(Former
name or former address, if changed from last report)
Registrant
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
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///////x No o
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. o
Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes iiiiiiii☐/////// No x
All
shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of November 3, 2022, 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 November 3, 2022, 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 November 3, 2022.
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 November 3, 2022, 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 November 3, 2022, 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 November 3, 2022, 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 November 3, 2022.
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 November 3, 2022, i60,101 shares of common stock, $10,000 par value, were outstanding.
This combined Form 10-Q 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 2 through 3, and Part II - Items 1 through 6, the following terms have the definitions indicated.
Berkshire Hathaway Energy Company and Related Entities
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
Northern Powergrid
Northern Powergrid Holdings Company and its subsidiaries
BHE Pipeline Group
BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas
Transmission Company
BHE GT&S
BHE GT&S, LLC and its subsidiaries
Northern Natural Gas
Northern Natural Gas Company
Kern River
Kern River Gas Transmission Company
BHE Transmission
BHE Canada Holdings Corporation and BHE U.S. 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
BHE Renewables
BHE Renewables, LLC and its subsidiaries
HomeServices
HomeServices of America, Inc. and its subsidiaries
Utilities
PacifiCorp and its subsidiaries,
MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
United States Court of Appeals for the District of Columbia Circuit
Dth
Decatherm
EPA
United
States Environmental Protection Agency
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
GTA
General
Tariff Application
GWh
Gigawatt Hour
IRP
Integrated Resource Plan
IUB
Iowa Utilities Board
kV
Kilovolt
MW
Megawatt
MWh
Megawatt
Hour
NAAQS
National Ambient Air Quality Standards
NOx
Nitrogen Oxides
Ofgem
Office of Gas and Electric Markets
OPUC
Oregon Public Utility Commission
PTC
Production
Tax Credit
PUCN
Public Utilities Commission of Nevada
RFP
Request for Proposals
RPS
Renewable Portfolio Standards
SCR
Selective Catalytic
Reduction
SEC
United States Securities and Exchange Commission
SIP
State Implementation Plan
SO2
Sulfur Dioxide
UPSC
Utah Public Service Commission
WUTC
Washington
Utilities and Transportation Commission
iii
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, 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 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, litigation, wars (including, for example, Russia's invasion of Ukraine in February 2022), 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 for which the cause has yet to be determined; 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 outcome of any legal proceedings initiated against the respective Registrant; the risk that the respective Registrant is not able to recover costs from insurance or through rates; and the effect on the respective Registrant's reputation of such wildfires, investigations and proceedings;
•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 where the Registrants may be found liable for real and personal property damages regardless of fault;
•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;
•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;
iv
•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;
•changes in the respective Registrant's credit ratings;
•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 Part II, Item 1A and other discussions contained in this Form 10-Q. 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.
v
Item
1.Financial Statements
Berkshire Hathaway Energy Company and its subsidiaries
Berkshire
Hathaway Energy Company and its subsidiaries
Consolidated Financial Section
3
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the Board of Directors and Shareholders of
Berkshire Hathaway Energy Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of September 30, 2022, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2022 and 2021, and of cash flows for the nine-month periods ended September 30, 2022 and 2021,
and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2021, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the 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 reviews in accordance
with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Adjustments
to reconcile net income to net cash flows from operating activities:
Losses (gains) on marketable securities, net
i1,999
(i1,142)
Depreciation
and amortization
i3,197
i2,834
Allowance
for equity funds
(i123)
(i90)
Equity
loss, net of distributions
i249
i346
Changes
in regulatory assets and liabilities
(i843)
(i518)
Deferred
income taxes and investment tax credits, net
(i350)
i661
Other,
net
i53
(i88)
Changes
in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets
(i246)
(i13)
Derivative
collateral, net
i106
i115
Pension
and other postretirement benefit plans
(i31)
(i37)
Accrued
property, income and other taxes, net
i501
(i29)
Accounts
payable and other liabilities
i1,125
i427
Net
cash flows from operating activities
i7,939
i6,984
Cash
flows from investing activities:
Capital expenditures
(i5,385)
(i4,594)
Acquisitions,
net of cash acquired
(i15)
(i64)
Purchases
of marketable securities
(i375)
(i243)
Proceeds
from sales of marketable securities
i961
i222
Purchases
of other investments
(i648)
(i20)
Proceeds
from other investments
i6
i1,296
Equity
method investments
(i29)
(i54)
Other,
net
i16
(i71)
Net
cash flows from investing activities
(i5,469)
(i3,528)
Cash
flows from financing activities:
Preferred stock redemptions
(i800)
(i1,450)
Preferred
dividends
(i33)
(i86)
Common
stock purchases
(i870)
i—
Proceeds
from BHE senior debt
i986
i—
Repayments
of BHE senior debt
i—
(i450)
Proceeds
from subsidiary debt
i1,198
i2,014
Repayments
of subsidiary debt
(i882)
(i1,271)
Net
repayments of short-term debt
(i540)
(i316)
Distributions
to noncontrolling interests
(i395)
(i366)
Contributions
from noncontrolling interests
i4
i9
Other,
net
(i273)
(i44)
Net
cash flows from financing activities
(i1,605)
(i1,960)
Effect
of exchange rate changes
(i51)
i1
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i814
i1,497
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i1,244
i1,445
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i2,058
$
i2,942
The
accompanying notes are an integral part of these consolidated financial statements.
10
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
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.
iThe unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments
(consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2022 and for the three- and nine-month periods ended September 30, 2022 and 2021. The results of operations for the three- and nine-month periods ended September 30, 2022 are not necessarily indicative of the results to be expected for the full year.
iThe
preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30,
2022, other than the updates associated with the Company's estimates of loss contingencies related to the Oregon and California 2020 wildfires (the "2020 Wildfires") as discussed in Note 8.
11
(2) iProperty, Plant and Equipment, Net
i
Property,
plant and equipment, net consists of the following (in millions):
As of
Depreciable
September 30,
December
31,
Life
2022
2021
Regulated assets:
Utility generation, transmission and distribution systems
i5-i80
years
$
i90,756
$
i90,223
Interstate
natural gas pipeline assets
i3-i80 years
i17,882
i17,423
i108,638
i107,646
Accumulated
depreciation and amortization
(i34,011)
(i32,680)
Regulated
assets, net
i74,627
i74,966
Nonregulated
assets:
Independent power plants
i2-i50
years
i8,052
i7,665
Cove
Point LNG facility
i40 years
i3,397
i3,364
Other
assets
i2-i30 years
i2,903
i2,666
i14,352
i13,695
Accumulated
depreciation and amortization
(i3,274)
(i3,041)
Nonregulated
assets, net
i11,078
i10,654
Net
operating assets
i85,705
i85,620
Construction
work-in-progress
i5,198
i4,196
Property,
plant and equipment, net
$
i90,903
$
i89,816
/
Construction
work-in-progress includes $i4.8 billion as of September 30, 2022 and $i3.8 billion as of December 31,
2021, related to the construction of regulated assets.
12
(3) iInvestments and Restricted Cash, Cash Equivalents
and Investments
i
Investments and restricted cash, cash equivalents and investments consists of the following (in millions):
Unrealized (losses) gains recognized on marketable securities still held at the reporting date
$
(i3,168)
$
i294
$
(i2,002)
$
i1,141
Net
(losses) gains recognized on marketable securities sold during the period
(i102)
i—
i3
i1
(Losses)
gains on marketable securities, net
$
(i3,270)
$
i294
$
(i1,999)
$
i1,142
/
13
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 presented in 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, current
i262
i127
Investments
and restricted cash, cash equivalents and investments, noncurrent
i19
i21
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i2,058
$
i1,244
(4) iRecent
Financing Transactions
Long-Term Debt
In October 2022, Nevada Power issued $i400 million of i5.90%
General and Refunding Mortgage bonds, Series GG, due 2053. The net proceeds were used to repay amounts outstanding under its existing revolving credit facility, to fund capital expenditures and for general corporate purposes.
In June 2022, Sierra Pacific purchased $i60 million of its variable-rate tax-exempt Gas & Water Facilities Refunding Revenue Bonds, Series 2016B, due 2036, as required by the bond indenture. Sierra Pacific is holding this bond and can re-offer it
at a future date.
In May 2022, Sierra Pacific issued $i250 million of i4.71% General and Refunding
Mortgage bonds, Series W, due 2052. The net proceeds were used to repay the outstanding $i200 million unsecured loan with NV Energy, Inc., repay amounts outstanding under its existing revolving credit facility and for general corporate purposes.
In April 2022, BHE issued $i1 billion
of its i4.6% Senior Notes due 2053 and used the net proceeds for general corporate purposes, which included repaying a portion of BHE's outstanding commercial paper obligations and redeeming a portion of its i4.00%
Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.
In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $i30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $i25 million
of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $i25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $i75 million
of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $i20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $i30 million
of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.
In April 2022, Northern Powergrid (Northeast) plc issued £i350 million of its i3.25%
bonds due 2052 and used the net proceeds for general corporate purposes.
In January 2022, Nevada Power entered into a $i300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate ("SOFR") or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $i200
million under the facility at an initial interest rate of i0.55%. In May 2022, Nevada Power drew the remaining $i100 million available under the facility
at an initial interest rate of i1.24%. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
14
Credit Facilities
In June 2022, BHE amended and restated its existing $i3.5 billion
unsecured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from the London Interbank Offered Rate ("LIBOR") to SOFR.
In June 2022, PacifiCorp amended and restated its existing $i1.2 billion unsecured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from LIBOR to SOFR.
In
June 2022, MidAmerican Energy amended and restated its existing $i1.5 billion unsecured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from LIBOR to SOFR.
In June 2022, Nevada Power and Sierra Pacific each amended and restated its existing $i400 million
and $i250 million secured credit facilities expiring in June 2024. The amendments extended the expiration date to June 2025 and amended pricing from LIBOR to SOFR.
(5) iIncome
Taxes
The effective income tax rate for the three-month period ended September 30, 2022, is i64% and results from a $i1,213 million
income tax benefit associated with a $i1,895 million pre-tax loss, primarily relating to a pre-tax loss of $i3,259 million
on the Company's investment in BYD Company Limited. The $i1,213 million income tax benefit is primarily comprised of a $i398 million
benefit (i21%) from the application of the statutory income tax rate to the pre-tax loss and a $i680 million
benefit (i36%) from income tax credits.
i
A reconciliation of
the federal statutory income tax rate to the effective income tax rate applicable to income before income tax benefit is as follows:
State
income tax, net of federal income tax impacts
i—
(i4)
(i2)
i—
Income
tax effect of foreign income
i—
(i1)
(i4)
i2
Effects
of ratemaking
i5
(i6)
(i18)
(i5)
Equity
income
i—
i—
(i4)
(i1)
Noncontrolling
interest
i2
(i1)
(i9)
(i2)
Other,
net
i—
i1
i3
i1
Effective
income tax rate
i64
%
(i21)
%
(i178)
%
(i13)
%
/
Income
tax credits relate primarily to PTCs 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 nine-month periods ended September 30,
2022 and 2021 totaled $i1,414 million and $i1,188 million,
respectively.
Income tax effect on foreign income includes, among other items, a deferred income tax charge of $i109 million recognized in June 2021 upon the enactment of an increase in the United Kingdom's corporate income tax rate from i19%
to i25% effective April 1, 2023.
15
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 received net cash payments for federal income taxes from Berkshire Hathaway for the nine-month periods ended September 30, 2022 and 2021 totaling $i1,742 million and $i1,259 million,
respectively.
In July 2022, the Company amended its tax allocation agreement with Berkshire Hathaway, which changed how state tax attributes will be settled. 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 has reclassified $ii744/ million
to retained earnings.
(6) iEmployee Benefit Plans
Domestic Operations
i
Net
periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):
Amounts
other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $i13 million and $i5 million,
respectively, during 2022. As of September 30, 2022, $i10 million and $i5
million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
Foreign Operations
Net periodic benefit credit for the United Kingdom pension plan included the following components (in millions):
Amounts
other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £i12 million during 2022. As of September 30, 2022, £i9 million,
or $i12 million, of contributions had been made to the United Kingdom pension plan.
(7) 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.
i
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 payable of $i22 million and receivable of $i26 million
as of September 30, 2022 and December 31, 2021, 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 the
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.
18
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 (in millions). Transfers out of Level 3 occur primarily due to increased price observability.
Three-Month Periods
Nine-Month Periods
Ended
September 30,
Ended September 30,
Interest
Interest
Commodity
Rate
Commodity
Rate
Derivatives
Derivatives
Derivatives
Derivatives
2022:
Beginning
balance
$
(i178)
$
i21
$
(i151)
$
i19
Changes
included in earnings(1)
(i14)
(i22)
(i96)
(i20)
Changes
in fair value recognized in OCI
i3
i—
i13
i—
Changes
in fair value recognized in net regulatory assets
(i5)
i—
(i64)
i—
Purchases
i1
i—
i2
i—
Settlements
i138
i—
i172
i—
Transfers
out of Level 3 into Level 2
i—
i—
i69
i—
Ending
balance
$
(i55)
$
(i1)
$
(i55)
$
(i1)
2021:
Beginning
balance
$
i105
$
i41
$
i116
$
i62
Changes
included in earnings(1)
(i18)
(i13)
(i34)
(i34)
Changes
in fair value recognized in OCI
(i6)
i—
(i13)
i—
Changes
in fair value recognized in net regulatory assets
i12
i—
i21
i—
Purchases
i1
i—
i2
i—
Settlements
(i62)
i—
(i60)
i—
Ending
balance
$
i32
$
i28
$
i32
$
i28
(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 Balance Sheets. 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 (in millions):
During the nine-month period ended September 30, 2022, PacifiCorp entered into certain procurement and construction services agreements for $i1.1 billion through 2024 for the construction of key Energy Gateway Transmission segments in Utah, Wyoming and Idaho, including $i849
million for the segment extending between the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah.
Fuel Contracts
During the nine-month period ended September 30, 2022, PacifiCorp entered into certain coal supply and transportation agreements totaling approximately $i214 million through 2028.
Purchased
Electricity Contracts - Not Commercially Operable
During the nine-month period ended September 30, 2022, PacifiCorp entered into a purchased electricity contract for a solar generating facility including battery storage with minimum obligations totaling approximately $i238 million through 2045. The facility associated with this contract has not yet achieved commercial operation. To the extent this facility does not achieve commercial operation, PacifiCorp has no
obligation to the counterparty.
Legal Matters
The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company 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 and are described below.
