as follows (in millions):
2023
2022
2021
Pension
costs
$
i14
$
i8
$
i21
Other
postretirement costs
i2
i1
i2
/
(11)iAsset
Retirement Obligations
Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements.
(12)iFair Value Measurements
Refer to Note 12 of MidAmerican Energy's Notes to Financial Statements.
MidAmerican
Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. iThe following table presents the carrying value and estimated fair value of MidAmerican Funding's
long-term debt as of December 31 (in millions):
2023
2022
Carrying
Value
Fair Value
Carrying
Value
Fair
Value
Long-term debt
$
i9,006
$
i8,515
$
i7,969
$
i7,219
(13)iCommitments
and Contingencies
Refer to Note 13 of MidAmerican Energy's Notes to Financial Statements.
Legal Matters
MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
(14) iRevenue
from Contracts with Customers
Refer to Note 14 of MidAmerican Energy's Notes to Financial Statements.
(15)iMember's Equity
In 2023 and 2022, MidAmerican Funding paid $i1,025 million
and $i69 million, respectively, in cash distributions to its parent company, BHE. In February 2024, MidAmerican Funding paid $i425
million in a cash distribution to its parent company, BHE.
329
(16)iOther Income (Expense)
i
Other,
net, as shown on the Consolidated Statements of Operations, includes the following other income (expense) items for the years ended December 31 (in millions):
2023
2022
2021
Corporate-owned
life insurance income (loss)
$
i23
$
(i16)
$
i21
Gains
on sales of assets and other investments
i12
i—
i—
Non-service
cost components of postretirement employee benefit plans
i8
i9
i26
Interest
income and other, net
i5
i7
i7
Total
$
i48
$
i—
$
i54
/
(17)iSupplemental Cash Flow Information
The summary of supplemental cash flow information as of and for the years ending December 31 is as follows (in millions):
2023
2022
2021
Supplemental
disclosure of cash flow information:
Interest paid, net of amounts capitalized
$
i317
$
i309
$
i296
Income
taxes received, net
$
i855
$
i845
$
i751
Supplemental
disclosure of non-cash investing and financing transactions:
Accruals related to property, plant and equipment additions
$
i193
$
i168
$
i257
(18)iRelated
Party Transactions
The companies identified as affiliates of MidAmerican Funding are Berkshire Hathaway and its subsidiaries, including BHE and its subsidiaries. The basis for the following transactions is provided for in-service agreements between MidAmerican Funding and the affiliates.
MidAmerican Funding is reimbursed for charges incurred on behalf of its affiliates. The majority of these reimbursed expenses are for allocated general costs, such as insurance and building rent, and for employee wages, benefits and costs for corporate functions, such as information technology, human resources, treasury, legal and accounting. The amount of such reimbursements was $i94 million,
$i77 million and $i65 million for 2023, 2022 and 2021, respectively.
MidAmerican Funding reimbursed BHE in the amount
of $i123 million, $i79 million and $i72 million
in 2023, 2022 and 2021, respectively, for its share of technology costs, corporate expenses and other costs. Amounts charged to MidAmerican Funding in 2023 and 2022 were primarily reflected in construction work-in-progress on the Consolidated Balance Sheets as of December 31, 2023 and 2022.
MidAmerican Energy purchases, in the normal course of business at either tariffed or market prices, natural gas transportation and storage capacity services from Northern Natural Gas Company, a wholly owned subsidiary of BHE and coal transportation services from BNSF Railway Company, a wholly owned subsidiary of Berkshire Hathaway. These purchases totaled $i141 million,
$i141 million and $i132 million in 2023, 2022 and 2021, respectively.
MidAmerican
Funding had accounts receivable from affiliates of $i10 million and $i10 million as of December 31, 2023 and 2022, respectively, that are included in other current assets on the Consolidated
Balance Sheets. MidAmerican Funding also had accounts payable to affiliates of $i32 million and $i22 million as of December 31, 2023 and 2022, respectively, that are included
in accounts payable on the Consolidated Balance Sheets.
MidAmerican Funding is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated U.S. federal income tax return. For current federal and state income taxes, MidAmerican Funding had a net payable to BHE of $i21 million and a receivable from BHE of $i43 million
as of December 31, 2023 and 2022, respectively. MidAmerican Funding received net cash payments for federal and state income taxes from BHE totaling $i855 million, $i845 million
and $i751 million for the years ended December 31, 2023, 2022 and 2021, respectively.
330
MidAmerican Funding recognizes the full amount of the funded status for its pension and postretirement plans, and amounts
attributable to MidAmerican Funding's affiliates that have not previously been recognized through income are recognized as an intercompany balance with such affiliates. MidAmerican Funding adjusts these balances when changes to the funded status of the respective plans are recognized and does not intend to settle the balances currently. Amounts receivable from affiliates attributable to the funded status of employee benefit plans totaled $i82 million and $i79 million
as of December 31, 2023 and 2022, respectively, and are included in other assets on the Consolidated Balance Sheets. Similar amounts payable to affiliates totaled $i55 million and $i40 million
as of December 31, 2023 and 2022, respectively, and are included in other long-term liabilities on the Consolidated Balance Sheets. See Note 10 for further information pertaining to pension and postretirement accounting.
The indenture pertaining to MidAmerican Funding's long-term debt restricts MidAmerican Funding from paying a distribution on its equity securities, unless after making such distribution either its debt to total capital ratio does not exceed i0.67:1.0
and its interest coverage ratio is not less than i2.2:1.0 or its senior secured long-term debt rating is at least BBB or its equivalent. MidAmerican Funding may seek a release from this restriction upon delivery to the indenture trustee of written confirmation from the ratings agencies that without this restriction MidAmerican Funding's senior secured long-term debt would be rated at least BBB+.
(19)iSegment
Information
MidAmerican Funding has identified itwo reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural
gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the nonregulated subsidiaries of MidAmerican Funding not engaged in the energy business and parent company interest expense. Refer to Note 9 for a discussion of items affecting income tax expense (benefit) for the regulated electric and natural gas operating segments.
i
The
following tables provide information on a reportable segment basis (in millions):
Goodwill
by reportable segment as of December 31, 2023 and 2022, was as follows (in millions):
Regulated electric
$
ii1,191/
Regulated
natural gas
ii79/
Total
$
ii1,270/
/
332
Nevada
Power Company and its subsidiaries
Consolidated Financial Section
333
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors.
This discussion should be read in conjunction with Nevada Power's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K. Nevada Power's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 2023 was $260 million, a decrease of $38 million, or 13%, compared to 2022, primarily due to lower utility margin, higher interest expense, mainly due to higher long-term debt at a higher average interest
rate, higher depreciation and amortization, primarily due to higher plant placed in-service, and higher operations and maintenance expenses. The decrease is partially offset by higher capitalized interest and allowance for equity funds, mainly due to higher construction work-in-progress, favorable interest and dividend income, primarily from carrying charges on regulatory balances, lower income tax expense, mainly due to lower pretax income and the effects of ratemaking, and higher cash surrender value of corporate-owned life insurance policies. Utility margin decreased primarily due to lower retail customer volumes and lower regulatory-related revenue deferrals due to an unfavorable outcome in the 2023 regulatory rate review, partially offset by higher other retail revenue. Retail customer volumes, including distribution only service customers, decreased 2.4% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers.
Operations and maintenance expenses increased primarily due to increased plant operations and maintenance expenses, higher technology costs, higher customer service operations expenses, regulatory disallowances from the 2023 regulatory rate review and higher insurance premiums due to additional wildfire and general excess liability coverage, partially offset by lower earnings sharing. Energy generated increased 5% for 2023 compared to 2022 primarily due to higher natural gas-fueled generation. Wholesale electricity sales volumes decreased 61% and purchased electricity volumes decreased 14%.
Net income for the year ended December 31, 2022 was $298 million, a decrease of $5 million, or 2%, compared to 2021, primarily due to lower cash surrender value of corporate-owned life insurance policies and higher pension expense, higher interest
expense, primarily due to higher long-term debt, higher depreciation and amortization, mainly due to higher plant placed in-service, higher property and other taxes, mainly due to a decrease in the amount of abatements available, higher operations and maintenance expenses, mainly due to higher earnings sharing and higher plant operations and maintenance expenses, partially offset by higher interest and dividend income, primarily from carrying charges on regulatory balances, higher capitalized interest and allowance for funds used during construction from higher construction work-in-progress and higher utility margin. Utility margin increased primarily due to higher regulatory-related revenue deferrals and higher retail customer volumes, partially offset by unfavorable price impacts from changes in sales mix, lower transmission and wholesale revenue and lower other retail revenue. Retail customer volumes, including distribution only service customers, increased1.9% primarily due to an increase in the average number of customers and favorable changes in customer usage, offset by the unfavorable impact of weather. Energy generated decreased 4% for 2022 compared to 2021 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes increased 65% and purchased electricity volumes increased 14%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
Nevada
Power's cost of fuel and energy is generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in Nevada Power's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with
GAAP.
334
The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
2023
2022
Change
2022
2021
Change
Utility
margin:
Operating revenue
$
3,088
$
2,630
$
458
17
%
$
2,630
$
2,139
$
491
23
%
Cost
of fuel and energy
1,942
1,427
515
36
1,427
939
488
52
Utility margin
1,146
1,203
(57)
(5)
1,203
1,200
3
—
Operations
and maintenance
312
303
9
3
303
301
2
1
Depreciation and amortization
432
417
15
4
417
406
11
3
Property
and other taxes
56
53
3
6
53
48
5
10
Operating income
$
346
$
430
$
(84)
(20)
%
$
430
$
445
$
(15)
(3)
%
335
Utility
Margin
A comparison of key operating results related to utility margin is as follows for the years ended December 31:
2023
2022
Change
2022
2021
Change
Utility
margin (in millions):
Operating revenue
$
3,088
$
2,630
$
458
17
%
$
2,630
$
2,139
$
491
23
%
Cost
of fuel and energy
1,942
1,427
515
36
1,427
939
488
52
Utility margin
$
1,146
$
1,203
$
(57)
(5)
%
$
1,203
$
1,200
$
3
—
%
Sales
(GWhs):
Residential
9,584
10,299
(715)
(7)
%
10,299
10,415
(116)
(1)
%
Commercial
4,807
4,904
(97)
(2)
4,904
4,838
66
1
Industrial
5,827
5,630
197
3
5,630
5,270
360
7
Other
179
191
(12)
(6)
191
198
(7)
(4)
Total
fully bundled(1)
20,397
21,024
(627)
(3)
21,024
20,721
303
1
Distribution only service
2,831
2,786
45
2
2,786
2,646
140
5
Total
retail
23,228
23,810
(582)
(2)
23,810
23,367
443
2
Wholesale
230
586
(356)
(61)
586
356
230
65
Total
GWhs sold
23,458
24,396
(938)
(4)
%
24,396
23,723
673
3
%
Average
number of retail customers (in thousands)
1,015
1,001
14
1
%
1,001
985
16
2
%
Average
revenue per MWh:
Retail - fully bundled(1)
$
147.38
$
120.21
$
27.17
23
%
$
120.21
$
98.62
$
21.59
22
%
Wholesale
$
62.73
$
61.83
$
0.90
1
%
$
61.83
$
60.69
$
1.14
2
%
Heating
degree days
1,962
1,904
58
3
%
1,904
1,613
291
18
%
Cooling degree days
3,651
4,016
(365)
(9)
%
4,016
4,109
(93)
(2)
%
Sources
of energy (GWhs)(2)(3):
Natural gas
13,719
13,068
651
5
%
13,068
13,655
(587)
(4)
%
Renewables
66
69
(3)
(4)
69
65
4
6
Total
energy generated
13,785
13,137
648
5
13,137
13,720
(583)
(4)
Energy purchased
7,606
8,830
(1,224)
(14)
8,830
7,778
1,052
14
Total
21,391
21,967
(576)
(3)
%
21,967
21,498
469
2
%
Average
cost of energy per MWh(2)(4):
Energy generated
$
65.25
$
49.82
$
15.42
31
%
$
49.82
$
24.41
$
25.41
104
%
Energy
purchased
$
137.08
$
87.49
$
49.59
57
%
$
87.49
$
77.64
$
9.85
13
%
(1) Fully
bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The average cost of energy per MWh and sources of energy excludes 846, 1,113 and 1,389 GWhs of natural gas generated energy that is purchased at cost by related parties for the years ended December 31, 2023, 2022 and 2021, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
Utility margin decreased $57 million, or 5%, for 2023 compared to 2022 primarily due to:
•$44 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 2.4% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and
•$31 million of lower regulatory-related revenue deferrals due to an unfavorable outcome in the 2023 regulatory rate review.
The
decrease in utility margin was partially offset by:
•$11 million of higher energy efficiency program rates (offset in operations and maintenance expense) and
•$5 million of higher other retail revenue.
Operations and maintenance increased $9 million, or 3%, for 2023 compared to 2022 primarily due to higher energy efficiency program costs (offset in operating revenue), increased plant operations and maintenance expenses, higher technology costs, higher customer service operations expenses, regulatory disallowances from the 2023 regulatory rate review and higher insurance premiums due to additional wildfire and general excess liability coverage, partially offset by lower earnings sharing.
Depreciation
and amortization increased $15 million, or 4%, for 2023 compared to 2022 primarily due to higher plant placed in-service.
Property and other taxes increased $3 million, or 6%, for 2023 compared to 2022 primarily due to a decrease in the amount of abatements available and an increase in commerce and franchise tax from higher revenue.
Interest expense increased $31 million, or 19%, for 2023 compared to 2022 primarily due to higher long-term debt and higher average interest rate.
Capitalized interest increased $17 million for 2023 compared to 2022 primarily due to higher construction work-in-progress.
Allowance
for equity funds increased $10 million, or 91%, for 2023 compared to 2022 primarily due to higher construction work-in-progress.
Interest and dividend income increased $25 million, or 53%, for 2023 compared to 2022 primarily due to favorable interest income, mainly from carrying charges on regulatory balances.
Other, net increased $11 million for 2023 compared to 2022 primarily due to favorable cash surrender value of corporate-owned life insurance policies.
Income tax expense decreased $14 million, or 39%, for 2023 compared to 2022 primarily due to lower pretax income and the effects of ratemaking. The effective tax rate was 8% in 2023
and 11% in 2022.
Utility margin increased $3 million for 2022 compared to 2021 primarily due to:
•$11 million of higher regulatory-related revenue deferrals and
•$4 million of higher electric retail utility margin due to higher retail customer volumes, offset by unfavorable price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 1.9% primarily due to an increase in the average number of
customers and favorable changes in customer usage, offset by the unfavorable impact of weather.
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The increase in utility margin was partially offset by:
•$6 million of lower energy efficiency program rates (offset in operations and maintenance expense);
•$3 million of lower transmission and wholesale revenue; and;
•$3 million due to lower other retail revenue.
Operations and maintenance increased $2 million, or 1%, for 2022 compared to 2021 primarily due to higher earnings sharing and higher plant
operations and maintenance expenses, partially offset by lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $11 million, or 3%, for 2022 compared to 2021 primarily due to higher plant placed in-service.
Property and other taxes increased $5 million, or 10%, for 2022 compared to 2021 primarily due to a decrease in the amount of abatements available.
Interest expense increased $12 million, or 8% for 2022 compared to 2021 primarily due to higher long-term debt.
Capitalized interest increased
$5 million for 2022 compared to 2021 primarily due to higher construction work-in-progress.
Allowance for equity funds increased $4 million, or 57%, for 2022 compared to 2021 primarily due to higher construction work-in-progress.
Interest and dividend income increased $27 million for 2022 compared to 2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net decreased $15 million, or 83%, for 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies and higher pension expense.
Liquidity
and Capital Resources
As of December 31, 2023, Nevada Power's total net liquidity was $620 million as follows (in millions):
Cash and cash equivalents
$
20
Credit facilities(1)
600
Total
net liquidity
$
620
Credit facilities:
Maturity dates
2026
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Nevada Power's credit facility.
Operating Activities
Net cash flows
from operating activities for the years ended December 31, 2023 and 2022 were $761 million and $355 million, respectively. The change was primarily due to higher collections from customers, increased customer and vendor deposits and higher income tax refunds, partially offset by the timing of payments for operating costs, higher payments related to fuel and energy costs and higher interest payments.
Net cash flows from operating activities for the years ended December 31, 2022 and 2021 were $355 million and $505 million, respectively. The change was primarily due to higher payments related to fuel and energy costs and the timing of payments for operating costs, partially offset by higher
collections from customers and lower payments for income taxes.
The timing of Nevada Power's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
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Investing Activities
Net cash flows from investing activities for the years ended December 31, 2023 and 2022 were $(1,309) million and $(862) million, respectively. The change was primarily due
to increased capital expenditures, offset by proceeds from an affiliate note receivable. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net cash flows from investing activities for the years ended December 31, 2022 and 2021 were $(862) million and $(447) million, respectively. The change was primarily due to increased capital expenditures and the issuance of an affiliate note receivable. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the years ended December 31,
2023 and 2022 were $525 million and $522 million, respectively. The change was primarily due to higher contributions from NV Energy, Inc. and lower repayments of short-term debt, partially offset by higher repayments of long-term debt, lower proceeds from the issuance of long-term debt and higher dividends paid to NV Energy, Inc.
Net cash flows from financing activities for the years ended December 31, 2022 and 2021 were $522 million and $(49) million, respectively. The change was primarily due to higher proceeds from the issuance of long-term debt, lower dividends paid to NV Energy, Inc. and higher contributions from NV Energy, Inc., partially offset by higher repayments of short-term debt.
In
February 2024, Nevada Power received a contribution from NV Energy, Inc. of $50 million.
Ability to Issue Debt
Nevada Power currently has an effective shelf registration statement with the SEC to issue an additional $2.1 billion of general and refunding mortgage securities through November 1, 2025. Additionally, Nevada Power's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2023, Nevada Power has financing authority from the PUCN consisting of the ability to issue long-term and short-term debt securities so long as the total amount of debt outstanding (excluding borrowings under Nevada Power's $600 million secured credit facility) does not exceed $3.8 billion and to issue
common and preferred stock so long as the total amounts outstanding do not exceed $4.1 billion and $800 million, respectively, as measured at the end of each calendar quarter. Nevada Power's revolving credit facility contains a financial maintenance covenant which Nevada Power was in compliance with as of December 31, 2023. In addition, certain financing agreements contain covenants which are currently suspended as Nevada Power's senior secured debt is rated investment grade. However, if Nevada Power's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, Nevada Power would be subject to limitations under these covenants.
Ability to Issue General and Refunding Mortgage Securities
To the extent Nevada Power has the
ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Nevada Power's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Nevada Power's indenture.
Nevada Power's indenture creates a lien on substantially all of Nevada Power's properties in Nevada. As of December 31, 2023, $10.3 billion of Nevada Power's assets were pledged. Nevada Power had the capacity to issue $3.2 billion of additional general and refunding mortgage securities as of December 31, 2023, determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity
listed above does not include eligible property in construction work-in-progress. Nevada Power also has the ability to release property from the lien of Nevada Power's indenture on the basis of net property additions, cash or retired bonds. To the extent Nevada Power releases property from the lien of Nevada Power's indenture, it will reduce the amount of securities issuable under the indenture.
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Future Uses of Cash
Nevada Power has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of secured revolving credit facilities,
capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including Nevada Power's credit ratings, investors' judgment of risk associated with Nevada Power and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business
conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
Historical
Forecast
2021
2022
2023
2024
2025
2026
Electric
distribution
$
184
$
236
$
352
$
316
$
282
$
294
Electric transmission
57
110
124
237
469
556
Solar
generation
8
85
188
58
195
332
Electric battery storage
—
8
338
183
189
592
Other
200
323
407
372
162
241
Total
$
449
$
762
$
1,409
$
1,166
$
1,297
$
2,015
Nevada
Power received or is seeking PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission and has included estimates from its IRP filings as well as potential future filings in its forecast capital expenditures for 2024 through 2026. These estimates are likely to change as a result of the RFP process, continued evaluation and future IRP filing refinements. Nevada Power's historical and forecast capital expenditures include the following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities'
Greenlink Nevada transmission expansion program. The Nevada Utilities have received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation, near Yerington, Nevada to the Northwest substation, near Las Vegas, Nevada to the Harry Allen substation, near Las Vegas, Nevada; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Mira Loma substations, near Yerington, Nevada; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Solar
generation includes two growth projects and other planned solar generating facilities. The first growth project consists of a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by early 2024. The second growth project, pending PUCN approval, consists of a 400-MW solar photovoltaic facility with an additional 400-MW of co-located battery storage that would be developed in Churchill County, Nevada with ownership share between Nevada Power and Sierra Pacific to be approved by the PUCN. Commercial operation of the solar is expected by early 2027.
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•Electric battery storage includes three growth projects and other planned electric
battery storage systems. The first project consists of a 220-MW grid-tied battery energy storage system that was developed on the site of the retired Reid Gardner generating station in Clark County, Nevada. Commercial operation was reached in December of 2023. The second growth project consists of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada. Commercial operation is expected by early 2024. The third growth project, pending PUCN approval, consists of a 400-MW battery energy storage system co-located with a 400MW solar photovoltaic facility that would be developed in Churchill County, Nevada with ownership share between Nevada Power and Sierra Pacific to be approved by the PUCN. Commercial operation of the battery energy storage system is expected by early 2026.
•Other includes both growth projects and operating
expenditures. Growth projects primarily consist of an additional 444 MW of peaking combustion turbines that were approved by the PUCN and are under development at the Silverhawk generating facility in Clark County, Nevada. Commercial operation is expected by the third quarter of 2024. Operating expenditures consist of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
2021 Joint Integrated Resource Plan
In August 2023, the Nevada Utilities filed its Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part (1) to convert the existing coal fueled plant at North Valmy Generating Station to a cleaner
natural gas fueled plant (2) to construct a company-owned 400 MW solar plant along with a 400 MW, four-hour battery storage system in Northern Nevada; (3) to continue operation of Tracy units 4 and 5 to 2049; (4) to purchase development assets for a 149 MW photovoltaic and 149 MW battery energy storage system known as the Crescent Valley Solar project; (5) to construct the Esmeralda and Amargosa substations transformers; and (6) to construct the necessary infrastructure in the Apex Area Master Plan. The Nevada Utilities seek approval of approximately $1.8 billion in total costs of new projects of which Nevada Power's share is approximately $1.0 billion with an order expected in 2024.
Material Cash Requirements
Nevada
Power has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Notes 7 and 8), operating and financing leases (refer to Note 5), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7 and Note 14) and AROs (refer to Note 11). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Nevada Power has cash requirements relating to interest payments of $3.2 billion on long-term debt, including $168 million due in 2024.
Regulatory
Matters
Nevada Power is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding Nevada Power's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations,
these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
341
Collateral
and Contingent Features
Debt of Nevada Power is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Nevada Power's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Nevada Power has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Nevada Power's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates
under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event
of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2023, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2023, Nevada Power would have been required to post $68 million of additional collateral. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically,
overall inflation and changing prices in the economies where Nevada Power operates has not had a significant impact on Nevada Power's consolidated financial results. Nevada Power operates under a cost-of-service based rate-setting structure administered by the PUCN and the FERC. Under this rate-setting structure, Nevada Power is allowed to include prudent costs in its rates, including the impact of inflation after Nevada Power experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Nevada Power attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending
programs and long-term debt issuances. There can be no assurance that such actions will be successful.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting Nevada Power, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make
estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Nevada Power's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Nevada Power's Summary of Significant Accounting Policies included in Nevada Power's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Nevada
Power prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
342
Nevada Power continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable
of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Nevada Power's ability to recover its costs. Nevada Power believes its application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as AOCI. Total regulatory assets were $1.1 billion and total regulatory liabilities were $1.1 billion as of December 31,
2023. Refer to Nevada Power's Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's regulatory assets and liabilities.
Impairment of Long-Lived Assets
Nevada Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds
the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of an asset, for the purposes of impairment analysis, requires the exercise of judgment. Circumstances that could significantly alter the calculation of fair value or the recoverable amount of an asset may include significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset, the physical condition of the asset, future market prices, load growth, competition and many other factors
over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Nevada Power's results of operations.
Income Taxes
In determining Nevada Power's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Nevada Power's various regulatory commissions. Nevada Power's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Nevada Power recognizes the tax benefit from
an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Nevada Power's federal, state and local income tax examinations is uncertain, Nevada Power believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations is not expected to have a material impact on Nevada Power's consolidated financial results. Refer to Nevada Power's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's income taxes.
It
is probable that Nevada Power will pass income tax benefit and expense related to the 2017 federal tax rate change from 35% to 21%, certain property related basis differences and other various differences on to its customers. As of December 31, 2023, these amounts were recognized as a net regulatory liability of $525 million and will be included in regulated rates when the temporary differences reverse.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Nevada Power's Consolidated
Balance Sheets include assets and liabilities with fair values that are subject to market risks. Nevada Power's significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Nevada Power transacts. The following discussion addresses the significant market risks associated with Nevada Power's business activities. Nevada Power has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Nevada Power's contracts accounted for as derivatives.
Commodity Price Risk
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity and natural gas
market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative
contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Nevada Power's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
The table that follows summarizes Nevada Power's price risk on commodity contracts accounted for as derivatives and shows the effects of a hypothetical 10% increase and 10% decrease
in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worse case scenarios (dollars in millions).
Nevada Power's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and therefore, net unrealized gains and losses associated with interim
price movements on commodity derivative contracts do not expose Nevada Power to earnings volatility. As of December 31, 2023 and 2022, a net regulatory asset of $68 million and $52 million, respectively, was recorded related to the net derivative liability of $68 million and $52 million, respectively. The settled cost of these commodity derivative contracts is generally included in regulated rates.
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Interest Rate Risk
Nevada Power is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances.
Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Nevada Power's fixed-rate long-term debt does not expose Nevada Power to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Nevada Power were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Nevada Power's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Nevada
Power's short- and long-term debt.
As of December 31, 2023 and 2022, Nevada Power had short- and long-term variable-rate obligations totaling $— million and $300 million, respectively, that expose Nevada Power to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Nevada Power's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2023 and 2022.
Credit Risk
Nevada
Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required,
Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As of December 31, 2023, Nevada Power's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.
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Item 8. Financial Statements and Supplementary Data
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Nevada Power Company and subsidiaries ("Nevada Power") as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial
statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Nevada Power as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Nevada Power's management. Our responsibility is to express an opinion on Nevada Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United
States) (PCAOB) and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Nevada Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Nevada Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures
that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Note 6 to the financial statements
Critical Audit Matter Description
Nevada Power is subject to rate regulation by a state public service commission as well as the Federal Energy Regulatory Commission (collectively,
the "Commissions"), which have jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where Nevada Power operates. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation has a pervasive effect on the financial statements.
347
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed
to allow Nevada Power an opportunity to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an effect on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While Nevada Power Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit Nevada Power's ability to recover its costs.
We identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory
orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated Nevada Power's disclosures related to the effects of rate regulation by testing recorded balances and
evaluating regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes filings made by Nevada Power and interveners, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected Nevada Power's filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to
identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i432
i417
i406
Allowance
for equity funds
(i21)
(i11)
(i7)
Deferred
energy
i14
(i541)
(i245)
Amortization
of deferred energy
i40
i160
i11
Other
changes in regulatory assets and liabilities
(i13)
(i15)
(i19)
Deferred
income taxes and amortization of investment tax credits
i26
i49
i—
Other,
net
(i1)
i8
i—
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i3)
(i178)
i6
Inventories
(i36)
(i29)
i5
Accrued
property, income and other taxes
i39
i21
(i18)
Accounts
payable and other liabilities
i24
i176
i63
Net
cash flows from operating activities
i761
i355
i505
Cash
flows from investing activities:
Capital expenditures
(i1,409)
(i762)
(i449)
Net
proceeds from (issuance of) affiliate note receivable
i100
(i100)
i—
Other,
net
i—
i—
i2
Net
cash flows from investing activities
(i1,309)
(i862)
(i447)
Cash
flows from financing activities:
Proceeds from long-term debt
i494
i694
i—
Repayments
of long-term debt
(i300)
i—
i—
Net
(repayments of) proceeds from short-term debt
i—
(i180)
i180
Dividends
paid
(i50)
i—
(i213)
Contributions
from parent
i400
i25
i—
Other,
net
(i19)
(i17)
(i16)
Net
cash flows from financing activities
i525
i522
(i49)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i23)
i15
i9
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i60
i45
i36
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i37
$
i60
$
i45
The
accompanying notes are an integral part of these consolidated financial statements.