Wildfire Liability Overview
A provision for a loss contingency is recorded when it is probable that a liability
has been incurred and the amount of the liability can be reasonably estimated. PacifiCorp evaluates which potential liabilities are probable and the related range of reasonably estimated losses and records a charge that reflects its best estimate or the lower end of the range, if there is no better estimate.
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 nevertheless be found liable for all damages proximately caused by negligence, including real and personal property and natural resource damages; fire suppression costs; personal injury and loss of life damages; and interest.
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. Fire suppression costs estimated by various agencies total approximately $i150 million.
Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts
engaged by PacifiCorp.
20
As of the date of this filing, i60 lawsuits have been filed in Oregon and California, including a class action complaint in Oregon, on behalf of plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages. Additionally,
several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. The final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
As of the date of this filing, PacifiCorp estimates the probable loss to be $i200 million, net of expected insurance recoveries and has accrued such amount as of September
30, 2022. During the nine-month period ended September 30, 2022, PacifiCorp accrued $i64 million of losses net of expected insurance recoveries, associated with the 2020 Wildfires. The accrual includes PacifiCorp's estimate of losses for 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 that are considered probable of being incurred and that it is reasonably able to estimate at
this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available. It is reasonably possible PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the variation in those types of properties and lack of available details. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover a portion of the losses. PacifiCorp's receivable for expected insurance recoveries was $i277 million
as of September 30, 2022.
2022 McKinney Fire
According to California Department of Forestry and Fire Protection ("Cal Fire"), on July 29, 2022, at approximately 2:16 p.m. Pacific Time, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. The Cal Fire McKinney Fire incident report last updated September 8, 2022 (the "Cal Fire incident report") indicates that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and 4 fatalities. According to InciWeb, an interagency all-risk incident
information management system, the 2022 McKinney Fire consumed 60,138 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the United States Forest Service.
Due to the preliminary nature of the investigation PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $i31 million,
net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp is unable to estimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $i103 million,
to cover potential losses.
As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages but the amount of damages sought are not specified. The final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct
disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.
21
Hydroelectric Relicensing
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 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 dams from PacifiCorp to the KRRC. The FERC approved 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 Klamath Hydroelectric 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 transfer of the four mainstem Klamath 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. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending. In August 2022, the FERC staff issued a final environmental impact statement for the project, concluding that dam removal is the preferred action.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
22
(9) iRevenue
from Contracts with Customers
Energy Products and Services
i
The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business, including a reconciliation to the Company's reportable segment information included in Note 12 (in millions):
(1)The
BHE and Other reportable segment represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
Real Estate Services
The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):
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 September 30, 2022, by reportable segment (in millions):
Performance
obligations expected to be satisfied:
Less than 12 months
More than 12 months
Total
BHE Pipeline Group
$
i2,931
$
i21,414
$
i24,345
BHE
Transmission
i688
i172
i860
Total
$
i3,619
$
i21,586
$
i25,205
/
(10) iBHE
Shareholders' Equity
In May 2022, BHE redeemed at par i800,006 shares of its i4.00%
Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $i800 million, plus an additional amount equal to the accrued dividends on the pro rata shares redeemed.
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.
(11) 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 tax (in millions):
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. Information related to the Company's reportable segments is shown below (in millions):
(1)The
differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
(Loss)
income before income tax benefit and equity loss by country:
U.S.
$
(i2,068)
$
i1,511
$
i395
$
i3,699
United
Kingdom
i118
i107
i344
i343
Canada
i43
i49
i135
i134
Other
i12
i8
i10
i13
Total
(loss) income before income tax benefit and equity loss by country
$
(i1,895)
$
i1,675
$
i884
$
i4,189
i
The
following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2022 (in millions):
Item
2.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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.
BHE is a holding company that owns a highly diversified
portfolio of locally managed businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway. As of November 3, 2022, 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, beneficially owned 92% and 8%, respectively, of BHE's common stock.
Berkshire Hathaway Energy'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, one of which owns 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 one of the largest residential real estate brokerage franchise networks in the U.S. 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 entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
29
Results of Operations for the Third Quarter and First Nine Months of 2022 and 2021
Overview
Operating revenue and (loss) earnings on common shares for the Company's reportable segments
are summarized as follows (in millions):
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Operating revenue:
PacifiCorp
$
1,635
$
1,491
$
144
10
%
$
4,246
$
4,031
$
215
5
%
MidAmerican
Funding
1,148
966
182
19
3,050
2,726
324
12
NV Energy
1,334
1,085
249
23
2,926
2,443
483
20
Northern
Powergrid
359
277
82
30
1,019
857
162
19
BHE Pipeline Group
964
785
179
23
2,855
2,584
271
10
BHE
Transmission
177
185
(8)
(4)
543
547
(4)
(1)
BHE Renewables
302
316
(14)
(4)
763
773
(10)
(1)
HomeServices
1,405
1,743
(338)
(19)
4,284
4,738
(454)
(10)
BHE
and Other
176
120
56
47
456
414
42
10
Total operating revenue
$
7,500
$
6,968
$
532
8
%
$
20,142
$
19,113
$
1,029
5
%
(Loss)
earnings on common shares:
PacifiCorp
$
409
$
333
$
76
23
%
$
622
$
728
$
(106)
(15)
%
MidAmerican
Funding
300
373
(73)
(20)
745
728
17
2
NV Energy
270
282
(12)
(4)
392
416
(24)
(6)
Northern
Powergrid
100
83
17
20
282
162
120
74
BHE Pipeline Group
234
144
90
63
755
627
128
20
BHE
Transmission
59
65
(6)
(9)
183
184
(1)
(1)
BHE Renewables(1)
173
163
10
6
526
360
166
46
HomeServices
29
102
(73)
(72)
134
321
(187)
(58)
BHE
and Other
(2,424)
351
(2,775)
*
(1,750)
580
(2,330)
*
Total (loss) earnings on common shares
$
(850)
$
1,896
$
(2,746)
*
$
1,889
$
4,106
$
(2,217)
(54)
%
(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
Earnings on common shares decreased $2,746 million for the third quarter of 2022 compared to 2021. The third quarter of 2022 included a pre-tax loss of $3,259 million ($2,574 million after-tax) compared to a pre-tax gain in the third quarter of 2021 of $296 million ($253 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the third quarter of 2022 was $1,724 million, an increase of $81 million, or 5%, compared to adjusted earnings on common shares in the third quarter of 2021 of $1,643 million.
Earnings
on common shares decreased $2,217 million for the first nine months of 2022 compared to 2021. The first nine months of 2022 included a pre-tax loss of $1,948 million ($1,539 million after-tax) compared to a pre-tax gain in the first nine months of 2021 of $1,126 million ($855 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first nine months of 2022 was $3,428 million, an increase of $177 million, or 5%, compared to adjusted earnings on common shares in the first nine months of 2021 of $3,251 million.
30
The decreases in earnings on common shares for the third quarter and for the first nine months of 2022 compared to 2021 were primarily
due to the following:
•The Utilities' earnings decreased $9 million for the third quarter and $113 million for the first nine months of 2022 compared to 2021. The decrease for the first nine months reflected higher operations and maintenance expense, higher depreciation and amortization expense and unfavorable investment earnings, partially offset by higher electric utility margin and a favorable income tax benefit from higher PTCs recognized. Electric retail customer volumes increased 1.7% for the first nine months of 2022 compared to 2021, primarily due to higher customer usage and an increase in the average number of customers;
•Northern Powergrid's earnings increased $17 million for the third quarter and $120 million for the first nine months of 2022 compared to 2021. The increase for the first nine months was 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;
•BHE Pipeline Group's earnings increased $90 million for the third quarter and $128 million for the first nine months of 2022 compared to 2021, largely due to higher earnings at BHE GT&S from the impacts of the EGTS general rate case, favorable income tax adjustments and lower operations and maintenance expense. In addition, earnings for the first nine months decreased from the effects of higher margins on natural gas sales and higher transportation revenue in the first quarter of 2021 at Northern Natural Gas from the February 2021 polar vortex weather event;
•BHE Renewables' earnings increased $10 million for
the third quarter and $166 million for the first nine months of 2022 compared to 2021. The increase for the first nine months was primarily due to higher operating revenue from owned renewable energy projects and higher earnings from tax equity investments, mainly due to the unfavorable impacts in the first quarter of 2021 from the February 2021 polar vortex weather event;
•HomeServices' earnings decreased $73 million for the third quarter and $187 million for the first nine months of 2022 compared to 2021, reflecting lower earnings from mortgage services mainly from a decrease in funded volumes and lower earnings from brokerage and settlement services largely attributable to a decrease in closed units at existing companies; and
•BHE and Other's earnings decreased $2,775 million for the third quarter and $2,330 million for the first
nine months of 2022 compared to 2021, mainly due to $2,827 million and $2,394 million, respectively, of unfavorable comparative changes in the Company's investment in BYD Company Limited, partially offset by lower federal income tax credits recognized on a consolidated basis in the third quarter and lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.
Reportable Segment Results
PacifiCorp
Operating revenue increased $144 million for the third quarter of 2022 compared to 2021, primarily due to higher retail revenues of $117 million and higher wholesale and other revenue of $27 million, largely from higher average wholesale prices. Retail revenue increased primarily due to
price impacts of $61 million from higher average retail rates largely due to tariff changes and $57 million from higher retail volumes. Retail customer volumes increased 3.5%, 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 $76 million for the third quarter of 2022 compared to 2021, primarily due to higher utility margin of $67 million and a favorable income tax benefit, partially offset by higher operations and maintenance expense of $22 million and higher depreciation and amortization expense of $5 million, mainly from additional assets placed in-service. Utility margin increased primarily due to higher retail rates and volumes, favorable deferred net power costs and higher average wholesale prices, partially offset by higher purchased power and thermal generation costs.
The favorable income tax benefit was largely due to higher PTCs recognized of $21 million and the effects of ratemaking.
Operating revenue increased $215 million for the first nine months of 2022 compared to 2021, primarily due to higher retail revenues of $143 million and higher wholesale and other revenue of $72 million, largely from higher average wholesale prices. Retail revenue increased primarily due to price impacts of $104 million from higher average retail rates largely due to tariff changes and $40 million from higher retail volumes. Retail customer volumes increased 0.8%, primarily due to an increase in the average number of customers and the favorable impact of weather, partially offset by lower customer usage.
31
Earnings
decreased $106 million for the first nine months of 2022 compared to 2021, primarily due to higher operations and maintenance expense of $160 million, an unfavorable income tax benefit, higher depreciation and amortization expense of $25 million, mainly from additional assets placed in-service, and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by higher utility margin of $88 million. Operations and maintenance expense increased mainly due to an increase in loss accruals associated with the September 2020 wildfires, net of estimated insurance recoveries, and higher general and plant maintenance costs, Utility margin increased primarily due to higher retail rates and volumes, higher average wholesale prices and favorable deferred net power costs, partially offset by higher purchased power and thermal generation costs. The unfavorable income tax benefit was largely due to the effects of ratemaking and lower
PTCs recognized of $6 million.
MidAmerican Funding
Operating revenue increased $182 million for the third quarter of 2022 compared to 2021, primarily due to higher electric operating revenue of $155 million and higher natural gas operating revenue of $29 million. Electric operating revenue increased due to higher wholesale and other revenue of $87 million and higher retail revenue of $68 million. Electric wholesale and other revenue increased mainly due to higher average wholesale per-unit prices of $96 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $47 million (fully offset in expense, primarily cost of sales) and higher customer volumes of $17 million. Electric retail customer volumes increased 3.1%, primarily due to higher customer usage. Natural
gas operating revenue increased due to higher purchased gas adjustment recoveries of $34 million (fully offset in cost of sales), primarily from a higher average per-unit cost of natural gas sold, partially offset by the impacts of certain regulatory recovery mechanisms of $6 million.
Earnings decreased $73 million for the third quarter of 2022 compared to 2021, primarily due to higher depreciation and amortization expense of $120 million, an unfavorable income tax benefit, higher operations and maintenance expense of $10 million and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by higher electric utility margin of $83 million. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service. Electric utility margin increased primarily due
to the higher wholesale and retail revenues, partially offset by higher purchased power costs. The unfavorable income tax benefit was largely due to the effects of ratemaking, partially offset by higher PTCs recognized of $14 million from higher wind- and solar-powered generation.
Operating revenue increased $324 million for the first nine months of 2022 compared to 2021, primarily due to higher electric operating revenue of $357 million, partially offset by lower natural gas operating revenue of $22 million and lower nonregulated operating revenue of $10 million. Electric operating revenue increased due to higher wholesale and other revenue of $192 million and higher retail revenue of $165 million. Electric wholesale and other revenue increased mainly due to higher average wholesale per-unit prices of $174 million and higher wholesale volumes of $23 million. Electric retail revenue
increased primarily due to higher recoveries through adjustment clauses of $110 million (fully offset in expense, primarily cost of sales) and higher customer volumes of $45 million. Electric retail customer volumes increased 4.0%, primarily due to higher customer usage. Natural gas operating revenue decreased due to lower purchased gas adjustment recoveries of $37 million (fully offset in cost of sales), primarily from a lower average per-unit cost of natural gas sold, partially offset by the impacts of tax reform of $6 million, the favorable impact of weather of $5 million and higher customer usage of $4 million.
Earnings increased $17 million for the first nine months of 2022 compared to 2021, primarily due to higher electric utility margin of $240 million, a favorable income tax benefit and higher natural gas utility margin of $15 million, partially offset by higher depreciation
and amortization expense of $231 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies, higher operations and maintenance expense of $25 million, higher interest expense of $12 million and lower nonregulated utility margin of $10 million. Electric utility margin increased primarily due to the higher wholesale and retail revenues, partially offset by higher purchased power costs. The favorable income tax benefit was mainly due to higher PTCs recognized of $106 million from higher wind- and solar-powered generation, partially offset by the effects of ratemaking. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service.
NV Energy
Operating revenue increased $249 million
for the third quarter of 2022 compared to 2021, primarily due to higher electric operating revenue of $244 million from higher fully-bundled energy rates (fully offset in cost of sales) of $243 million. Electric retail customer volumes increased 0.3%.
32
Earnings decreased $12 million for the third quarter of 2022 compared to 2021, primarily due to higher operations and maintenance expense of $11 million, higher depreciation and amortization expense of $6 million, mainly from additional plant placed in-service, and lower cash surrender value of corporate-owned life insurance policies, partially offset by higher interest and dividend income of $10 million from carrying charges on regulatory balances. Operations and maintenance expense increased mainly due to higher plant operations
and maintenance expenses and an unfavorable change in earnings sharing at the Nevada Utilities.
Operating revenue increased $483 million for the first nine months of 2022 compared to 2021, primarily due to higher electric operating revenue of $457 million, from higher fully-bundled energy rates (fully offset in cost of sales) of $452 million, and higher natural gas operating revenue of $26 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric retail customer volumes increased 1.3%, primarily due to an increase in the average number of customers, partially offset by the unfavorable impact of weather.
Earnings decreased $24 million for the first nine months of 2022 compared to 2021, primarily due to higher operations and maintenance expense of $19 million,
unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher depreciation and amortization expense of $12 million, mainly from additional plant placed in-service, partially offset by higher interest and dividend income of $24 million from carrying charges on regulatory balances. Operations and maintenance expense increased mainly due to higher plant operations and maintenance expenses and an unfavorable change in earnings sharing at the Nevada Utilities.
Northern Powergrid
Operating revenue increased $82 million for the third quarter of 2022 compared to 2021, primarily due to higher revenue at CE Gas of $72 million from a gas project that commenced commercial operation in March 2022 and a solar project that commenced commercial operation in July 2022 and higher
distribution revenue of $63 million, partially offset by $60 million from the stronger U.S. dollar. Distribution revenue increased due to the recovery of Supplier of Last Resort payments totaling $45 million (fully offset in cost of sales) and higher tariff rates of $28 million, partially offset by a 5.5% decline in units distributed of $10 million.
Earnings increased $17 million for the third quarter of 2022 compared to 2021, primarily due to the higher distribution tariff rates and improved earnings at CE Gas of $19 million from the new gas and solar projects, partially offset by $17 million from the stronger U.S. dollar, the decline in units distributed and higher distribution-related operating and depreciation expenses of $6 million.
Operating revenue increased $162 million for the first nine months
of 2022 compared to 2021, primarily due to higher distribution revenue of $133 million and higher revenue at CE Gas of $122 million from the new gas and solar projects, partially offset by $105 million from the stronger U.S. dollar. Distribution revenue increased due to the recovery of Supplier of Last Resort payments totaling $90 million (fully offset in cost of sales) and higher tariff rates of $67 million, partially offset by a 4.0% decline in units distributed of $22 million.
Earnings increased $120 million for the first nine months of 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, the higher distribution tariff rates and improved earnings at CE Gas of $28 million from
the new gas and solar projects, partially offset by higher distribution-related operating and depreciation expenses of $33 million, including higher storm-related costs, the decline in units distributed and $25 million from the stronger U.S. dollar.
BHE Pipeline Group
Operating revenue increased $179 million for the third quarter of 2022 compared to 2021, primarily due to higher operating revenue of $151 million at BHE GT&S and higher operating revenue of $27 million at Northern Natural Gas. The increase in operating revenue at BHE GT&S was primarily due to higher non-regulated revenue of $61 million (largely offset in cost of sales) from favorable commodity prices, higher LNG revenue of $59 million at Cove Point, from favorable variable revenue and additional services due to a decrease in scheduled outage days, and
an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $41 million, partially offset by lower gas sales of $14 million at EGTS used for operational and system balancing activities. The increase in operating revenue at Northern Natural gas was largely due to higher transportation revenue of $22 million from higher volumes and rates.
33
Earnings increased $90 million for the third quarter of 2022 compared to 2021, primarily due to higher earnings of $95 million at BHE GT&S largely due to the impacts of the EGTS general rate case of $50 million, favorable income tax adjustments, lower operations and maintenance expense of $18 million and higher earnings at Cove Point of $15 million from the higher operating
revenue.
Operating revenue increased $271 million for the first nine months of 2022 compared to 2021, primarily due to higher operating revenue of $280 million at BHE GT&S, partially offset by lower operating revenue of $17 million at Northern Natural Gas. The increase in operating revenue at BHE GT&S was primarily due to higher non-regulated revenue of $130 million (largely offset in cost of sales) from favorable commodity prices, higher LNG revenue of $97 million at Cove Point, from favorable variable revenue and additional services due to a decrease in scheduled outage days, and an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $66 million, partially offset by lower gas sales of $31 million at EGTS used for operational and system balancing activities. The decrease in operating revenue at Northern Natural Gas was
mainly due to lower gas sales of $27 million related to system balancing activities offset by higher transportation revenue of $19 million. The variances in gas sales and transportation revenue included favorable impacts recognized in the first quarter of 2021 of $77 million and $49 million, respectively, from the February 2021 polar vortex weather event. Excluding this item, gas sales increased $50 million (largely offset in cost of sales) and transportation revenue increased $68 million due to higher volumes and rates.
Earnings increased $128 million for the first nine months of 2022 compared to 2021, primarily due to higher earnings of $194 million at BHE GT&S, partially offset by lower earnings of $62 million at Northern Natural Gas. Earnings at BHE GT&S increased mainly due to the impacts of the EGTS general rate case of $81 million, favorable income tax adjustments, lower
operations and maintenance and property and other tax expense of $47 million, increased earnings at Cove Point of $24 million from the higher operating revenue and higher margin of $22 million from non-regulated activities. Earnings at Northern Natural Gas decreased as the higher gross margin on gas sales and higher transportation revenue in the first quarter of 2021 from the February 2021 polar vortex weather event were partially offset by the favorable transportation revenue in 2022 due to higher volumes and rates.
BHE Transmission
Operating revenue decreased $8 million for the third quarter and $4 million for the first nine months of 2022 compared to 2021, primarily due to the stronger U.S. dollar of $6 million and $13 million, respectively, and lower revenue from the Montana-Alberta Tie Line, partially offset
by higher non-regulated revenue from a wind-powered generating facility.
Earnings decreased $6 million for the third quarter and $1 million for the first nine months of 2022 compared to 2021, primarily due to lower earnings from the Montana-Alberta Tie Line, higher non-regulated interest expense and the stronger U.S. dollar of $2 million and $3 million, respectively, partially offset by improved equity earnings at Electric Transmission Texas, LLC and the higher non-regulated revenue.
BHE Renewables
Operating revenue decreased $14 million for the third quarter of 2022 compared to 2021, primarily due to higher wind, geothermal and solar revenues of $37 million, from higher generation and pricing, and favorable changes
in the valuation of certain derivative contracts totaling $6 million, partially offset by lower natural gas revenues of $45 million from lower generation and hedge losses and lower hydro earnings of $13 million due to the transfer of the Casecnan generating facility to the Philippine National Irrigation Administration in December 2021.
Earnings increased $10 million for the third quarter of 2022 compared to 2021, primarily due to higher wind earnings of $29 million and higher geothermal earnings of $9 million, largely due to the higher operating revenue, partially offset by lower natural gas earnings of $21 million, largely due to the lower operating revenue and lower hydro earnings of $9 million due to the Casecnan generating facility transfer. Wind earnings increased primarily due to higher earnings from owned projects of $16 million, largely from the higher operating revenue, and
higher earnings from tax equity investments of $13 million, mainly from higher production tax credits offset by unfavorable operating performance.
Operating revenue decreased $10 million for the first nine months of 2022 compared to 2021, primarily due to lower natural gas revenues of $55 million from lower generation and hedge losses, unfavorable changes in the valuation of certain derivative contracts totaling $51 million and lower hydro revenues of $19 million due to the Casecnan generating facility transfer, partially offset by higher wind, geothermal and solar revenues of $114 million from higher generation and pricing.
34
Earnings increased $166 million
for the first nine months of 2022 compared to 2021, primarily due to higher wind earnings of $179 million, higher geothermal earnings of $18 million, largely due to the higher operating revenue and lower maintenance costs, and higher solar earnings of $13 million, mainly due to the higher operating revenue, partially offset by lower natural gas earnings of $20 million largely due to the lower operating revenue and lower hydro earnings of $19 million due to the Casecnan generating facility transfer. Wind earnings increased primarily due to higher earnings from tax equity investments of $136 million, mainly as a result of the unfavorable impacts recognized in the first quarter of 2021 from the February 2021 polar vortex weather event and higher production tax credits offset by unfavorable operating performance, and higher earnings from owned projects of $43 million, largely from the higher operating revenue and favorable production tax credits offset by the unfavorable
derivative contract valuations.
HomeServices
Operating revenue decreased $338 million for the third quarter of 2022 compared to 2021, primarily due to lower brokerage and settlement services revenue of $252 million, from a 16% decrease in closed transaction volume, and lower mortgage revenue of $82 million from a 39% decrease in funded volume, primarily due to a decline in refinance activity. The decrease in brokerage volume was due to 24% fewer closed units at existing companies offset by acquisitions and a 5% increase in average sales price at existing companies.
Earnings decreased $73 million for the third quarter of 2022 compared to 2021, primarily due to lower earnings from brokerage and settlement services of $49 million,
largely attributable to the decrease in closed units at existing companies, and lower earnings from mortgage services of $30 million from the decrease in funded volume.
Operating revenue decreased $454 million for the first nine months of 2022 compared to 2021, primarily due to lower mortgage revenue of $242 million from a 36% decrease in funded volume, primarily due to a decline in refinance activity, and lower brokerage and settlement services revenue of $212 million from a 4% decrease in closed transaction volume. The decrease in brokerage volume was due to 19% fewer closed units at existing companies offset by acquisitions and an 8% increase in average sales price at existing companies.
Earnings decreased $187 million for the first nine months of 2022 compared to 2021, primarily due to lower earnings
from mortgage services of $101 million, largely from the decrease in funded volumes, and lower earnings from brokerage and settlement services of $98 million due to the decrease in closed units at existing companies, partially offset by favorable operating expense variances.
BHE and Other
Operating revenue increased $56 million for the third quarter of 2022 compared to 2021, primarily due to higher electric and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing, including changes in unrealized positions on natural gas derivative contracts, and higher electric volumes, partially offset by lower natural gas volumes.
Earnings decreased $2,775 million for the third quarter of 2022 compared to 2021, primarily
due to the $2,827 million unfavorable comparative change in the Company's investment in BYD Company Limited, lower earnings of $16 million at MidAmerican Energy Services, LLC, mainly due to unfavorable changes in unrealized positions on derivative contracts, higher BHE corporate interest expense from an April 2022 debt issuance and higher corporate costs, partially offset by $77 million of higher federal income tax credits recognized on a consolidated basis and $18 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.
Operating revenue increased $42 million for the first nine months of 2022 compared to 2021, primarily due to higher natural gas and electric sales revenue at MidAmerican Energy Services, LLC, from favorable natural gas pricing, including changes in unrealized positions on derivative contracts, and higher
electric volumes, partially offset by unfavorable electric pricing and lower natural gas volumes.
Earnings decreased $2,330 million for the first nine months of 2022 compared to 2021, primarily due to the $2,394 million unfavorable comparative change in the Company's investment in BYD Company Limited, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher BHE corporate interest expense from an April 2022 debt issuance, partially offset by $64 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway, lower corporate costs and higher earnings of $29 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts.
35
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
the Company's Annual Report on Form 10-K for the year ended December 31, 2021 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of September 30, 2022, 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
$
106
$
219
$
582
$
123
$
164
$
60
$
291
$
232
$
1,777
Credit
facilities(1)
3,500
1,200
1,509
650
237
777
3,400
—
11,273
Less:
Short-term
debt
(100)
—
—
(320)
(14)
(261)
(746)
—
(1,441)
Tax-exempt
bond support and letters of credit
—
(218)
(370)
(17)
—
(1)
—
—
(606)
Net
credit facilities
3,400
982
1,139
313
223
515
2,654
—
9,226
Total
net liquidity
$
3,506
$
1,201
$
1,721
$
436
$
387
$
575
$
2,945
$
232
$
11,003
Credit
facilities:
Maturity dates
2025
2025
2023, 2025
2025
2024,
2026
2023, 2026
2023, 2026
(1)Includes $14 million drawn on a capital expenditure credit facility at Northern Powergrid Holdings.
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2022 and 2021 were $7.9 billion and $7.0 billion, respectively. The increase
was primarily due to favorable income tax cash flows, improved operating results and changes in working capital.
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 nine-month periods ended September 30, 2022 and 2021 were $(5.5) billion and $(3.5) billion, respectively. The change was primarily due to higher capital expenditures of $791 million, higher other investment purchases of $628 million, including $614
million of U.S. Treasury Bills, and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement, partially offset by higher net sales of marketable securities of $607 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
36
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2022 was $(1.6) billion. Sources of cash totaled $2.2 billion and consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and proceeds from BHE senior debt issuances totaling $1.0 billion.
Uses of cash totaled $3.8 billion and consisted mainly of repayments of subsidiary debt totaling $882 million, purchases of common stock totaling $870 million, preferred stock redemptions of $800 million, net repayments of short-term debt totaling $540 million and distributions to noncontrolling interests of $395 million.
For discussions of recent financing and BHE shareholders' equity transactions, refer to Notes 4 and 10 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Net cash flows from financing activities for the nine-month period ended September 30, 2021 was $(2.0) billion. Sources of cash consisted of proceeds from subsidiary debt issuances totaling $2.0 billion. Uses of cash totaled $4.0 billion and consisted
mainly of preferred stock redemptions of $1.5 billion, repayments of subsidiary debt totaling $1.3 billion, repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $366 million and net repayments of short-term debt totaling $316 million.
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 customer 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.
37
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Nine-Month
Periods
Annual
Ended September 30,
Forecast
2021
2022
2022
Capital expenditures by business:
PacifiCorp
$
1,157
$
1,481
$
2,255
MidAmerican
Funding
1,266
1,404
2,039
NV Energy
519
801
1,289
Northern Powergrid
564
614
791
BHE
Pipeline Group
684
800
1,223
BHE Transmission
234
143
223
BHE Renewables
129
99
161
HomeServices
29
31
53
BHE
and Other(1)
12
12
18
Total
$
4,594
$
5,385
$
8,052
Capital
expenditures by type:
Wind generation
$
872
$
583
$
846
Electric distribution
1,217
1,316
1,814
Electric
transmission
539
1,157
1,743
Natural gas transmission and storage
647
640
959
Solar generation
104
333
408
Other
1,215
1,356
2,282
Total
$
4,594
$
5,385
$
8,052
(1)BHE
and Other represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
The Company's historical and forecast capital expenditures consisted mainly of the following:
•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 $39 million and $275 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned spending for the construction of additional wind-powered generating facilities
totals $74 million for the remainder of 2022.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $422 million and $274 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned spending for the repowering of wind-powered generating facilities totals $98 million for the remainder of 2022. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. As a result of the Inflation Reduction Act of 2022, all of the 310 MWs of current repowering projects not in-service as of September 30, 2022, are currently expected to qualify for 100% of the PTCs available for
10 years following each facility's return to service.