352
NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) iOrganization
and Operations
Nevada Power Company and its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a U.S. regulated electric utility company serving retail customers, including residential, commercial and industrial customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) iSummary
of Significant Accounting Policies
i
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of Nevada Power and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2023, 2022
and 2021.
i
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects
of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
i
Accounting for the Effects of Certain Types of Regulation
Nevada Power prepares its Consolidated
Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Nevada Power defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
i
Fair
Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair
value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
353
i
Cash and Cash Equivalents and Restricted Cash
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills
and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist of funds restricted by the PUCN for a certain renewable energy contract. iA reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2023 and December 31, 2022, as presented on the Consolidated
Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Restricted
cash and cash equivalents included in other current assets
i17
i17
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i37
$
i60
i
Allowance
for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Nevada Power's assessment of the collectability of amounts owed to Nevada Power by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Nevada Power primarily utilizes credit loss history. However, Nevada Power may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. Nevada Power also has the ability to assess deposits on customers who have delayed
payments or who are deemed to be a credit risk. iThe changes in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
2023
2022
2021
Beginning
balance
$
i20
$
i18
$
i19
Charged
to operating costs and expenses, net
i18
i14
i13
Write-offs,
net
(i18)
(i12)
(i14)
Ending
balance
$
i20
$
i20
$
i18
i
Derivatives
Nevada Power employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases
or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity on the Consolidated Statements of Operations.
For Nevada Power's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
354
i
Inventories
Inventories
consist mainly of materials and supplies totaling $i129 million and $i93 million as of December 31, 2023 and 2022. The cost is determined
using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used.
/
i
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded
at cost. Nevada Power capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the Public Utilities Commission of Nevada ("PUCN").
Depreciation and amortization are generally computed by applying the composite or straight-line method
based on either estimated useful lives or mandated recovery periods as prescribed by Nevada Power's various regulatory authorities. Depreciation studies are completed by Nevada Power to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.
Generally when Nevada Power retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from
the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Nevada Power is permitted to earn a return on these costs as a component
of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Nevada Power's AFUDC rate used during 2023 and 2022 was i6.95% and i6.55%,
respectively.
i
Asset Retirement Obligations
Nevada Power recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Nevada Power's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated
over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.
355
i
Impairment
Nevada
Power evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
i
Leases
Nevada
Power has non-cancelable operating leases primarily for land, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities, office space and vehicles. These leases generally require Nevada Power to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Nevada Power does not include options in its lease calculations unless there is a triggering event indicating Nevada Power is reasonably certain to exercise the option. Nevada Power's
accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Nevada Power's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are
primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
Nevada Power's operating and right-of-use assets are recorded in other assets and the operating lease liabilities are recorded in current and long-term other liabilities accordingly.
i
Revenue Recognition
Nevada Power uses a single five-step model to identify and recognize
revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Nevada Power expects to be entitled in exchange for those goods or services. Nevada Power records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of Nevada Power's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of amounts not
considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers" and revenue recognized in accordance with ASC 842, "Leases."
Revenue recognized is equal to what Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power's performance to date and includes billed and unbilled amounts. As of December 31, 2023 and 2022, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $i151
million and $i143 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In addition, Nevada Power has recognized contract
assets of $i3 million and $i4 million as of December 31, 2023 and 2022, respectively, due to Nevada Power's performance on certain contracts.
356
i
Unamortized
Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
i
Income Taxes
Berkshire Hathaway includes Nevada Power in its consolidated U.S. federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for income taxes has been computed on a stand-alone basis.
Deferred
income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with certain property‑related basis differences and other various differences that Nevada Power deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted
income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Investment tax credits are deferred and amortized over the estimated useful lives of the related properties.
Nevada Power recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement.
Nevada Power's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
i
Segment Information
Nevada Power currently has ione
segment, which includes its regulated electric utility operations.
/
i
New Accounting Pronouncements
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating
decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to
Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
357
(3) iProperty,
Plant and Equipment, Net
i
Property, plant and equipment, net consists of the following as of December 31 (in millions):
Depreciable Life
2023
2022
Utility
plant:
Generation
i30 - i55
years
$
i4,476
$
i3,977
Transmission
i45
- i70 years
i1,590
i1,562
Distribution
i20
- i65 years
i4,451
i4,134
General
and intangible plant
i5 - i65 years
i906
i871
i11,423
i10,544
Accumulated
depreciation and amortization
(i3,856)
(i3,624)
Utility
plant, net
i7,567
i6,920
Nonregulated,
net of accumulated depreciation and amortization
i45 years
i1
i1
i7,568
i6,921
Construction
work-in-progress
i1,090
i485
Property,
plant and equipment, net
$
i8,658
$
i7,406
/
Almost
all of Nevada Power's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Nevada Power's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2023, 2022 and 2021 was i3.1%, i3.1%,
and i3.2%, respectively. Nevada Power is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings. The most recent study was filed in 2023.
Construction work-in-progress is primarily related to the construction of regulated assets.
(4) iJointly
Owned Utility Facilities
Under joint facility ownership agreements, Nevada Power, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Nevada Power accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Nevada Power's share of the expenses of these facilities.
i
The
amounts shown in the table below represent Nevada Power's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2023 (dollars in millions):
Nevada
Construction
Power's
Utility
Accumulated
Work-in-
Share
Plant
Depreciation
Progress
Navajo
Generating Station(1)
i11
%
$
i—
$
i2
$
i—
ON
Line Transmission Line
i19
i129
i28
i1
Other
transmission facilities
Various
i60
i28
i1
Total
$
i189
$
i58
$
i2
(1)Represents
Nevada Power's proportionate share of capitalized asset retirement costs to retire the Navajo Generating Station, which was shut down in November 2019.
/
358
(5) iiLeases/
i
The
following table summarizes Nevada Power's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
2023
2022
Right-of-use assets:
Operating leases
$
i7
$
i9
Finance
leases
i289
i303
Total right-of-use assets
$
i296
$
i312
Lease
liabilities:
Operating leases
$
i9
$
i11
Finance
leases
i298
i313
Total lease liabilities
$
i307
$
i324
/
i
The
following table summarizes Nevada Power's lease costs for the years ended December 31 (in millions):
2023
2022
2021
Variable
$
i264
$
i369
$
i449
Operating
i2
i2
i2
Finance:
Amortization
i15
i14
i13
Interest
i26
i27
i28
Total
lease costs
$
i307
$
i412
$
i492
Weighted-average
remaining lease term (years):
Operating leases
i3.7
i4.8
i5.7
Finance
leases
i28.2
i29.1
i28.7
Weighted-average
discount rate:
Operating leases
i4.5
%
i4.5
%
i4.5
%
Finance
leases
i8.6
%
i8.6
%
i8.6
%
/
i
The
following table summarizes Nevada Power's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
2023
2022
2021
Cash
paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
$
(i3)
$
(i3)
$
(i3)
Operating
cash flows from finance leases
(i26)
(i28)
(i29)
Financing
cash flows from finance leases
(i18)
(i17)
(i16)
Right-of-use
assets obtained in exchange for lease liabilities:
Operating leases
$
i1
$
i—
$
i—
Finance
leases
i4
i3
i1
/
359
i
Nevada
Power has the following remaining lease commitments as of December 31, 2023 (in millions):
Operating
Finance
Total
2024
$
i3
$
i45
$
i48
2025
i3
i44
i47
2026
i3
i44
i47
2027
i2
i42
i44
2028
i—
i39
i39
Thereafter
i—
i377
i377
Total
undiscounted lease payments
i11
i591
i602
Less
- amounts representing interest
(i2)
(i293)
(i295)
Lease
liabilities
$
i9
$
i298
$
i307
/
Operating
and Finance Lease Obligations
Nevada Power's lease obligation primarily consists of a transmission line, One Nevada Transmission Line ("ON Line"), which was placed in-service on December 31, 2013. Nevada Power and Sierra Pacific, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a i25% interest and Great Basin Transmission South, LLC has a i75%
interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at i75% for Nevada Power and i25% for Sierra Pacific. The term of the lease is i41
years with the agreement ending December 31, 2054. Total ON Line finance lease obligations of $i264 million and $i276 million were included on the Consolidated Balance Sheets as of December 31, 2023 and 2022,
respectively. See Note 2 for further discussion of Nevada Power's other lease obligations.
(6) iRegulatory Matters
Regulatory Assets
i
Regulatory
assets represent costs that are expected to be recovered in future rates. Nevada Power's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Deferred energy costs
i1 year
$
i575
$
i654
Merger
costs from 1999 merger
i21 years
i100
i105
Asset
retirement obligations
i7 years
i69
i69
Unrealized
loss on regulated derivative contracts
i1 year
i68
i75
Decommissioning
costs
i3 years
i56
i116
Deferred
operating costs
i18 years
i41
i67
Other
Various
i176
i208
Total
regulatory assets
$
i1,085
$
i1,294
Reflected
as:
Current assets
$
i586
$
i666
Noncurrent
assets
i499
i628
Total regulatory assets
$
i1,085
$
i1,294
/
Nevada
Power had regulatory assets not earning a return on investment of $i299 million and $i320 million
as of December 31, 2023 and 2022, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, AROs, unrealized losses on regulated derivative contracts, deferred operating costs, losses on reacquired debt and a portion of the employee benefit plans
360
Regulatory Liabilities
i
Regulatory
liabilities represent amounts that are expected to be returned to customers in future periods. Nevada Power's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Deferred income taxes(1)
Various
$
i525
$
i560
Cost
of removal(2)
i30 years
i368
i358
Earning
sharing mechanism
i3 years
i115
i114
Other
Various
i52
i106
Total
regulatory liabilities
$
i1,060
$
i1,138
Reflected
as:
Current liabilities
$
i43
$
i45
Noncurrent
liabilities
i1,017
i1,093
Total
regulatory liabilities
$
i1,060
$
i1,138
(1)Amounts
primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
/
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
Deferred Energy
Nevada statutes
permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates
and recorded as cost of fuel, energy and capacity in future time periods.
Regulatory Rate Review
In June 2023, Nevada Power filed a regulatory rate review with the PUCN that requested an annual revenue increase of $i93 million, or i3.3%.
In addition, a filing was made to revise depreciation rates based on a study, the results of which are reflected in the proposed revenue requirement. In August, 2023, Nevada Power filed an updated certification filing that requested an annual revenue increase of $i96 million, or i3.3%.
Parties to the review filed testimony and evidence in August and September 2023. Hearings in the cost of capital, revenue requirement and rate design phases were held in October and November 2023. In December 2023, the PUCN issued an order approving an increase in base rates of $i37 million, effective January 1, 2024, reflecting a reduction in Nevada Power's requested rate of return and updated depreciation and amortization rates for its electric operations. In January 2024, Nevada Power filed a petition for reconsideration
and clarification of the order. In February of 2024, the PUCN issued a final order approving in part and denying in part the petition for reconsideration.
361
(7)iShort-term Debt and Credit Facilities
Nevada
Power has a $i600 million secured credit facility expiring in June 2026 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which is for general corporate purposes and provide for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate ("SOFR") or a base rate, at Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long‑term debt securities. As of December 31,
2023 and 2022, Nevada Power had iino/ borrowings outstanding under the credit facility. Amounts due under Nevada Power's credit
facility are collateralized by Nevada Power's general and refunding mortgage bonds. The credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not exceed i0.65 to 1.0 as of the last day of each quarter.
As of December 31, 2023, Nevada Power had $i50 million
of letter of credit capacity under its $i600 million secured credit facility, of which ino amount was outstanding.
As of
December 31, 2022, Nevada Power had $i100 million of letter of credit capacity under its $i400 million secured credit facility,
of which ino amount was outstanding.
(8) iLong-term Debt
i
Nevada
Power's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par Value
2023
2022
General and refunding mortgage securities:
i3.700%
Series CC, due 2029
$
i500
$
i498
$
i497
i2.400%
Series DD, due 2030
i425
i423
i422
i6.650%
Series N, due 2036
i367
i360
i360
i6.750%
Series R, due 2037
i349
i346
i346
i5.375%
Series X, due 2040
i250
i248
i248
i5.450%
Series Y, due 2041
i250
i240
i239
i3.125%
Series EE, due 2050
i300
i298
i298
5.900%
Series GG, due 2053
i400
i394
i394
i6.000%
Series 2023A, due 2054
i500
i494
i—
Tax-exempt
refunding revenue bond obligations:
Fixed-rate series:
i4.125% Pollution Control Bonds Series 2017A, due 2032(1)
i40
i39
i39
i3.750%
Pollution Control Bonds Series 2017, due 2036(1)
i40
i39
i39
i3.750%
Pollution Control Bonds Series 2017B, due 2039(1)
i13
i13
i13
Variable-rate
i4.821% Term Loan, due 2024(2)
i—
i—
i300
Total
long-term debt
$
i3,434
$
i3,392
$
i3,195
Reflected
as:
Total long-term debt
$
i3,392
$
i3,195
(1)Subject
to mandatory purchase by Nevada Power in March 2026 at which date the interest rate may be adjusted.
(2)Amounts borrowed under the facility bear interest at variable rates based on SOFR or a base rate, at Nevada Power's option, plus a pricing margin.
/
Annual Payment on Long-Term Debt
i
The
annual repayments of long-term debt for the years beginning January 1, 2024 and thereafter, are as follows (in millions):
2029
and thereafter
$
i3,434
Total
i3,434
Unamortized
premium, discount and debt issuance cost
(i42)
Total
$
i3,392
/
362
The
issuance of General and Refunding Mortgage Securities by Nevada Power is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2023, approximately $i10.3 billion (based on original cost) of Nevada Power's property was subject to the liens of the mortgages.
(9) iIncome
Taxes
i
Income tax expense consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Current
– Federal
$
(i4)
$
(i13)
$
i37
Deferred
– Federal
(i74)
i49
i—
Investment
tax credits
i100
i—
i—
Total
income tax expense
$
i22
$
i36
$
i37
/
i
A
reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
2023
2022
2021
Federal
statutory income tax rate
i21
%
i21
%
i21
%
Effects
of ratemaking
(i13)
(i11)
(i11)
Other
i—
i1
i1
Effective
income tax rate
i8
%
i11
%
i11
%
/
i
The
net deferred income tax liability consists of the following as of December 31 (in millions):
2023
2022
Deferred income tax assets:
Regulatory liabilities
$
i195
$
i186
Operating
and finance leases
i66
i68
Customer advances
i38
i27
Unamortized
contract value
i14
i20
Other
i9
i9
Total
deferred income tax assets
i322
i310
Deferred
income tax liabilities:
Property-related items
(i828)
(i821)
Regulatory
assets
(i245)
(i273)
Operating and finance leases
(i62)
(i65)
Other
(i23)
(i26)
Total
deferred income tax liabilities
(i1,158)
(i1,185)
Net
deferred income tax liability
$
(i836)
$
(i875)
/
The
U.S. Internal Revenue Service has closed or effectively settled its examination of Nevada Power's income tax return through the short year ended December 31, 2013. The closure of examinations, or the expiration of the statute of limitations, may not preclude the U.S. Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
363
(10) iEmployee
Benefit Plans
Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Nevada Power did iiinot//
make any contributions to the Qualified Pension Plan for the years ended December 31, 2023, 2022 and 2021. Nevada Power contributed $iii1//
million to the Non-Qualified Pension Plans for the years ended December 31, 2023, 2022 and 2021. Nevada Power did iiinot//
make any contributions to the Other Postretirement Plans for the years ended December 31, 2023, 2022 and 2021. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
i
Amounts
receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31 (in millions):
2023
2022
Qualified Pension Plan -
Other non-current assets
$
i38
$
i27
Non-Qualified
Pension Plans:
Other current liabilities
(i1)
(i1)
Other
long-term liabilities
(i6)
(i6)
Other
Postretirement Plans -
Other non-current assets
i10
i7
/
(11) iAsset
Retirement Obligations
Nevada Power estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Nevada Power does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized
on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $i368 million and $i358 million as of December 31,
2023 and 2022, respectively.
i
The following table presents Nevada Power's ARO liabilities by asset type as of December 31 (in millions):
2023
2022
Waste
water remediation
$
i33
$
i31
Evaporative ponds
and dry ash landfills
i12
i14
Solar-powered
generating facilities
i6
i3
Other
i11
i11
Total
asset retirement obligations
$
i62
$
i59
/
364
i
The
following table reconciles the beginning and ending balances of Nevada Power's ARO liabilities for the years ended December 31 (in millions):
2023
2022
Beginning balance
$
i59
$
i68
Change
in estimated costs
i6
i5
Additions
i3
i—
Retirements
(i9)
(i16)
Accretion
i3
i2
Ending
balance
$
i62
$
i59
Reflected
as:
Other current liabilities
$
i9
$
i16
Other
long-term liabilities
i53
i43
$
i62
$
i59
/
In
2008, Nevada Power signed an administrative order of consent as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. Based on the administrative order of consent, Nevada Power recorded estimated AROs and capital remediation costs. However, actual costs of work under the administrative order of consent may vary significantly once the scope of work is defined and additional site characterization has been completed. In connection with the termination of the co-ownership arrangement, effective October 22, 2013, between Nevada Power and California Department of Water Resources ("CDWR") for the Reid Gardner Generating Station Unit No. 4, Nevada Power and CDWR entered into a cost-sharing agreement that sets forth how the parties will jointly share in costs associated with all investigation, characterization and, if necessary, remedial activities
as required under the administrative order of consent.
Certain of Nevada Power's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Nevada Power is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Management has identified legal obligations to retire generation plant assets specified in land leases for Nevada Power's jointly-owned Navajo Generating Station, retired in November 2019, and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Nevada Power's estimated share of the
decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
(12)iRisk Management and Hedging Activities
Nevada Power is exposed to the impact of market fluctuations in commodity
prices and interest rates. Nevada Power is principally exposed to electricity and natural gas market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and
interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
365
i
The
following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
(1)Nevada
Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of December 31, 2023 and 2022, a regulatory asset of $i68 million and $i52 million,
respectively, was recorded related to the net derivative liability of $i68 million and $i52
million, respectively.
/
Derivative Contract Volumes
i
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
Unit of
Measure
2023
2022
Electricity purchases
Megawatt
hours
i1
i2
Natural gas purchases
Decatherms
i132
i109
/
Credit
Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting
agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels "credit-risk-related contingent features") or provide the right for
counterparties to demand "adequate assurance" if there is a material adverse change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2023, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
366
The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $i7
million and $i5 million as of December 31, 2023 and 2022, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(13) iFair
Value Measurements
The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement
date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.
i
The
following table presents Nevada Power's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Nevada
Power's investments in money market mutual funds and investment funds are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices
at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities,
which as of December 31, 2023, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.
i
The following table reconciles the beginning and ending balances of Nevada Power's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3
inputs for the years ended December 31 (in millions):
2023
2022
2021
Beginning balance
$
(i52)
$
(i113)
$
i15
Changes
in fair value recognized in regulatory assets or liabilities
(i166)
(i68)
(i90)
Settlements
i150
i129
(i38)
Ending
balance
$
(i68)
$
(i52)
$
(i113)
/
Nevada
Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. iThe following table presents the carrying value and estimated fair value of Nevada Power's long-term debt as of December 31 (in millions):
2023
2022
Carrying
Fair
Carrying
Fair
Value
Value
Value
Value
Long-term
debt
$
i3,392
$
i3,417
$
i3,195
$
i3,114
368
(14) iCommitments
and Contingencies
Commitments
i
Nevada Power has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2023 are as follows (in millions):
Nevada Power has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2024 to 2067. Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Nevada Power's lease commitments.
Nevada Power has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been
approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.
Fuel Contracts
Nevada Power's gas transportation contracts expire from 2024 to 2039.
Construction Commitments
Nevada Power's construction commitments included in the table above relate to firm commitments and include costs associated with a planned 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada, the planned Greenlink Nevada transmission expansion program that will be developed in western and northern Nevada, a planned 444
MWs of peaking combustion turbines that will be developed at the Silverhawk generating facility in Clark County, Nevada and certain other generation plant projects.
Transmission
Nevada Power has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to Nevada Power's customers.
Easements
Nevada Power has non-cancelable easements for land. Operations and maintenance expense on non-cancelable easements totaled $iii4//
million for the years ended December 31, 2023, 2022 and 2021.
369
Maintenance, Service and Other Contracts
Nevada Power has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 2024 to 2038.
Environmental Laws and Regulations
Nevada
Power is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact its current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Nevada Power is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties
and other costs in substantial amounts.
(15) iRevenues from Contracts with Customers
i
The
following table summarizes Nevada Power's Customer Revenue by customer class for the years ended December 31 (in millions):
2023
2022
2021
Customer
Revenue:
Retail:
Residential
$
i1,633
$
i1,440
$
i1,207
Commercial
i647
i525
i414
Industrial
i689
i528
i386
Other
i23
i14
i14
Total
fully bundled
i2,992
i2,507
i2,021
Distribution-only
service
i14
i20
i22
Total
retail
i3,006
i2,527
i2,043
Wholesale,
transmission and other
i63
i82
i74
Total
Customer Revenue
i3,069
i2,609
i2,117
Other
revenue
i19
i21
i22
Total
operating revenue
$
i3,088
$
i2,630
$
i2,139
/
(16) iSupplemental
Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2023
2022
2021
Supplemental
disclosure of cash flow information:
Interest paid, net of amounts capitalized
$
i159
$
i121
$
i115
Income
taxes (refunded) paid
$
(i52)
$
(i29)
$
i63
Supplemental
disclosure of non-cash investing and financing transactions:
Accruals related to property, plant and equipment additions
$
i230
$
i98
$
i53
370
(17) iRelated
Party Transactions
Nevada Power has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Nevada Power under this agreement, either directly or through NV Energy, totaled $i55 million, $i46
million and $i30 million for the years ended December 31, 2023, 2022 and 2021, respectively. Amounts charged to Nevada Power in 2023 and 2022 primarily relate to information technology projects billed at a consolidated level and passed through to affiliates.
Kern River Gas Transmission Company, an indirect subsidiary of BHE, provided natural gas transportation
and other services to Nevada Power of $i50 million, $i49 million, $i52 million
for the years ended December 31, 2023, 2022 and 2021, respectively. As of December 31, 2023 and 2022, Nevada Power's Consolidated Balance Sheets included amounts due to Kern River Gas Transmission Company of $i4 million and $i3 million,
respectively.
Nevada Power provided electricity and other services to PacifiCorp, an indirect subsidiary of BHE, of $i1 million, $i4 million and $i3 million
for the years ended December 31, 2023, 2022 and 2021, respectively. There were iino/
receivables associated with these services as of December 31, 2023 and 2022.
Nevada Power provided electricity to Sierra Pacific of $i230 million, $i362 million
and $i179 million for the years ended December 31, 2023, 2022 and 2021, respectively. Receivables associated with these transactions were $i10 million and $i41 million
as of December 31, 2023 and 2022, respectively. Nevada Power purchased electricity from Sierra Pacific of $i70 million, $i86 million
and $i43 million for the years ended December 31, 2023, 2022 and 2021, respectively. Payables associated with these transactions were $i1 million
and $i5 million as of December 31, 2023 and 2022, respectively.
Nevada Power incurs intercompany administrative and shared facility costs with NV Energy and Sierra Pacific. These transactions are governed by an intercompany service agreement and are priced at cost. Nevada Power provided services to NV Energy of $i4
million, $i3 million and $i1 million for each of the years ending December 31, 2023, 2022 and 2021,
respectively. NV Energy provided services to Nevada Power of $iii9// million
for the years ending December 31, 2023, 2022 and 2021. Nevada Power provided services to Sierra Pacific of $i28 million, $i25
million and $i25 million for the years ended December 31, 2023, 2022 and 2021, respectively. Sierra Pacific provided services to Nevada Power of $i19
million, $i16 million and $i15 million for the years ended December 31, 2023, 2022
and 2021, respectively. As of December 31, 2023 and 2022, Nevada Power's Consolidated Balance Sheets included amounts due to NV Energy of $i82 million and $i51
million, respectively. There were iino/ receivables due from NV Energy as of December 31, 2023 and 2022.
In November 2022, Nevada Power entered into a $i100 million unsecured note with NV Energy receivable upon demand and $i— million and $i100 million
was outstanding as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, Nevada Power's Consolidated Balance Sheets included receivables due from Sierra Pacific of $i— million and $i33 million,
respectively. There were $i20 million and $i— million payables due to Sierra Pacific as of December 31, 2023 and 2022.
Nevada
Power is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated U.S. federal income tax return. Federal income taxes payable to NV Energy were $i31 million as of December 31, 2023 and federal income taxes receivable from NV Energy were $i12
million as of December 31, 2022. Nevada Power received cash refunds of $i52 million and $i29 million
for federal income taxes for the years ended December 31, 2023 and 2022, respectively and made cash payments of $i63 million for federal income taxes for the year ended December 31, 2021.
Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Nevada Power and reimbursed
automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.
371
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
372
Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K. Sierra Pacific's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net
income for the year ended December 31, 2023 was $117 million, a decrease of $1 million, or 1%, compared to 2022, primarily due to higher depreciation and amortization, mainly due to increased plant placed in-service and higher regulatory amortizations, higher operations and maintenance expenses and higher interest expense, mainly due to higher long-term debt at a higher average interest rates. The decrease is partially offset by higher utility margin, higher allowances for borrowed and equity funds, primarily due to increased construction work-in-progress, higher interest and dividend income, mainly from carrying charges on regulatory balances, lower income tax expense, mainly due to the effects of ratemaking, and higher cash surrender value of corporate-owned life insurance policies. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective
January 2023 and higher transmission and wholesale revenue, partially offset by lower customer volumes and lower regulatory-related revenue deferrals. Electric retail customer volumes, including distribution only service customers, decreased 2.9% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Operations and maintenance expenses increased primarily due to increased plant operations and maintenance expenses, higher insurance premiums due to additional wildfire coverage and higher customer service operations expenses. Energy generated decreased 2% for 2023 compared to 2022 primarily due to lower coal-fueled generation, offset by higher natural gas-fueled generation. Wholesale electricity sales volumes decreased 16% and purchased electricity volumes decreased 2%.
Net income for the year ended December 31,
2022 was $118 million, a decrease of $6 million, or 5%, compared to 2021, primarily due to higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses, lower other, net, mainly due to higher pension expense and lower cash surrender value of corporate-owned life insurance policies, higher depreciation and amortization, primarily due to higher plant in-service, higher interest expense mainly due to higher long-term debt, partially offset by higher electric utility margin and higher interest and dividend income, mainly from carrying charges on regulatory balances. Electric utility margin increased primarily due to higher transmission and wholesale revenue, higher customer volumes and higher regulatory-related revenue deferrals, partially offset by unfavorable price impacts from changes in sales mix. Electric retail customer volumes, including distribution only service customers, increased 2.8% primarily due to an increase
in the average number of customers, offset by the unfavorable impact of weather and unfavorable changes in customer usage. Energy generated decreased 13% for 2022 compared to 2021 primarily due to lower natural gas- and coal-fueled generation. Wholesale electricity sales volumes increased 13% and purchased electricity volumes decreased 5%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions
presented on the Consolidated Statements of Operations.
Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms and, as a result, changes in Sierra Pacific's expenses included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
373
Electric
utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
2023
2022
Change
2022
2021
Change
Electric
utility margin:
Operating revenue
$
1,194
$
1,025
$
169
16
%
$
1,025
$
848
$
177
21
%
Cost
of fuel and energy
689
555
134
24
555
407
148
36
Electric utility margin
505
470
35
7
%
470
441
29
7
%
Natural
gas utility margin:
Operating revenue
237
168
69
41
%
168
117
51
44
%
Natural
gas purchased for resale
176
111
65
59
111
61
50
82
Natural gas utility margin
61
57
4
7
%
57
56
1
2
%
Utility
margin
566
527
39
7
%
527
497
30
6
%
Operations
and maintenance
204
189
15
8
%
189
163
26
16
%
Depreciation and amortization
185
149
36
24
149
143
6
4
Property
and other taxes
25
24
1
4
24
24
—
—
Operating income
$
152
$
165
$
(13)
(8)
%
$
165
$
167
$
(2)
(1)
%
374
Electric
Utility Margin
A comparison of key operating results related to electric utility margin is as follows for the years ended December 31:
2023
2022
Change
2022
2021
Change
Utility
margin (in millions):
Operating revenue
$
1,194
$
1,025
$
169
16
%
$
1,025
$
848
$
177
21
%
Cost
of fuel and energy
689
555
134
24
555
407
148
36
Utility margin
$
505
$
470
$
35
7
%
$
470
$
441
$
29
7
%
Sales
(GWhs):
Residential
2,655
2,747
(92)
(3)
%
2,747
2,769
(22)
(1)
%
Commercial
2,998
3,124
(126)
(4)
3,124
3,056
68
2
Industrial
2,684
2,867
(183)
(6)
2,867
3,716
(849)
(23)
Other
11
13
(2)
(15)
13
15
(2)
(13)
Total
fully bundled(1)
8,348
8,751
(403)
(5)
8,751
9,556
(805)
(8)
Distribution only service
2,829
2,757
72
3
2,757
1,639
1,118
68
Total
retail
11,177
11,508
(331)
(3)
11,508
11,195
313
3
Wholesale
621
741
(120)
(16)
741
656
85
13
Total
GWhs sold
11,798
12,249
(451)
(4)
%
12,249
11,851
398
3
%
Average
number of retail customers (in thousands)
376
371
5
1
%
371
365
6
2
%
Average
revenue per MWh:
Retail - fully bundled(1)
$
132.97
$
106.57
$
26.40
25
%
$
106.57
$
81.77
$
24.80
30
%
Wholesale
$
79.63
$
75.48
$
4.15
5
%
$
75.48
$
58.14
$
17.34
30
%
Heating
degree days
4,950
4,631
319
7
%
4,631
4,494
137
3
%
Cooling degree days
1,097
1,353
(256)
(19)
%
1,353
1,366
(13)
(1)
%
Sources
of energy (GWhs)(2)(3):
Natural gas
4,310
4,075
235
6
%
4,075
4,712
(637)
(14)
%
Coal
759
1,077
(318)
(30)
1,077
1,220
(143)
(12)
Renewables
24
26
(2)
(8)
26
31
(5)
(16)
Total
energy generated
5,093
5,178
(85)
(2)
5,178
5,963
(785)
(13)
Energy purchased
4,612
4,691
(79)
(2)
4,691
4,960
(269)
(5)
Total
9,705
9,869
(164)
(2)
%
9,869
10,923
(1,054)
(10)
%
Average
cost of energy per MWh(2)(4):
Energy generated
$
64.82
$
46.05
$
18.77
41
%
$
46.05
$
28.84
$
17.21
60
%
Energy
purchased
$
77.85
$
67.49
$
10.36
15
%
$
67.49
$
47.39
$
20.10
42
%
(1) Fully
bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The average cost of energy per MWh and sources of energy excludes 4, — and 2 GWhs of coal and —, — and 6 GWhs of natural gas generated energy that is purchased at cost by related parties for the years ended December 31, 2023, 2022 and 2021, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
375
Natural
Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows for the years ended December 31:
Electric utility margin increased $35 million, or 7%, for 2023 compared to 2022 primarily due to:
•$39 million of higher electric retail utility margin primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 2.9% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and
•$2 million of higher transmission and
wholesale revenue.