◦Construction of wind-powered generating facilities at PacifiCorp totaling $5 million and $99 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Construction includes 516 MWs of new wind-powered generating facilities that were placed in-service in 2021. Planned spending for constructing additional wind-powered generating facilities totals $22 million for the remainder of 2022.
38
◦Planned acquisition and repowering of two wind-powered generating facilities by PacifiCorp totaling $16 million
and $9 million for the nine-month periods ended September 30, 2022 and 2021, respectively. The repowered facilities are expected to be placed in-service in 2023 and 2024. Planned spending for acquiring and repowering generating facilities totals $8 million for the remainder of 2022.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $45 million for the nine-month period ended September 30, 2022.
•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, wildfire mitigation, storm damage restoration and repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
•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 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; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation
near Boise, Idaho. Expenditures for these segments totaled $640 million and $57 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $299 million for the remainder of 2022.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new
Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Expenditures for the expansion program and other growth projects totaled $91 million and $64 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026-2028 and other growth projects totals $53 million for the remainder of 2022.
◦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.
•Natural
gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for asset modernization and the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for pipeline integrity projects, automation and controls upgrades, underground storage, corrosion control, unit exchanges, compressor modifications, projects related to Pipeline and Hazardous Materials Safety Administration natural gas storage rules and natural gas transmission, storage and liquefied natural gas terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including spending for the following:
◦Construction of solar-powered generating facilities
at MidAmerican Energy totaling 141 MWs of small- and utility-scale solar generation, all of which were placed in-service as of September 30, 2022, with total spend of $103 million and $97 million for the nine-month periods ended September 30, 2022 and 2021, respectively, and planned spending of $33 million for the remainder of 2022.
◦Construction of a solar-powered generating facility at Nevada Power totaling $47 million and $7 million for the nine-month periods ended September 30, 2022 and 2021, respectively and planned spending of $42 million for the remainder of 2022. Construction 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. Commercial operation is expected by the end of 2023.
◦BHE Renewables made down payments on 785 MWs of solar modules totaling $22 million for the nine-month period ended September 30, 2022.
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•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 coal combustion
residuals.
Material Cash Requirements
As of September 30, 2022, there have been no material changes in cash requirements from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2021, other than those disclosed in Notes 4 and 8 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Quad Cities Generating Station Operating Status
Constellation
Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, which was a subsidiary of Exelon Corporation prior to February 1, 2022), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. 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. The proceeds from the ZECs will provide Constellation Energy additional revenue through 2027
as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will 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, 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-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future
auctions.
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 in May 2021. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources 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. In response to the FERC's order, the PJM submitted a compliance filing on March
18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 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 D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, 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 at 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 will no longer apply to Quad Cities Station. 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. Constellation
Energy is strenuously opposing these appeals.
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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's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard 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.
Regulatory Matters
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2021 and new regulatory matters occurring in 2022.
PacifiCorp
Oregon
In March 2022,
PacifiCorp filed a general rate case requesting an overall rate change of $82 million, or 6.6%, to become effective January 1, 2023, that includes cost increases associated with the implementation of PacifiCorp's wildfire mitigation and vegetation management plans. Parties to the case filed testimony in June 2022. PacifiCorp filed reply testimony in July 2022 supporting an overall rate increase of $94 million but proposing that the request be capped at PacifiCorp's original request. PacifiCorp and parties to the case settled various aspects of the general rate case in multiple settlement stipulations. In August 2022, the first partial stipulation was filed resolving issues related to wildfire mitigation and vegetation management, including addressing the associated costs increases. Also in August 2022, a second partial stipulation was filed representing the settlement of certain revenue requirement issues among the stipulating
parties, including the extension of Oregon's recovery period for Jim Bridger Units 1 and 2 that will be converted to natural gas-fueled units and certain other issues. In September 2022, a third stipulation was filed resolving most of the remaining issues in the general rate case following the first and second partial stipulations. The stipulations together result in a total rate increase of $49 million, or 3.9%, effective January 1, 2023. The stipulating parties also agreed to amortize certain deferrals totaling approximately $10 million, or 0.8 %, in the first year of amortization, effective April 1, 2023. Further, in the third stipulation, PacifiCorp agreed to a general rate case stay-out provision under which it agreed not to file a general rate case with rates effective any earlier than January 1, 2025. In September
2022, the fourth and final partial stipulation was filed resolving technical issues related to a voluntary renewable energy tariff that will allow non-residential customers to purchase energy from renewable resources not currently in PacifiCorp's rates. A commission decision on the stipulations is pending.
In May 2022, PacifiCorp filed its 2021 power cost adjustment mechanism ("PCAM"), which is the first time since the mechanism has been in place that a rate change has been warranted. After consideration of the mechanism's deadband, sharing band and earnings test, PacifiCorp requested recovery of $52 million, or a 4.2% increase, to become effective January 1, 2023. This request is incremental to the rate change sought in the general rate case. In September 2022, a settlement stipulation was filed agreeing to the recovery of the
requested $52 million over a four-year period beginning April 1, 2023. A commission decision on the stipulation is pending.
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. Oregon Senate Bill 762 provides for utilities to timely recover these costs through an automatic adjustment clause. The filing requests a rate increase of $20 million, or 1.6%, to recover incremental costs in 2022 and is incremental to costs addressed in PacifiCorp's wildfire mitigation and vegetation management mechanism through the general rate case stipulation described above. While PacifiCorp requested an effective date of August 24, 2022, the
OPUC has suspended the filing for further review. A decision is expected in 2023.
Washington
In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. PacifiCorp requested a $13 million, or 3.7%, rate increase with an effective date of January 1, 2022. In November 2021, PacifiCorp reached a proposed settlement with most of the parties, which includes an agreement to adjust the PTC rate in base rates and apply a production factor and include a net power cost update as part of the compliance filing. A hearing was held in January 2022 and the WUTC issued an order approving the settlement in March 2022. A compliance filing reflecting a $43 million, or 12.2%, increase was filed in April 2022 with rates effective
May 1, 2022.
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In June 2022, PacifiCorp filed its 2021 PCAM and the new tracking mechanism for PTCs approved in the 2021 general rate case. For the 2021 PCAM, PacifiCorp is requesting a recovery of $26 million, or a 6.5% increase. PacifiCorp proposed that the 2021 PCAM be amortized over two years, rather than the one-year period required under the current terms of the PCAM. For the new 2021 PTC tracker, PacifiCorp is seeking recovery of $3 million, or an 0.8% increase. Should the WUTC approve the proposal to extend the amortization period of the 2021 PCAM from one to two years, the combined annual increase would be $16 million, or 4.0%, effective January
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 June 2022, a proposed procedural schedule was developed that would result in a decision in August 2023.
In August 2022, PacifiCorp filed an Energy Cost Adjustment Clause ("ECAC") application requesting an overall rate increase of $15 million, or 13.6%, effective January 1, 2023. Approximately $4 million of the increase, or 3.6%, is attributed to the ECAC rate and $11 million of the increase, or 10.0%, to the Greenhouse Gas rate.
MidAmerican
Energy
South Dakota
In May 2022, MidAmerican Energy filed a request with the South Dakota Public Utilities Commission ("SDPUC") for an increase in its South Dakota retail natural gas rates, which would increase revenue by $7 million annually. If approved, the requested rates would increase retail customers' bills by an average of 6.4%.
Wind PRIME
In January 2022, MidAmerican Energy filed an application with the IUB for advance ratemaking principles for Wind PRIME. If approved, MidAmerican Energy expects to proceed with Wind PRIME, which consists of up to 2,042 MWs of new wind generation and up to 50 MWs of solar generation. If
all of 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 secured sufficient safe harbor equipment necessary to remain eligible for 100% PTCs under current tax law. Procedural hearings with the IUB are expected to begin in February 2023.
NV Energy (Nevada Power and Sierra Pacific)
Senate Bill 448 ("SB 448")
SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission
development, renewable energy and storage, and accelerate transportation electrification within the state of Nevada. In September 2021, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of their Transmission Infrastructure for a Clean Energy Economy Plan that sets forth a plan for the construction of high-voltage transmission infrastructure, Greenlink North among others, that will be placed into service no later than December 31, 2028, and requires the IRP to include at least one scenario that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. In September 2021, the Nevada Utilities filed an application for the approval of their Economic Recovery Transportation Electrification Plan to accelerate transportation electrification in the state of Nevada. The plan establishes requirements for the contents of the transportation electrification investment as well
as requirements for review, cost recovery and monitoring. The plan covers an initial period beginning January 1, 2022 and ending on December 31, 2024. In November 2021, the PUCN issued an order granting the application and accepting the Economic Recovery Transportation Electrification Plan with some modifications. The PUCN opened rulemakings to address other regulations that resulted from SB 448. In February 2022, the PUCN adopted regulations regarding the Economic Development Electric Rate Rider Program to revise the discounted electric rates to ease the economic burden on small businesses who take advantage of the discounted rates under the tariff. In September 2022, the PUCN adopted regulations regarding resource planning, which incorporates a plan to accelerate transportation electrification into the distributed resources plan pursuant to SB 448.
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ON
Line Temporary Rider ("ONTR")
In October 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR with corresponding updates to its electric rate tariffs to authorize recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being accumulated as a result of the ON Line cost reallocation as well as the related on-going reallocated revenue requirement. Sierra Pacific's application would have, if approved by the PUCN as filed, resulted in a one-time rate increase of $28 million to be collected over a nine-month period starting on April 1, 2022. In March 2022, the PUCN issued an order directing Sierra Pacific to recover $14 million of the ON Line regulatory asset as a one-time rate increase collectable over a nine-month period effective April 1, 2022,
with the expected remaining balance at December 31, 2022 to be included in rate base in the 2022 regulatory rate review for inclusion in the rates set in that case.
Merger Application
In March 2022, the Nevada Utilities filed a joint application with the PUCN for authorization to merge Sierra Pacific with and into Nevada Power, with Nevada Power being the surviving entity. If approved by the PUCN as filed, Nevada Power will have two distinct electric service territories in northern and southern Nevada each with their own rates and one natural gas service territory in the Reno and Sparks area. In October 2022, the proceedings relating to the joint application were postponed to November 2022. An order is expected in the first half
of 2023.
Regulatory Rate Review
In June 2022, Sierra Pacific filed a regulatory rate review with the PUCN that requested an annual revenue increase of $88 million, or 9.7%. 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 2022, Sierra Pacific filed an updated certification filing that requested an annual revenue increase of $77 million, or 8.5%. Parties to the review filed testimony and evidence in August and September 2022. Hearings in the cost of capital and revenue requirement phases were held in September and October 2022, respectively. The hearings in the rate design phase are scheduled for November 2022. An order is expected by the end of 2022 and, if approved, would be effective January
1, 2023.
Transportation Electrification Plan ("TEP")
In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of a Distributed Resource Plan amendment to implement the state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs and schedules to implement the TEP. The 2022 TEP outlines programs, investments and incentives to accelerate transportation electrification across Nevada. The Nevada Utilities anticipate a budget of $348 million, which represents the maximum cost over the depreciable life of the TEP's programs and assets, to deploy the TEP in 2023 through 2024.
Northern Powergrid Distribution Companies
GEMA,
through Ofgem, is undertaking its scheduled review of the electricity distribution price control to put in place a new price control at the end of the current period that ends March 2023. The new price control ("ED2") will run for five years from April 2023 to March 2028. In December 2020 and March 2021, GEMA published its decision on the methodology it will use to set ED2. This confirmed that Ofgem will maintain many aspects of the current price control and that the changes being made will 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, while others will be discontinued, and partially updating the allowed return on equity within the period for changes in the interest rate on government bonds.
In
December 2021, Northern Powergrid published and filed its business plan with Ofgem, setting out its detailed approach for 2023-2028 including the cost allowances this approach would require. In June 2022, Ofgem published its draft determinations, which included an allowed cost of equity of 4.75% plus inflation (calculated using the United Kingdom's consumer price index including owner occupiers' housing costs). When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, this working assumption is approximately two percentage points lower than the current cost of equity for electricity distribution. Ofgem's proposals also set out cost allowances and associated expectations. In August 2022, Northern Powergrid formally responded to Ofgem's consultation on its draft determinations to lobby for a better settlement. Final values from Ofgem are expected in November 2022.
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BHE
Pipeline Group
BHE GT&S
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. 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, resolving EGTS' general rate case for its FERC-jurisdictional services and providing for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transportation and storage revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. As of September 30, 2022, EGTS' provision for rate refund for April 2022 through September 2022 totaled $56 million and was included in other current liabilities on the Consolidated Balance Sheet. FERC approval of the settlement is expected late 2022 or early 2023.
Northern
Natural Gas
In July 2022, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $1.3 billion. This is an increase of $323 million above the cost of service filed in its 2019 rate case of $1.0 billion. Depreciation on increased rate base and an increase in depreciation and negative salvage rates account for $115 million of the $323 million increase in the filed cost of service. Northern Natural Gas has requested increases in various rates, including transportation reservation rates ranging from approximately 45% in the Field Area to 120% in the Market Area to be implemented, subject to refund, on August 1, 2022. In July 2022, the FERC issued an order that suspended the rates proposed for five months following the proposed effective date, until January
1, 2023, subject to refund and the outcome of hearing procedures.
BHE Transmission
AltaLink
2022-2023 General Tariff Application
In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year-over-year increase of approximately 2% in 2022 and 2023 revenue requirements. The application
requested the approval of transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively after proposed refunds. In September 2021, AltaLink provided responses to information requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates.
In January 2022, the AUC issued its decision with respect to AltaLink's 2022-2023 GTA. AltaLink's 2022-2023 GTA reflected its continued commitment to provide rate stability to customers by maintaining flat tariffs and providing additional tariff relief measures, including a proposed tariff refund of C$60 million of accumulated depreciation in each of 2022 and 2023. The AUC did not approve AltaLink's proposed refund due to an anticipated improvement in general economic conditions in Alberta. In March 2022, AltaLink filed a review and variance application requesting the AUC to review
and vary its decision to deny AltaLink's proposed C$120 million refund of accumulated depreciation surplus, given material changes in circumstances since the decision was issued in January 2022. In May 2022, the AUC issued a decision with respect to AltaLink's application to review and vary its proposed $120 million refund of accumulated depreciation surplus. The AUC found that a material decline in Alberta's economic circumstances is not sufficient evidence to warrant the refund.
In July 2022, AltaLink submitted its second compliance filing application with total 2022 and 2023 revenue requirements at C$879 million and C$883 million, respectively. In August 2022, the AUC approved the revised revenue requirements as filed, allowing AltaLink to fully deliver on its flat-for-five commitment to customers.
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2023
Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the 2023 generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider 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 2023 GCOC 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 due to the COVID-19 pandemic. 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.
Environmental
Laws and Regulations
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species 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 are subject to interpretation that may ultimately be resolved
by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2021, and new environmental matters occurring in 2022.
Climate Change
Affordable Clean Energy Rule
In June 2014, the EPA released proposed regulations to address greenhouse gas 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 United States 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 United States 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 United States Supreme Court issued its decision regarding the scope of the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The United States 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 United States 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 United States Supreme Court reversed the D.C. Circuit's vacatur of the Affordable Clean Energy rule and remanded the case for further proceedings. The ruling has no immediate impact on the Registrants, as there is no Section 111(d) rule currently in effect.
The Biden administration plans to propose by March 2023 its own rule to replace the Clean Power Plan and Affordable Clean Energy rule.
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Clean Air Act Regulations
The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA.
The major Clean Air Act programs most directly affecting the Registrants' operations are described below.
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.
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. The EPA must finalize the proposed rules by December 15, 2022. In addition, the EPA must, by December 15, 2022, 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. Until the EPA takes final action consistent with this decree, additional impacts to the relevant Registrants cannot be determined.
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 the 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, will be reclassified as Moderate Non-Attainment, and will 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.
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., including Iowa, 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.
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The first phase of the rule was implemented January 1, 2015. In November
2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, the EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. The EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern U.S. in that year. Accordingly, the 20 CSAPR Update-affected states
would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind states to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update Rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps
on emissions of NOx from generating facilities in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update Rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at generating facilities in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update Rule largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule. In June 2021,
a new lawsuit was filed that challenges the Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court. Until litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.
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. The rule focuses on reductions of NOx, precursors to ozone formation and covers 26 states. Relevant to the Registrants, four states are included in the cross-state program for the first time - California, Nevada, Utah and Wyoming. Iowa is not included in the proposal. In a separate but related action in February 2022, the EPA proposed to approve the good neighbor provisions of Iowa's SIP addressing ozone transport and the 2015
ozone standard. The EPA proposes to retain emissions allowance trading for generating facilities. Beginning in 2023, emissions budgets would be set at the level of reductions achievable through immediately available measures such as consistently operating existing emissions controls. Starting in 2026, emissions budgets would be set at levels achievable by the installation of SCR controls at certain generating facilities. The proposal also includes additional industries beyond the power sector for the first time, with a focus on the top NOx emitting stationary source categories. These include natural gas pipeline compressor stations, pulp and paper mills, cement production, iron and steel boilers and furnaces, glass furnaces, chemical manufacturing and petroleum and coal product manufacturing. These sources will not have access to trading and will instead be subject to rate-based limits that are assigned for each source
category. The EPA accepted comments on the proposal through June 21, 2022. Until the EPA takes final action consistent with this decree, impacts to the relevant Registrants 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.
47
The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2 and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2 and Huntington Units 1 and 2.
In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a FIP requiring the installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA
issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. 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 Utah Division of Air Quality submitted the SIP revision to the EPA for approval at the end of 2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon generating facility federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington generating facilities. The proposed approval withdraws the FIP requirements to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the
FIP requirements for the Hunter and Huntington generating facilities. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. 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. PacifiCorp and the state of Utah moved to intervene in the litigation. After review of the rule by the Biden administration, the EPA determined it would defend the rule, and briefing has been completed. A date for oral arguments has not been scheduled. The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for the regional haze second
planning period on June 6, 2022. The SIP sets mass-based NOx emissions limits and rate-based SO2 limits for PacifiCorp's Hunter and Huntington generating facilities to ensure reasonable visibility progress for the second planning period.
48
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. In addition, the EPA initially proposed in June 2012 to disapprove portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NOx and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP 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 within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. 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 EPA, U.S. Department of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to install SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. The EPA did not give final approval to the settlement agreement and parties were unable to reach an agreement through mediation. The abatement on litigation was lifted September 28, 2022, and opening briefs are due October 28, 2022. PacifiCorp objects to the EPA's FIP requiring SCR on the Wyodak Unit. That requirement in the agency's plan remains stayed by the court. PacifiCorp has also intervened on
behalf of the EPA against claims that Units 1 and 2 at the Naughton generating facility should have been subject to a SCR requirement. On February 5, 2019, PacifiCorp submitted a reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of SCR, to be replaced with a permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. In May 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NOx and SO2 emission limits on the four Jim Bridger units and submitted a regional haze SIP revision to the EPA. The revised SIP would grant approval of PacifiCorp's Jim Bridger
reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency suspension order under Section 110(g) of the Clean Air Act, allowing the operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA proposed to reject the SIP revisions. The EPA took comment on the proposal through February 17, 2022. 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
under Sections 201 and 209(a) of the Wyoming Environmental Quality Act, 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 and as forecasted in PacifiCorp's 2021 IRP, PacifiCorp must convert both units to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. In addition, PacifiCorp must propose an RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and 4. Wyoming issued its proposed implementation plan for second planning period reasonable progress on February 18, 2022 and accepted comments through March
23, 2022. 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. The proposed SIP revision reflecting these agreements is currently being evaluated under parallel processes by the state of Wyoming and the EPA. The Wyoming Department of Environmental Quality submitted the Jim Bridger Units 1 and 2 proposed SIP revision to federal land managers for a 60-day consultation on June 7, 2022. Wyoming
held a public hearing for the Bridger gas conversion SIP revision on September 14, 2022, and accepted public comments on the plan through September 20, 2022. For the second round of regional haze planning, Wyoming determined that no controls will be necessary on any Wyoming resources to make reasonable progress.
In February 2022, NV Energy received 30-day notice letters from the Nevada Division of Environmental Protection regarding the reopening and revision of the Valmy and Tracy Generating Station's Title V air quality operating permits to add federally enforceable retirement dates of December 31, 2028 for Valmy Units 1 and 2 and December 31, 2031 for Tracy Unit
4. The enforceable retirement dates will implement Nevada's SIP for the regional haze second planning period. The revised permits were received in March and April 2022. The Nevada Division of Environmental Protection accepted public comment on its SIP through July 25, 2022.
49
Nevada, Utah and Wyoming each submitted regional haze SIPs for second planning period to the EPA in August 2022. The EPA has 18 months to approve or disapprove all or parts of the states' plans. 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 anticipates submitting a final plan to the EPA in spring 2023.
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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2021. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2021.
50
PacifiCorp
and its subsidiaries
Consolidated Financial Section
51
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the Board of Directors and Shareholders of
PacifiCorp
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2022, the related consolidated statements of operations and changes in shareholders' equityfor the three-month and nine-month periods ended September 30, 2022 and 2021, and of cash flows for the nine-month periods ended September 30, 2022 and 2021, and the related notes (collectively referred
to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2021, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, we expressed an unqualified opinion on those consolidated financial statements.
In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of PacifiCorp's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying
analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i836
i811
Allowance
for equity funds
(i47)
(i38)
Changes
in regulatory assets and liabilities
(i285)
(i185)
Deferred
income taxes and amortization of investment tax credits
i48
i33
Other,
net
i15
i—
Changes
in other operating assets and liabilities:
Trade receivables, other receivables and other assets
(i233)
(i12)
Inventories
i3
i17
Derivative
collateral, net
i28
i19
Accrued
property, income and other taxes, net
i180
i96
Accounts
payable and other liabilities
i586
i77
Net
cash flows from operating activities
i1,752
i1,544
Cash
flows from investing activities:
Capital expenditures
(i1,481)
(i1,157)
Other,
net
i4
i7
Net
cash flows from investing activities
(i1,477)
(i1,150)
Cash
flows from financing activities:
Proceeds from long-term debt
i—
i984
Repayments
of long-term debt
(i104)
(i400)
Repayments
of short-term debt
i—
(i93)
Dividends
paid
(i100)
i—
Other,
net
(i2)
(i5)
Net
cash flows from financing activities
(i206)
i486
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i69
i880
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i186
i19
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i255
$
i899
The
accompanying notes are an integral part of these consolidated financial statements.
57
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
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").
iThe unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly,
they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2022 and for the three- and nine-month periods ended September 30, 2022 and 2021. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 2022 and 2021. The results of operations for the three- and nine-month periods ended September 30,
2022 and 2021 are not necessarily indicative of the results to be expected for the full year.
iThe preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements.
Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30, 2022, other than the updates associated with PacifiCorp's estimates of loss contingencies related to the Oregon and California 2020 wildfires (the "2020 Wildfires") as discussed in Note 9.
(2) iCash
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. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets. iA
reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented in 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
i33
i4
Restricted
cash included in other assets
i3
i3
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i255
$
i186
58
(3) iProperty,
Plant and Equipment, Net
i
Property, plant and equipment, net consists of the following (in millions):
As
of
September 30,
December 31,
Depreciable Life
2022
2021
Utility Plant:
Generation
i15
- i59 years
$
i13,761
$
i13,679
Transmission
i60
- i90 years
i7,982
i7,894
Distribution
i20
- i75 years
i8,321
i8,044
Intangible
plant(1)
i5 - i75 years
i1,147
i1,106
Other
i5
- i60 years
i1,606
i1,539
Utility
plant in-service
i32,817
i32,262
Accumulated
depreciation and amortization
(i11,057)
(i10,507)
Utility
plant in-service, net
i21,760
i21,755
Other
non-regulated, net of accumulated depreciation and amortization
i14 - i95
years
i18
i18
Plant,
net
i21,778
i21,773
Construction
work-in-progress
i2,115
i1,141
Property,
plant and equipment, net
$
i23,893
$
i22,914
(1)Computer
software costs included in intangible plant are initially assigned a depreciable life of i5 to i10 years.
/
(4) iRecent
Financing Transactions
Credit Facilities
In June 2022, PacifiCorp amended and restated its existing $i1.2 billion unsecured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from the London Interbank Offered Rate to the Secured Overnight Financing Rate.
Common
Shareholders' Equity
In May 2022, PacifiCorp declared a common stock dividend of $i100 million, paid in June 2022, to PPW Holdings LLC.
(5) iIncome
Taxes
i
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax benefit is as follows:
State
income tax, net of federal income tax benefit
i4
i4
i4
i4
Federal
income tax credits
(i22)
(i20)
(i22)
(i20)
Effects
of ratemaking(1)
(i13)
(i13)
(i12)
(i14)
Valuation
allowance
i—
i—
i1
i—
Other
i—
(i1)
i1
i—
Effective
income tax rate
(i10)
%
(i9)
%
(i7)
%
(i9)
%
(1)Effects
of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
/
59
Income tax credits relate primarily to production tax credits ("PTCs") from 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 recognized for the nine-month periods ended September 30, 2022 and 2021 totaled $i127 million and $i133 million,
respectively.
For the nine-month period ended September 30, 2022, PacifiCorp recorded a valuation allowance related to state net operating loss carryforwards.
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the nine-month periods ended September 30, 2022 and 2021,
PacifiCorp received net cash payments for federal and state income tax from BHE totaling $i194 million and $i109 million,
respectively.
(6) iEmployee Benefit Plans
i
Net
periodic benefit cost for the pension and other postretirement benefit plans included the following components (in millions):
Amounts
other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $i4 million and $i— million,
respectively, during 2022. As of September 30, 2022, $i3 million of contributions had been made to the pension plans.
(7) 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.
60
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 may from time to time 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. Refer to Note 8 for additional information on derivative contracts.
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 September 30, 2022 a regulatory liability of $i166 million was recorded related to the net derivative asset of $i166 million.
As of December 31, 2021 a regulatory liability of $i53 million was recorded related to the net derivative asset of $i53 million.
/
61
i
The
following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
Changes
in fair value recognized in regulatory assets
(i79)
(i128)
(i296)
(i247)
Net
gains (losses) reclassified to operating revenue
i7
i—
(i4)
(i5)
Net
gains reclassified to energy costs
i129
i81
i187
i86
Ending
balance
$
(i166)
$
(i149)
$
(i166)
$
(i149)
/
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 (in millions):
Unit
of
September 30,
December 31,
Measure
2022
2021
Electricity purchases, net
Megawatt hours
i2
i2
Natural
gas purchases
Decatherms
i108
i106
/
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 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 PacifiCorp's creditworthiness. These rights can vary by contract and by the counterparty. As of September 30, 2022, PacifiCorp'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.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $ii37/ million
as of September 30, 2022 and December 31, 2021, respectively, for which PacifiCorp had posted collateral of $i— million and $i5 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 September 30, 2022 and December 31, 2021, PacifiCorp would have been required to post $i7 million and $i23 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.
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(8) 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.
i
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 payable of $i23 million and a net cash collateral receivable of $i5 million
as of September 30, 2022 and December 31, 2021, respectively.
/
63
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 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 7 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.
i
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. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):
During the nine-month period ended September 30, 2022, PacifiCorp entered into certain procurement and construction services agreements for $i1.1 billion through 2024 for the construction of key Energy Gateway Transmission segments in Utah, Wyoming and Idaho, including $i849
million for the segment extending between the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah.
Fuel Contracts
During the nine-month period ended September 30, 2022, PacifiCorp entered into certain coal supply and transportation agreements totaling approximately $i214 million through 2028.
Purchased
Electricity Contracts - Not Commercially Operable
During the nine-month period ended September 30, 2022, PacifiCorp entered into a purchased electricity contract for a solar generating facility including battery storage with minimum obligations totaling approximately $i238 million through 2045. The facility associated with this contract has not yet achieved commercial operation. To the extent this facility does not achieve commercial operation, PacifiCorp has no obligation
to the counterparty.
64
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. PacifiCorp 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 and are described below.
Wildfire Liability Overview
A
provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PacifiCorp evaluates which potential liabilities are probable and the related range of reasonably estimated losses and records a charge that reflects its best estimate or the lower end of the range, if there is no better estimate.
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 nevertheless be found liable for all damages proximately caused by negligence, including real and personal property and natural resource damages; fire suppression costs; personal injury and loss of life damages; and interest.
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. Fire suppression costs estimated by various agencies total approximately $i150 million.
Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States 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, i60 lawsuits have been filed in Oregon and California, including a class action complaint in Oregon, on behalf of plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made
in the aforementioned lawsuits. The final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
As of the date of this filing, PacifiCorp estimates the probable loss to be $i200 million, net of expected insurance recoveries and has accrued such amount as of September 30, 2022. During the nine-month period ended September
30, 2022, PacifiCorp accrued $i64 million of losses net of expected insurance recoveries, associated with the 2020 Wildfires. The accrual includes PacifiCorp's estimate of losses for 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 that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information
necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available. It is reasonably possible PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the variation in those types of properties and lack of available details. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover a portion of the losses. PacifiCorp's receivable for expected insurance recoveries was $i277 million
as of September 30, 2022.