The increase in electric utility margin was offset by:
•$3 million of lower regulatory-related revenue deferrals.
Natural gas utility margin increased $4 million, or 7%, for 2023 compared to 2022 primarily due to higher customer volumes from the favorable impact of weather and an increase in the average number of customers.
Operations and maintenance increased $15 million, or 8%, for 2023 compared to 2022 primarily due to increased plant operations and maintenance expenses, lower regulatory credits from the deferral of the ON Line lease cost reallocation in 2022, higher insurance premiums due to additional wildfire coverage and higher customer service operations expenses,
partially offset by lower regulatory approved amortization from the recovery for the ON Line reallocation (offset in operating revenue).
Depreciation and amortization increased $36 million, or 24%, for 2023 compared to 2022 primarily due to higher plant placed in-service and higher regulatory amortizations.
Interest expense increased $8 million, or 14%, for 2023 compared to 2022 primarily due to higher long-term debt and higher average interest rates.
376
Allowance for borrowed funds increased
$4 million for 2023 compared to 2022 primarily due to higher construction work-in-progress.
Allowance for equity funds increased $7 million for 2023 compared to 2022 primarily due to higher construction work-in-progress.
Interest and dividend income increased $4 million, or 22%, for 2023 compared to 2022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $2 million for 2023 compared to 2022 primarily due to higher cash surrender value of corporate-owned life insurance policies.
Income tax expense decreased
$3 million, or 16%, for 2023 compared to 2022 primarily due to the effects of ratemaking. The effective tax rate was 12% in 2023 and 14% in 2022.
Electric utility margin increased $29 million, or 7%, for 2022 compared to 2021 primarily due to:
•$15 million of higher ON Line temporary rider (offset in operations and maintenance expense) for the recovery of deferred costs for ON Line due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific;
•$9
million of higher transmission and wholesale revenue;
•$4 million of higher regulatory-related revenue deferrals; and
•$1 million of higher electric retail utility margin due to higher customer volumes, offset by unfavorable price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 2.8% primarily due to an increase in the average number of customers, offset by the unfavorable impact of weather and unfavorable changes in customer usage.
The increase in electric utility margin was offset by:
•$2 million in lower energy efficiency program rates (offset in operations and maintenance expense).
Operations and maintenance
increased $26 million, or 16%, for 2022 compared to 2021 primarily due to higher regulatory-approved cost recovery for the ON Line reallocation of $15 million (offset in operating revenue) and higher plant operations and maintenance expenses, partially offset by lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $6 million, or 4%, for 2022 compared to 2021 primarily due to higher plant in-service.
Interest expense increased $4 million, or 7%, for 2022 compared to 2021 primarily due to higher interest rates and debt.
Interest and dividend income increased $9 million for 2022 compared to
2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net decreased $9 million, or 82%, for 2022 compared to 2021 primarily due to higher pension expense and lower cash surrender value of corporate-owned life insurance policies.
377
Liquidity and Capital Resources
As of December 31, 2023, Sierra Pacific's total net liquidity was $444 million
as follows (in millions):
Cash and cash equivalents
$
44
Credit facilities(1)
400
Total
net liquidity
$
444
Credit facilities:
Maturity dates
2026
(1)Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Sierra Pacific's credit facility.
Operating Activities
Net
cash flows from operating activities for the years ended December 31, 2023 and 2022 were $419 million and $109 million, respectively. The change was primarily due to higher collections from customers and lower payments related to fuel and energy costs, partially offset by higher payments for income taxes, the timing of payments for operating costs and lower customer deposits.
Net cash flows from operating activities for the years ended December 31, 2022 and 2021 were $109 million and $183 million, respectively. The change was primarily due to higher payments related to fuel and energy costs and the timing of payments for operating costs, partially offset by higher collections from customers.
The
timing of Sierra Pacific's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2023 and 2022 were $(388) million and $(351) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Net cash flows from investing activities for the years ended December 31,
2022 and 2021 were $(351) million and $(300) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the years ended December 31, 2023 and 2022 were $(35) million and $282 million, respectively. The change was primarily due to lower contributions from NV Energy, Inc., higher repayments of long-term debt and higher dividends paid to NV Energy, Inc., partially offset by lower long-term debt reacquired, lower repayments of short-term debt and higher proceeds from the issuance
of long-term debt.
Net cash flows from financing activities for the years ended December 31, 2022 and 2021 were $282 million and $107 million, respectively. The change was primarily due to higher contributions from NV Energy, Inc. and greater proceeds from the issuance of long-term debt, partially offset by higher long-term debt reacquired, higher repayments of short-term debt and higher dividends paid to NV Energy, Inc.
In February 2024, Sierra Pacific declared and paid a dividend to NV Energy, Inc. of $150 million.
378
Ability
to Issue Debt
Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of December 31, 2023, Sierra Pacific has financing authority from the PUCN consisting of the ability to issue long-term and short-term debt securities so long as the total amount of debt outstanding (excluding borrowings under Sierra Pacific's $400 million secured credit facility) does not exceed $1.9 billion and to issue common and preferred stock so long as the total amounts outstanding do not exceed $2.2 billion and $500 million, respectively, as measured at the end of each calendar quarter. Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of December 31, 2023. In addition, certain financing
agreements contain covenants which are currently suspended as Sierra Pacific's senior secured debt is rated investment grade. However, if Sierra Pacific's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, Sierra Pacific would be subject to limitations under these covenants.
Ability to Issue General and Refunding Mortgage Securities
To the extent Sierra Pacific has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, Sierra Pacific's ability to issue secured debt is limited by the amount of bondable property or retired bonds that can be used to issue debt under Sierra Pacific's indenture.
Sierra
Pacific's indenture creates a lien on substantially all of Sierra Pacific's properties in Nevada. As of December 31, 2023, $5.0 billion of Sierra Pacific's assets were pledged. Sierra Pacific had the capacity to issue $1.4 billion of additional general and refunding mortgage securities as of December 31, 2023 determined on the basis of 70% of net utility property additions. Property additions include plant-in-service and specific assets in construction work-in-progress. The amount of bond capacity listed above does not include eligible property in construction work-in-progress. Sierra Pacific also has the ability to release property from the lien of Sierra Pacific's indenture on the basis of net property additions, cash or retired bonds. To the extent Sierra Pacific releases property from the lien of Sierra Pacific's indenture, it will reduce the amount of securities issuable
under the indenture.
Long-Term Debt
In February 2024, Sierra Pacific entered into a re-offering of the following series of fixed-rate tax exempt bonds: $75 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $60 million of Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds, Series 2016B, due 2036; $30 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; $30 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $20 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016A due 2029; and $20 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Humboldt County Series
2016A and Series 2016B bonds were offered at a term rate of 3.550%. The Washoe County Series 2016B and Series 2016G bonds were offered at a fixed rate of 3.625% and the Washoe County Series 2016C and Series 2016F bonds were offered at a fixed rate of 4.125%. Sierra Pacific previously purchased the bonds as required by the bond indentures. Sierra Pacific used the net proceeds of the re-offering for general corporate purposes.
Future Uses of Cash
Sierra Pacific has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of secured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements
and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including Sierra Pacific's credit ratings, investors' judgment of risk associated with Sierra Pacific and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials;
commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
379
Historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
Historical
Forecast
2021
2022
2023
2024
2025
2026
Electric
distribution
$
96
$
113
$
169
$
207
$
250
$
177
Electric transmission
77
75
114
191
263
272
Solar
generation
17
36
1
7
133
106
Electric battery storage
18
—
14
88
53
203
Other
92
127
90
181
204
172
Total
$
300
$
351
$
388
$
674
$
903
$
930
Sierra
Pacific received or is seeking PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission and has included estimates from its latest IRP filing as well as potential future filings in its forecast capital expenditures for 2024 through 2026. These estimates are likely to change as a result of the RFP process, continued evaluation and future IRP filing refinements. Sierra Pacific's historical and forecast capital expenditures include the following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission
expansion program. The Nevada Utilities have received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation, near Yerington, Nevada to the Northwest substation, near Las Vegas, Nevada to the Harry Allen substation, near Las Vegas, Nevada; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Mira Loma substations, near Yerington, Nevada; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation, near Yerington, Nevada to the Robinson Summit substation, near Ely, Nevada. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Solar
generation includes solar photovoltaic panels procured for future growth projects and a 400-MW solar photovoltaic facility with an additional 400-MW of co-located battery storage, pending PUCN approval, that would be developed in Churchill County, Nevada with ownership share between Nevada Power and Sierra Pacific to be approved by the PUCN. Commercial operation of the solar is expected by early 2027.
•Electric battery storage includes a 400-MW battery energy storage system co-located with a 400-MW solar photovoltaic facility, pending PUCN approval, that would be developed in Churchill County, Nevada with ownership share between Nevada Power and Sierra Pacific to be approved by the PUCN. Commercial operation of the battery energy storage system is expected by early 2026.
•Other includes both growth projects and operating expenditures
consisting of turbine upgrades at the Tracy generating facility, a repower project at the Valmy generating station to convert existing coal-fired combustion to natural gas-fired combustion, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
2021 Joint Integrated Resource Plan
In August 2023, the Nevada Utilities filed its Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part (1) to convert the existing coal fueled plant at North Valmy Generating Station to a cleaner natural gas fueled plant (2) to construct a company-owned 400 MW solar plant along with a 400 MW, four-hour battery storage system in Northern Nevada; (3) to continue operation of
Tracy units 4 and 5 to 2049; (4) to purchase development assets for a 149 MW photovoltaic and 149 MW battery energy storage system known as the Crescent Valley Solar project; (5) to construct the Esmeralda and Amargosa substations transformers; and (6) to construct the necessary infrastructure in the Apex Area Master Plan. The Nevada Utilities seek approval of approximately $1.8 billion in total costs of new projects of which Sierra Pacific's share is approximately $0.8 billion with an order expected in 2024.
380
Material Cash Requirements
Sierra
Pacific has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Notes 7 and 8), operating and financing leases (refer to Note 5), purchased electricity contracts (refer to Note 14), fuel contracts (refer to Note 14), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7 and Note 14) and AROs (refer to Note 11). Refer to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Sierra Pacific has cash requirements relating to interest payments of $1.3 billion on long-term debt, including $63 million due in 2024.
Regulatory
Matters
Sierra Pacific is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding Sierra Pacific's general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations,
these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral
and Contingent Features
Debt of Sierra Pacific is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Sierra Pacific's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Sierra Pacific has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. Sierra Pacific's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest
rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in
the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2023, the applicable credit ratings obtained from recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2023, Sierra Pacific would have been required to post $36 million of additional collateral. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
381
Inflation
Historically,
overall inflation and changing prices in the economies where Sierra Pacific operates has not had a significant impact on Sierra Pacific's financial results. Sierra Pacific operates under a cost-of-service based rate-setting structure administered by the PUCN and the FERC. Under this rate-setting structure, Sierra Pacific is allowed to include prudent costs in its rates, including the impact of inflation after Sierra Pacific experiences cost increases. Fuel and purchase power costs are recovered through a balancing account, minimizing the impact of inflation related to these costs. Sierra Pacific attempts to minimize the potential impact of inflation on its operations through the use of periodic rate adjustments for fuel and energy costs, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs
and long-term debt issuances. There can be no assurance that such actions will be successful.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting Sierra Pacific, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates
and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by Sierra Pacific's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Sierra Pacific's Summary of Significant Accounting Policies included in Sierra Pacific's Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Sierra
Pacific prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Sierra Pacific continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to
another form of regulation, other regulatory actions or the impact of competition that could limit Sierra Pacific's ability to recover its costs. Sierra Pacific believes its application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as AOCI. Total regulatory assets were $381 million and total regulatory liabilities were $439 million as of December 31, 2023. Refer to Sierra Pacific's Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K
for additional information regarding Sierra Pacific's regulatory assets and liabilities.
Impairment of Long-Lived Assets
Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements
of Operations. As substantially all property, plant and equipment was used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
382
The estimate of cash flows arising from the future use of an asset, for the purposes of impairment analysis, requires the exercise of judgment. Circumstances that could significantly alter the calculation of fair value or the recoverable amount of an asset may include significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset, the physical condition of the asset, future market prices, load growth, competition and many other factors over
the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Sierra Pacific's results of operations.
Income Taxes
In determining Sierra Pacific's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by Sierra Pacific's various regulatory commissions. Sierra Pacific's income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Sierra Pacific recognizes the
tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Sierra Pacific's federal, state and local income tax examinations is uncertain, Sierra Pacific believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations is not expected to have a material impact on Sierra Pacific's financial results. Refer to Sierra Pacific's Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's income taxes.
It
is probable that Sierra Pacific will pass income tax benefit and expense related to the 2017 federal tax rate change from 35% to 21%, certain property-related basis differences and other various differences on to its customers. As of December 31, 2023, these amounts were recognized as a net regulatory liability of $206 million and will be included in regulated rates when the temporary differences reverse.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Sierra Pacific's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Sierra Pacific's significant market risks are
primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which Sierra Pacific transacts. The following discussion addresses the significant market risks associated with Sierra Pacific's business activities. Sierra Pacific has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Sierra Pacific's contracts accounted for as derivatives.
Commodity Price Risk
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in
its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures,
options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. Sierra Pacific's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates through its deferred energy mechanism, which is subject to disallowance and regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.
383
The table that follows summarizes Sierra Pacific's price risk
on commodity contracts accounted for as derivatives and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worse case scenarios (dollars in millions).
Sierra Pacific's commodity derivative contracts not designated as hedging contracts are recoverable from customers in regulated rates and therefore, net unrealized gains and losses associated with
interim price movements on commodity derivative contracts do not expose Sierra Pacific to earnings volatility. As of December 31, 2023 and 2022, a net regulatory asset of $16 million and $13 million, respectively, was recorded related to the net derivative liability of $16 million and $13 million, respectively. The settled cost of these commodity derivative contracts is generally included in regulated rates.
Interest Rate Risk
Sierra Pacific is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt
and by monitoring market changes in interest rates. As a result of the fixed interest rates, Sierra Pacific's fixed-rate long-term debt does not expose Sierra Pacific to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Sierra Pacific were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Sierra Pacific's short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Notes 7 and 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Sierra Pacific's short- and long-term debt.
As of December 31,
2023 and 2022, Sierra Pacific had no short-term variable-rate obligations that expose Sierra Pacific to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Sierra Pacific's annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2023 and 2022.
Credit Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions
and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
As
of December 31, 2023, Sierra Pacific's aggregate credit exposure from energy related transactions were not material, based on settlement and mark-to-market exposures, net of collateral.
384
Item 8. Financial Statements and Supplementary Data
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred
to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sierra Pacific as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Sierra Pacific's management. Our responsibility is to express an opinion on Sierra Pacific's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight
Board (United States) (PCAOB) and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Sierra Pacific is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Sierra Pacific's internal control over financial reporting. Accordingly, we express no such opinion.
Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements
and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Note 6 to the financial statements
Critical Audit Matter Description
Sierra Pacific is subject to rate regulation by a state public service commission as well as the Federal Energy Regulatory Commission (collectively, the "Commissions"), which have
jurisdiction with respect to the rates of electric and natural gas companies in the respective service territories where Sierra Pacific operates. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation has a pervasive effect on the financial statements.
386
Regulated rates are subject to regulatory rate-setting processes. Rates are determined, approved, and established based on a cost-of-service basis, which is designed to allow Sierra Pacific an opportunity
to recover its prudently incurred costs of providing services and to earn a reasonable return on its invested capital. Regulatory decisions can have an effect on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. While Sierra Pacific Power Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that changes to the Commissions' approach to setting rates or other regulatory actions could limit Sierra Pacific's ability to recover its costs.
We identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory orders on the financial
statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We evaluated Sierra Pacific's disclosures related to the effects of rate regulation by testing recorded balances and evaluating regulatory
developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by Sierra Pacific and interveners, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected Sierra Pacific's filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects
that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i185
i149
i143
Allowance
for equity funds
(i14)
(i7)
(i7)
Deferred
energy
i117
(i267)
(i116)
Amortization
of deferred energy
i83
i97
i29
Other
changes in regulatory assets and liabilities
i1
(i1)
(i39)
Deferred
income taxes and amortization of investment tax credits
(i56)
i31
i13
Other,
net
i—
i3
(i1)
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i7)
(i52)
(i27)
Inventories
(i38)
(i14)
i12
Accrued
property, income and other taxes
i18
(i13)
i9
Accounts
payable and other liabilities
i13
i65
i43
Net
cash flows from operating activities
i419
i109
i183
Cash
flows from investing activities:
Capital expenditures
(i388)
(i351)
(i300)
Net
cash flows from investing activities
(i388)
(i351)
(i300)
Cash
flows from financing activities:
Proceeds from long-term debt
i393
i248
i—
Long-term
debt reacquired
i—
(i265)
i—
Repayments
of long-term debt
(i250)
i—
i—
Net
(repayments of) proceeds from short-term debt
i—
(i159)
i114
Net
(repayments of) proceeds from affiliate note payable
(i70)
i70
i—
Dividends
paid
(i100)
(i70)
i—
Contributions
from parent
i—
i465
i—
Other,
net
(i8)
(i7)
(i7)
Net
cash flows from financing activities
(i35)
i282
i107
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i4)
i40
(i10)
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i56
i16
i26
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i52
$
i56
$
i16
The
accompanying notes are an integral part of these consolidated financial statements.
391
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) iOrganization
and Operations
Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a U.S. regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) iSummary
of Significant Accounting Policies
i
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of Sierra Pacific and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2023, 2022
and 2021.
i
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects
of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
i
Accounting for the Effects of Certain Types of Regulation
Sierra
Pacific prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Sierra Pacific defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
i
Fair
Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair
value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
392
i
Cash and Cash Equivalents and Restricted Cash
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other
investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist of funds restricted by the PUCN for a certain renewable energy contract. iA reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2023 and December 31, 2022, as presented on the Consolidated Statements
of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Restricted
cash and cash equivalents included in other current assets
i8
i7
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i52
$
i56
i
Allowance
for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Sierra Pacific's assessment of the collectability of amounts owed to Sierra Pacific by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Sierra Pacific primarily utilizes credit loss history. However, Sierra Pacific may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. Sierra Pacific also has the ability to assess deposits on customers who have
delayed payments or who are deemed to be a credit risk. iThe changes in the balance of the allowance for credit losses, which is included in trade receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
2023
2022
2021
Beginning
balance
$
i2
$
i1
$
i2
Charged
to operating costs and expenses, net
i4
i2
i2
Write-offs,
net
(i3)
(i1)
(i3)
Ending
balance
$
i3
$
i2
$
i1
i
Derivatives
Sierra Pacific employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases
or normal sales contracts are not marked‑to‑market and settled amounts are recognized as cost of fuel, energy and capacity or natural gas purchased for resale on the Consolidated Statements of Operations.
For Sierra Pacific's derivative contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For a derivative contract not probable of inclusion in rates, changes in the fair value are recognized in earnings.
393
i
Inventories
Inventories
consist mainly of materials and supplies totaling $i95 million and $i69 million as of December 31, 2023 and 2022, respectively, and fuel,
which includes coal stock, stored natural gas and fuel oil, totaling $i22 million and $i10 million as of December 31, 2023 and 2022,
respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the Public Utilities Commission of Nevada ("PUCN").
/
i
Property, Plant and
Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Sierra Pacific capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved
by the PUCN.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by Sierra Pacific's various regulatory authorities. Depreciation studies are completed by Sierra Pacific to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as a non-current regulatory liability on the Consolidated Balance Sheets. As actual removal costs are incurred, the associated liability is reduced.
Generally
when Sierra Pacific retires or sells a component of regulated property, plant and equipment depreciated using the composite method, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings with the exception of material gains or losses on regulated property, plant and equipment depreciated on a straight-line basis, which is then recorded to a regulatory asset or liability.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. The rate applied to construction costs is the lower of the PUCN allowed rate of return and rates computed based
on guidelines set forth by the Federal Energy Regulatory Commission ("FERC"). After construction is completed, Sierra Pacific is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. Sierra Pacific's AFUDC rate used during 2023 and 2022 was i6.85% and i5.52%,
respectively, for electric, i5.75% and i5.09%, respectively, for natural gas and i6.76%
and i5.23%, respectively, for common facilities.
i
Asset Retirement Obligations
Sierra Pacific
recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Sierra Pacific's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability
on the Consolidated Balance Sheets. The costs are not recovered in rates until the work has been completed.
394
i
Impairment
Sierra Pacific evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not
be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
i
Leases
Sierra
Pacific has non-cancelable operating leases primarily for transmission and delivery assets, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require Sierra Pacific to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Sierra Pacific does not include options in its lease calculations unless there is a triggering event indicating Sierra Pacific is reasonably certain to exercise the
option. Sierra Pacific's accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Sierra Pacific's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced.
These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.
Sierra Pacific's operating and finance right-of-use assets are recorded in other assets and the operating and current finance lease liabilities are recorded in current and long-term other liabilities accordingly.
i
Revenue Recognition
Sierra Pacific uses
a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Sierra Pacific expects to be entitled in exchange for those goods or services. Sierra Pacific records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
Substantially all of Sierra Pacific's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory commissions. These tariff-based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or
services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 842, "Leases" and amounts not considered Customer Revenue within ASC 606, "Revenue from Contracts with Customers."
Revenue recognized is equal to what Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific's performance to date and includes billed and unbilled amounts. As of December 31, 2023 and 2022, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $i95
million and $i94 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.
395
i
Unamortized
Debt Premiums, Discounts and Issuance Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
i
Income Taxes
Berkshire Hathaway includes Sierra Pacific in its consolidated U.S. federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for income taxes has been computed on a stand-alone
basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with certain property-related basis differences and other various differences that Sierra Pacific deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income
tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Investment tax credits are deferred and amortized over the estimated useful lives of the related properties.
Sierra Pacific recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position
are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Sierra Pacific's unrecognized tax benefits are primarily included in other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
i
New Accounting Pronouncements
In November 2023, the FASB issued ASU
No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated
Financial Statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included
within Notes to Consolidated Financial Statements.
396
(3) iProperty, Plant and Equipment, Net
i
Property,
plant and equipment, net consists of the following as of December 31 (in millions):
Depreciable Life
2023
2022
Utility plant:
Electric generation
i25
- i70 years
$
i1,313
$
i1,298
Electric
transmission
i50 - i76 years
i1,023
i993
Electric
distribution
i20 - i76 years
i2,074
i1,983
Electric
general and intangible plant
i5 - i65 years
i247
i219
Natural
gas distribution
i35 - i70 years
i537
i455
Natural
gas general and intangible plant
i5 - i65 years
i17
i15
Common
general
i5 - i65 years
i376
i380
Utility
plant
i5,587
i5,343
Accumulated
depreciation and amortization
(i2,091)
(i1,992)
Utility
plant, net
i3,496
i3,351
Construction
work-in-progress
i326
i236
Property,
plant and equipment, net
$
i3,822
$
i3,587
/
All
of Sierra Pacific's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. Sierra Pacific's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the depreciable property balances as of December 31, 2023, 2022 and 2021 was i3.3%, i3.0%
and i3.1%, respectively. Sierra Pacific is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate review filings. The most recent study was filed in 2022.
Construction work-in-progress is primarily related to the construction of regulated assets.
(4) iJointly
Owned Utility Facilities
Under joint facility ownership agreements, Sierra Pacific, as tenants in common, has undivided interests in jointly owned generation and transmission facilities. Sierra Pacific accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include Sierra Pacific's share of the expenses of these facilities.
i
The
amounts shown in the table below represent Sierra Pacific's share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2023 (dollars in millions):
Sierra
Construction
Pacific's
Utility
Accumulated
Work-in-
Share
Plant
Depreciation
Progress
Valmy
Generating Station
i50
%
$
i405
$
i351
$
i4
ON
Line Transmission Line
i6
i43
i14
i—
Valmy
Transmission
i50
i4
i2
i5
Total
$
i452
$
i367
$
i9
/
397
(5) iiLeases/
i
The
following table summarizes Sierra Pacific's leases recorded on the Consolidated Balance Sheet as of December 31 (in millions):
2023
2022
Right-of-use assets:
Operating leases
$
i16
$
i16
Finance
leases
i100
i105
Total right-of-use assets
$
i116
$
i121
Lease
liabilities:
Operating leases
$
i15
$
i15
Finance
leases
i103
i108
Total lease liabilities
$
i118
$
i123
/
i
The
following table summarizes Sierra Pacific's lease costs for the years ended December 31 (in millions):
2023
2022
2021
Variable
$
i99
$
i103
$
i86
Operating
i2
i1
i1
Finance:
Amortization
i5
i5
i5
Interest
i8
i8
i9
Total
lease costs
$
i114
$
i117
$
i101
Weighted-average
remaining lease term (years):
Operating leases
24.6
26.0
27.4
Finance leases
27.6
28.2
28.4
Weighted-average
discount rate:
Operating leases
i5.0
%
i5.0
%
i5.0
%
Finance
leases
i8.4
%
i8.4
%
i8.2
%
/
i
The
following table summarizes Sierra Pacific's supplemental cash flow information relating to leases for the years ended December 31 (in millions):
2023
2022
2021
Cash paid
for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
$
(i2)
$
(i1)
$
(i1)
Operating
cash flows from finance leases
(i8)
(i9)
(i9)
Financing
cash flows from finance leases
(i7)
(i7)
(i7)
Right-of-use
assets obtained in exchange for lease liabilities:
Operating leases
$
i1
$
i1
$
i—
Finance
leases
i3
i1
i1
/
398
i
Sierra
Pacific has the following remaining lease commitments as of December 31, 2023 (in millions):
Operating
Finance
Total
2024
$
i1
$
i16
$
i17
2025
i1
i16
i17
2026
i1
i15
i16
2027
i1
i13
i14
2028
i1
i12
i13
Thereafter
i23
i127
i150
Total
undiscounted lease payments
i28
i199
i227
Less
- amounts representing interest
(i13)
(i96)
(i109)
Lease
liabilities
$
i15
$
i103
$
i118
/
Operating
and Finance Lease Obligations
Sierra Pacific's operating and finance lease obligations consist mainly of ON Line and Truckee-Carson Irrigation District ("TCID"). ON Line was placed in-service on December 31, 2013. Sierra Pacific and Nevada Power, collectively the ("Nevada Utilities"), entered into a long-term transmission use agreement, in which the Nevada Utilities have a i25% interest and Great Basin Transmission South, LLC has a i75%
interest. The Nevada Utilities' share of the long-term transmission use agreement and ownership interest is split at i75% for Nevada Power and i25% for Sierra Pacific. The term of the lease is i41
years with the agreement ending December 31, 2054. In 1999, Sierra Pacific entered into a i50-year agreement with TCID to lease electric distribution facilities. Total finance lease obligations of $i117 million and $i107
million were included on the Consolidated Balance Sheets as of December 31, 2023 and 2022, respectively, for these leases. See Note 2 for further discussion of Sierra Pacific's remaining lease obligations.
(6) iRegulatory Matters
Regulatory Assets
i
Regulatory
assets represent costs that are expected to be recovered in future rates. Sierra Pacific's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Natural disaster protection plan
i1 year
$
i78
$
i69
Deferred
energy costs
i1 year
i77
i277
Merger
costs from 1999 merger
i23 years
i60
i63
Employee
benefit plans (1)
i8 years
i48
i57
Deferred
operating costs
i4 years
i25
i35
Other
Various
i93
i110
Total
regulatory assets
$
i381
$
i611
Reflected
as:
Current assets
$
i161
$
i357
Noncurrent
assets
i220
i254
Total regulatory assets
$
i381
$
i611
(1)Represents
amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
/
Sierra Pacific had regulatory assets not earning a return on investment of $i132 million and $i143 million
as of December 31, 2023 and 2022, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, a portion of the employee benefit plans, unrealized losses on regulated derivative contracts, AROs and losses on reacquired debt.
399
Regulatory Liabilities
i
Regulatory
liabilities represent amounts that are expected to be returned to customers in future periods. Sierra Pacific's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average
Remaining
Life
2023
2022
Deferred income taxes(1)
Various
$
i206
$
i223
Cost
of removal(2)
i31 years
i211
i200
Other
Various
i22
i32
Total
regulatory liabilities
$
i439
$
i455
Reflected
as:
Current liabilities
$
i15
$
i19
Noncurrent
liabilities
i424
i436
Total regulatory liabilities
$
i439
$
i455
(1)Amounts
primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.
/
Deferred Energy
Nevada
statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments
to rates and recorded as cost of fuel, energy and capacity in future time periods.
Regulatory Rate Review
In February 2024, Sierra Pacific filed electric and gas regulatory rate reviews with the PUCN that requested annual revenue increases of $i95 million, or i8.8%
and $i11 million, or i4.9%, respectively. Orders are expected by the third quarter of 2024 and, if approved, would be effective October
1, 2024.
(7)iShort-term Debt and Credit Facilities
Sierra Pacific has a $i400
million secured credit facility expiring in June 2026 with an unlimited number of maturity extension options, subject to lender consent. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate or a base rate, at Sierra Pacific's option, plus a spread that varies based on Sierra Pacific's credit ratings for its senior secured long‑term debt securities. As of December 31, 2023 and 2022, Sierra Pacific had iino/
borrowings outstanding under the credit facility. Amounts due under Sierra Pacific's credit facility are collateralized by Sierra Pacific's general and refunding mortgage bonds. The credit facility requires Sierra Pacific's ratio of debt, including current maturities, to total capitalization not exceed i0.65 to 1.0 as of the last day of each quarter.
As of December 31, 2023, Sierra Pacific had $i50 million
of letter of credit capacity under its $i400 million secured credit facility, of which ino amount was outstanding.
400
As
of December 31, 2022, Sierra Pacific had $i75 million of letter of credit capacity under its $i250 million secured credit facility,
of which ino amount was outstanding.
(8) iLong-term Debt
i
Sierra
Pacific's long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars in millions):
Par Value
2023
2022
General and refunding mortgage securities:
i3.375%
Series T, due 2023
$
i—
$
i—
$
i249
i2.600%
Series U, due 2026
i400
i398
i397
i6.750%
Series P, due 2037
i252
i254
i254
i4.710%
Series W, due 2052
i250
i248
i248
i5.900%
Series 2023A, due 2054
i400
i393
i—
Total
long-term debt
$
i1,302
$
i1,293
$
i1,148
Reflected
as:
Current portion of long-term debt
$
i—
$
i250
Long-term
debt
i1,293
i898
Total
long-term debt
$
i1,293
$
i1,148
/
Annual
Payment on Long-Term Debt
i
The annual repayments of long-term debt for the years beginning January 1, 2024 and thereafter, are as follows (in millions):
2026
$
i400
2029
and thereafter
i902
Total
i1,302
Unamortized
premium, discount and debt issuance cost
(i9)
Total
$
i1,293
/
In
February 2024, Sierra Pacific entered into a re-offering of the following series of fixed-rate tax exempt bonds: $i75 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $i60 million of Washoe County, Nevada Gas and Water
Facilities Refunding Revenue Bonds, Series 2016B, due 2036; $i30 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; $i30 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016C, due
2036; $i20 million of Humboldt County, Nevada Pollution Control Refunding Revenue Bonds, Series 2016A due 2029; and $i20 million of Washoe County, Nevada Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Humboldt County Series 2016A and Series 2016B
bonds were offered at a term rate of ii3.550/%. The Washoe County Series 2016B and Series 2016G bonds were offered
at a fixed rate of ii3.625/% and the Washoe County Series 2016C and Series 2016F bonds were offered at a fixed rate
of ii4.125/%. Sierra Pacific previously purchased the bonds as required by the bond indentures. Sierra Pacific used
the net proceeds of the re-offering for general corporate purposes.
The issuance of General and Refunding Mortgage Securities by Sierra Pacific is subject to PUCN approval and is limited by available property and other provisions of the mortgage indentures. As of December 31, 2023, approximately $i5.0 billion (based on original cost) of Sierra Pacific's property was subject to the liens of the mortgages.
401
(9) iIncome
Taxes
i
Income tax expense consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Current
– Federal
$
i72
$
(i12)
$
i5
Deferred
– Federal
(i57)
i31
i13
Investment
tax credits
i1
i—
i—
Total
income tax expense
$
i16
$
i19
$
i18
/
i
A
reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
2023
2022
2021
Federal
statutory income tax rate
i21
%
i21
%
i21
%
Effects
of ratemaking
(i9)
(i7)
(i8)
Effective
income tax rate
i12
%
i14
%
i13
%
/
i
The
net deferred income tax liability consists of the following as of December 31 (in millions):
2023
2022
Deferred income tax assets:
Regulatory liabilities
$
i62
$
i63
Operating
and finance leases
i25
i26
Customer advances
i16
i17
Unamortized
contract value
i3
i6
Other
i5
i6
Total
deferred income tax assets
i111
i118
Deferred
income tax liabilities:
Property-related items
(i376)
(i387)
Regulatory
assets
(i100)
(i135)
Operating and finance leases
(i24)
(i25)
Other
(i15)
(i16)
Total
deferred income tax liabilities
(i515)
(i563)
Net deferred income tax liability
$
(i404)
$
(i445)
/
The
U.S. Internal Revenue Service has closed or effectively settled its examination of Sierra Pacific's income tax return through the short year ended December 31, 2013. The closure of examinations, or the expiration of the statute of limitations, may not preclude the U.S. Internal Revenue Service from adjusting the federal net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
402
(10) iEmployee
Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific did iiinot//
make any contributions to the Qualified Pension Plan for the years ended December 31, 2023, 2022 and 2021. Sierra Pacific contributed $iii1//
million to the Non-Qualified Pension Plans for the years ended December 31, 2023, 2022 and 2021. Sierra Pacific contributed $i3 million, $i5
million, and $i1 million to the Other Post Retirement Plans for the years ended December 31, 2023, 2022, and 2021 respectively. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that
will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
i
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31 (in millions):
2023
2022
Qualified
Pension Plan -
Other non-current assets
$
i53
$
i43
Non-Qualified
Pension Plans:
Other current liabilities
(i1)
(i1)
Other
long-term liabilities
(i5)
(i5)
Other
Postretirement Plans:
Other non-current assets
i1
i—
Other
long-term liabilities
i—
(i2)
/
(11) iAsset
Retirement Obligations
Sierra Pacific estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Sierra Pacific does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain generation, transmission, distribution and other assets cannot currently be estimated, and no amounts are
recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled $i211 million and $i200 million as of December 31,
2023 and 2022, respectively.
i
The following table presents Sierra Pacific's ARO liabilities by asset type as of December 31 (in millions):
2023
2022
Asbestos
$
i5
$
i5
Evaporative
ponds and dry ash landfills
i3
i3
Solar-powered generating facilities
i1
i—
Other
i3
i3
Total
asset retirement obligations
$
i12
$
i11
/
403
i
The
following table reconciles the beginning and ending balances of Sierra Pacific's ARO liabilities for the years ended December 31 (in millions):
2023
2022
Beginning balance
$
i11
$
i11
Additions
i1
i—
Ending
balance
$
i12
$
i11
Reflected
as -
Other long-term liabilities
$
i12
$
i11
/
Certain
of Sierra Pacific's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, Sierra Pacific is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. Sierra Pacific's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
(12)iRisk
Management and Hedging Activities
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost
of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.
Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Sierra
Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
404
i
The
following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Sierra Pacific's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
(1)Sierra
Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of December 31, 2023 and 2022, a regulatory asset of $i16 million and $i13
million, respectively, was recorded related to the net derivative liability of $i16 million and $i13
million, respectively.
/
Derivative Contract Volumes
i
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
Unit of
Measure
2023
2022
Electricity purchases
Megawatt
hours
i—
i1
Natural gas purchases
Decatherms
i55
i52
/
Credit
Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product
netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the
right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2023, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
405
The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $i1
million and $i— million as of December 31, 2023 and 2022, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(13) iFair
Value Measurements
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the
measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.
i
The
following table presents Sierra Pacific's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Sierra
Pacific's investments in money market mutual funds and investment funds are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
406
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Sierra Pacific transacts. When
quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Sierra Pacific uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The
determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Sierra Pacific's nonperformance risk on its liabilities, which as of December 31, 2023, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.
i
The following table reconciles the beginning
and ending balances of Sierra Pacific's net commodity derivative assets or liabilities measured at fair value on a recurring basis using significant Level 3 inputs for the years ended December 31 (in millions):
2023
2022
2021
Beginning balance
$
(i13)
$
(i33)
$
i7
Changes
in fair value recognized in regulatory assets or liabilities
(i50)
(i21)
(i25)
Settlements
i47
i41
(i15)
Ending
balance
$
(i16)
$
(i13)
$
(i33)
/
Sierra
Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. iThe following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt as of December 31 (in millions):
2023
2022
Carrying
Fair
Carrying
Fair
Value
Value
Value
Value
Long-term
debt
$
i1,293
$
i1,311
$
i1,148
$
i1,111
407
(14) iCommitments
and Contingencies
Commitments
i
Sierra Pacific has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2023 are as follows (in millions):
Sierra Pacific has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2026 to 2048. Purchased power includes estimated payments for contracts which meet the definition of a lease and payments are based on the amount of energy expected to be generated. See Note 5 for further discussion of Sierra Pacific's lease commitments.
Sierra Pacific has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have
been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.
Fuel Contracts
Sierra Pacific has a long-term contract for the transport of coal that expires in 2024. Additionally, gas transportation contracts expire from 2024 to 2046.
Construction Commitments
Sierra Pacific's construction commitments included in the table above relate to firm commitments and include costs associated with a solar photovoltaic facility project, solar photovoltaic panels for future projects, the planned Greenlink Nevada transmission expansion project that will be developed in western
and northern Nevada and other certain plant projects. The solar project, pending PUCN approval, is a 400-MW solar photovoltaic facility with an additional 400 MWs of co-located battery storage that would be developed in Churchill County, Nevada.
Transmission
Sierra Pacific has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to Sierra Pacific's customers.
Easements
Sierra Pacific has non-cancelable easements for land. Operating and maintenance expense on non-cancelable easements totaled $iii2//
million for the years ended December 31, 2023, 2022 and 2021.
408
Maintenance, Service and Other Contracts
Sierra Pacific has long-term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage. The estimated expiration of these service agreements range from 2024 to 2046.
Environmental Laws and Regulations
Sierra
Pacific is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact its current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its financial results. Sierra Pacific is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs
in substantial amounts.
(15) iRevenues from Contracts with Customers
i
The
following table summarizes Sierra Pacific's Customer Revenue by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 18, for the years ended December 31 (in millions):
2023
2022
2021
Electric
Natural
Gas
Total
Electric
Natural Gas
Total
Electric
Natural Gas
Total
Customer Revenue:
Retail:
Residential
$
i421
$
i143
$
i564
$
i365
$
i105
$
i470
$
i307
$
i76
$
i383
Commercial
i385
i64
i449
i333
i45
i378
i267
i29
i296
Industrial
i299
i27
i326
i229
i16
i245
i202
i10
i212
Other
i5
i1
i6
i6
i1
i7
i5
i—
i5
Total
fully bundled
i1,110
i235
i1,345
i933
i167
i1,100
i781
i115
i896
Distribution
only service
i5
i—
i5
i5
i—
i5
i3
i—
i3
Total
retail
i1,115
i235
i1,350
i938
i167
i1,105
i784
i115
i899
Wholesale,
transmission and other
i78
i—
i78
i86
i—
i86
i62
i—
i62
Total
Customer Revenue
i1,193
i235
i1,428
i1,024
i167
i1,191
i846
i115
i961
Other
revenue
i1
i2
i3
i1
i1
i2
i2
i2
i4
Total
operating revenue
$
i1,194
$
i237
$
i1,431
$
i1,025
$
i168
$
i1,193
$
i848
$
i117
$
i965
/
(16)iSupplemental
Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2023
2022
2021
Supplemental
disclosure of cash flow information:
Interest paid, net of amounts capitalized
$
i49
$
i45
$
i41
Income
taxes paid (refunded)
$
i56
$
(i1)
$
(i3)
Supplemental
disclosure of non-cash investing and financing transactions:
Accruals related to property, plant and equipment additions
$
i51
$
i57
$
i27
409
(17) iRelated
Party Transactions
Sierra Pacific has an intercompany administrative services agreement with BHE and its subsidiaries. Amounts charged to Sierra Pacific under this agreement, either directly or through NV Energy, totaled $i27 million, $i23
million and $i14 million for the years ended December 31, 2023, 2022 and 2021. Amounts charged to Sierra Pacific in 2023 and 2022 primarily relate to information technology projects billed at a consolidated level and passed through to affiliates.
Sierra Pacific provided electricity to Nevada Power of $i70 million,
$i86 million and $i43 million for the years ended December 31, 2023, 2022 and 2021, respectively. Receivables associated with these transactions were $i1 million
and $i5 million as of December 31, 2023 and 2022, respectively. Sierra Pacific purchased electricity from Nevada Power of $i230 million,
$i362 million and $i179 million for the years ended December 31, 2023, 2022
and 2021, respectively. Payables associated with these transactions were $i10 million and $i41 million as of December 31, 2023 and 2022,
respectively.
Sierra Pacific incurs intercompany administrative and shared facility costs with NV Energy and Nevada Power. These transactions are governed by an intercompany service agreement and are priced at cost. NV Energy provided services to Sierra Pacific of $iii5// million
for the years ending December 31, 2023, 2022 and 2021, respectively. Sierra Pacific provided services to Nevada Power of $i19 million, $i16
million, and $i15 million for the years ended December 31, 2023, 2022 and 2021, respectively. Nevada Power provided services to Sierra Pacific of $i28 million,
$i25 million, and $i25 million for the years ended December 31, 2023, 2022 and
2021, respectively. Sierra Pacific provided services to NV Energy of $i1 million, $i1 million, and $i— million
for the years ended December 31, 2023, 2022 and 2021, respectively. As of December 31, 2023 and 2022, Sierra Pacific's Consolidated Balance Sheets included amounts due to NV Energy of $i24 million and $i47
million, respectively. There were iino/ receivables due from NV Energy as of December 31, 2023 and 2022.
In November 2022, Sierra Pacific entered into a $i100 million unsecured note with NV Energy payable upon demand and $i— million and $i70 million
was outstanding as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, Sierra Pacific's Consolidated Balance Sheets included payables due to Nevada Power of $i— million and $i33 million,
respectively. There were $i20 million and $i— million receivables due from Nevada Power as of December 31, 2023 and 2022.
Sierra
Pacific is party to a tax-sharing agreement with NV Energy and NV Energy is part of the Berkshire Hathaway consolidated U.S. federal income tax return. Federal income taxes payable to NV Energy were $i4 million as of December 31, 2023 and federal income taxes receivable from NV Energy were $i11 million
as of December 31, 2022. Sierra Pacific made cash payments of $i55 million for federal income taxes for the year ended December 31, 2023 and received cash refunds of $i1 million
and $i3 million for federal income taxes for the years ended December 31, 2022 and 2021, respectively.
Certain disbursements for accounts payable and payroll are made by NV Energy on behalf of Sierra Pacific and reimbursed automatically when settled by the bank. These amounts are recorded as accounts payable at the time of disbursement.
(18)iSegment
Information
Sierra Pacific has identified itwo reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting
natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.
410
i
The following tables provide information on a reportable segment basis (in millions):
(1) Consists
principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.
/
411
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
412
Item 7.Management's
Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
Net
income attributable to Eastern Energy Gas for the year ended December 31, 2023 was $474 million, an increase of $48 million, or 11%, compared to 2022, primarily due to the acquisition of DEI's 50% noncontrolling interest in Cove Point, lower income tax expense primarily due to favorable state tax adjustments, higher earnings from Iroquois due to favorable negotiated rate agreements and hedges and interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement, partially offset by a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case, lower margin from EGTS' regulated gas transmission and storage operations of $20 million, an increase in salaries, wages and benefits and higher technology and related charges.
Net income attributable to
Eastern Energy Gas for the year ended December 31, 2022 was $426 million, an increase of $164 million, or 63%, compared to 2021, primarily due to higher margin from EGTS' regulated gas transmission and storage operations of $128 million, a benefit from the settlement of regulated tax matters in the Iroquois rate case and a decrease due to the settlement of depreciation rates in EGTS' general rate case, partially offset by an increase in income tax expense primarily due to higher pre-tax income.
Operating revenue increased $53 million, or 3%, for 2023 compared
to 2022, primarily due to an increase in regulated gas transmission and storage services revenues primarily due to the settlement of EGTS' general rate case of $49 million, increased LNG service as a result of decreased scheduled maintenance days of $26 million, an increase in variable revenue related to park and loan activity of $17 million and an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $15 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $29 million and a decrease in Cove Point LNG variable revenue of $26 million.
Cost of (excess) gas was an expense of $38 million for 2023 compared to a credit of $30 million for 2022. The change
is primarily from a decrease from other operational and system balancing fuel activities prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $45 million and the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of $27 million.
Operations and maintenance increased $60 million, or 11%, for 2023 compared to 2022, primarily due to an increase in salaries, wages and benefits of $28 million, higher technology and related charges of $11 million, an increase in operational materials and services of $10 million and an increase in fuel used in operations primarily due to volumes of $6 million, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.
Depreciation
and amortization increased $1 million for 2023 compared to 2022, primarily due to higher plant placed in-service of $9 million, partially offset by the settlement of depreciation rates in EGTS' general rate case of $8 million.
Property and other taxes decreased $5 million, or 4%, for 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.
Interest and dividend income increased $23 million for 2023 compared to 2022, primarily due to interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement of $13 million and income from money market mutual fund investments of $10 million.
Income
tax expense decreased $57 million, or 34%, for 2023 compared to 2022 and the effective tax rate was 13% for 2023 and 18% for 2022. The effective tax rate decreased primarily due to various changes in the state effective rate related to the acquisition of DEI's 50% noncontrolling interest in Cove Point.
413
Equity income decreased $29 million, or 28%, for 2023 compared to 2022, primarily due to a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case of $45 million, offset by higher earnings from Iroquois due to favorable negotiated rate agreements and hedges of $16 million.
Net
income attributable to noncontrolling interests decreased $67 million, or 16%, for 2023 compared to 2022, primarily due to the acquisition of DEI's 50% noncontrolling interest in Cove Point of $63 million and lower net income attributable to Cove Point of $4 million.
Operating revenue increased $136 million, or 7%, for 2022 compared to 2021, primarily due to an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $101 million, an increase in Cove Point LNG variable revenue of $69 million and an increase in variable revenue
related to park and loan activity of $24 million, partially offset by a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased volumes of $49 million and decreased LNG service as a result of increased scheduled maintenance days of $13 million.
Cost of (excess) gas was a credit of $30 million for 2022 compared to an expense of $12 million for 2021. The change is primarily due to a decrease in volumes sold of $62 million, partially offset by an unfavorable change to operational and system balancing volumes of $20 million.
Operations and maintenance increased $15 million, or 3%, for 2022 compared to 2021, primarily due to a 2021 benefit from the finalization of entries for the disallowance of capitalized AFUDC
of $11 million and higher technology and related charges of $11 million, partially offset by lower long-term incentive plan expenses of $8 million.
Depreciation and amortization decreased $7 million, or 2%, for 2022 compared to 2021, primarily due to the settlement of depreciation rates in EGTS' general rate case of $23 million, partially offset by higher plant placed in-service of $16 million.
Property and other taxes decreased $10 million, or 7%, for 2022 compared to 2021, primarily due to lower than estimated 2021 tax assessments.
Interest expense decreased $4 million, or 3%, for 2022 compared to 2021, primarily due to the repayment of $500 million of long-term
debt in the second quarter of 2021.
Interest and dividend income increased $7 million for 2022 compared to 2021, primarily due to interest income from BHE GT&S' intercompany revolving credit agreement with Eastern Energy Gas.
Other, net was an expense of $1 million for 2022 compared to a credit of $1 million for 2021. The change is primarily due to losses on marketable securities.
Income tax expense increased $50 million, or 43%, for 2022 compared to 2021 and the effective tax rate was 18% for 2022 and 16% for 2021. The effective tax rate increased primarily due to the revaluation of deferred taxes from changes in various state income tax rates.
Equity
income increased $59 million for 2022 compared to 2021, primarily due to a benefit from the settlement of regulated tax matters in the Iroquois rate case of $45 million and higher operating revenues at Iroquois due to favorable fixed negotiated rate agreements and hedges of $15 million.
Net income attributable to noncontrolling interests increased $33 million for 2022 compared to 2021, primarily due to an increase in Cove Point LNG variable revenue, partially offset by decreased LNG service as a result of increased scheduled maintenance days.
414
Liquidity
and Capital Resources
As of December 31, 2023, Eastern Energy Gas' total net liquidity was as follows (in millions):
Cash and cash equivalents
$
62
Intercompany revolving credit agreement(1)
400
Less:
Notes
payable to affiliates
400
Net intercompany revolving credit agreement
—
Total net liquidity
$
62
Intercompany revolving credit agreement:
Maturity
date
2025
(1)Refer to Note 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding Eastern Energy Gas' intercompany revolving credit agreement.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2023 and 2022 were $1.2 billion and $1.3 billion, respectively. The change was primarily due to the timing of income tax payments and the repayment of EGTS rate refunds to customers, partially offset by the
timing of payments for operating costs and other changes in working capital.
Net cash flows from operating activities for the years ended December 31, 2022 and 2021 were $1.3 billion and $1.1 billion, respectively. The change was primarily due to the impacts from the proposed rate increase in effect April 1, 2022 for the EGTS general rate case, timing of income tax payments and other changes in working capital, partially offset by lower collections from customers.
The timing of Eastern Energy Gas' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods elected and assumptions made for each
payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2023 and 2022 were $177 million and $(778) million, respectively. The change was primarily due to an increase in repayments of notes by affiliates of $695 million, a decrease in notes to its parent under an intercompany revolving credit agreement of $366 million, a decrease in capital expenditures of $22 million and proceeds from the assignment of shale development rights of $8 million, partially offset by equity method distribution of $150 million in 2022.
Net cash flows from investing activities for the years ended December 31,
2022 and 2021 were $(778) million and $(486) million, respectively. The change was primarily due to an increase in notes to its parent under an intercompany revolving credit agreement of $381 million and lower repayments of notes by affiliates of $266 million, partially offset by equity method distribution of $150 million in 2022, equity method contributions of $154 million in 2021 and a decrease in capital expenditures of $55 million.
Financing Activities
Net cash flows from financing activities for the year ended December 31, 2023 were $(1.4) billion. Sources of cash totaled $3.3 billion and consisted of proceeds from equity contributions to fund the purchase of Cove Point noncontrolling interest
of $2.9 billion and net issuance of notes payable to affiliates of $400 million. Uses of cash totaled $4.7 billion and consisted of $3.3 billion for the purchase of Cove Point noncontrolling interest, repayment of long-term debt of $650 million, distributions to noncontrolling interests from Cove Point of $388 million and distributions to its indirect parent, BHE, of $332 million.
Net cash flows from financing activities for the year ended December 31, 2022 were $(515) million and consisted of distributions to noncontrolling interests from Cove Point.
415
Net cash flows from financing activities
for the year ended December 31, 2021 were $(615) million. Sources of cash totaled $346 million and consisted of proceeds from equity contributions, that included a contribution from its indirect parent, BHE, to Eastern Energy Gas to assist in the repayment of $500 million of debt. Uses of cash totaled $961 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $450 million and repayment of notes to affiliates of $9 million.
Short-term Debt
As of December 31, 2023, Eastern Energy Gas had $400 million of an outstanding note payable to an affiliate at a weighted average interest rate of 5.84%. There were no amounts outstanding
under the credit agreement as of December 31, 2022. For further discussion, refer to Note 19 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Long-term Debt
Eastern Energy Gas currently has an effective shelf registration statement with the SEC to issue up to $2.5 billion of long-term debt securities through January 11, 2027.
Future Uses of Cash
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly
as a result of these reviews, which may consider, among other factors, new growth projects and the timing of growth projects; changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
Eastern Energy Gas' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
Historical
Forecast
2021
2022
2023
2024
2025
2026
Natural
gas transmission and storage
$
16
$
43
$
23
$
54
$
86
$
90
Other
426
344
342
347
343
340
Total
$
442
$
387
$
365
$
401
$
429
$
430
Eastern
Energy Gas' natural gas transmission and storage capital expenditures primarily include growth capital expenditures related to planned regulated projects. Eastern Energy Gas' other capital expenditures consist primarily of nonregulated and routine capital expenditures for natural gas transmission, storage and LNG terminalling infrastructure needed to serve existing and expected demand.
Off-Balance Sheet Arrangements
Eastern Energy Gas has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on Eastern Energy Gas' Consolidated Balance Sheets as an equity investment and is increased or decreased for Eastern Energy
Gas' pro-rata share of earnings or losses, respectively, less any dividends from such investments.
As of December 31, 2023, Eastern Energy Gas' investments that are accounted for under the equity method had short- and long-term debt of $303 million and an unused revolving credit facility of $10 million. As of December 31, 2023, Eastern Energy Gas' pro-rata share of such short- and long-term debt was $152 million and unused revolving credit facility was $5 million. The entire amount of Eastern Energy Gas' pro-rata share of the outstanding short- and long-term debt and unused revolving credit facility is non-recourse to Eastern Energy Gas. Although Eastern Energy Gas is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse
short- and long-term debt could result in a loss of invested equity.
416
Material Cash Requirements
The following table summarizes Eastern Energy Gas' material cash requirements as of December 31, 2023 (in millions):
Payments
Due by Periods
2024
2025-2026
2027-2028
2029 and thereafter
Total
Interest payments on long-term debt(1)
$
118
$
174
$
155
$
934
$
1,381
Natural
gas supply and transmission(1)
46
92
93
26
257
Total cash requirements
$
164
$
266
$
248
$
960
$
1,638
(1)Not
reflected on the Consolidated Balance Sheets.
In addition, Eastern Energy Gas also has cash requirements that may affect its consolidated financial condition that arise from long-term debt (refer to Note 8), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7), uncertain tax positions (refer to Note 9) and AROs (refer to Note 11). Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K for additional information.
Regulatory Matters
Eastern Energy Gas is subject
to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding Eastern Energy Gas' general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines,
injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Eastern Energy Gas is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral and Contingent Features
Debt
of Eastern Energy Gas is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of Eastern Energy Gas' ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
Eastern Energy Gas has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments.
417
Inflation
Historically,
overall inflation and changing prices in the economies where Eastern Energy Gas operates have not had a significant impact on Eastern Energy Gas' consolidated financial results. Eastern Energy Gas and its subsidiaries primarily operate under cost-of-service based rate-setting structures administered by the FERC. Under these rate-setting structures, Eastern Energy Gas is allowed to include prudent costs in its rates, including the impact of inflation. Eastern Energy Gas attempts to minimize the potential impact of inflation on its operations by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
New
Accounting Pronouncements
For a discussion of new accounting pronouncements affecting Eastern Energy Gas, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the
future as additional information becomes available. The following critical accounting estimates are impacted significantly by Eastern Energy Gas' methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with Eastern Energy Gas' Summary of Significant Accounting Policies included in Eastern Energy Gas' Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
Eastern Energy Gas prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Eastern Energy Gas defers the recognition of certain costs or income if it is probable that, through the ratemaking
process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Eastern Energy Gas continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Eastern Energy Gas' ability to recover its costs. Eastern Energy Gas believes its application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable
of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal level. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $54 million and total regulatory liabilities were $656 million as of December 31, 2023. Refer to Eastern Energy Gas' Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Eastern Energy Gas' regulatory assets and liabilities.