65
2022 McKinney Fire
According to California Department of Forestry and Fire Protection ("Cal Fire"), on July 29, 2022, at approximately 2:16 p.m. Pacific Time, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. The Cal Fire McKinney Fire incident report last updated September 8, 2022 (the "Cal Fire incident report") indicates that
the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and 4 fatalities. According to InciWeb, an interagency all-risk incident information management system, the 2022 McKinney Fire consumed 60,138 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the United States Forest Service.
Due to the preliminary nature of the investigation PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $i31 million,
net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp is unable to estimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $i103 million,
to cover potential losses.
As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages but the amount of damages sought are not specified. The final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal
combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
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.
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In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved 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 Klamath Hydroelectric 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 transfer of the four mainstem Klamath 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. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending. In August 2022, the FERC staff issued a final environmental impact statement for the project, concluding that dam removal is the preferred action.
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.
(10) iRevenue
from Contracts with Customers
i
The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
Item
2.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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.
Results
of Operations for the Third Quarter and First Nine Months of 2022 and 2021
Overview
Net income for the third quarter of 2022 was $409 million, an increase of $77 million, or 23%, compared to 2021. Net income increased primarily due to higher utility margin, lower other expense and higher income tax benefit, partially offset by increased operations and maintenance expense largely due to higher general and plant maintenance costs and higher depreciation and amortization expense. Utility margin increased primarily due to higher retail prices and volumes, higher net power cost deferrals, higher average wholesale market prices and lower thermal generation volumes, partially offset by higher purchased electricity costs from higher volumes and prices and higher natural gas prices. Retail customer volumes increased
3.5%, primarily due to favorable impacts of weather and an increase in the average number of customers, partially offset by a decrease in customer usage. Energy generated decreased 5% for the third quarter of 2022 compared to 2021 primarily due to lower coal-fueled, wind-powered and natural gas-fueled generation, partially offset by higher hydroelectric generation. Wholesale electricity sales volumes decreased 5% and purchased electricity volumes increased 32%.
Net income for the first nine months of 2022 was $621 million, a decrease of $105 million, or 14%, compared to 2021 primarily due to higher operations and maintenance expense largely due to an increase to the wildfire damage provision and higher general and plant maintenance costs, higher depreciation and amortization expense and lower income tax benefit, partially offset by higher utility margin and lower other expense. Utility
margin increased primarily due to higher retail prices and volumes, higher net power cost deferrals, higher average wholesale market prices, lower thermal generation volumes, lower purchased electricity prices and higher wheeling revenues, partially offset by higher purchased electricity volumes, higher natural gas and coal prices and lower wind-based ancillary revenues. Retail customer volumes increased 0.8%, primarily due to an increase in the average number of customers and favorable impacts of weather, partially offset by a decrease in customer usage. Energy generated decreased 4% for the first nine months of 2022 compared to 2021 primarily due to lower coal-fueled and natural gas-fueled generation, partially offset by higher wind-powered and hydroelectric generation. Wholesale electricity sales volumes decreased 2% and purchased electricity volumes increased 17%.
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 customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. 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.
68
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 comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Utility margin:
Operating
revenue
$
1,635
$
1,491
$
144
10
%
$
4,246
$
4,031
$
215
5
%
Cost
of fuel and energy
581
505
76
15
1,497
1,370
127
9
Utility margin
1,054
986
68
7
2,749
2,661
88
3
Operations
and maintenance
289
267
22
8
941
781
160
20
Depreciation and amortization
277
272
5
2
836
811
25
3
Property
and other taxes
51
54
(3)
(6)
161
158
3
2
Operating income
$
437
$
393
$
44
11
%
$
811
$
911
$
(100)
(11)
%
69
Utility
Margin
A comparison of key operating results related to utility margin is as follows:
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Utility margin (in millions):
Operating
revenue
$
1,635
$
1,491
$
144
10
%
$
4,246
$
4,031
$
215
5
%
Cost
of fuel and energy
581
505
76
15
1,497
1,370
127
9
Utility margin
$
1,054
$
986
$
68
7
%
$
2,749
$
2,661
$
88
3
%
Sales
(GWhs):
Residential
5,035
4,732
303
6
%
13,653
13,396
257
2
%
Commercial
5,343
5,078
265
5
14,526
14,181
345
2
Industrial,
irrigation and other
5,337
5,375
(38)
(1)
14,709
14,976
(267)
(2)
Total retail
15,715
15,185
530
3
42,888
42,553
335
1
Wholesale
1,037
1,093
(56)
(5)
3,835
3,928
(93)
(2)
Total
sales
16,752
16,278
474
3
%
46,723
46,481
242
1
%
Average
number of retail customers (in thousands)
2,040
2,006
34
2
%
2,033
1,998
35
2
%
Average
revenue per MWh:
Retail
$
93.38
$
88.91
$
4.47
5
%
$
89.19
$
86.53
$
2.66
3
%
Wholesale
$
84.28
$
53.45
$
30.83
58
%
$
55.37
$
37.23
$
18.14
49
%
Heating
degree days
91
196
(105)
(54)
%
6,572
6,111
461
8
%
Cooling
degree days
2,021
1,681
340
20
%
2,432
2,427
5
—
%
Sources
of energy (GWhs)(1):
Coal
8,606
9,011
(405)
(4)
%
21,777
24,157
(2,380)
(10)
%
Natural
gas
3,684
3,886
(202)
(5)
9,546
10,174
(628)
(6)
Wind(2)
1,051
1,264
(213)
(17)
5,260
4,385
875
20
Hydroelectric
and other(2)
555
439
116
26
2,572
2,130
442
21
Total energy generated
13,896
14,600
(704)
(5)
39,155
40,846
(1,691)
(4)
Energy
purchased
4,047
3,058
989
32
10,987
9,407
1,580
17
Total
17,943
17,658
285
2
%
50,142
50,253
(111)
—
%
Average
cost of energy per MWh:
Energy generated(3)
$
21.60
$
18.39
$
3.21
17
%
$
20.74
$
17.98
$
2.76
15
%
Energy
purchased
$
97.72
$
88.48
$
9.24
10
%
$
68.82
$
67.10
$
1.72
3
%
(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 Renewable Energy Credits 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 increased $68 million, or 7%, for the third quarter of 2022 compared to 2021 primarily due to:
•$117 million increase in retail revenue due to higher average prices and higher volumes. Retail customer volumes increased 3.5%, primarily due to favorable impacts of weather and an increase in the average number of customers, partially offset by a decrease in customer usage;
•$80 million of higher deferred net power costs in accordance with established adjustment mechanisms, including 2021 cost deferrals under the Oregon power cost adjustment mechanism;
•$29 million increase in wholesale revenue primarily due to higher average market prices,
partially offset by lower volumes; and
•$4 million of lower coal-fueled generation costs primarily due to lower volumes, partially offset by higher average prices.
The increases above were partially offset by:
•$125 million of higher purchased electricity costs from higher volumes and higher average market prices; and
•$36 million of higher natural gas-fueled generation costs due to higher average market prices, partially offset by lower volumes.
Operations and maintenance increased $22 million, or 8%, for the third quarter of 2022 compared to 2021 primarily due to higher plant maintenance costs, consumption of materials, higher insurance premiums due
to cost increases related to wildfire coverage, higher start-up and equipment-related fuel costs and higher chemical costs.
Depreciation and amortization increased $5 million, or 2%, for the third quarter of 2022 compared to 2021 primarily due to higher plant in-service balances in the current quarter and prior year deferrals in Idaho associated with the increase in depreciation expense resulting from the implementation of the 2018 depreciation study compounded by amortization of those deferrals in the current quarter, partially offset by current year deferrals in Oregon associated with certain wind-powered generating facilities.
Property and other taxes decreased $3 million, or 6%, for the third quarter of 2022 compared to 2021 primarily due to lower
property tax rates in Utah.
Allowance for borrowed and equity funds increased $9 million, or 47%, for the third quarter of 2022 compared to 2021 primarily due to higher qualified construction work-in-progress balances, partially offset by lower rates.
Income tax benefit increased $9 million, or 32%, for the third quarter of 2022 compared to 2021 and the effective tax rate was (10)% for 2022 and (9)% for 2021. The effective tax rate decreased primarily due to increased PTCs from PacifiCorp's wind-powered generating facilities.
First Nine Months of 2022 compared to First Nine Months of 2021
Utility
margin increased $88 million, or 3%, for the first nine months of 2022 compared to 2021 primarily due to:
•$143 million increase in retail revenue due to higher average prices and volumes. Retail customer volumes increased 0.8%, primarily due to an increase in the average number of customers and favorable impacts of weather, partially offset by a decrease in customer usage;
•$76 million higher deferred net power costs in accordance with established adjustment mechanisms, including 2021 cost deferrals under the Oregon power cost adjustment mechanism;
•$66 million increase in wholesale revenue primarily due to higher average market prices, partially offset by lower volumes;
•$39
million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices; and
•$14 million of favorable wheeling activities.
The increases above were partially offset by:
•$125 million of higher purchased electricity costs from higher volumes, partially offset by lower average market prices;
71
•$116 million of higher natural gas-fueled generation costs due to higher average market prices, partially offset by lower volumes; and
•$8 million of lower wind-based ancillary
revenue.
Operations and maintenance increased $160 million, or 20%, for the first nine months of 2022 compared to 2021 primarily due to a $64 million increase in the loss accruals associated with the September 2020 wildfires net of estimated insurance recoveries, higher plant maintenance costs, higher DSM amortization expense, higher insurance premiums due to cost increases related to wildfire coverage, consumption of materials, higher start-up and equipment-related fuel costs and higher chemical costs.
Depreciation and amortization increased $25 million, or 3%, for the first nine months of 2022 compared to 2021 primarily due to higher plant in-service balances in the current year and prior year deferrals in Idaho associated with the increase in depreciation expense resulting from the implementation
of the 2018 depreciation study compounded by amortization of those deferrals in the current year, partially offset by lower depreciation associated with Oregon's accelerated depreciation of coal units due to an update to the Oregon allocation factor applied in computing the incremental depreciation and current year deferrals in Oregon associated with certain wind-powered generating facilities.
Property and other taxes increased $3 million, or 2%, for the first nine months of 2022 compared to 2021 primarily due to higher public utility taxes in Washington.
Allowance for borrowed and equity funds increased$12 million, or 21%, for the first nine months of 2022 compared to 2021 primarily due to higher qualified
construction work-in-progress balances and higher rates.
Other, net decreased $17 million for the first nine months of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies associated with PacifiCorp's supplemental executive retirement plan
Income tax benefit decreased $15 million, or 26%, for the first nine months of 2022 compared to 2021 and the effective tax rate was (7)% for 2022 and (9)% for 2021. The effective tax rate increased primarily due to lower effects of ratemaking associated with excess deferred income tax amortization in the current year and a valuation allowance PacifiCorp recorded in the first quarter of 2022 against state net operating loss carryforwards, partially offset by the
relative impact on a percentage basis of PTCs on the lower pre-tax book income in 2022 compared to that of 2021, which results in a higher benefit related to PTCs in the current year.
Liquidity and Capital Resources
As of September 30, 2022, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents
$
219
Credit
facilities
1,200
Less:
Tax-exempt bond support
(218)
Net credit facilities
982
Total net liquidity
$
1,201
Credit
facilities:
Maturity dates
2025
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2022 and 2021 were $1,752 million and $1,544 million, respectively. The change was primarily due to timing of operating accounts payables, cash received for income taxes, higher transmission deposits and collections from retail customers, partially offset by higher expenditures for materials and supplies and operating expenses.
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 and assumptions for each payment date.
72
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2022 and 2021 were $(1,477) million and $(1,150) million, respectively. The change is primarily due to an increase in capital expenditures of $324 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.
Financing
Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2022 were $(206) million. Uses of cash consisted primarily of $100 million for common stock dividends paid to PPW Holdings LLC and $104 million for the repayment of long-term debt.
Net cash flows from financing activities for the nine-month period ended September 30, 2021 were $486 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $984 million. Uses of cash consisted substantially of $400 million for the repayment of long-term debt and $93 million for the repayment of short-term debt.
Short-term Debt
Regulatory
authorities limit PacifiCorp to $1.5 billion of short-term debt. As of September 30, 2022 and December 31, 2021, PacifiCorp had no short-term debt outstanding.
Debt Authorizations
PacifiCorp currently has regulatory authority from the OPUC and the Idaho Public Utilities Commission to issue an additional $2 billion of long-term debt. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023. PacifiCorp must make a notice filing with the WUTC prior to any future issuance.
Common Shareholders' Equity
In
May 2022, PacifiCorp declared a common stock dividend of $100 million, paid in June 2022, to PPW Holdings LLC.
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, 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.
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; 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.
73
Historical
and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Nine-Month Periods
Annual
Ended September 30,
Forecast
2021
2022
2022
Wind
generation
$
110
$
21
$
59
Electric distribution
461
503
691
Electric transmission
212
816
1,200
Other
374
141
305
Total
$
1,157
$
1,481
$
2,255
PacifiCorp's
2021 IRP identified a roadmap for a significant increase in renewable and carbon-free generation resources, coal-to-natural gas conversion of certain coal-fueled units, energy storage and associated transmission. PacifiCorp's 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to be online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp has included an estimate for these new generation resources and associated transmission in its forecast capital expenditures for 2022 through 2024. These estimates are likely to change as a result of the 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 wind-powered generating facilities at PacifiCorp totaling $5 million and $99 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Construction includes 516 MWs of new wind-powered generating facilities that were placed in-service in 2021. Planned spending for constructing additional wind-powered generating facilities totals $22 million for the remainder of 2022.
◦Planned acquisition and repowering of two wind-powered generating facilities by PacifiCorp totaling $16 million and $9 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned spending for acquiring and repowering generating facilities totals $8 million for the remainder
of 2022.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures include spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled $117 million and $144 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned spending for wildfire mitigation and wildfire and storm damage restoration totals $39 million for the remainder of 2022. The remaining investments relate to expenditures for new connections and distribution operations.
•Electric transmission includes both growth projects and operating expenditures. Transmission investment primarily reflects planned costs for
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; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these segments totaled $640 million and $57 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $299 million for the remainder of 2022.
•Other includes both growth projects and
operating expenditures. Expenditures for information technology totaled $115 million and $69 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned information technology spending totals $56 million for the remainder of 2022. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.
74
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. 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 cost recovery or prudency of resources ultimately selected.