Impairment of Goodwill and Long-Lived Assets
Eastern Energy Gas' Consolidated Balance Sheet as of December 31,
2023 includes goodwill of acquired businesses of $1.3 billion. Eastern Energy Gas evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2023. Additionally, no indicators of impairment were identified as of December 31, 2023. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. Eastern Energy Gas uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices.
In estimating future cash flows, Eastern Energy Gas incorporates current market information, as well as historical factors.
418
Eastern Energy Gas evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair
value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. The impacts of regulation are considered when evaluating the carrying value of regulated assets.
The estimate of cash flows arising from the future use of an asset, for the purposes of impairment analysis, requires the exercise of judgment. Circumstances that could significantly alter the calculation of fair value or the recoverable amount of an asset may include significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset, the physical condition of the asset, future market prices, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect Eastern Energy Gas' results of operations.
Income
Taxes
In determining Eastern Energy Gas' income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the FERC. Eastern Energy Gas' income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Eastern Energy Gas recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured
based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Eastern Energy Gas' federal, state and local income tax examinations is uncertain, Eastern Energy Gas believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations is not expected to have a material impact on Eastern Energy Gas' consolidated financial results. Refer to Eastern Energy Gas' Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Eastern Energy Gas' income taxes.
It is probable that Eastern Energy Gas will pass income tax benefit and expense related to the 2017 federal tax rate change from 35% to 21%, certain property-related basis differences and other various differences on to
their customers. As of December 31, 2023, these amounts were recognized as a net regulatory liability of $425 million and will be included in regulated rates when the temporary differences reverse.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Eastern Energy Gas' Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Eastern Energy Gas' significant market risks are primarily associated with commodity prices, interest rates, foreign currency and the extension of credit to counterparties with which Eastern Energy Gas
transacts. The following discussion addresses the significant market risks associated with Eastern Energy Gas' business activities. Eastern Energy Gas has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Eastern Energy Gas' contracts accounted for as derivatives.
Commodity Price Risk
As of February 2023, all of Eastern Energy Gas' regulated operations recover their cost of gas through fuel trackers and are no longer subject to significant commodity price risk.
419
Interest
Rate Risk
Eastern Energy Gas is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. Eastern Energy Gas manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, Eastern Energy Gas' fixed-rate long-term debt does not expose Eastern Energy Gas to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if Eastern Energy Gas were to reacquire all or a portion of these instruments prior to their maturity. The nature and amount of Eastern Energy Gas' short- and long-term debt can
be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Note 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of Eastern Energy Gas' long-term debt.
As of December 31, 2023, Eastern Energy Gas had short-term variable-rate obligations totaling $400 million that expose Eastern Energy Gas to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on Eastern Energy Gas' annual interest expense. The carrying value of the variable-rate obligations approximates fair value as of December 31, 2023.
Eastern
Energy Gas holds foreign currency swaps with the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of December 31, 2023 and 2022, Eastern Energy Gas had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in fair value of Eastern Energy Gas' foreign currency swaps as of December 31, 2023 and 2022.
The impact of a change in interest rates on the Eastern Energy Gas' interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts
are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.
Credit Risk
Eastern Energy Gas is exposed to counterparty credit risk associated with natural gas transmission and storage service contracts with utilities, natural gas producers, power generators, industrials, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Eastern Energy Gas' counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Eastern Energy Gas analyzes the financial condition of each wholesale counterparty,
establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate counterparty credit risk, Eastern Energy Gas obtains third-party guarantees, letters of credit, financial guarantee bonds and cash deposits. If required, Eastern Energy Gas exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Eastern Energy Gas' gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. As of December 31, 2023, Eastern Energy Gas' credit exposure totaled $24 million. Of this
amount, investment grade counterparties, including those internally rated, represented 100%, and no single counterparty, whether investment grade or non-investment grade, exceeded $5 million of exposure.
420
Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eastern Energy Gas Holdings, LLC
Opinion on the Financial Statements
We
have audited the accompanying consolidated balance sheets of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Eastern Energy Gas as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Eastern Energy Gas' management. Our responsibility is to express an opinion on Eastern Energy Gas' financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to Eastern Energy Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the
PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Eastern Energy Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Eastern Energy Gas' internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding
the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial
statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the Financial Statements
Critical Audit Matter Description
Eastern Energy Gas, through its subsidiaries, is subject to rate regulation by the Federal Energy Regulatory Commission ("FERC"), which has jurisdiction with respect to the rates of interstate natural gas transmission companies in the respective service territories where Eastern Energy Gas operates. Management has determined its regulated operations
meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economic effects of rate regulation has a pervasive effect on the financial statements.
Revenue provided by the Eastern Energy Gas interstate natural gas transmission operations is based primarily on rates approved by the FERC. Eastern Energy Gas defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. Eastern Energy Gas continually
evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such
422
as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Eastern Energy Gas' ability to recover its costs. The evaluation reflects the current political and regulatory climate. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the regulatory assets and liabilities will be recognized in net income, returned to customers, or re-established as accumulated other comprehensive income (loss).
We
identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the FERC, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our
audit procedures related to the uncertainty of future decisions by the FERC included the following, among others:
•We evaluated the Eastern Energy Gas disclosures related to the effects of rate regulation by testing recorded balances and evaluating regulatory developments.
•We read relevant regulatory orders issued by the FERC, regulatory statutes, filings made by Eastern Energy Gas and interveners, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected Eastern Energy Gas' filings with the
FERC, and the filings with the FERC by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the FERC's treatment of similar costs under similar circumstances.
•We inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the FERC to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
Adjustments
to reconcile net income to net cash flows from operating activities:
(Gains) losses on other items, net
(i3)
i5
(i3)
Depreciation
and amortization
i322
i321
i328
Allowance
for equity funds
(i8)
(i6)
(i7)
Equity
income, net of distributions
(i1)
(i58)
i—
Changes
in regulatory assets and liabilities
(i91)
i56
(i20)
Deferred
income taxes
i353
i126
i186
Other,
net
(i5)
i8
(i19)
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i29
(i48)
(i66)
Gas
balancing activities
i22
(i29)
i73
Derivative
collateral, net
i1
(i1)
i10
Accrued
property, income and other taxes
(i232)
i27
(i30)
Accounts
payable and other liabilities
(i19)
i99
(i12)
Net
cash flows from operating activities
i1,198
i1,349
i1,092
Cash
flows from investing activities:
Capital expenditures
(i365)
(i387)
(i442)
Proceeds
from assignment of shale development rights
i8
i—
i—
Notes
to affiliates
(i198)
(i564)
(i183)
Repayment
of notes by affiliates
i734
i39
i305
Equity
method investments
i—
i150
(i154)
Other,
net
(i2)
(i16)
(i12)
Net
cash flows from investing activities
i177
(i778)
(i486)
Cash
flows from financing activities:
Repayments of long-term debt
(i650)
i—
(i500)
Repayment
of affiliated current borrowings, net
i—
i—
(i9)
Issuance
of notes payable to affiliates, net
i400
i—
i—
Proceeds
from equity contributions
i2,893
i—
i346
Purchase
of Cove Point noncontrolling interest
(i3,300)
i—
i—
Distributions
to noncontrolling interests
(i388)
(i515)
(i450)
Distributions
to parent
(i332)
i—
i—
Other,
net
i—
i—
(i2)
Net
cash flows from financing activities
(i1,377)
(i515)
(i615)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i2)
i56
(i9)
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i95
i39
i48
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i93
$
i95
$
i39
The
accompanying notes are an integral part of these consolidated financial statements.
429
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)iOrganization
and Operations
Eastern Energy Gas Holdings, LLC is a holding company, and together with its subsidiaries ("Eastern Energy Gas") conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transmission systems and underground storage operations in the eastern region of the U.S. and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. On September 1, 2023, Eastern Energy Gas completed its acquisition of i50%
of the limited partner interests in Cove Point from Dominion Energy, Inc. ("DEI"), and accordingly, owns an aggregate of i75% of the limited partner interest and continues to own i100% of the general partner interest of Cove Point. See Note 3 for more information.
In addition, Eastern Energy Gas owns a i50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a i416-mile FERC-regulated interstate natural gas transmission system. Eastern Energy Gas is an indirect wholly owned subsidiary
of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
(2) iSummary of Significant Accounting Policies
i
Basis
of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of Eastern Energy Gas and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Eastern Energy Gas consolidates variable interest entities ("VIE") in which it possesses both (i) the power to direct the activities that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Intercompany accounts and transactions have been eliminated.
i
Use
of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing
the Consolidated Financial Statements.
i
Accounting for the Effects of Certain Types of Regulation
Eastern Energy Gas prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Eastern Energy Gas defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect
the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
430
i
Fair
Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value.
Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
i
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan
agreements or other contractual provisions. Restricted cash and cash equivalents consist of customer deposits as allowed under the FERC gas tariffs. iA reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2023 and 2022, as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i93
$
i95
i
Investments
Eastern
Energy Gas utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when the investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate that the ability to exercise significant influence is restricted. In applying the equity method, Eastern Energy Gas records the investment at cost and subsequently increases or decreases the carrying value of the investment by Eastern Energy Gas' share of the net earnings or losses and other comprehensive income ("OCI") of the investee. Eastern Energy Gas records dividends or other equity distributions as reductions in the carrying value of the investment.
i
Allowance
for Credit Losses
Trade receivables are primarily short-term in nature and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Eastern Energy Gas' assessment of the collectability of amounts owed to Eastern Energy Gas by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Eastern Energy Gas primarily evaluates the financial condition of the individual customer and the nature of any disputed amount.
i
The
changes in the balance of the allowance for credit losses, which is included in trades receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
2023
2022
2021
Beginning balance
$
i3
$
i6
$
i5
Charged
to operating costs and expenses, net
i—
i—
i1
Write-offs,
net
i—
(i3)
i—
Ending
balance
$
i3
$
i3
$
i6
/
431
i
Derivatives
Eastern
Energy Gas employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets or other current liabilities on the Consolidated Balance Sheets.
Commodity derivatives used
in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of gas on the Consolidated Statements of Operations.
For Eastern Energy Gas' derivatives not designated as hedging contracts, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for derivatives related to natural gas sales contracts.
For Eastern Energy Gas' derivatives designated as hedging contracts, Eastern Energy Gas formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item.
Eastern Energy Gas formally documents hedging activity by transaction type and risk management strategy. For derivative instruments that are accounted for as cash flow hedges or fair value hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.
Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. Eastern Energy Gas discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative
contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.
i
Inventories
Inventories consist mainly of materials and supplies and are determined
using the average cost method.
i
Natural Gas Imbalances
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Eastern Energy Gas values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Eastern Energy
Gas from other parties are reported in natural gas imbalances and imbalances that Eastern Energy Gas owes to other parties are reported in other current liabilities on the Consolidated Balance Sheets.
i
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Eastern Energy Gas capitalizes all construction-related materials, direct labor and contract services, as well as indirect
construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.
432
Depreciation and amortization are generally computed by applying the composite or straight-line method based on estimated useful lives. Depreciation studies are completed by Eastern Energy Gas to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the FERC. Net salvage includes
the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when Eastern Energy Gas retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the
construction of regulated facilities, is capitalized by Eastern Energy Gas as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, Eastern Energy Gas is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
i
Asset Retirement Obligations
Eastern Energy Gas recognizes
AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Eastern Energy Gas' AROs are primarily related to the obligations associated with its natural gas pipeline and storage well assets. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For Eastern Energy Gas, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to
satisfy such liabilities is recorded as a regulatory asset or liability.
i
Impairment
Eastern Energy Gas evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted
cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. The impacts of regulation are considered when evaluating the carrying value of regulated assets.
i
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable
net assets acquired in business combinations. Eastern Energy Gas evaluates goodwill for impairment at least annually and completed its annual review as of October 31, 2023. When evaluating goodwill for impairment, Eastern Energy Gas estimates the fair value of its reporting unit. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the excess is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The determination of fair value incorporates significant unobservable inputs. During 2023, 2022 and 2021, Eastern Energy Gas did not record any goodwill impairments.
Eastern Energy Gas records goodwill adjustments for changes to the purchase price allocation prior to the end of the
measurement period, which is not to exceed one year from the acquisition date.
433
i
Revenue Recognition
Eastern Energy Gas uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Eastern
Energy Gas expects to be entitled in exchange for those goods or services. Eastern Energy Gas records sales and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
A majority of Eastern Energy Gas' Customer Revenue is derived from tariff-based sales arrangements approved by the FERC. These tariff-based revenues are mainly comprised of natural gas transmission and storage services and have performance obligations which are satisfied over time as services are provided. Eastern Energy Gas' revenue that is nonregulated primarily relates to LNG terminalling services.
Revenue recognized is equal to the value to the customer of Eastern Energy Gas' performance to date and includes billed and unbilled
amounts. As of December 31, 2023 and 2022, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $i26 million and $i18
million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In the event one of the parties to a contract has performed before the other, Eastern Energy Gas would recognize a contract asset or contract liability depending on the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern Energy Gas has recognized contract assets of $i8
million and $i10 million as of December 31, 2023 and 2022, respectively, and $i40 million and $i80 million
of contract liabilities as of December 31, 2023 and 2022, respectively, due to Eastern Energy Gas' performance on certain contracts. Eastern Energy Gas recognizes revenue as it fulfills its obligations to provide services to its customers. For the year ended December 31, 2023, Eastern Energy Gas recognized revenue of $i52 million from the beginning contract liability balance.
i
Unamortized
Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
i
Income Taxes
Berkshire Hathaway includes Eastern Energy Gas in its consolidated U.S. federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provision for income taxes has been computed on a stand-alone basis.
Deferred
income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with certain property-related basis differences and other various differences that Eastern Energy Gas' regulated businesses deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax
rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
Eastern Energy Gas recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense (benefit) on the Consolidated Statements of Operations.
i
Segment
Information
Eastern Energy Gas currently has ione segment, which includes its natural gas pipeline, storage and LNG operations.
/
434
i
New
Accounting Pronouncements
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. Eastern Energy
Gas is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application
is permitted. Eastern Energy Gas is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
(3) iBusiness Acquisitions
On September 1, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"),
a wholly owned subsidiary of Eastern Energy Gas, completed the acquisition of DECP Holdings, Inc.'s (the "Seller"), an indirect wholly owned subsidiary of DEI, i50% limited partner interests in Cove Point ("The Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 9, 2023 (the "Purchase Agreement"), the Buyer paid $i3.3
billion in cash, plus the pro rata portion of the quarterly distribution made by Cove Point for the third fiscal quarter of 2023. Eastern Energy Gas funded the Transaction through cash provided by BHE GT&S, LLC ("BHE GT&S"), which included an equity contribution of $i2.9 billion and the repayment of affiliated notes of $i474
million. The Buyer now owns an aggregate of i75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, continues to own i100%
of the general partner interest, of Cove Point. Prior to the Transaction, Eastern Energy Gas owned i100% of the general partner interest and i25%
of the limited partner interests in Cove Point. Eastern Energy Gas previously determined it has the power to direct the activities that most significantly impact Cove Point's economic performance as well as the obligation to absorb losses and benefits which could be significant to it and accordingly, consolidated Cove Point. Because Eastern Energy Gas controls Cove Point both before and after the Transaction, the changes in Eastern Energy Gas' ownership interest in Cove Point were accounted for as an equity transaction and no gain or loss was recognized. In connection with the Transaction, Eastern Energy Gas recognized $i120
million of income taxes in equity primarily attributable to the step up in tax basis of the investment in Cove Point of $i144 million, partially offset by establishing additional regulatory liabilities related to excess deferred income taxes of $i24
million.
435
(4) iProperty, Plant and Equipment, Net
i
Property,
plant and equipment, net consists of the following as of December 31 (in millions):
Depreciable Life
2023
2022
Utility Plant:
Interstate
natural gas transmission and storage assets
i23 - i49 years
$
i9,318
$
i8,922
Intangible
plant
i5 - i18 years
i117
i113
Utility
plant in-service
i9,435
i9,035
Accumulated
depreciation and amortization
(i3,201)
(i3,039)
Utility
plant in-service, net
i6,234
i5,996
Nonutility
Plant:
LNG facility
i40 years
i4,533
i4,547
Accumulated
depreciation and amortization
(i655)
(i542)
Nonutility
plant, net
i3,878
i4,005
i10,112
i10,001
Construction
work- in-progress
i231
i201
Property,
plant and equipment, net
$
i10,343
$
i10,202
/
Construction
work-in-progress includes $i223 million and $i181 million as of December 31,
2023 and 2022, respectively, related to the construction of utility plant.
Assignment of Shale Development Rights
In June 2023, Eastern Gas Transmission and Storage, Inc. ("EGTS") conveyed development rights to a natural gas producer for approximately i6,500 acres of Utica Shale and Point Pleasant Formation underneath one of its natural gas storage fields and received proceeds of $i8
million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in an $i8 million ($i6
million after-tax) gain, included in operations and maintenance expense in its Consolidated Statements of Operations.
(5) iJointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, Eastern Energy Gas, as a tenant in common, has undivided interests in jointly owned transmission and storage facilities. Eastern Energy Gas
accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners primarily based on their percentage of ownership. Operating costs and expenses on the Consolidated Statements of Operations include Eastern Energy Gas' share of the expenses of these facilities.
436
i
The amounts shown in the table
below represent Eastern Energy Gas' share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2023 (dollars in millions):
Accumulated
Construction
Eastern
Energy Gas'
Facility in
Depreciation and
Work-in-
Share
Service
Amortization
Progress
Ellisburg Pool
i39
%
$
i33
$
i12
$
i—
Ellisburg
Station
i50
i29
i9
i2
Harrison
i50
i56
i19
i1
Leidy
i50
i148
i49
i2
Oakford
i50
i216
i73
i4
Total
$
i482
$
i162
$
i9
/
(6) iRegulatory
Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future regulated rates. iEastern Energy Gas' regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average Remaining Life
2023
2022
Employee benefit plans(1)
i11 years
$
i33
$
i32
Other
Various
i21
i16
Total
regulatory assets
$
i54
$
i48
Reflected
as:
Other current assets
$
i9
$
i8
Other
assets
i45
i40
Total regulatory assets
$
i54
$
i48
(1)Represents
costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain rate-regulated subsidiaries.
Eastern Energy Gas had regulatory assets not earning a return on investment of $i48 million and $i44
million as of December 31, 2023 and 2022, respectively.
437
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts expected to be returned to customers in future periods. iEastern Energy Gas'
regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted Average Remaining Life
2023
2022
Income
taxes refundable through future rates(1)
Various
$
i425
$
i406
Other
postretirement benefit costs(2)
Various
i124
i123
Provision
for rate refunds(3)
i—
i90
Cost
of removal(4)
i47 years
i85
i82
Other
Various
i22
i21
Total
regulatory liabilities
$
i656
$
i722
Reflected
as:
Current liabilities
$
i33
$
i126
Noncurrent
liabilities
i623
i596
Total regulatory liabilities
$
i656
$
i722
(1)Amounts
primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.
(3)Reflects amounts refunded to customers in late February 2023 in connection with the EGTS rate case. See below for more information.
(4)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing
regulated property, plant and equipment in accordance with accepted regulatory practices. Refer to Note 11 for more information.
Regulatory Matters
Carolina Gas Transmission, LLC
In November 2023, Carolina Gas Transmission, LLC ("CGT") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective January 1, 2024. CGT's current rates were established by a 2011 settlement. CGT proposed an annual cost-of-service of $i167 million,
and requested increases in various rates, including Zone 1 general system transportation rates by i84% and Zone 2 general system transportation rates by i23%. In December 2023, the FERC suspended the rate
changes for five months following the proposed effective date, until June 1, 2024, subject to refund and the outcome of hearing procedures. This matter is pending.
Eastern Gas Transmission and Storage, Inc.
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS proposed an annual cost-of-service of approximately $i1.1 billion,
and requested increases in various rates, including general system storage rates by i85% and general system transmission rates by i60%. In October 2021, the FERC issued an order that accepted the November
1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $i160 million and a decrease in
annual depreciation expense of approximately $i30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $i91 million.
In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.
438
(7) iInvestments and Restricted Cash and Cash Equivalents
i
Investments
and restricted cash and cash equivalents consists of the following as of December 31 (in millions):
2023
2022
Investments:
Investment funds
$
i19
$
i14
Equity
method investments:
Iroquois
i262
i264
Total
investments
i281
i278
Restricted
cash and cash equivalents:
Customer deposits
i31
i30
Total
restricted cash and cash equivalents
i31
i30
Total
investments and restricted cash and cash equivalents
$
i312
$
i308
Reflected
as:
Current assets
$
i31
$
i30
Noncurrent
assets
i281
i278
Total
investments and restricted cash and cash equivalents
$
i312
$
i308
/
Equity
Method Investments
Eastern Energy Gas, through subsidiaries, owns i50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut.
As of December 31, 2023 and 2022, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in net assets by $ii130/ million.
The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas made contributions of $i154 million in 2021. Eastern Energy Gas received distributions from its investments of $i73
million, $i195 million and $i44 million for the years ended December 31, 2023, 2022
and 2021, respectively. In the third quarter of 2022, in connection with the settlement of regulated tax matters in the Iroquois rate case, Eastern Energy Gas released a long-term regulatory liability and recognized a $i45 million benefit that was recorded in equity income (loss) in its Consolidated Statements of Operations.
(8) iLong-term
Debt
On June 30, 2021, as part of an intercompany transaction with its wholly owned subsidiary EGTS, Eastern Energy Gas exchanged a total of $i1.6 billion of its issued and outstanding third-party notes, making EGTS the primary obligor of the exchanged notes. The intercompany debt exchange was a common control transaction accounted for as a debt modification with no gain or loss recognized on the Consolidated Financial Statements.
439
i
Eastern
Energy Gas' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars and euros in millions):
Par Value
2023
2022
Eastern
Energy Gas:
i2.875% Senior Notes, due 2023
$
i—
$
i—
$
i250
i3.55%
Senior Notes, due 2023
i—
i—
i399
i2.50%
Senior Notes, due 2024
i600
i600
i598
i3.60%
Senior Notes, due 2024
i339
i339
i338
i3.32%
Senior Notes, due 2026 (€i250)(1)
i276
i274
i267
i3.00%
Senior Notes, due 2029
i174
i173
i173
i3.80%
Senior Notes, due 2031
i150
i150
i150
i4.80%
Senior Notes, due 2043
i54
i53
i53
i4.60%
Senior Notes, due 2044
i56
i56
i56
i3.90%
Senior Notes, due 2049
i27
i26
i26
EGTS:
i3.60%
Senior Notes, due 2024
i111
i111
i110
i3.00%
Senior Notes, due 2029
i426
i422
i422
i4.80%
Senior Notes, due 2043
i346
i342
i342
i4.60%
Senior Notes, due 2044
i444
i437
i437
i3.90%
Senior Notes, due 2049
i273
i271
i271
Total
long-term debt
$
i3,276
$
i3,254
$
i3,892
Reflected
as:
Current portion of long-term debt
$
i1,050
$
i649
Long-term
debt
i2,204
i3,243
Total
long-term debt
$
i3,254
$
i3,892
(1)The
senior notes are denominated in Euros with an outstanding principal balance of €i250 million and a fixed interest rate of i1.45%. Eastern Energy Gas has entered into cross currency swaps that fix USD payments for i100%
of the notes. The fixed USD outstanding principal when combined with the swaps is $ii280/ million,
with fixed interest rates as of December 31, 2023 and 2022 that averaged ii3.32/%.
/
Eastern
Energy Gas currently has an effective shelf registration statement with the U.S. Securities and Exchange Commission to issue up to $i2.5 billion of long-term debt securities through January 11, 2027.
Annual Payment on Long-Term Debt
i
The
annual repayments of long-term debt for the years beginning January 1, 2024 and thereafter, are as follows (in millions):
2024
$
i1,050
2025
i—
2026
i276
2027
i—
2028
i—
2029
and thereafter
i1,950
Total
i3,276
Unamortized
premium, discount and debt issuance cost
(i22)
Total
$
i3,254
/
440
(9) iIncome
Taxes
i
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Current:
Federal
$
(i236)
$
i12
$
(i47)
State
(i7)
i29
(i21)
(i243)
i41
(i68)
Deferred:
Federal
i357
i88
i129
State
(i4)
i38
i56
i353
i126
i185
Total
$
i110
$
i167
$
i117
/
i
A
reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense (benefit) is as follows for the years ended December 31:
2023
2022
2021
Federal
statutory income tax rate
i21
%
i21
%
i21
%
State
income tax, net of federal income tax benefit
(i1)
i6
i3
Equity
interest
i2
i2
i1
Effects
of ratemaking
i—
(i1)
i1
Noncontrolling
interest
(i9)
(i10)
(i11)
Other,
net
i—
i—
i1
Effective
income tax rate
i13
%
i18
%
i16
%
/
For
the year ended December 31, 2023, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by the absence of tax on noncontrolling interest.
441
i
The net deferred income tax liability consists of the following as of December 31 (in millions):
2023
2022
Deferred
income tax assets:
Federal and state carryforwards
$
i22
$
i23
Employee
benefits
i29
i22
Intangibles
i98
i112
Derivatives
and hedges
i13
i16
Deferred state income taxes
i24
i—
Other
i4
i7
Total
deferred income tax assets
i190
i180
Deferred
income tax liabilities:
Property-related items
(i343)
(i214)
Partnership
investments
(i158)
(i51)
Debt
exchange
(i50)
(i53)
Deferred
state income taxes
i—
(i4)
Other
(i5)
(i12)
Total
deferred income tax liabilities
(i556)
(i334)
Net deferred income tax liability(1)
$
(i366)
$
(i154)
/
(1)As
of December 31, 2023 and 2022, net deferred income tax liability is presented in other assets and long-term liabilities in the Consolidated Balance Sheets.
As of December 31, 2023, Eastern Energy Gas' state tax carryforwards, entirely related to $i22 million of net operating losses, expire at various intervals between 2036 and
indefinite.
The U.S. Internal Revenue Service has not closed or effectively settled an examination of Eastern Energy Gas' income tax returns for any tax years beginning on or after November 1, 2020. The statute of limitations for Eastern Energy Gas' states remains open for periods beginning on or after November 1, 2020. The closure of examinations, or the expiration of the statute of limitations, for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
(10) iEmployee
Benefit Plans
Defined Benefit Plans
Eastern Energy Gas is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Eastern Energy Gas. Eastern Energy Gas made $i8
million, $i14 million and $i18 million of contributions to the MidAmerican Energy Company Retirement Plan for the years ended December 31, 2023,
2022 and 2021, respectively. Eastern Energy Gas made $i2 million, $i2 million and $i10
million of contributions to the MidAmerican Energy Company Welfare Benefit Plan for the years ended December 31, 2023, 2022 and 2021, respectively. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense in the Consolidated Statements of Operations. Amounts attributable to Eastern Energy Gas were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
442
Defined
Contribution Plan
Eastern Energy Gas participated in the BHE GT&S defined contribution employee savings plan. Effective April 1, 2023, Eastern Energy Gas participates in the MidAmerican Energy defined contribution plan. Eastern Energy Gas' matching contributions are based on each participant's level of contribution. Contributions cannot exceed the maximum allowable for tax purposes. Certain participants now receive enhanced benefits in the plan and no longer accrue benefits in the noncontributory defined benefit pension plans. Eastern Energy Gas' contributions to the plans were $i12
million, $i6 million and $i5 million for the years ended December 31, 2023, 2022 and 2021,
respectively.
(11) iAsset Retirement Obligations
Eastern Energy Gas estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates
could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Eastern Energy Gas does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on the Cove Point LNG facility, interim removal of natural gas pipelines and certain storage wells in EGTS' underground natural gas storage network cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. Cost of removal regulatory liabilities totaled $i85
million and $i82 million as of December 31, 2023 and 2022, respectively. Eastern Energy Gas will continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets.
i
The
following table reconciles the beginning and ending balances of Eastern Energy Gas' ARO liabilities for the years ended December 31 (in millions):
2023
2022
Beginning balance
$
i48
$
i55
Additions
i—
i4
Retirements
(i19)
(i12)
Accretion
i1
i1
Ending
balance
$
i30
$
i48
Reflected
as:
Other current liabilities
$
i5
$
i25
Other
long-term liabilities
i25
i23
Total ARO liability
$
i30
$
i48
/
(12) iRisk
Management and Hedging Activities
Eastern Energy Gas is exposed to the impact of market fluctuations in commodity prices, interest rates, and foreign currency exchange rates. Eastern Energy Gas is principally exposed to natural gas market fluctuations primarily through fuel retained and used during the operation of the pipeline system, to interest rate risk on its outstanding variable-rate short-term debt and future debt issuances, and to foreign currency exchange risk associated with Euro denominated debt. Eastern Energy Gas has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Eastern Energy Gas uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future
supply or sell future production generally at fixed prices. Eastern Energy Gas also uses interest rate swaps to hedge its exposure to variable interest rates on long-term debt as well as foreign currency swaps to hedge its exposure to principal and interest payments denominated in Euros. Eastern Energy Gas does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Eastern Energy Gas' accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
443
Derivative Contract Volumes
i
The
following table summarizes the combined absolute value of long and short positions of outstanding commodity and foreign currency derivative contracts with fixed price terms that comprise the mark-to-market values as of December 31 (in millions):
Unit of
Measure
2023
2022
Foreign
currency
Euro €
i250
i250
Natural
gas
Dth
i6
i3
/
Credit
Risk
Eastern Energy Gas is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Eastern Energy Gas' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, Eastern Energy Gas analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Eastern Energy Gas enters into netting and collateral arrangements that may include margining and cross-product
netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, Eastern Energy Gas exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Upon the Cove Point LNG export/liquefaction facility commencing commercial operations, the majority of Cove Point's revenue and earnings are from annual reservation payments under certain terminalling, storage and transmission contracts with ST Cove Point, LLC, a joint venture of Sumitomo Corporation and Tokyo Gas Co., LTD., and GAIL Global (USA) LNG, LLC (the "Export Customers"). If such agreements were terminated and Cove Point was unable to replace such agreements on comparable terms, there could be a material impact on results of operations, financial condition and/or cash flows.