In September 2021, PacifiCorp filed its 2021 IRP with its state commissions and subsequently filed its 2021 IRP Update in March and April 2022. In March 2022, the OPUC acknowledged PacifiCorp's 2021 IRP and its preferred portfolio. In June 2022, the UPSC issued an order declining to acknowledge the 2021 IRP
due to its determination that PacifiCorp did not meet the commission's IRP guidelines by excluding new natural gas-fueled resources in its modeling of the 2021 IRP's preferred portfolio, as well as the commission's view that PacifiCorp did not provide ample time for public input and information exchange during the development of the IRP. The UPSC did approve the 2022 All Source RFP ("2022AS RFP") to procure resources identified in the 2021 IRP. In August 2022, the Idaho Public Utilities Commission acknowledged PacifiCorp's 2021 IRP and its preferred portfolio. Reviews of the 2021 IRP by the Wyoming Public Service Commission and the WUTC are ongoing.
Requests for Proposals
PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands. The IRP
and the RFPs provide for the identification and staged procurement of resources to meet load or 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.
A draft of PacifiCorp's 2022AS RFP was filed for approval with the WUTC in December 2021, and with the UPSC and the OPUC in January 2022. The draft 2022AS RFP was approved by the WUTC in March 2022 and by the UPSC and the OPUC in April 2022. The 2022AS RFP was issued to market in April 2022. PacifiCorp-owned bids are due late November 2022 and market bids are due February 2023.
Material Cash Requirements
As
of September 30, 2022, there have been no material changes in cash requirements from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2021, other than those disclosed in Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Regulatory Matters
PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.
Environmental
Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species 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 Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
75
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 September 30, 2022, PacifiCorp'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.
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 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 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 September 30, 2022, PacifiCorp would have been required to post $338 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 7 of Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.
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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, pension and other postretirement benefits, income taxes
and revenue recognition-unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2021. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2021.
76
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
77
PART
I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
MidAmerican Energy Company
Results of Review of Interim Financial Information
We have reviewed the accompanying balance sheet of MidAmerican Energy Company
("MidAmerican Energy") as of September 30, 2022, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2022 and 2021, and of cash flows for the nine-month periods ended September 30, 2022 and 2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously
audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2021, and the related statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.
Basis for Review Results
This
interim financial information is the responsibility of MidAmerican Energy's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i865
i634
Amortization
of utility plant to other operating expenses
i26
i26
Allowance
for equity funds
(i41)
(i25)
Deferred
income taxes and investment tax credits, net
i11
i121
Settlements
of asset retirement obligations
(i55)
(i51)
Other,
net
i40
i42
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i10)
(i331)
Inventories
(i38)
i34
Pension
and other postretirement benefit plans
i4
i2
Accrued
property, income and other taxes, net
i197
i80
Accounts
payable and other liabilities
i46
i21
Net
cash flows from operating activities
i1,801
i1,290
Cash
flows from investing activities:
Capital expenditures
(i1,404)
(i1,266)
Purchases
of marketable securities
(i306)
(i166)
Proceeds
from sales of marketable securities
i299
i163
Other,
net
i12
(i7)
Net
cash flows from investing activities
(i1,399)
(i1,276)
Cash
flows from financing activities:
Dividends paid
(i50)
i—
Proceeds
from long-term debt
i—
i492
Repayments
of long-term debt
(i2)
(i1)
Other,
net
i—
(i2)
Net
cash flows from financing activities
(i52)
i489
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i350
i503
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i239
i45
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i589
$
i548
The
accompanying notes are an integral part of these financial statements.
83
MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
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").
iThe
unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2022, and for the three- and nine-month periods ended September 30, 2022 and 2021. The results of operations for the three- and nine-month periods ended September 30,
2022, are not necessarily indicative of the results to be expected for the full year.
iThe preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for
the year ended December 31, 2021, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30, 2022.
(2) iCash
and Cash Equivalents and Restricted Cash and Cash Equivalents
iCash 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 presented in 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
i8
i7
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i589
$
i239
84
(3) iProperty,
Plant and Equipment, Net
iProperty, plant and equipment, net consists of the following (in millions):
As
of
September 30,
December 31,
Depreciable Life
2022
2021
Utility plant in-service, net:
Generation
i20-i70
years
$
i18,201
$
i17,397
Transmission
i52-i75
years
i2,609
i2,474
Electric
distribution
i20-i75 years
i4,777
i4,661
Natural
gas distribution
i29-i75 years
i2,101
i2,039
Utility
plant in-service
i27,688
i26,571
Accumulated
depreciation and amortization
(i7,886)
(i7,376)
Utility
plant in-service, net
i19,802
i19,195
Nonregulated
property, net:
Nonregulated property, gross
i20-i50
years
i7
i7
Accumulated
depreciation and amortization
(i1)
(i1)
Nonregulated
property, net
i6
i6
i19,808
i19,201
Construction
work-in-progress
i972
i1,100
Property,
plant and equipment, net
$
i20,780
$
i20,301
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 three- and nine-month periods ended September 30, 2022, $i115 million
and $i211 million, respectively, was accrued. iiNo/
accrual was recorded for the three- and nine-months periods ended September 30, 2021.
(4) iRecent Financing Transactions
Credit Facilities
In June 2022, MidAmerican Energy amended and restated
its existing $i1.5 billion unsecured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from the London Interbank Offered Rate to the Secured Overnight Financing Rate.
(5) iIncome
Taxes
i
A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:
State
income tax, net of federal income tax impacts
(i21)
(i26)
(i21)
(i27)
Effects
of ratemaking
(i13)
(i12)
(i12)
(i13)
Other,
net
i3
i—
i1
i—
Effective
income tax rate
(i79)
%
(i61)
%
(i233)
%
(i162)
%
/
85
Income
tax credits relate primarily to production tax credits ("PTCs") from 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. MidAmerican Energy recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. 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 nine-month periods ended September 30, 2022 and 2021 totaled $i505 million and $i400 million,
respectively.
Berkshire Hathaway includes BHE and subsidiaries in its U.S. federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Energy received net cash payments for income tax from BHE totaling $i757 million
and $i677 million for the nine-month periods ended September 30, 2022 and 2021, respectively.
(6) iEmployee
Benefit Plans
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. 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.
i
Net
periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
Amounts
other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $i7 million and $i3 million,
respectively, during 2022. As of September 30, 2022, $i5 million and $i2 million
of contributions had been made to the pension and other postretirement benefit plans, respectively.
86
(7) 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.
i
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 $i2 million and $i5 million
as of September 30, 2022 and December 31, 2021, 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.
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):
Changes
in fair value recognized in regulatory assets
(i2)
i2
i42
i2
Settlements
(i10)
(i1)
(i23)
(i4)
Ending
balance
$
i14
$
i—
$
i14
$
i—
/
88
MidAmerican
Energy's long-term debt is carried at cost on the Balance Sheets. 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 (in millions):
MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected
species 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.
Transmission Rates
MidAmerican Energy's wholesale transmission rates are set annually using Federal Energy Regulatory Commission ("FERC")-approved formula rates subject to true-up for actual cost of service. MidAmerican Energy is authorized by the FERC to include a i0.50%
adder beyond the approved base return on equity ("ROE") effective January 2015. Prior to September 2016, the rates in effect were based on a i12.38% ROE. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the i12.38%
ROE no longer be found just and reasonable and sought to reduce the base ROE to i9.15% and i8.67%, respectively. In September 2016, the FERC issued an order
for the first complaint, which reduces the base ROE to i10.32% and required refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. In November 2019, the FERC issued an order addressing the second complaint and issues on appeal in the first complaint. The order established a ROE of i9.88%
(i10.38% including the i0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016
forward. In May 2020, the FERC issued an order on rehearing of the November 2019 order. The May 2020 order affirmed the FERC's prior decision to dismiss the second complaint and established an ROE of i10.02% (i10.52%
including the i0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 to the date of the May 2020 order. In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion vacating these orders and remanding them back to the FERC. MidAmerican Energy cannot predict the ultimate outcome of these matters and, as of September 30, 2022, has accrued an $i8 million
liability for refunds of amounts collected under the higher ROE during the periods covered by the complaints.
89
(9) iRevenue from Contracts with Customers
i
The
following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 10 (in millions):
MidAmerican Energy has identified itwo reportable 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.
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
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of September 30, 2022, the related consolidated statements of operations and changes in member's equity for the three-month and nine-month periods ended September 30, 2022 and 2021, and of cash flows for the nine-month periods ended September 30,
2022 and 2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2021, and the related consolidated statements of operations, changes in member's equity, and cash flows for the year then ended (not presented
herein); and in our report dated February 25, 2022, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB and with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i865
i634
Amortization
of utility plant to other operating expenses
i26
i26
Allowance
for equity funds
(i41)
(i25)
Deferred
income taxes and investment tax credits, net
i11
i121
Settlements
of asset retirement obligations
(i55)
(i51)
Other,
net
i42
i42
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i12)
(i331)
Inventories
(i38)
i34
Pension
and other postretirement benefit plans
i4
i2
Accrued
property, income and other taxes, net
i197
i80
Accounts
payable and other liabilities
i42
i16
Net
cash flows from operating activities
i1,786
i1,276
Cash
flows from investing activities:
Capital expenditures
(i1,404)
(i1,266)
Purchases
of marketable securities
(i306)
(i166)
Proceeds
from sales of marketable securities
i299
i163
Other,
net
i12
(i7)
Net
cash flows from investing activities
(i1,399)
(i1,276)
Cash
flows from financing activities:
Proceeds from long-term debt
i—
i492
Repayments
of long-term debt
(i2)
(i1)
Net
change in note payable to affiliate
(i34)
i13
Other,
net
(i1)
(i1)
Net
cash flows from financing activities
(i37)
i503
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i350
i503
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i240
i46
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i590
$
i549
The
accompanying notes are an integral part of these consolidated financial statements.
97
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
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.
iThe
unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2022, and for the three- and nine-month periods ended September 30, 2022 and 2021. The results of operations for the three- and nine-month
periods ended September 30, 2022, are not necessarily indicative of the results to be expected for the full year.
iThe preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial
Statements. Note 2 of Notes to Consolidated Financial Statements included in MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2021, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30, 2022.
(2) iCash
and Cash Equivalents and Restricted Cash and Cash Equivalents
iCash 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 presented in 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
i8
i7
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i590
$
i240
(3) iProperty,
Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.
(4) iRecent Financing Transactions
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
98
(5) iIncome
Taxes
i
A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit is as follows:
State
income tax, net of federal income tax impacts
(i22)
(i27)
(i24)
(i29)
Effects
of ratemaking
(i13)
(i12)
(i13)
(i14)
Other,
net
i2
i—
i3
i—
Effective
income tax rate
(i84)
%
(i63)
%
(i251)
%
(i172)
%
/
Income
tax credits relate primarily to production tax credits ("PTCs") from 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. MidAmerican Funding recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. 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 nine-month periods ended September 30, 2022 and 2021 totaled $i505 million and $i400 million,
respectively.
Berkshire Hathaway includes BHE and subsidiaries in its U.S. federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Funding received net cash payments for income tax from BHE totaling $i761 million
and $i681 million for the nine-month periods ended September 30, 2022 and 2021, respectively.
(6) iEmployee
Benefit Plans
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.
(7) iFair Value Measurements
Refer to Note 7 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 (in millions):
MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.
(9) iRevenue
from Contracts with Customers
Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.
(10) iSegment Information
MidAmerican Funding has identified itwo
reportable 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 financial results and assets of nonregulated operations, MHC and MidAmerican Funding.
i
The following tables provide information on a reportable segment basis (in millions):
Assets
by reportable segment reflect the assignment of goodwill to applicable reporting units.
/
100
Item 2.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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements
in Part I, Item 1 of this Form 10-Q. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.
Results of Operations for the Third Quarter and First Nine Months of 2022 and 2021
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the third quarter of 2022 was $305 million, a decrease of $72 million, or 19%, compared to 2021, primarily due to higher depreciation and amortization expense of $120 million, higher operations and maintenance expense of $10 million, lower income
tax benefit of $8 million, lower natural gas utility margin of $6 million, unfavorable other, net of $4 million, higher property and other taxes of $4 million and higher interest expense of $3 million, offset by higher electric utility margin of $83 million. The increase in depreciation and amortization expense was primarily due to higher Iowa revenue sharing of $115 million. Electric retail customer volumes increased 3% due to higher customer usage for certain industrial customers. Wholesale electricity sales volumes decreased 4% due to unfavorable market conditions. Natural gas retail customer volumes increased 1% due to the favorable impact of weather.
MidAmerican Energy's net income for the first nine months of 2022 was $756 million, an increase of $19 million, or 3%, compared to 2021, primarily due to higher electric utility margin of $240 million, higher income tax benefit of $73
million, higher allowances for equity and borrowed funds of $20 million and higher natural gas utility margin of $14 million, offset by higher depreciation and amortization expense of $231 million, unfavorable other, net of $45 million, higher operations and maintenance expense of $25 million, higher interest expense of $11 million, lower nonregulated utility margins of $10 million and higher property and other taxes of $7 million. Electric retail customer volumes increased 4% primarily due to higher customer usage for certain industrial customers. Wholesale electricity sales volumes increased 12% due to favorable market conditions. Natural gas retail customer volumes increased 10% due to the favorable impact of weather. The increase in depreciation and amortization expense was primarily due to higher Iowa revenue sharing of $211 million.
MidAmerican Funding -
MidAmerican
Funding's net income for the third quarter of 2022 was $300 million, a decrease of $73 million, or 20%, compared to 2021. MidAmerican Funding's net income for the first nine months of 2022 was $745 million, an increase of $17 million, or 2%, compared to 2021. The variances in net income were primarily due to the changes in MidAmerican Energy's earnings discussed above.
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 regulated 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.
101
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 expense 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 running 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 comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Electric utility margin:
Operating
revenue
$
1,009
$
854
$
155
18
%
$
2,342
$
1,985
$
357
18
%
Cost
of fuel and energy
235
163
72
44
534
417
117
28
Electric utility margin
774
691
83
12
%
1,808
1,568
240
15
%
Natural
gas utility margin:
Operating revenue
138
110
28
25
%
705
728
(23)
(3)
%
Natural
gas purchased for resale
97
63
34
54
515
552
(37)
(7)
Natural gas utility margin
41
47
(6)
(13)
%
190
176
14
8
%
Utility
margin
815
738
77
10
%
1,998
1,744
254
15
%
Other
operating revenue
1
2
(1)
(50)
%
3
13
(10)
(77)
%
Other cost of sales
—
1
(1)
*
—
1
(1)
*
Operations
and maintenance
210
200
10
5
602
577
25
4
Depreciation and amortization
338
218
120
55
865
634
231
36
Property
and other taxes
38
34
4
12
114
107
7
7
Operating
income
$
230
$
287
$
(57)
(20)
%
$
420
$
438
$
(18)
(4)
%
* Not
meaningful.