The
Export Customers comprised approximately ii38/% of Eastern Energy Gas' operating revenues for the years ended December 31, 2023 and 2022,
with Eastern Energy Gas' largest customer representing approximately i19% and i20% of such amounts, respectively.
For the year ended December 31, 2023, EGTS provided operational service
to i250 customers with approximately i93% of its storage and transmission revenue being provided through firm services. The 10 largest customers provided approximately i40%
of EGTS' total storage and transmission revenue and the thirty largest provided approximately i71% of EGTS' total storage and transmission revenue.
(13) iFair
Value Measurements
The carrying value of Eastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Eastern Energy Gas has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Eastern Energy Gas has the ability to access at
the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Eastern Energy Gas' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Eastern Energy Gas develops these inputs based on the best information available, including its own data.
444
i
The
following table presents Eastern Energy Gas' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Eastern
Energy Gas' investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Eastern Energy Gas transacts. When quoted prices for identical contracts are not available, Eastern Energy Gas uses forward price curves. Forward price curves represent Eastern Energy Gas' estimates of the prices at which a buyer or seller could contract today
for delivery or settlement at future dates. Eastern Energy Gas bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by Eastern Energy Gas. Market price quotations are generally readily obtainable for the applicable term of Eastern Energy Gas' outstanding derivative contracts; therefore, Eastern Energy Gas' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, Eastern Energy Gas uses forward price curves derived from internal models based on perceived pricing
relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
445
Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Financial Statements. The fair value of Eastern Energy Gas' long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities
with similar credit risks. iThe following table presents the carrying value and estimated fair value of Eastern Energy Gas' long-term debt as of December 31 (in millions):
2023
2022
Carrying
Fair
Carrying
Fair
Value
Value
Value
Value
Long-term
debt
$
i3,254
$
i2,968
$
i3,892
$
i3,510
(14) iCommitments
and Contingencies
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Eastern Energy Gas is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Eastern Energy Gas does not believe that such normal
and routine litigation will have a material impact on its consolidated financial results.
Surety Bonds
As of December 31, 2023, Eastern Energy Gas had purchased $i18 million of surety bonds. Under the terms of the surety bonds, Eastern Energy Gas is obligated to indemnify the respective surety bond company for any amounts paid.
(15) iRevenue
from Contracts with Customers
i
The following table summarizes Eastern Energy Gas' Customer Revenue by regulated and nonregulated, with further disaggregation of regulated by line of business, for the years ended December 31 (in millions):
2023
2022
2021
Customer
Revenue:
Regulated:
Gas transmission and storage
$
i1,210
$
i1,179
$
i1,044
Wholesale
i22
i8
i57
Other
i5
i1
(i2)
Total
regulated
i1,237
i1,188
i1,099
Nonregulated
i818
i821
i767
Total
Customer Revenue
i2,055
i2,009
i1,866
Other
revenue(1)
i4
(i3)
i4
Total
operating revenue
$
i2,059
$
i2,006
$
i1,870
(1)Other
revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" which includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts and the royalties from the conveyance of mineral rights accounted for under ASC 932 "Extractive Activities – Oil and Gas".
/
Remaining Performance Obligations
446
i
The
following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2023 (in millions):
Performance obligations expected to be satisfied
Less than 12 months
More
than 12 months
Total
Eastern Energy Gas
$
i1,678
$
i14,687
$
i16,365
/
(16) iComponents
of Accumulated Other Comprehensive Loss, Net
i
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income taxes, for the year ended December 31 (in millions):
The
following table shows the reclassifications from AOCI to net income for the year ended December 31 (in millions):
Amounts
Affected Line Item In The
Reclassified
Consolidated Statements
From
AOCI
of Operations
2023
Deferred (gains) and losses on derivatives-hedging activities:
Interest rate contracts
$
i3
Interest
expense
Foreign currency contracts
(i8)
Other, net
Total
(i5)
Tax
i1
Income
tax expense (benefit)
Total, net of tax
$
(i4)
2022
Deferred
(gains) and losses on derivatives-hedging activities:
Interest rate contracts
$
i3
Interest expense
Foreign
currency contracts
i1
Other, net
Total
i4
Tax
(i1)
Income
tax expense (benefit)
Total, net of tax
$
i3
2021
Deferred (gains)
and losses on derivatives-hedging activities:
Interest rate contracts
$
i6
Interest expense
Foreign currency contracts
i21
Other,
net
Total
i27
Tax
(i7)
Income
tax expense (benefit)
Total, net of tax
$
i20
/i
The
following table presents selected information related to losses on cash flow hedges included in AOCI in Eastern Energy Gas' Consolidated Balance Sheet as of December 31, 2023 (in millions):
AOCI After-Tax
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax
Maximum
Term
Interest rate
$
(i35)
$
(i3)
i252
months
Foreign currency
(i3)
(i2)
i30
months
Total
$
(i38)
$
(i5)
/
The
amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates and foreign currency exchange rates.
448
(17) iVariable
Interest Entities and Noncontrolling Interests
The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity's economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
As of December 31, 2022, Eastern Energy Gas owned i100%
of the general partner interest and i25% of the limited partner interest in Cove Point. As discussed in Note 3, on September 1, 2023, Eastern Energy Gas completed its acquisition of i50%
of the limited partner interests in Cove Point from DEI, and accordingly, owns an aggregate of i75% of the limited partner interests and continues to own i100% of the general partner interest of Cove Point. Eastern Energy Gas concluded that Cove Point is a VIE due
to the limited partners lacking the characteristics of a controlling financial interest. Eastern Energy Gas is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Eastern Energy Gas purchased shared services from Carolina Gas Services, Inc. ("Carolina Gas Services") an affiliated VIE, of $i3 million, $i12
million and $i12 million for the years ended December 31, 2023, 2022 and 2021, respectively. Effective April 2023, Carolina Gas Services no longer provides services to Eastern Energy Gas. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $i1
million as of December 31, 2022. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of Carolina Gas Services as neither it nor any of its consolidated entities had both the power to direct the activities that most significantly impacted its economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Carolina Gas Services provided marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of Carolina Gas Services costs.
Included in noncontrolling interests in the Consolidated Financial Statements are DEI's i50%
interest in Cove Point (through August 2023) and Brookfield Super-Core Infrastructure Partner's i25% interest in Cove Point.
(18) iSupplemental
Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2023
2022
2021
Supplemental disclosure of cash flow information:
Interest
paid, net of amounts capitalized
$
i144
$
i143
$
i144
Income
taxes paid (received), net
$
i5
$
i2
$
(i60)
Supplemental
disclosure of non-cash investing and financing transactions:
Accruals related to property, plant and equipment additions
$
i18
$
i29
$
i42
Equity
distributions(1)
$
(i224)
$
(i42)
$
(i137)
Equity
contributions(1)
$
i38
$
i98
$
i73
(1)Amounts
primarily represent the forgiveness of affiliated receivables/payables.
(19) iRelated Party Transactions
Eastern Energy Gas is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated U.S. federal income tax return. For current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $i67
million and $i16 million as of December 31, 2023 and 2022, respectively. Eastern Energy Gas received net cash receipts for federal and state income taxes from BHE totaling $i47
million for the year ended December 31, 2021.
As of December 31, 2022, Eastern Energy Gas had $i1 million of natural gas imbalances payable to affiliates, presented in other current liabilities on the Consolidated Balance Sheets.
449
i
Presented
below are Eastern Energy Gas' significant transactions with affiliated and related parties for the years ended December 31 (in millions):
2023
2022
2021
Sales of natural
gas and transmission and storage services
$
i5
$
i27
$
i32
Purchases
of natural gas and transmission and storage services
i—
i4
i5
Services
provided by related parties(1)
i99
i83
i51
Services
provided to related parties
i35
i38
i32
(1)Includes
capitalized expenditures.
/
Eastern Energy Gas participates in certain MidAmerican Energy benefit plans as described in Note 10. As of December 31, 2023 and 2022, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $i53
million and $i51 million, respectively.
Borrowings with BHE GT&S
Eastern Energy Gas has a $i400
million intercompany revolving credit agreement from its parent, BHE GT&S, expiring in March 2025. The credit agreement, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate ("SOFR") plus a fixed spread. Net outstanding borrowings totaled $i400 million with a weighted-average interest rate of i5.84%
as of December 31, 2023. Interest expense related to this borrowing totaled $i4 million for the year ended December 31, 2023. There were ino amounts outstanding under the credit agreement
as of December 31, 2022.
BHE GT&S has a $i650 million intercompany revolving credit agreement from Eastern Energy Gas expiring in November 2024. The credit agreement has a variable interest rate based on SOFR plus a fixed spread. There were ino
amounts outstanding under the credit agreement as of December 31, 2023. As of December 31, 2022, $i536 million was outstanding under the credit agreement. Interest income related to this borrowing totaled $i20
million and $i7 million for the years ended December 31, 2023 and 2022, respectively.
450
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Consolidated
Financial Section
451
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of EGTS during the periods included herein. This discussion should be read in conjunction with EGTS' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. EGTS' actual results
in the future could differ significantly from the historical results.
Results of Operations
Overview
Net income for the year ended December 31, 2023 was $238 million, a decrease of $23 million, or 9%, compared to 2022, primarily due to lower margin from regulated gas transmission and storage operations of $20 million, an increase in salaries, wages and benefits and higher technology and related charges, partially offset by lower income tax expense primarily due to favorable state tax adjustments.
Net
income for the year ended December 31, 2022 was $261 million, an increase of $105 million, or 67%, compared to 2021, primarily due to higher margin from regulated gas transmission and storage operations of $128 million and a decrease due to the settlement of depreciation rates in EGTS' general rate case, partially offset by an increase in income tax expense primarily due to higher pre-tax income.
Operating revenue increased $51 million, or 5%, for 2023 compared to 2022, primarily due to an increase in regulated gas transmission and storage services revenues primarily
due to the settlement of EGTS' general rate case of $49 million, an increase in variable revenue related to park and loan activity of $17 million and an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $15 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $29 million.
Cost of (excess) gas was an expense of $38 million for 2023 compared to a credit of $33 million for 2022. The change is primarily from a decrease from other operational and system balancing fuel activities prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $45 million and the unfavorable revaluation of the volumes retained
prior to the effective date of the new fuel tracker due to lower natural gas prices of $27 million.
Operations and maintenance increased $40 million, or 11%, for 2023 compared to 2022, primarily due to an increase in salaries, wages and benefits of $23 million, higher technology and related charges of $13 million and an increase in operational materials and services of $3 million, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.
Depreciation and amortization decreased $1 million, or 1%, for 2023 compared to 2022, primarily due to the settlement of depreciation rates in EGTS' general rate case of $8 million, partially offset by higher plant placed in-service of $7 million.
Property
and other taxes decreased $4 million, or 7%, for 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.
Other, net was income of $1 million for 2023 compared to an expense of $2 million for 2023. The change is primarily from gains on marketable securities.
Income tax expense decreased $30 million, or 28%, for2023 compared to 2022 and the effective tax rate was 25% in 2023 and 29% in 2022. The effective tax rate decreased primarily due to the reduction in the state effective rate.
Operating revenue increased $82 million, or 9%, for 2022 compared to 2021, primarily due to an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $101 million and an increase in variable revenue related to park and loan activity of $24 million, partially offset by a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased volumes of $49 million.
452
Cost of (excess) gas was a credit
of $33 million for 2022 compared to an expense of $13 million for 2021. The change is primarily due to a decrease in volumes sold of $62 million, partially offset by unfavorable change to operational and system balancing volumes of $20 million.
Operations and maintenance decreased $12 million, or 3%, for 2022 compared to 2021, primarily due to a decrease in post-retirement benefit related costs.
Depreciation and amortization decreased $14 million, or 8%, for 2022 compared to 2021, primarily due to the settlement of depreciation rates in EGTS' general rate case of $23 million, partially offset by higher plant placed in-service of $9 million.
Property and other taxes
decreased $8 million, or 13%, for 2022 compared to 2021, primarily due to lower than estimated 2021 tax assessments.
Disallowance and abandonment of utility plant was a credit of $11 million for 2021. The change is due to a 2021 benefit from the finalization of entries for the disallowance of capitalized AFUDC.
Interest expense decreased $9 million, or 12%, for 2022 compared to 2021, primarily due to lower expense of $44 million related to the elimination of long-term indebtedness to Eastern Energy Gas following the Debt Exchange Transaction in June 2021. These decreases were partially offset by $32 million of interest expense incurred under the senior notes issued in connection with that transaction, which bear lower interest rates than the original long-term indebtedness
to Eastern Energy Gas.
Other, net was an expense of $2 million for 2022 compared to a credit of $2 million in 2021. The change is primarily due to losses on marketable securities.
Income tax expense increased $48 million, or 79%, for 2022 compared to 2021 and the effective tax rate was 29% in 2022 and 28% in 2021. The effective tax rate increased primarily due to the revaluation of deferred taxes from changes in various state income tax rates.
Liquidity and Capital Resources
As
of December 31, 2023, EGTS' total net liquidity was as follows (in millions):
Cash and cash equivalents
$
5
Intercompany revolving credit agreement(1)
400
Less:
Notes
payable to affiliates
2
Net intercompany revolving credit agreement
398
Total net liquidity
$
403
Intercompany revolving credit agreement:
Maturity
date
2025
(1)Refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding EGTS' intercompany revolving credit agreement.
Operating Activities
Net cash flows from operating activities for the years ended December 31, 2023 and 2022 were $418 million and $552 million, respectively. The change was primarily due to the repayment of EGTS rate refunds to customers and the timing of income tax payments, partially offset by other changes in
working capital.
453
Net cash flows from operating activities for the years ended December 31, 2022 and 2021 were $552 million and $367 million, respectively. The change was primarily due to the impacts from the proposed rate increase in effect April 1, 2022 for the EGTS general rate case, timing of income tax payments, higher collections of receivables from affiliates and other working capital adjustments.
The timing of EGTS' income tax cash flows from period to period can be significantly affected
by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years ended December 31, 2023 and 2022 were $(237) million and $(286) million, respectively. The change was primarily due to a decrease in capital expenditures of $34 million, proceeds from the assignment of shale development rights of $8 million and a decrease in notes to affiliates of $8 million, partially offset by a decrease in repayments of notes by affiliates of $11 million.
Net cash flows from investing activities for the years ended December 31,
2022 and 2021 were $(286) million and $(357) million, respectively. The change was primarily due to a decrease in capital expenditures of $83 million and lower notes to affiliates of $6 million, partially offset by lower repayments of notes by affiliates of $8 million.
Financing Activities
Net cash flows from financing activities for the year ended December 31, 2023 were $(192) million and consisted of dividends paid to Eastern Energy Gas of $158 million and net repayment of notes payable to Eastern Energy Gas of $34 million.
Net cash flows from financing activities for the year ended December 31,
2022 were $(247) million and consisted of dividends paid to Eastern Energy Gas of $215 million and net repayment of notes payable to Eastern Energy Gas of $32 million.
Net cash flows from financing activities for the year ended December 31, 2021 were $(7) million, primarily reflecting dividends paid of $18 million and the net repayment of notes payable to Eastern Energy Gas of $13 million, partially offset by a $20 million equity contribution from Eastern Energy Gas.
Short-term Debt
As of December 31, 2023, EGTS had $2 million of an outstanding note payable to an affiliate at a weighted average interest rate of 5.41%.
As of December 31, 2022, EGTS had $36 million of an outstanding note payable to an affiliate at a weighted average interest rate of 1.43%. For further discussion, refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Future Uses of Cash
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, new growth projects and the timing of growth projects; changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; system
reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
EGTS' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the years ending December 31 are as follows (in millions):
Historical
Forecast
2021
2022
2023
2024
2025
2026
Natural
gas transmission and storage
$
10
$
35
$
16
$
17
$
46
$
—
Other
348
240
225
250
222
261
Total
$
358
$
275
$
241
$
267
$
268
$
261
454
EGTS'
natural gas transmission and storage capital expenditures primarily include growth capital expenditures related to planned regulated projects. EGTS' other capital expenditures consist primarily of pipeline integrity work, automation and controls upgrades, underground storage, corrosion control, unit exchanges, compressor modifications and projects related to Pipeline Hazardous Materials Safety Administration natural gas storage rules. The amounts also include EGTS' asset modernization program, which includes projects for vintage pipeline replacement, compression replacement, pipeline assessment and underground storage integrity.
Material Cash Requirements
The following table summarizes EGTS' material
cash requirements as of December 31, 2023 (in millions):
Payments Due by Periods
2024
2025-2026
2027-2028
2029
and thereafter
Total
Interest payments on long-term debt(1)
$
64
$
121
$
121
$
813
$
1,119
Natural
gas supply and transmission(1)
46
92
93
26
257
Total cash requirements
$
110
$
213
$
214
$
839
$
1,376
(1)Not
reflected on the Consolidated Balance Sheets.
In addition, EGTS also has cash requirements that may affect its consolidated financial condition that arise from operating leases (refer to Note 5), long-term debt (refer to Note 8), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7), uncertain tax positions (refer to Note 9) and AROs (refer to Note 11). Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10‑K for additional information.
Regulatory Matters
EGTS is
subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding EGTS' general regulatory framework and current regulatory matters.
Environmental Laws and Regulations
EGTS is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. EGTS believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and EGTS is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral and Contingent
Features
Debt of EGTS is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of EGTS' ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
EGTS has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments.
455
Inflation
Historically,
overall inflation and changing prices in the economies where EGTS operates have not had a significant impact on EGTS' consolidated financial results. EGTS operates under cost-of-service based rate-setting structures administered by the FERC. Under these rate-setting structures, EGTS is allowed to include prudent costs in its rates, including the impact of inflation. EGTS attempts to minimize the potential impact of inflation on its operations by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
New
Accounting Pronouncements
For a discussion of new accounting pronouncements affecting EGTS, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional
information becomes available. The following critical accounting estimates are impacted significantly by EGTS' methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with EGTS' Summary of Significant Accounting Policies included in EGTS' Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
EGTS prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, EGTS defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory
assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
EGTS continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit EGTS' ability to recover its costs. EGTS believes its application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal
level. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as AOCI. Total regulatory assets were $36 million and total regulatory liabilities were $545 million as of December 31, 2023. Refer to EGTS' Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding EGTS' regulatory assets and liabilities.
Impairment of Long-Lived Assets
EGTS evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being
held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment supports EGTS' regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
456
The estimate of cash flows arising from the future use of an asset, for the purposes
of impairment analysis, requires the exercise of judgment. Circumstances that could significantly alter the calculation of fair value or the recoverable amount of an asset may include significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset, the physical condition of the asset, future market prices, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect EGTS' results of operations.
Income Taxes
In determining EGTS' income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the FERC. EGTS' income tax returns are
subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. EGTS recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of EGTS' federal, state and local income tax examinations is uncertain, EGTS believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities
that may result from these examinations is not expected to have a material impact on EGTS' consolidated financial results. Refer to EGTS' Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding EGTS' income taxes.
It is probable that EGTS will pass income tax benefit and expense related to the 2017 federal tax rate change from 35% to 21%, certain property-related basis differences and other various differences on to their customers. As of December 31, 2023, these amounts were recognized as a net regulatory liability of $377 million and will be included in regulated rates when the temporary differences reverse.
Item 7A.Quantitative
and Qualitative Disclosures About Market Risk
EGTS' Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. EGTS' significant market risks are primarily associated with commodity prices, interest rates and the extension of credit to counterparties with which EGTS transacts. The following discussion addresses the significant market risks associated with EGTS' business activities. EGTS has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding EGTS' contracts accounted for as derivatives.
Commodity Price Risk
As of February 2023, EGTS recovers its
cost of gas through a fuel tracker and is no longer subject to significant commodity price risk.
Interest Rate Risk
EGTS is exposed to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances. EGTS manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. As a result of the fixed interest rates, EGTS' fixed-rate long-term debt does not expose EGTS to the risk of loss due to changes in market interest rates. Additionally, because fixed-rate long-term debt is not carried at fair value on the Consolidated Balance Sheets, changes in fair value would impact earnings and cash flows only if EGTS were to reacquire all or a portion of these
instruments prior to their maturity. The nature and amount of EGTS' short- and long-term debt can be expected to vary from period to period as a result of future business requirements, market conditions and other factors. Refer to Note 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional discussion of EGTS' long-term debt.
As of December 31, 2023 and 2022, EGTS had short-term variable-rate obligations totaling $2 million and $36 million, respectively, that expose EGTS to the risk of increased interest expense in the event of increases in short-term interest rates. If variable interest rates were to increase by 10% from December 31 levels, it would not have a material effect on EGTS' annual interest expense. The carrying value of the variable-rate obligations
approximates fair value as of December 31, 2023 and 2022.
457
Credit Risk
EGTS is exposed to counterparty credit risk associated with natural gas transmission and storage service contracts with utilities, natural gas producers, power generators, industrials, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent EGTS' counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering
into a transaction, EGTS analyzes the financial condition of each wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate counterparty credit risk, EGTS obtains third-party guarantees, letters of credit, financial guarantee bonds and cash deposits. If required, EGTS exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
EGTS' gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. As of December 31, 2023, EGTS' credit exposure
totaled $24 million. Of this amount, investment grade counterparties, including those internally rated, represented 100%, and no single counterparty, whether investment grade or non-investment grade, exceeded $5 million of exposure.
458
Item 8.Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eastern Gas Transmission and Storage, Inc.
Opinion on the Financial Statements
We
have audited the accompanying consolidated balance sheets of Eastern Gas Transmission and Storage, Inc., and subsidiaries ("EGTS") as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, changes in shareholder's equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of EGTS as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of EGTS' management. Our responsibility is to express an opinion on EGTS' financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to EGTS in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. EGTS is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of EGTS' internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also
included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical
audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters — Effects of Rate Regulation on the Financial Statements — Refer to Notes 2 and 6 to the Financial Statements
EGTS is subject to rate regulation by the Federal Energy Regulatory Commission ("FERC"), which has jurisdiction with respect to the rates of interstate natural gas transmission companies in the respective service territories where EGTS operates. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the
economic effects of rate regulation has a pervasive effect on the financial statements.
Revenue provided by the EGTS' interstate natural gas transmission operations is based primarily on rates approved by the FERC. EGTS defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. EGTS continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another
form of regulation, other regulatory actions or the impact of competition that could limit EGTS' ability to recover its costs. The evaluation reflects the current political and regulatory climate. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the regulatory assets
460
and liabilities will be recognized in net income, returned to customers, or re-established as accumulated other comprehensive income (loss).
We identified the effects of rate regulation on the financial statements as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and
disclosures and the high degree of subjectivity involved in assessing the impact of regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of decisions by the FERC, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the FERC included the following, among others:
•We
evaluated EGTS' disclosures related to the effects of rate regulation by testing recorded balances and evaluating regulatory developments.
•We read relevant regulatory orders issued by the FERC, regulatory statutes, filings made by EGTS and interveners, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected EGTS' filings with the FERC, and the filings with the FERC by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the FERC's treatment of similar costs under similar circumstances.
•We
inquired of management about property, plant, and equipment that may be abandoned. We inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the FERC to identify any evidence that may contradict management's assertion regarding probability of an abandonment.
Adjustments
to reconcile net income to net cash flows from operating activities:
(Gains) losses on other items, net
(i8)
i1
(i8)
Depreciation
and amortization
i151
i152
i166
Allowance
for equity funds
(i5)
(i4)
(i6)
Changes
in regulatory assets and liabilities
(i76)
i61
i—
Deferred
income taxes
i119
i92
i93
Other,
net
(i8)
i6
(i7)
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i15
(i14)
(i28)
Receivables
from affiliates
i4
(i4)
(i46)
Gas
balancing activities
i27
(i31)
i76
Pension
and other postretirement benefit plans
i—
i—
(i17)
Accrued
property, income and other taxes
(i57)
i18
(i23)
Accounts
payable to affiliates
i24
(i8)
i11
Accounts
payable and other liabilities
(i6)
i22
i—
Net
cash flows from operating activities
i418
i552
i367
Cash
flows from investing activities:
Capital expenditures
(i241)
(i275)
(i358)
Proceeds
from assignment of shale development rights
i8
i—
i—
Notes
to affiliates
i—
(i8)
(i14)
Repayment
of notes by affiliates
i—
i11
i19
Other,
net
(i4)
(i14)
(i4)
Net
cash flows from investing activities
(i237)
(i286)
(i357)
Cash
flows from financing activities:
Repayment of notes payable to affiliates, net
(i34)
(i32)
(i13)
Proceeds
from equity contributions
i—
i—
i20
Dividends
paid
(i158)
(i215)
(i18)
Other,
net
i—
i—
i4
Net
cash flows from financing activities
(i192)
(i247)
(i7)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i11)
i19
i3
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i45
i26
i23
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i34
$
i45
$
i26
The
accompanying notes are an integral part of these consolidated financial statements.
467
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)iOrganization
and Operations
Eastern Gas Transmission and Storage, Inc. and its subsidiaries ("EGTS") conduct business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transmission and underground storage. EGTS' operations include transmission assets located in Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. EGTS also operates one of the nation's largest underground natural gas storage systems located in New York, Pennsylvania and West Virginia. EGTS is a wholly owned subsidiary of Eastern Energy Gas Holdings, LLC ("Eastern Energy Gas"), which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway
Inc. ("Berkshire Hathaway").
(2) iSummary of Significant Accounting Policies
i
Basis of Consolidation and
Presentation
The Consolidated Financial Statements include the accounts of EGTS and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.
i
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
i
Accounting
for the Effects of Certain Types of Regulation
EGTS prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, EGTS defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers
or re-established as accumulated other comprehensive income (loss) ("AOCI").
i
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under
the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered when determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
468
i
Cash
and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist of customer deposits as allowed under the FERC gas tariff. iA reconciliation of cash and cash
equivalents and restricted cash and cash equivalents as of December 31, 2023 and 2022, as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i34
$
i45
i
Allowance
for Credit Losses
Trade receivables are primarily short-term in nature and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on EGTS' assessment of the collectability of amounts owed to EGTS by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, EGTS primarily evaluates the financial condition of the individual customer and the nature of any disputed amount.
i
The
changes in the balance of the allowance for credit losses, which is included in trades receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
2023
2022
2021
Beginning balance
$
i—
$
i3
$
i2
Charged
to operating costs and expenses, net
i—
i—
i1
Write-offs,
net
i—
(i3)
i—
Ending
balance
$
i—
$
i—
$
i3
/
i
Derivatives
EGTS
employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price and interest rate risks. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets or other current liabilities on the Consolidated Balance Sheets.
Commodity derivatives used in normal business operations that are settled
by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of gas on the Consolidated Statements of Operations.
For EGTS' derivatives not designated as hedging contracts, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for derivatives related to natural gas sales contracts.
For EGTS' derivatives designated as hedging contracts, EGTS formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. EGTS formally documents hedging activity by transaction type and risk management strategy.
For derivative instruments that are accounted for as cash flow hedges or fair value hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.
469
Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. EGTS discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When
hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.
i
Inventories
Inventories consist
mainly of materials and supplies and are determined using the average cost method.
i
Natural Gas Imbalances
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. EGTS values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind.
Imbalances due to EGTS from other parties are reported in natural gas imbalances and imbalances that EGTS owes to other parties are reported in other current liabilities on the Consolidated Balance Sheets.
i
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. EGTS capitalizes all construction-related materials, direct labor and contract services, as well as indirect construction costs. Indirect construction
costs include debt and equity allowance for funds used during construction ("AFUDC"), as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on estimated useful lives. Depreciation studies are completed by EGTS to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the FERC. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance
Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when EGTS retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by EGTS as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, EGTS
is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
470
i
Asset Retirement Obligations
EGTS recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. EGTS' AROs are primarily
related to the obligations associated with its natural gas pipeline and storage well assets. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For EGTS, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
i
Impairment
EGTS
evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment supports EGTS' regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets.
i
Leases
EGTS
has non-cancelable operating leases primarily for office space, office equipment and land and finance leases consisting primarily of natural gas pipeline facilities and vehicles. These leases generally require EGTS to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. EGTS does not include options in its lease calculations unless there is a triggering event indicating EGTS is reasonably certain to exercise the option. EGTS' accounting policy is to not recognize right-of-use assets and lease obligations
for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
EGTS' operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
i
Revenue
Recognition
EGTS uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which EGTS expects to be entitled in exchange for those goods or services. EGTS records sales and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
A majority of EGTS' Customer Revenue is derived from tariff-based sales arrangements approved by the FERC. These tariff-based revenues are mainly comprised of natural gas transmission and storage services and have performance obligations which are satisfied over time as services are provided.
471
Revenue
recognized is equal to what EGTS has the right to invoice as it corresponds directly with the value to the customer of EGTS' performance to date and includes billed and unbilled amounts. As of December 31, 2023 and 2022, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $i17 million and $i9
million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In the event one of the parties to a contract has performed before the other, EGTS would recognize a contract asset or contract liability depending on the relationship between EGTS' performance and the customer's payment. EGTS has recognized contract assets of $i8
million and $i10 million as of December 31, 2023 and 2022, respectively, and $i2 million and $i9
million of contract liabilities as of December 31, 2023 and 2022, respectively, due to EGTS' performance on certain contracts.
i
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
i
Income
Taxes
Berkshire Hathaway includes EGTS in its consolidated U.S. federal income tax return. Consistent with established regulatory practice, EGTS' provision for income taxes has been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with certain property-related basis differences and other various differences that EGTS' regulated businesses deems probable to be passed on to its customers
are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
EGTS recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated
Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense (benefit) on the Consolidated Statements of Operations.
i
Segment Information
EGTS currently has ione
segment, which includes its natural gas pipeline and storage operations.
/
i
New Accounting Pronouncements
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting Topic 280, "Segment Reporting—Improvements to Reportable Segment Disclosures" which allows disclosure of one or more measures of segment profit or loss used by the chief
operating decision maker to allocate resources and assess performance. Additionally, the standard requires enhanced disclosures of significant segment expenses and other segment items as well as incremental qualitative disclosures on both an annual and interim basis. This guidance is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods after December 15, 2024. Early adoption is permitted and retrospective application is required for all periods presented. EGTS is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
472
In
December 2023, the FASB issued ASU No. 2023-09, Income Taxes Topic 740, "Income Tax—Improvements to Income Tax Disclosures" which requires enhanced disclosures, including specific categories and disaggregation of information in the effective tax rate reconciliation, disaggregated information related to income taxes paid, income or loss from continuing operations before income tax expense or benefit, and income tax expense or benefit from continuing operations. This guidance is effective for annual reporting periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis, however retrospective application is permitted. EGTS is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
(3) iProperty,
Plant and Equipment, Net
i
Property, plant and equipment, net consists of the following as of December 31 (in millions):
Depreciable Life
2023
2022
Interstate
natural gas transmission and storage assets
i28 - i50 years
$
i7,046
$
i6,724
Intangible
plant
i12 - i20 years
i80
i79
Plant
in-service
i7,126
i6,803
Accumulated
depreciation and amortization
(i2,563)
(i2,440)
i4,563
i4,363
Construction
work-in-progress
i152
i141
Property,
plant and equipment, net
$
i4,715
$
i4,504
/
Assignment
of Shale Development Rights
In June 2023, EGTS conveyed development rights to a natural gas producer for approximately i6,500 acres of Utica Shale and Point Pleasant Formation underneath one of its natural gas storage fields and received proceeds of $i8
million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in an $i8 million ($i6
million after-tax) gain, included in operations and maintenance expense in its Consolidated Statements of Operations
(4) iJointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, EGTS, as a tenant in common, has undivided interests in jointly owned transmission and storage facilities. EGTS accounts for its proportionate
share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners primarily based on their percentage of ownership. Operating costs and expenses on the Consolidated Statements of Operations include EGTS' share of the expenses of these facilities.
i
The amounts shown in the table below represent EGTS' share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2023 (dollars in millions):
Accumulated
Construction
EGTS'
Facility
in
Depreciation and
Work-in-
Share
Service
Amortization
Progress
Ellisburg Pool
i39
%
$
i33
$
i12
$
i—
Ellisburg
Station
i50
i29
i9
i2
Harrison
i50
i56
i19
i1
Leidy
i50
i148
i49
i2
Oakford
i50
i216
i73
i4
Total
$
i482
$
i162
$
i9
/
473
(5)iLeases
i
The
following table summarizes EGTS' leases recorded on the Consolidated Balance Sheets as of December 31 (in millions):
2023
2022
Right-of-use assets:
Operating leases
$
i18
$
i19
Total
right-of-use assets
$
i18
$
i19
Lease
liabilities:
Operating leases
$
i17
$
i18
Total
lease liabilities
$
i17
$
i18
/
i
The
following table summarizes EGTS' operating lease costs for the years ended December 31 (in millions):
2023
2022
2021
Total
operating lease costs
$
i2
$
i2
$
i3
Weighted-average
remaining operating lease term (years)
i12.7
i13.7
i14.7
Weighted-average
operating lease discount rate
i4.3
%
i4.3
%
i4.3
%
/
i
The
following table summarizes EGTS' supplemental cash flow information relating to leases for the years ended December 31 (in millions):
2023
2022
2021
Cash
paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
$
i2
$
i2
$
i3
Operating
cash flows from finance leases
i—
i—
i1
/
i
EGTS
has the following remaining operating lease commitments as of December 31, 2023 (in millions):
2024
$
i2
2025
i2
2026
i2
2027
i2
2028
i2
Thereafter
i12
Total
undiscounted lease payments
i22
Less - amounts representing interest
(i5)
Lease
liabilities
$
i17
/
474
(6) iRegulatory
Matters
Regulatory Assets
i
Regulatory assets represent costs that are expected to be recovered in future regulated rates. EGTS' regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted
Average Remaining Life
2023
2022
Employee benefit plans(1)
i11 years
$
i32
$
i31
Other
Various
i4
i8
Total
regulatory assets
$
i36
$
i39
Reflected
as:
Other current assets
$
i3
$
i5
Other
assets
i33
i34
Total regulatory assets
$
i36
$
i39
(1)Represents
costs expected to be recovered through future rates generally over the expected remaining service period of plan participants.
/
EGTS had regulatory assets not earning a return on investment of $i36 million
and $i39 million as of December 31, 2023 and 2022, respectively.
475
Regulatory Liabilities
i
Regulatory
liabilities represent income to be recognized or amounts expected to be returned to customers in future periods. EGTS' regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
Weighted Average Remaining Life
2023
2022
Income
taxes refundable through future rates(1)
Various
$
i377
$
i382
Other
postretirement benefit costs(2)
Various
i124
i123
Provision
for rate refunds(3)
i—
i90
Cost
of removal(4)
i47 years
i28
i24
Other
Various
i16
i8
Total
regulatory liabilities
$
i545
$
i627
Reflected
as:
Current liabilities
$
i22
$
i109
Noncurrent
liabilities
i523
i518
Total regulatory liabilities
$
i545
$
i627
(1)Amounts
primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.
(3)Reflects amounts refunded to customers in late February 2023 in connection with the EGTS rate case. See below for more information.
(4)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing
regulated property, plant and equipment in accordance with accepted regulatory practices. Refer to Note 11 for more information.
/
Regulatory Matters
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS proposed an annual cost-of-service of approximately $i1.1 billion,
and requested increases in various rates, including general system storage rates by i85% and general system transmission rates by i60%. In October 2021, the FERC issued an order that accepted the November
1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $i160 million and a decrease in
annual depreciation expense of approximately $i30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $i91 million.
In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.
476
In July 2017, the FERC audit staff communicated to EGTS that it had substantially completed an audit of EGTS' compliance with the accounting and reporting requirements of the FERC's Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report. In December 2017, EGTS provided its response to the audit report. EGTS requested FERC review of the contested findings and submitted its plan for compliance with the uncontested portions of the report. EGTS reached resolution of certain matters with the FERC
in the fourth quarter of 2018. EGTS recognized a charge for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with the FERC. In December 2020, the FERC issued a final ruling on the remaining matter, which resulted in a $i43 million ($i31 million
after-tax) estimated charge for disallowance of capitalized AFUDC. As a condition of the December 2020 ruling, EGTS filed its proposed accounting entries and supporting documentation with the FERC during the second quarter of 2021. During the finalization of these entries, EGTS refined the estimated charge for disallowance of capitalized AFUDC, which resulted in a reduction to the estimated charge of $i11 million ($i8 million
after-tax) that was recorded in disallowance and abandonment of utility plant on the Consolidated Statement of Operations in the second quarter of 2021. In September 2021, the FERC approved EGTS' accounting entries and supporting documentation.
(7) iInvestments and Restricted Cash and Cash Equivalents
i
Investments
and restricted cash and cash equivalents consists of the following as of December 31 (in millions):
2023
2022
Investments:
Investment funds
$
i19
$
i14
Restricted
cash and cash equivalents:
Customer deposits
i29
i29
Total
restricted cash and cash equivalents
i29
i29
Total
investments and restricted cash and cash equivalents
$
i48
$
i43
Reflected
as:
Current assets
$
i29
$
i29
Other
assets
i19
i14
Total
investments and restricted cash and cash equivalents
$
i48
$
i43
/
(8) iLong-term
Debt
On June 30, 2021, Eastern Energy Gas exchanged a total of $i1.6 billion of its issued and outstanding third-party notes for new notes, making EGTS the primary obligor of the new notes. The terms of the new notes are substantially similar to the terms of the original Eastern Energy Gas notes. The debt exchange was a common control transaction accounted for as a debt modification. As such, no gain or loss was recognized on the Consolidated Statements of Operations and approximately $i17 million
of unamortized discounts and debt issuance costs and $i32 million of deferred losses on previously settled interest rate swaps remaining in AOCI were contributed to EGTS by Eastern Energy Gas in connection with the transaction. In addition, new fees of $i2 million
paid directly to note holders in connection with the exchange were deferred as additional debt issuance costs that will be amortized over the lives of the respective notes. As a result of the transaction, EGTS' $i1.9 billion of long-term indebtedness to Eastern Energy Gas was cancelled in full and the remaining balance was satisfied through a capital contribution.
i
477
EGTS'
long-term debt consists of the following, including unamortized discounts and debt issuance costs, as of December 31 (dollars in millions):
Par Value
2023
2022
i3.60%
Senior Notes, due 2024
$
i111
$
i111
$
i110
i3.00%
Senior Notes, due 2029
i426
i422
i422
i4.80%
Senior Notes, due 2043
i346
i342
i342
i4.60%
Senior Notes, due 2044
i444
i437
i437
i3.90%
Senior Notes, due 2049
i273
i271
i271
Total
long-term debt
$
i1,600
$
i1,583
$
i1,582
Reflected
as:
Current portion of long-term debt
$
i111
$
i—
Long-term
debt
i1,472
i1,582
Total
long-term debt
$
i1,583
$
i1,582
Annual
Payment on Long-Term Debt
i
The annual repayments of long-term debt for the years beginning January 1, 2024 and thereafter, are as follows (in millions):
2024
$
i111
2025
i—
2026
i—
2027
i—
2028
i—
2029
and thereafter
i1,489
Total
i1,600
Unamortized
discounts and debt issuance costs
(i17)
Total
$
i1,583
/
AOCI
i
The
following table presents selected information related to losses on interest rate cash flow hedges included in AOCI in EGTS' Consolidated Balance Sheets as of December 31, 2023 (in millions):
AOCI After-Tax
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax
Maximum
Term
Interest rate
$
(i28)
$
(i2)
i252
months
/
EGTS reclassified $i3 million, $i2
million and $i1 million from AOCI to interest expense for the years ended December 31, 2023, 2022 and 2021, respectively.
478
(9) iIncome
Taxes
i
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2023
2022
2021
Current:
Federal
$
(i28)
$
i5
$
(i22)
State
(i12)
i12
(i10)
(i40)
i17
(i32)
Deferred:
Federal
i91
i64
i67
State
i28
i28
i26
i119
i92
i93
Total
$
i79
$
i109
$
i61
/
i
A
reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income (loss) before income tax expense (benefit) is as follows for the years ended December 31:
2023
2022
2021
Federal
statutory income tax rate
i21
%
i21
%
i21
%
State
income tax, net of federal income tax benefit
i4
i9
i8
Other,
net
i—
(i1)
(i1)
Effective
income tax rate
i25
%
i29
%
i28
%
/
i
The
net deferred income tax (liability) asset consists of the following as of December 31 (in millions):
2023
2022
Deferred income tax assets:
Federal and state carryforwards
$
i5
$
i6
Employee
benefits
i26
i22
Intangibles
and goodwill
i252
i265
Derivatives
and hedges
i10
i11
Other
i5
i4
Total
deferred income tax assets
i298
i308
Deferred
income tax liabilities:
Property-related items
(i264)
(i146)
Debt
exchange
(i50)
(i53)
Employee benefits
i—
(i4)
Total
deferred income tax liabilities
(i314)
(i203)
Net deferred income tax (liability)
asset(1)
$
(i16)
$
i105
(1)As
of December 31, 2023, net federal deferred income tax liability is presented in other long-term liabilities and net state deferred income tax asset is presented in other assets in the Consolidated Balance Sheets. As of December 31, 2022, net deferred income tax assets is presented in other assets in the Consolidated Balance Sheets.
/
479
As of December 31, 2023, EGTS' state tax carryforwards, entirely related to $i5
million of net operating losses, expire at various intervals between 2036 and indefinite.
The U.S. Internal Revenue Service has not closed or effectively settled an examination of EGTS' income tax returns for any tax years beginning on or after November 1, 2020. The statute of limitations for EGTS' states remains open for periods beginning on or after November 1, 2020. The closure of examinations, or the expiration of the statute of limitations, for state filings may not preclude the state from adjusting the state net operating loss carryforward utilized in a year for which the statute of limitations is not closed.
(10) iEmployee
Benefit Plans
Defined Benefit Plans
EGTS is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of EGTS. EGTS made $i7
million, $i12 million and $i16 million of contributions to the MidAmerican Energy Company Retirement Plan for the years ended December 31, 2023,
2022 and 2021, respectively. EGTS made $i2 million, $i2 million and $i9
million of contributions to the MidAmerican Energy Company Welfare Benefit Plan for the years ended December 31, 2023, 2022 and 2021, respectively. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense in the Consolidated Statements of Operations. Amounts attributable to EGTS were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates.
Defined Contribution Plan
EGTS
participated in the BHE GT&S defined contribution employee savings plan. Effective April 1, 2023, EGTS participates in the MidAmerican Energy defined contribution plan. EGTS' matching contributions are based on each participant's level of contribution. Contributions cannot exceed the maximum allowable for tax purposes. Certain participants now receive enhanced benefits in the plan and no longer accrue benefits in the noncontributory defined benefit pension plans. EGTS' contributions to the plans were $i9
million, $i5 million and $i4 million for the years ended December 31,
2023, 2022 and 2021, respectively.
(11) iAsset Retirement Obligations
EGTS estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending
estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
EGTS does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the interim removal of natural gas pipelines and certain storage wells in EGTS' underground natural gas storage network cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. Cost of removal regulatory liabilities totaled $i28
million and $i24 million as of December 31, 2023 and 2022, respectively. EGTS will continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets.
480
i
The
following table reconciles the beginning and ending balances of EGTS' ARO liabilities for the years ended December 31 (in millions):
2023
2022
Beginning balance
$
i48
$
i55
Additions
i—
i4
Retirements
(i19)
(i12)
Accretion
i1
i1
Ending
balance
$
i30
$
i48
Reflected
as:
Current liabilities
$
i5
$
i25
Other
long-term liabilities
i25
i23
Total ARO liability
$
i30
$
i48
/
(12) iRisk
Management and Hedging Activities
EGTS is exposed to the impact of market fluctuations in commodity prices, principally, to natural gas market fluctuations primarily related to fuel retained and used during the operation of the pipeline system. EGTS has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report, each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, EGTS uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. EGTS does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. See Note 13 for further information about fair value measurements and associated valuation methods
for derivatives.
There have been no significant changes in EGTS' accounting policies related to derivatives. Refer to Notes 2 and 13 for additional information on derivative contracts.
Credit Risk
EGTS is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent EGTS' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. For the year ended December 31, 2023, the 10 largest customers provided i40%
of the total storage and transmission revenues. Before entering into a transaction, EGTS analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, EGTS enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, EGTS exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
(13) iFair
Value Measurements
The carrying value of EGTS' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. EGTS has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that EGTS has the ability to access at the measurement date.
•Level
2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
481
•Level 3 - Unobservable inputs reflect EGTS' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. EGTS develops these inputs based on the best information available, including its own data.
i
The
following table presents EGTS' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
EGTS'
investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which EGTS transacts. When quoted prices for identical contracts are not available, EGTS uses forward price curves. Forward price curves represent EGTS' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future
dates. EGTS bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by EGTS. Market price quotations are generally readily obtainable for the applicable term of EGTS' outstanding derivative contracts; therefore, EGTS' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, EGTS uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of
these derivative contracts is a function of underlying forward commodity prices, related volatility, counterparty creditworthiness and duration of contracts.
EGTS' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Financial Statements. The fair value of EGTS' long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. iThe
following table presents the carrying value and estimated fair value of EGTS' long-term debt as of December 31 (in millions):
2023
2022
Carrying
Fair
Carrying
Fair
Value
Value
Value
Value
Long-term
debt
$
i1,583
$
i1,386
$
i1,582
$
i1,337
482
(14) iCommitments
and Contingencies
Environmental Laws and Regulations
EGTS is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. EGTS believes it is in material compliance with all applicable laws and regulations.
Legal Matters
EGTS is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. EGTS does not believe that such normal and routine litigation will have a material impact on
its consolidated financial results.
Surety Bonds
As of December 31, 2023, EGTS had purchased $i15 million of surety bonds. Under the terms of the surety bonds, Eastern Energy Gas is obligated to indemnify the respective surety bond company for any amounts paid.
(15) iRevenue
from Contracts with Customers
i
The following table summarizes EGTS' Customer Revenue by regulated and other, with further disaggregation of regulated by line of business, for the years ended December 31 (in millions):
2023
2022
2021
Customer
Revenue:
Regulated:
Gas transmission
$
i656
$
i644
$
i574
Gas
storage
i274
i248
i188
Wholesale
i22
i8
i57
Other
i2
i—
i—
Total
regulated
i954
i900
i819
Management
services and other revenues
i66
i79
i73
Total
Customer Revenue
i1,020
i979
i892
Other
revenue(1)
i4
(i6)
(i1)
Total
operating revenue
$
i1,024
$
i973
$
i891
(1)Other
revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" which includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts and the royalties from the conveyance of mineral rights accounted for under ASC 932 "Extractive Activities – Oil and Gas".
/
Remaining Performance Obligations
i
The
following table summarizes EGTS' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of December 31, 2023 (in millions):
Performance obligations expected to be satisfied
Less than 12 months
More
than 12 months
Total
EGTS
$
i794
$
i3,346
$
i4,140
/
(16) iSupplemental
Cash Flow Disclosures
483
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2023
2022
2021
Supplemental
disclosure of cash flow information:
Interest paid, net of amounts capitalized
$
i69
$
i67
$
i71
Income
taxes paid (received), net
$
i5
$
i2
$
(i12)
Supplemental
disclosure of non-cash investing and financing transactions:
Accruals related to property, plant and equipment additions
$
i9
$
i15
$
i29
Equity
dividends(1)
$
(i23)
$
(i21)
$
(i58)
Equity
contributions(2)
$
i29
$
i34
$
i292
(1)Equity
dividends represents the forgiveness of affiliated receivables.
(2)Equity contributions for the year ended December 31, 2021 primarily reflect the impacts from the intercompany debt exchange with Eastern Energy Gas. See Note 8 for more information regarding the intercompany debt exchange with Eastern Energy Gas.
(17) iRelated Party
Transactions
EGTS is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated U.S. federal income tax return. For current federal and state income taxes, EGTS had a receivable from BHE of $i57 million and $i21
million as of December 31, 2023 and 2022, respectively. EGTS received net cash receipts for federal and state income taxes from BHE totaling $i10 million for the year ended December 31, 2021.
Trade receivables, net as of December 31, 2022 included $i2
million of accrued unbilled revenue. This revenue is based on estimated amounts of services provided but not yet billed to an affiliate.
As of December 31, 2023, EGTS had $i2 million of natural gas imbalances receivable from affiliates, presented in natural gas imbalances on the Consolidated Balance Sheets. As of December 31, 2022, EGTS had $i10
million of natural gas imbalances payable to affiliates, presented in other current liabilities on the Consolidated Balance Sheets.
EGTS participates in certain MidAmerican Energy benefit plans as described in Note 10. As of December 31, 2023 and 2022, EGTS' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $i48 million and $i47
million, respectively.
i
Presented below are EGTS' significant transactions with related parties for the years ended December 31 (in millions):
2023
2022
2021
Sales
of natural gas and transmission and storage services
$
i4
$
i26
$
i28
Purchases
of natural gas and transmission and storage services
i—
i4
i5
Services
provided by related parties(1)
i58
i46
i26
Services
provided to related parties
i59
i62
i57
(1)Includes
capitalized expenditures.
/
Borrowings With Eastern Energy Gas
EGTS has a $i400 million intercompany revolving credit agreement from its parent, Eastern Energy Gas, expiring in March 2025. The credit agreement, which is for general corporate purposes, has
a variable interest rate based on the Secured Overnight Financing Rate ("SOFR") plus a fixed spread. Net outstanding borrowings totaled $i2 million with a weighted-average interest rate of i5.41% as of December 31, 2023 and $i36
million with a weighted-average interest rate of i1.43% as of December 31, 2022. Interest expense related to this borrowing totaled $i1 million for the year ended December 31, 2023.
Eastern
Energy Gas has a $i400 million intercompany revolving credit agreement from EGTS expiring in March 2025. The credit agreement has a variable interest rate based on SOFR plus a fixed spread. There were iino/
amounts outstanding under the
EGTS
had also borrowed from Eastern Energy Gas pursuant to a series of long-term notes with fixed interest rates ranging from i3.6% to i5.0%, due 2024 to 2047. EGTS incurred interest charges related to these borrowings of $i44
million for the year ended December 31, 2021. Refer to Note 8 for more information.
485
Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.Controls and Procedures
Disclosure
Controls and Procedures
At the end of the period covered by this Annual Report on Form 10-K, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief
Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the U.S. Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended
December 31, 2023 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
Management of each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc., respectively, is responsible for establishing and maintaining, for such entity, adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). Under the supervision and with the participation of management for each such entity, including
its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, such management conducted an evaluation for the relevant entity of the effectiveness of internal control over financial reporting as of December 31, 2023, as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, management for each such respective entity used the criteria set forth in the framework in "Internal Control - Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation conducted under the framework in "Internal Control - Integrated Framework (2013)," management for each such respective entity concluded that internal control over financial reporting for such entity was effective as of December 31,
2023.
Item 10.Directors, Executive Officers and Corporate Governance
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, SIERRA PACIFIC, EASTERN ENERGY GAS AND EGTS
Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
PacifiCorp is an indirect subsidiary of BHE, and its directors consist of executive management from both BHE
and PacifiCorp. Each director was elected based on individual responsibilities, experience in the energy industry and functional expertise. There are no family relationships among the executive officers, nor any arrangements or understandings between any executive officer and any other person pursuant to which the executive officer was appointed. Set forth below is certain information, as of January 31, 2024, with respect to the current directors and executive officers of PacifiCorp:
CINDY A. CRANE, 62,Chair of the Board of Directors and Chief Executive Officer since September 2023. Prior to her current positions, Ms. Crane served as President and Chief Executive Officer of Rocky Mountain
Power from 2014 and director from 2015 to 2018. Ms. Crane was Vice President of Interwest Mining Company, a subsidiary of PacifiCorp, from 2009 to 2014. Ms. Crane joined PacifiCorp in 1990 and has significant strategy, operational and leadership experience in the energy industry, including complex commercial negotiations.
GARY W. HOOGEVEEN, 55, Director since November 2018, President since June 2018 and Chief Executive Officer since November 2018 of Rocky Mountain Power. Prior to his current positions, Mr. Hoogeveen served as Senior Vice President and Chief Commercial Officer of Rocky Mountain Power since November 2014 and President and CEO of Kern River Gas Transmission Company from 2010 to 2014. He joined Kern River after serving as Vice President of Customer Service and Business
Development for Northern Natural Gas Company. Prior to joining Northern Natural Gas Company, Mr. Hoogeveen held various management positions at Berkshire Hathaway Energy, joining BHE in 2000. He has significant operational, public policy and leadership experience in both the electricity and natural gas industries, including customer, regulatory and government relations.
NIKKI L. KOBLIHA, 51, Director since 2017. Vice President and Chief Financial Officer since 2015 and Treasurer since 2017. Ms. Kobliha joined PacifiCorp in 1997 and has significant financial, accounting and leadership experience in the energy industry, including expertise in financial reporting to the SEC and FERC.
CALVIN
D. HAACK, 55, Director since May 2020. Mr. Haack has been Senior Vice President and Chief Financial Officer of BHE since March 2020 and was Vice President and Treasurer of BHE from 2010 to 2020. Mr. Haack joined BHE in 1997 and has significant financial experience, including expertise in mergers and acquisitions, accounting, treasury and tax functions. Mr. Haack is also a manager of MidAmerican Funding, LLC and Eastern Energy Gas Holdings, LLC.
NATALIE L. HOCKEN, 54, Director since 2007. Ms. Hocken has been Senior Vice President and General Counsel of BHE since 2015 and Corporate Secretary since 2017. Ms. Hocken was Senior Vice President, Transmission and System Operations of PacifiCorp from 2012 to 2015 and Vice President and General Counsel of Pacific
Power from 2007 to 2012. Ms. Hocken joined PacifiCorp in 2002 and has significant experience in the utility industry, including expertise in transmission, legal matters and federal and state regulatory matters. Ms. Hocken is also a manager of MidAmerican Funding, LLC and Eastern Energy Gas Holdings, LLC.
Board's Role in the Risk Oversight Process
PacifiCorp's Board of Directors is comprised of a combination of BHE senior executives and PacifiCorp senior management who have direct and indirect responsibility for the management and oversight of risk. PacifiCorp's Board of Directors has not established a separate risk management and oversight committee.
Audit Committee and Audit Committee Financial Expert
During
the year ended December 31, 2023, and as of the date of this Annual Report on Form 10-K, PacifiCorp's Board of Directors did not have an audit committee. PacifiCorp is not required to have an audit committee as its common stock is indirectly and wholly owned by BHE. However, the audit committee of BHE acts as the audit committee for PacifiCorp.
487
Code of Ethics
PacifiCorp has adopted a code of ethics that applies to its principal executive officer, its principal financial and accounting officer, or persons acting in such capacities, and certain other covered officers. The code of ethics is incorporated
by reference in the exhibits to this Annual Report on Form 10-K.
Item 11.Executive Compensation
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, SIERRA PACIFIC, EASTERN ENERGY GAS AND EGTS
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Compensation
Discussion and Analysis
Compensation Philosophy and Overall Objectives
On September 1, 2023, Mr. Scott W. Thon resigned as PacifiCorp's Chair ("Chair") of the Board of Directors (the "Board") and Chief Executive Officer ("CEO") and Ms. Cindy A. Crane was elected as PacifiCorp's Chair and CEO. Mr. Thon did not receive any direct compensation from PacifiCorp in 2023. Rather, PacifiCorp reimbursed its indirect parent company, BHE, for the cost of Mr. Thon's time spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative
services agreement among BHE and its subsidiaries. As an employee of PacifiCorp, Ms. Crane receives direct compensation from PacifiCorp.
PacifiCorp believes that the compensation paid to its CEO, Chief Financial Officer ("CFO"), and its other most highly compensated executive officers, referred to collectively as the Named Executive Officers ("NEOs"), should be closely aligned with PacifiCorp's overall performance, and each NEO's contribution to that performance, on both a short- and long-term basis, and that such compensation should be sufficient to attract and retain highly qualified leaders who can create significant value for the organization. PacifiCorp's compensation programs are designed to provide its NEOs meaningful incentives for superior corporate and individual performance. Performance is evaluated on a subjective basis within the context of both financial and
non-financial objectives, among which are customer service, employee commitment, environmental respect, regulatory integrity, operational excellence and financial strength, which PacifiCorp believes contribute to its long-term success.
How Compensation is Determined
PacifiCorp's compensation committee consists solely of the Chair and CEO. The Chair and CEO is responsible for the establishment and oversight of PacifiCorp's compensation policy and for approving compensation decisions for the other NEOs, such as approving their base pay increases, incentive and performance awards, off-cycle pay changes, and participation in other employee benefit plans and programs.
PacifiCorp's criteria for assessing executive performance
and determining compensation in any year is inherently subjective and is not based upon specific formulas or weighting of factors. PacifiCorp does not specifically use other companies as benchmarks when establishing its NEOs' compensation.
488
Discussion and Analysis of Specific Compensation Elements
Base Salary
The Chair and CEO determines base salaries for all of its NEOs, other than the Chair and CEO, by reviewing PacifiCorp's overall performance, and each NEO's performance, the value each NEO brings to PacifiCorp and general labor market conditions. Base
salary is intended to compensate NEOs for services rendered during the fiscal year and to provide sufficient cash income for retention and recruitment purposes. While base salary provides a base level of compensation intended to be competitive with the external market, the annual base salary adjustment for each NEO, other than the Chair and CEO, is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. All merit increases for the NEOs (other than the Chair and CEO) are approved by the Chair and CEO and take effect in the last payroll period of the year. An increase or decrease in base salary may also result from a promotion or other significant change in an NEO's responsibilities during the year. For 2023, base salaries for all NEOs, other than the Chair and CEO, increased on average by 3.20% from the previous year effective December 26, 2022,
reflecting merit increases. Ms. Crane's base salary for her role as CEO is based upon her offer of employment.
Short-Term Incentive Compensation
The objective of short-term incentive compensation is to reward the achievement of significant annual corporate and business unit goals while also providing NEOs with competitive total cash compensation. PacifiCorp's short-term incentive compensation programs consist of the Annual Incentive Plan and Cash Performance Awards as described below.
Annual Incentive Plan
Under PacifiCorp's Annual Incentive Plan ("AIP"), all NEOs, other than the Chair and CEO and CFO, are eligible to earn an
annual discretionary cash incentive award, which is determined on a subjective basis at the Chair and CEO's sole discretion and is not based on a specific formula or cap. The Chair and CEO considers a variety of factors in determining each NEO's annual incentive award including the NEO's performance, PacifiCorp's overall performance and each NEO's contribution to that overall performance. The Chair and CEO evaluates performance holistically using a number of objectives, including customer service, employee commitment, environmental respect, regulatory integrity, operational excellence and financial strength, as well as the NEO's response to issues and opportunities that arise during the year. No factor was individually material to the Chair and CEO's determination regarding the amounts paid to each NEO under the AIP for 2023. Approved awards are paid prior to year-end.
Cash Performance
Awards
In addition to the annual awards under the AIP, PacifiCorp may grant cash performance awards ("Cash Performance Awards") periodically during the year to one or more NEOs, other than the Chair and CEO, to reward the accomplishment of significant non-recurring tasks or projects. These awards are discretionary and are approved by the Chair and CEO. No Cash Performance Awards were earned by the NEOs during 2023.
Long-Term Incentive Compensation
The objective of long-term incentive compensation is to retain NEOs, reward their exceptional performance and motivate them to create long-term, sustainable value. PacifiCorp's current long-term incentive compensation program is cash-based. PacifiCorp does not utilize
stock options or other forms of equity-based awards.
489
Long-Term Incentive Partnership Plan
The PacifiCorp Long-Term Incentive Partnership Plan ("LTIP") is designed to retain key employees and to align PacifiCorp's interests and the interests of the participating employees. All of PacifiCorp's NEOs, other than the Chair and CEO and CFO, are eligible to participate in the LTIP. The LTIP provides for annual discretionary awards based upon significant accomplishments by the individual participants and the achievement of the holistic objectives previously described. The goals are developed with the objective of being attainable with a sustained,
focused and concerted effort and are determined and communicated by January of each plan year. The BHE President and CEO and PacifiCorp's Presidents approve eligibility to participate in the LTIP for employees other than the Presidents and the amount of the incentive award. Awards are finalized in the first quarter of the following year. PacifiCorp's Presidents may participate in the LTIP but only the BHE President and CEO shall make determinations regarding their participation and the value of their incentive awards. These cash-based LTIP awards are subject to mandatory deferral and equal annual vesting over a four-year period starting in the performance year. Participants allocate the value of their deferral accounts among various investment alternatives. Gains or losses may be incurred based on investment performance. Participating NEOs may elect to defer all or a part of the award or receive payment in cash after the four-year mandatory deferral and vesting period.
Vested balances (including any investment gains or losses thereon) of terminating participants are paid at the time of termination. No amounts were awarded to the NEOs under the LTIP for the 2023 performance period.
Critical Personnel Agreements
Beginning in 2023, PacifiCorp entered into Critical Personnel Agreements with certain key employees, including the CFO, who possess skills that are important to the continued success of PacifiCorp. These agreements provide for cash amounts to be awarded to the employee in four installment payments to be made at specified dates as long as the employee is in good standing in the defined position as of December 31 each year within the award period. Amounts awarded under the Critical Personnel Agreements are in lieu of AIP and LTIP awards. The agreements do not constitute
a guarantee of future employment.
Deferred Compensation Plan
PacifiCorp's Executive Voluntary Deferred Compensation Plan ("DCP") provides a means for all NEOs, other than Mr. Thon, to make voluntary deferrals of up to 50% of their base salary and 100% of their short-term incentive compensation awards. PacifiCorp includes the DCP as part of the participating NEO's overall compensation in order to provide a comprehensive, competitive package. The deferrals and any investment returns grow on a tax-deferred basis. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of various investment alternatives offered under the DCP and selected by the participant. The DCP allows participants to choose from three forms of distribution. The DCP permits PacifiCorp to
make discretionary contributions on behalf of participants; however, no such contributions were made in 2023.
Potential Payments Upon Termination
PacifiCorp's NEOs are generally not entitled to severance or enhanced benefits upon termination of employment or change in control. None of PacifiCorp's NEOs have a formal employment agreement or offer letter with termination provisions; therefore, payments upon termination are determined by the applicable plan documents, applicable Critical Personnel Agreements, and PacifiCorp's general employment policies and practices as discussed below.
Compensation Committee Report
Ms. Crane, PacifiCorp's
current Chair and CEO and sole member of PacifiCorp's compensation committee, has reviewed the Compensation Discussion and Analysis and, based on her review, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
(1)The amounts shown under "Bonus" for year 2023 consists of annual cash incentive awards earned pursuant to the AIP for PacifiCorp's NEOs, amounts earned under applicable Critical Personnel Agreements, Cash Performance Awards
and the vesting of LTIP awards and associated vested earnings. No Cash Performance Awards were awarded to the NEOs during 2023. The breakout for 2023 is as follows:
The
ultimate payouts of LTIP awards are undeterminable as the amounts to be paid out may increase or decrease depending on investment performance. The BHE President and CEO and PacifiCorp's Presidents have historically established the award categories for determining LTIP awards based on net income target goals or other criteria.
(2)Amounts are based upon the aggregate change in the actuarial present value of all qualified and nonqualified defined benefit plans, which includes the Retirement Plan. Refer to the Pension Benefits table below for a discussion of the assumptions used in calculating these amounts. No participant in PacifiCorp's nonqualified deferred compensation plans earned "above market" or "preferential" earnings on amounts deferred.
(3)The amounts shown for "All Other Compensation" for year 2023 consist
of PacifiCorp K Plus Employee Savings Plan, or 401(k) Plan, contributions PacifiCorp paid on behalf of the NEOs, except for Ms. Crane who had $166,668 in relocation allowance, $29,506 in relocation expenses (plus $14,197 in tax gross-up), and for Mr. Hoogeveen and Ms. Kobliha for whom PacifiCorp also includes an amount paid for a tax gross-up with respect to a personal benefit with a value less than $10,000.
(4)Any amounts voluntarily deferred by the NEO, if applicable, are included in the appropriate column in the Summary Compensation Table.
(5)On April 13, 2022, Mr. Scott W. Thon was elected as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer, replacing Mr. William J. Fehrman who
concurrently resigned as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer.
491
(6)In 2023, PacifiCorp reimbursed BHE $303,807 for the cost of Mr. Thon's time spent on matters supporting PacifiCorp pursuant to the intercompany administrative services agreement.
(7)On September 1, 2023, Mr. Scott W. Thon resigned as PacifiCorp's Chair of the Board of Directors and Chief Executive Officer and Ms. Cindy A. Crane was elected as PacifiCorp's Chair of
the Board of Directors and Chief Executive Officer to replace Mr. Thon in such capacities.
(8)On January 2, 2024, Mr. Stefan A. Bird resigned as Pacific Power's President and Chief Executive Officer.
Pension Benefits
The following table sets forth certain information regarding the defined benefit pension plan accounts held by each of PacifiCorp's NEOs as of December 31, 2023:
(1)Amounts are computed using assumptions, other than the expected retirement age, consistent with those used in preparing the related pension
disclosures in the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K and are as of December 31, 2023, which is the measurement date for the plans. The expected retirement age assumption has been determined in accordance with Instruction 2 to Item 402(h)(2) of Regulation S-K. For the Retirement Plan calculations of the present value of accumulated benefits, the following assumptions were used: 60% lump sum payment; 40% joint and 100% survivor annuity if participant is married and 40% single life annuity if participant is single. The present value assumptions used in calculating the present value of accumulated benefits for the Retirement Plan were as follows: a discount rate of 5.20%; an expected retirement age of 65; cash balance interest crediting assumption of 5.98% for 2024 and 2025, and 3.10% thereafter; postretirement mortality using the Pri-2012 gender specific tables; generational
mortality improvements from 2012 forward based on MP-2021; and the applicable lump sum interest and mortality rates set forth in IRC 417(e)(3) for the upcoming fiscal year.
Historically, PacifiCorp has adopted the Retirement Plan for the majority of its employees, other than employees subject to collective bargaining agreements that do not provide for coverage under the Retirement Plan. Through May 31, 2007, participants earned benefits at retirement payable for life based on length of service through May 31, 2007 and average pay in the 60 consecutive months of highest pay out of the 120 months prior to May 31, 2007. Pay for this purpose included base salary and annual incentive plan payments up to 10% of base salary, but was limited to
the amounts specified in Internal Revenue Code Section 401(a)(17). Benefits were based on 1.3% of final average pay plus 0.65% of final average pay in excess of covered compensation (as defined in Internal Revenue Code Section 401(1)(5)(E)) multiplied by years of service.
The Retirement Plan was amended effective June 1, 2007 to change from a traditional final average pay formula as described above to a cash balance formula for non-union participants. Benefits under the final average pay formula were frozen as of May 31, 2007, and no future benefits will accrue under that formula for non-union participants. Under the cash balance formula, benefits are based on pay credits to each participant's account of 6.5% (5.0% for employees hired after June
30, 2006 and before January 1, 2008) of eligible compensation. In addition, through August 1, 2009, there was a pay credit of 4% of eligible compensation in excess of the Social Security Wage Base. Interest is also credited to each participant's account. Employees who were age 40 or older as of May 31, 2007 received certain additional transition pay credits for five years from the effective date of the Retirement Plan restatement.
Participants in the Retirement Plan are entitled to receive full benefits upon retirement on or after age 65. Such participants are also entitled to receive reduced benefits upon early retirement after age 55 with at least five years of service or when age plus years of service equals 75.
The
Retirement Plan was closed to non-union employees hired after December 31, 2007 (which includes Mr. Hoogeveen). In 2008, non-union employee participants in the Retirement Plan were offered the option to continue to receive pay credits in the Retirement Plan or receive equivalent fixed contributions to the 401(k) Plan with any such election becoming effective January 1, 2009. Ms. Kobliha elected the equivalent fixed 401(k) contribution option and, therefore, no longer receives pay credits in the Retirement Plan. In 2017, the Retirement Plan was frozen for the remainder of the non-union employees who had participated (which includes Ms. Crane and Mr. Bird) with pay credits equivalent to those received in the Retirement Plan allocated into the 401(k) Plan. Ms. Crane, Mr. Bird, and Ms. Kobliha continue to receive interest credits in the Retirement Plan.
492
Nonqualified
Deferred Compensation
The following table sets forth certain information regarding the nonqualified deferred compensation plan accounts held by each of PacifiCorp's NEOs as of December 31, 2023:
(1)The executive contribution amount shown for Mr. Hoogeveen represents a deferral of $253,626 of his 2020 LTIP award. $180,130 of the deferred 2020 LTIP award is included in the 2023 total compensation reported for him in the Summary Compensation Table and is not additional
compensation. The remaining LTIP award was earned prior to 2023.
(2)The executive contribution amount shown for Ms. Kobliha represents a deferral of $60,289 of her 2023 compensation and a deferral of $187,593 of her 2020 LTIP award. $74,183 of the deferred 2020 LTIP award is included in the 2023 total compensation reported for her in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2023.
(3)The aggregate balance as of December 31, 2023, shown for Mr. Hoogeveen and Ms. Kobliha includes $642,091 and $149,598, respectively, of compensation previously reported in the Summary Compensation Table.
Eligibility for PacifiCorp's DCP is restricted to
select management and highly compensated employees. The plan provides tax benefits to eligible participants by allowing them to defer compensation on a pretax basis, thus reducing their current taxable income. Deferrals and any investment returns grow on a tax-deferred basis, thus participants pay no income tax until they receive distributions. The DCP permits participants to make a voluntary deferral of up to 50% of base salary and 100% of short-term incentive compensation awards. All deferrals are net of social security taxes. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of various investment alternatives offered by the plan and selected by the participant. Gains or losses are calculated daily, and returns are posted to accounts based on participants' fund allocation elections. Participants can change their fund allocations as of the end of any day on which the market is open.
The
DCP allows participants to maintain three accounts based upon when they want to receive payments: retirement account, in-service account and education account. Both the retirement and in-service accounts can be distributed as lump sums or in up to 10 annual installments, except in the case of the four DCP transition accounts that allow for a grandfathered payout based on the previous deferred compensation plan distribution elections of lump sum, 5, 10 or 15 annual installments. Effective December 31, 2006, no new money may be deferred into the DCP transition accounts. The education account is distributed in four annual installments. If a participant leaves employment prior to retirement (age 55), all amounts in the participant's account will be paid out in a lump sum as soon as administratively practicable. Participants are 100% vested in their deferrals and any investment gains or losses recorded in their accounts.
Participants
in PacifiCorp's LTIP also have the option of deferring all or a part of those awards after the four-year mandatory deferral and vesting period. The provisions governing the deferral of LTIP awards are similar to those described for the DCP above.
Potential Payments Upon Termination
PacifiCorp's NEOs are not generally entitled to severance or enhanced benefits upon termination of employment or change in control. None of PacifiCorp's NEOs have a formal employment agreement or offer letter with termination provisions; therefore, payments upon termination are determined by the applicable plan documents, applicable Critical Personnel Agreements and PacifiCorp's general employment policies and practices as discussed below.
493
The
following table sets forth the estimated increase in the present value of benefits pursuant to the termination scenarios indicated for PacifiCorp's NEOs. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2023 and are payable as lump sums unless otherwise noted.
Retirement,
Voluntary and Involuntary With or Without Cause
—
—
Death and Disability
134,288
—
Termination, For Good Reason or Without Cause
1,520,107
n/a
(1)Death
and Disability amounts represent the unvested portion of each NEO's LTIP account, which becomes 100% vested under certain circumstances. For Ms. Kobliha Termination, For Good Reason or Without Cause amounts represent the unearned portion of amounts awarded under her Critical Personnel Agreement, which become 100% earned and payable under such circumstances where Termination For Good Reason occurs if the employee terminates employment in the event PacifiCorp or its subsidiaries engage in fraudulent or gross misconduct.
(2)Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits table.
Chief Executive Officer Pay Ratio
PacifiCorp's
former CEO, Mr. Thon, received no direct compensation from PacifiCorp, and no amounts are reported for Mr. Thon in the Summary Compensation Table. Ms. Crane received direct compensation from PacifiCorp in her role as CEO beginning September 1, 2023. Accordingly, PacifiCorp has calculated the CEO pay ratio based upon annualization of Ms. Crane's compensation.
The following information about the relationship of the annualized total compensation of Ms. Crane to the annual total compensation of the individual identified as PacifiCorp's "median" employee is provided in accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 402(u) of Regulation S-K.
•The 2023 annualized total compensation of
Ms. Crane was $2,198,393;
•The 2023 annual total compensation of the employee identified as PacifiCorp's median employee based on all employees other than Ms. Crane was $134,025; and
•The resulting ratio between the 2023 annualized total compensation of Ms. Crane to the 2023 annual total compensation of the identified median employee is 16.4-to-1.
The methodology and material assumptions, adjustments and estimates used to identify the median employee for this purpose were as follows:
•A determination date of December 31, 2023 was used for purposes of identifying the median employee at which time PacifiCorp's employee
population consisted of approximately 5,000 individuals, all of whom were located in the United States.
•For purposes of measuring the compensation of employees to identify the median employee, rather than using annual total compensation, base salary and wages with overtime pay plus AIP for 2023 was used as the compensation measure.
494
•Employee compensation was annualized for any new hires in 2023 as if they were hired at the beginning of the fiscal year in identifying the median employee.
•To determine the annualized total compensation of Ms. Crane, the amount reported for Ms. Crane in the "Salary"
column for 2023 in the Summary Compensation Table was annualized.
This pay ratio is a reasonable estimate calculated in a manner consistent with SEC rules based on payroll and employment records and the methodology described above. The SEC rules for identifying the median paid employee and calculating this pay ratio allow companies to apply various methodologies and assumptions. As a result, the pay ratio reported above may not be comparable to the pay ratio reported by other companies.
Director Compensation
PacifiCorp's directors do not receive additional compensation for their service as directors of PacifiCorp. Compensation information for Ms. Crane, Messrs. Thon, Bird, Hoogeveen, and Ms. Kobliha for their services as executive
officers of PacifiCorp is described above.
Compensation Committee Interlocks and Insider Participation
Ms. Crane is PacifiCorp's Chair and CEO. None of PacifiCorp's executive officers serves as a member of the compensation committee of any company that has an executive officer serving as a member of PacifiCorp's Board of Directors. None of PacifiCorp's executive officers serves as a member of the board of directors of any company that has an executive officer serving as a member of PacifiCorp's compensation committee. See also PacifiCorp's Item 13 in this Annual Report on Form 10-K.
495
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, SIERRA PACIFIC, EASTERN ENERGY GAS AND EGTS
Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Beneficial Ownership
PacifiCorp is a consolidated subsidiary of BHE. PacifiCorp's common stock is indirectly owned by BHE, 666 Grand Avenue, Des Moines,
Iowa50309-2580. BHE is a consolidated subsidiary of Berkshire Hathaway that, as of January 31, 2024, owns 92% of BHE's common stock. The balance of BHE's common stock is privately held by a limited group of investors.
None of PacifiCorp's executive officers or directors owns shares of its preferred stock. The following table sets forth certain information regarding the beneficial ownership of BHE's common stock and the Class A and Class B shares of Berkshire Hathaway common stock held by each of PacifiCorp's directors, executive officers and all of its directors and executive officers as a group as of January 31, 2024:
All
executive officers and directors as a group (5 persons)
—
—
—
—
511
*
* Indicates beneficial ownership of less than one percent of all outstanding shares.
(1)Includes shares of which the listed beneficial owner is deemed
to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.
496
Item 13.Certain Relationships and Related Transactions, and Director Independence
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, SIERRA PACIFIC, EASTERN ENERGY GAS AND EGTS
Information
required by Item 13 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Certain Relationships and Related Transactions
The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the BHE Code of Business Conduct, or the Codes, which apply to all of PacifiCorp's directors, officers and employees and those of its subsidiaries, generally govern the review, approval or ratification of any related-person transaction. A related-person transaction is one in which PacifiCorp or any of its subsidiaries participate and in which one or more of PacifiCorp's directors, executive officers, holders of more than five percent of its voting securities or any of such persons' immediate family members have a direct or indirect
material interest.
Under the Codes, all of PacifiCorp's directors and executive officers (including those of its subsidiaries) must disclose to PacifiCorp's legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with its interests. No action may be taken with respect to such transaction or relationship until approved by the legal department. For PacifiCorp's chief executive officer and chief financial officer, prior approval for any such transaction or relationship must be given by Berkshire Hathaway's audit committee. In addition, prior legal department approval must be obtained before a director or executive officer can accept employment, offices or board positions in other for-profit businesses, or engage in his or her own business that raises a potential conflict or appearance of conflict with PacifiCorp's interests.
Under
an intercompany administrative services agreement PacifiCorp has entered into with BHE and its other subsidiaries, the costs of certain administrative services provided by BHE to PacifiCorp or by PacifiCorp to BHE, or shared with BHE and other subsidiaries, are directly charged or allocated to the entity receiving such services. This agreement has been filed with the regulatory commissions in the states where PacifiCorp serves retail customers. PacifiCorp also provides an annual report of all transactions with its affiliates to its state regulatory commissions, who have the authority to refuse recovery in rates for payments PacifiCorp makes to its affiliates deemed to have the effect of subsidizing the separate business activities of BHE or its other subsidiaries.
Refer to Note 21 of the Notes to the Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for additional information
regarding related party transactions.
Director Independence
Because PacifiCorp's common stock is indirectly, wholly owned by BHE and its Board of Directors consists of BHE and PacifiCorp employees, PacifiCorp is not required to have independent directors or audit, nominating or compensation committees consisting of independent directors.
Based on the standards of the New York Stock Exchange LLC, on which the common stock of PacifiCorp's ultimate parent company, Berkshire Hathaway, is listed, PacifiCorp's Board of Directors has determined that none of its directors are considered independent because of their employment by BHE or PacifiCorp.
497
Item 14.Principal
Accountant Fees and Services
The following table shows the fees paid or accrued by each Registrant for audit and audit-related services and fees paid for tax and all other services rendered by Deloitte & Touche LLP (PCAOB ID No. iiiiiiii34///////),
the member firms of Deloitte Touche Tohmatsu Limited, and their respective affiliates (collectively, the "Deloitte Entities") for each of the last two years (in millions):
Berkshire
Eastern
Hathaway
MidAmerican
MidAmerican
Nevada
Sierra
Energy
Energy(1)
PacifiCorp
Funding(1)
Energy
Power
Pacific
Gas(1)
EGTS
2023
Audit
fees(2)
$
14.2
$
1.9
$
1.5
$
1.4
$
1.1
$
1.1
$
1.7
$
1.0
Audit-related
fees(3)
0.8
—
—
—
—
—
0.2
0.1
Tax fees(4)
—
—
—
—
—
—
—
—
Other
0.9
—
—
—
—
—
—
—
Total
$
15.9
$
1.9
$
1.5
$
1.4
$
1.1
$
1.1
$
1.9
$
1.1
2022
Audit
fees(2)
$
12.6
$
1.7
$
1.3
$
1.2
$
1.0
$
0.9
$
1.7
$
1.3
Audit-related
fees(3)
0.8
—
—
—
—
—
0.2
0.1
Tax fees(4)
—
—
—
—
—
—
—
—
Other
0.6
—
—
—
—
—
—
—
Total
$
14.0
$
1.7
$
1.3
$
1.2
$
1.0
$
0.9
$
1.9
$
1.4
(1)The
reported fees for Berkshire Hathaway Energy include those fees reported for PacifiCorp, MidAmerican Funding, Nevada Power, Sierra Pacific and Eastern Energy Gas while the reported fees for MidAmerican Funding include those fees reported for MidAmerican Energy and the reported fees for Eastern Energy Gas include those fees reported for EGTS.
(2)Audit fees include fees for the audit of the consolidated financial statements and interim reviews of the quarterly financial statements for each Registrant, audit services provided in connection with required statutory audits of certain of BHE's subsidiaries and comfort letters, consents and other services related to SEC matters for each Registrant.
(3)Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of certain
employee benefit plans and consultations on various accounting and reporting matters.
(4)Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal, state and international tax compliance, tax return preparation and tax audits.
The audit committee has considered whether the non-audit services provided to the Registrants by the Deloitte Entities impaired the independence of the Deloitte Entities and concluded that they did not. All of the services performed by the Deloitte Entities were pre-approved in accordance with the pre-approval policy adopted by the audit committee. The policy provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by the Deloitte Entities to the Registrants. The policy (a) identifies
the guiding principles that must be considered by the audit committee in approving services to ensure that the Deloitte Entities' independence is not impaired; (b) describes the audit, audit-related and tax services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, requests to provide services that require specific approval by the audit committee will be submitted to the audit committee by both the Registrants' independent auditor and BHE's Chief Financial Officer. All requests for services to be provided by the independent auditor that do not require specific approval by the audit committee will be submitted to BHE's Chief Financial Officer and must include a detailed description of the services to be rendered. BHE's Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval
of the audit committee. The audit committee will be informed on a timely basis of any such services rendered by the independent auditor.
498
PART IV
Item 15.Exhibits and Financial Statement Schedules
(a)
Financial
Statements and Schedules
(1)
Financial Statements
The financial statements of all Registrants are included in their respective Item 8 of this Form 10-K.
Schedules not listed above have been omitted because they are either not applicable, not required or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto.
The
accompanying notes are an integral part of this financial statement schedule.
503
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS
Basis of Presentation - The condensed financial information of BHE investments in subsidiaries are presented under the equity method of accounting. Under this method,
the assets and liabilities of subsidiaries are not consolidated. The investments in subsidiaries are recorded in the Condensed Balance Sheets. The income from operations of subsidiaries is reported on a net basis as equity income in the Condensed Statements of Operations.
Dividends and distributions from subsidiaries - Cash dividends paid to BHE by its subsidiaries for the years ended December 31, 2023, 2022 and 2021 were $i6.8
billion, $i1.9 billion and $i2.4 billion, respectively. In January and February 2024, BHE received cash dividends from its subsidiaries totaling $i691
million.
Guarantees and commitments - BHE has issued guarantees and letters of credit in respect of subsidiaries, equity method investments and other related parties aggregating $i2.6 billion and commitments.
See the notes to the consolidated BHE financial statements in Part II, Item 8 for other disclosures regarding long-term obligations (Notes 9, 10 and 11) and shareholders' equity (Note 18).
The
accompanying notes are an integral part of this financial statement schedule.
506
Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by reference are MidAmerican Funding, LLC and Subsidiaries Consolidated Statements of Changes in Member's Equity for the three years ended December 31, 2023, 2022 and 2021 in Part II,
Item 8.
Basis of Presentation - The condensed financial information of MidAmerican Funding, LLC's ("MidAmerican Funding's") investments in subsidiaries is presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded on the Condensed Balance Sheets. The income from operations of the subsidiaries is reported on a net basis as equity in undistributed earnings of subsidiary companies on the Condensed Statements of Operations. The Condensed Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2023, 2022 and 2021.
Income
Taxes - MidAmerican Funding is not subject to income tax and is disregarded by the taxing authorities. However, a portion of Berkshire Hathaway Inc.'s consolidated income tax expense has been allocated to MidAmerican Funding for presentation in its separate financial statements commensurate with computing MidAmerican Funding's provision on a stand-alone basis.
Payable to Affiliate - MHC, Inc. ("MHC") settles all obligations of MidAmerican Funding including interest costs on, and repayments of, MidAmerican Funding's long-term debt, income taxes and distributions to parent. MHC paid $i1,037 million,$i81 million
and $i12 million in 2023, 2022 and 2021, respectively, on behalf of MidAmerican Funding.
Distributions to Parent - In 2023 and 2022, MidAmerican Funding declared and paid, via MHC, cash dividends of $i1,025
million and $i69 million, respectively. In February 2024, MidAmerican Funding declared and paid, via MHC, a cash dividend of $i425 million.
See the notes to the consolidated MidAmerican Funding financial statements in Part II, Item 8
for other disclosures.
Mortgage
and Deed of Trust dated as of January 9, 1989, between PacifiCorp and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, incorporated by reference to Exhibit 4-E to the PacifiCorp Form 8-B, as supplemented and modified by the following Supplemental Indentures each incorporated by reference:
The
following financial information from each respective Registrant's Annual Report on Form 10-K for the year ended December 31, 2023 is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.
104
Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.
(a) Not
available electronically on the SEC website as it was filed in paper previous to the electronic system currently in place.
* Management contract or compensatory plan.
Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, each Registrant has not filed as an exhibit to this Form 10-K certain instruments with respect to long-term debt not registered in which the total amount of securities authorized thereunder does not exceed 10% of the total assets of the respective Registrant. Each Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.
524
SIGNATURES
BERKSHIRE
HATHAWAY ENERGY COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 23rd day of February 2024.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 23rd day of February 2024.
Director, Vice President, Chief Financial
Officer and
Treasurer
(principal financial and accounting officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 23rd day
of February 2024.
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 23rd day of February 2024.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 23rd day of February 2024.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 23rd day of February 2024.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 23rd day of February 2024.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 23rd day of February 2024.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
SUPPLEMENTAL
INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
No annual report to security holders covering each respective Registrant's last fiscal year or proxy material has been sent to security holders.
533
Dates Referenced Herein and Documents Incorporated by Reference