102
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Utility margin (in millions):
Operating
revenue
$
1,009
$
854
$
155
18
%
$
2,342
$
1,985
$
357
18
%
Cost
of fuel and energy
235
163
72
44
534
417
117
28
Utility margin
$
774
$
691
$
83
12
%
$
1,808
$
1,568
$
240
15
%
Sales
(GWhs):
Residential
2,056
2,060
(4)
—
%
5,461
5,284
177
3
%
Commercial
1,055
1,039
16
2
3,021
2,871
150
5
Industrial
4,335
4,106
229
6
12,463
11,981
482
4
Other
422
423
(1)
—
1,231
1,194
37
3
Total
retail
7,868
7,628
240
3
22,176
21,330
846
4
Wholesale
3,267
3,420
(153)
(4)
12,738
11,343
1,395
12
Total
sales
11,135
11,048
87
1
%
34,914
32,673
2,241
7
%
Average
number of retail customers (in thousands)
813
805
8
1
%
812
803
9
1
%
Average
revenue per MWh:
Retail
$
101.53
$
96.42
$
5.11
5
%
$
84.10
$
79.90
$
4.20
5
%
Wholesale
$
55.68
$
27.07
$
28.61
106
%
$
31.12
$
18.22
$
12.90
71
%
Heating
degree days
67
21
46
219
%
4,059
3,820
239
6
%
Cooling degree days
838
870
(32)
(4)
%
1,259
1,296
(37)
(3)
%
Sources
of energy (GWhs)(1):
Wind and other(2)
4,528
4,164
364
9
%
20,182
16,163
4,019
25
%
Coal
3,990
4,609
(619)
(13)
7,830
10,302
(2,472)
(24)
Nuclear
987
1,007
(20)
(2)
2,770
2,911
(141)
(5)
Natural
gas
624
503
121
24
1,255
982
273
28
Total energy generated
10,129
10,283
(154)
(1)
32,037
30,358
1,679
6
Energy
purchased
1,189
1,038
151
15
3,466
2,898
568
20
Total
11,318
11,321
(3)
—
%
35,503
33,256
2,247
7
%
Average
cost of energy per MWh:
Energy generated(3)
$
12.60
$
9.81
$
2.79
28
%
$
8.03
$
7.48
$
0.55
7
%
Energy
purchased
$
90.62
$
60.32
$
30.30
50
%
$
79.97
$
65.60
$
14.37
22
%
(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 generating facilities 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 renewable energy credits or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
103
Natural Gas Utility Margin
A comparison
of key operating results related to natural gas utility margin is as follows:
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Utility margin (in millions):
Operating
revenue
$
138
$
110
$
28
25
%
$
705
$
728
$
(23)
(3)
%
Natural
gas purchased for resale
97
63
34
54
515
552
(37)
(7)
Utility margin
$
41
$
47
$
(6)
(13)
%
$
190
$
176
$
14
8
%
Throughput
(000's Dths):
Residential
2,798
2,689
109
4
%
37,397
34,243
3,154
9
%
Commercial
1,492
1,511
(19)
(1)
17,551
16,255
1,296
8
Industrial
1,097
1,110
(13)
(1)
4,406
3,616
790
22
Other
4
4
—
—
55
52
3
6
Total
retail sales
5,391
5,314
77
1
59,409
54,166
5,243
10
Wholesale sales
5,556
6,365
(809)
(13)
22,700
22,955
(255)
(1)
Total
sales
10,947
11,679
(732)
(6)
82,109
77,121
4,988
6
Natural gas transportation service
20,901
26,789
(5,888)
(22)
74,705
83,282
(8,577)
(10)
Total
throughput
31,848
38,468
(6,620)
(17)
%
156,814
160,403
(3,589)
(2)
%
Average
number of retail customers (in thousands)
781
776
5
1
%
784
776
8
1
%
Average
revenue per retail Dth sold
$
16.48
$
14.21
$
2.27
16
%
$
9.10
$
11.20
$
(2.10)
(19)
%
Heating
degree days
84
28
56
200
%
4,303
3,954
349
9
%
Average
cost of natural gas per retail Dth sold
$
10.38
$
7.09
$
3.29
46
%
$
6.42
$
8.47
$
(2.05)
(24)
%
Combined
retail and wholesale average cost of natural gas per Dth sold
Electric utility margin increased $83 million, or 12%, for the third quarter of 2022 compared to 2021, primarily due to:
•a $74 million increase in wholesale utility margin due to higher margins per unit of $77 million, reflecting higher market prices, partially offset by lower volumes of 4.5%; and
•a $9 million increase in retail utility margin primarily due to $17 million from higher customer usage; and $5 million due to price impacts from changes in sales
mix; partially offset by $8 million, net of energy costs, from lower recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $5 million from lower wind-turbine performance settlements. Retail customer volumes increased 3.1%.
Natural gas utility margin decreased $6 million, or 13%, for the third quarter of 2022 compared to 2021 primarily due to:
•a $6 million decrease from lower average prices, primarily due to the timing of recoveries through a capital tracker mechanism.
Operations and maintenance increased $10 million, or 5%, for the third quarter of 2022 compared to 2021 primarily due to higher steam and other power generation costs of
$7 million, and higher electric distribution and transmission costs of $6 million, partially offset by lower nonregulated operations costs of $3 million.
104
Depreciation and amortization increased $120 million, or 55%, for the third quarter of 2022 compared to 2021 primarily due to $115 million from higher Iowa revenue sharing accruals, $10 million from wind-powered generating facilities and other plant placed in-service, and $7 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $12 million from a regulatory mechanism deferring certain depreciation expense in 2022.
Property
and other taxes increased $4 million, or 12%, for the third quarter of 2022 compared to 2021 primarily due to $4 million from higher wind turbine property taxes.
Interest expense increased $3 million, or 4%, for the third quarter of 2022 compared to 2021 due to higher interest rates on variable rate long-term debt and higher interest expense from a July 2021 long-term debt issuance.
Other, net decreased $4 million, or 50%, for the third quarter of 2022 compared to 2021 primarily due to unfavorable investment earnings, largely attributable to lower cash surrender values of corporate-owned life insurance policies, and higher non-service costs of employee benefit plans, partially offset by higher interest income.
Income
tax benefit decreased $8 million, or 6%, for the third quarter of 2022 compared to 2021 primarily due to state income tax impacts and the effects of ratemaking, partially offset by higher PTCs and lower pretax income. PTCs for the third quarter of 2022 and 2021 totaled $117 million and $103 million, respectively.
MidAmerican Funding -
Income tax benefit decreased $7 million, or 5%, for the third quarter of 2022 compared to 2021 principally due to the factors discussed for MidAmerican Energy.
First Nine Months of 2022 Compared to First Nine Months of 2021
MidAmerican Energy -
Electric
utility margin increased $240 million, or 15%, for the first nine months of 2022 compared to 2021, due to:
•a $201 million increase in wholesale utility margin due to higher margins per unit of $174 million, reflecting higher market prices and lower energy costs, and higher volumes of 12.3%; and
•a $39 million increase in retail utility margin primarily due to $45 million from higher customer usage; and $9 million due to price impacts from changes in sales mix; partially offset by $11 million, net of energy costs, from lower recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $6 million from lower wind-turbine performance settlements. Retail customer volumes increased 4.0%.
Natural
gas utility margin increased $14 million, or 8%, for the first nine months of 2022 compared to 2021 primarily due to:
•a $6 million increase from lower refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit);
•a $5 million increase from the favorable impact of weather;
•a $2 million increase from higher average rates; and
•a $2 million increase from higher customer usage.
Operations and maintenance increased $25 million, or 4%, for the first nine months of 2022 compared to 2021 primarily
due to higher steam and other power generation costs of $20 million, and higher electric distribution and transmission costs of $16 million, partially offset by lower energy efficiency program expense of $4 million (offset in operating revenue), lower nonregulated operations costs of $4 million and lower gas distribution costs of $2 million.
Depreciation and amortization increased $231 million, or 36%, for the first nine months of 2022 compared to 2021 primarily due to $211 million from higher Iowa revenue sharing accruals, $31 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects and $26 million from wind-powered generating facilities and other plant placed in-service, partially offset by $37 million from a regulatory mechanism deferring certain depreciation expense in 2022.
105
Property
and other taxes increased $7 million, or 7%, for the first nine months of 2022 compared to 2021 primarily due to $7 million from higher wind turbine property taxes.
Interest expense increased $11 million, or 5%, for the first nine months of 2022 compared to 2021 due to higher interest expense from a July 2021 long-term debt issuance and higher interest rates on variable rate long-term debt.
Allowance for borrowed and equity funds increased $20 million, or 61%, for the first nine months of 2022 compared to 2021 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation.
Other, net
decreased $45 million for the first nine months of 2022 compared to 2021 primarily due to unfavorable investment earnings, largely attributable to lower cash surrender values of corporate-owned life insurance policies, and higher non-service costs of employee benefit plans.
Income tax benefit increased $73 million, or 16%, for the first nine months of 2022 compared to 2021 primarily due to higher PTCs and lower pretax income, partially offset by state income tax impacts and the effects of ratemaking. PTCs for the first nine months of 2022 and 2021 totaled $505 million and $400 million, respectively.
MidAmerican Funding -
Income tax benefit increased $73 million, or 16%,
for the first nine months of 2022 compared to 2021 principally due to the factors discussed for MidAmerican Energy.
Liquidity and Capital Resources
As of September 30, 2022, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
MidAmerican Energy:
Cash
and cash equivalents
$
581
Credit facilities, maturing 2023 and 2025
1,505
Less:
Tax-exempt bond support
(370)
Net credit
facilities
1,135
MidAmerican Energy total net liquidity
$
1,716
MidAmerican Funding:
MidAmerican Energy total net liquidity
$
1,716
Cash
and cash equivalents
1
MHC, Inc. credit facility, maturing 2023
4
MidAmerican Funding total net liquidity
$
1,721
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2022 and 2021,
were $1,801 million and $1,290 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2022 and 2021, were $1,786 million and $1,276 million, respectively. Cash flows from operating activities reflect higher utility margins for MidAmerican Energy's regulated electric and natural gas businesses, and higher income tax receipts, partially offset by higher derivative collateral posted and higher interest payments. Higher utility margins are largely attributable to 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
and assumptions for each payment date.
106
Investing Activities
MidAmerican Energy's net cash flows from investing activities for the nine-month periods ended September 30, 2022 and 2021, were $(1,399) million and $(1,276) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2022 and 2021, were $(1,399) million and $(1,276) million, 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 substantially 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 for the nine-month periods ended September 30, 2022 and 2021 were $(52) million and $489 million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2022 and 2021, were $(37) million and
$503 million, respectively. Proceeds from long-term debt reflect MidAmerican Energy's issuance in July 2021 of $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Funding made repayments of $34 million and received $13 million in 2022 and 2021, respectively, through its note payable with BHE.
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 2025. 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 automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities and preferred stock through June 13, 2024. MidAmerican Energy has authorization from the FERC to issue, through June 30,
2023, long-term debt securities up to an aggregate of $2.0 billion and preferred stock up to an aggregate of $500 million and from the Illinois Commerce Commission to issue, through May 25, 2025, long-term debt securities up to an aggregate of $2.2 billion and preferred stock up to an aggregate of $500 million. Additionally, MidAmerican Energy has authority from the Illinois Commerce Commission through October 15, 2024, to issue $750 million of long-term debt securities for the purpose of refinancing $250 million of its 3.70% Senior notes due September 2023 and $500 million of its 2.40% Senior notes due October 2024.
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 regulatory approvals, 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 customer 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.
107
MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Nine-Month
Periods
Annual
Ended September 30,
Forecast
2021
2022
2022
Wind generation
$
605
$
515
$
739
Electric
distribution
154
206
294
Electric transmission
105
78
137
Solar generation
97
103
136
Other
305
502
733
Total
$
1,266
$
1,404
$
2,039
MidAmerican
Energy's capital expenditures provided above consist of the following:
•Wind generation includes the construction, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction of wind-powered generating facilities totaling $39 million and $275 million for the nine-month periods ended September 30, 2022 and 2021, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $74 million for the remainder of 2022.
◦Repowering of wind-powered generating facilities totaling $422 million and $274 million for the nine-month periods ended September 30,
2022 and 2021, respectively. Planned spending for the repowering of wind-powered generating facilities totals $98 million for the remainder of 2022. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. As a result of the Inflation Reduction Act of 2022, all of the 310 MWs of current repowering projects not in-service as of September 30, 2022, are currently expected to qualify for 100% of the PTCs available for 10 years following each facility's return to 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 of solar-powered generating facilities totaling 141 MWs of small- and utility-scale solar generation, all of which were placed in-service as of September 30, 2022, with total spend of $103 million and $97 million for the nine-month periods ended September 30, 2022 and 2021, respectively, and planned spending of $33 million for the remainder of 2022.
•Remaining expenditures primarily relate to routine expenditures for other generation, natural gas distribution,
technology, facilities and other operational needs to serve existing and expected demand.
Material Cash Requirements
As of September 30, 2022, there have been no material changes in MidAmerican Energy's and MidAmerican Funding's cash requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2021.
108
Quad
Cities Generating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, which was a subsidiary of Exelon Corporation prior to February 1, 2022), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. 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. The proceeds from the ZECs will provide Constellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will 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, 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-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when
bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
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 in May 2021. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources 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. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 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 D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction
for the 2022-2023 planning year, 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 at 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 will no longer apply to Quad Cities Station. 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. Constellation Energy is strenuously opposing these appeals.
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's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard 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.
Regulatory Matters
MidAmerican Energy is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.
109
Environmental Laws and
Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species 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 consolidated financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2021. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2021.
110
Nevada
Power Company and its subsidiaries
Consolidated Financial Section
111
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the Board of Directors and Shareholder of
Nevada Power Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of September 30, 2022, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2022 and 2021, and of cash flows for the nine-month periods ended September 30, 2022 and 2021, and the
related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2021, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim
financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i312
i304
Allowance
for equity funds
(i8)
(i5)
Changes
in regulatory assets and liabilities
(i9)
(i11)
Deferred
income taxes and amortization of investment tax credits
i48
(i19)
Deferred
energy
(i543)
(i154)
Amortization of deferred energy
i113
(i7)
Other,
net
i11
i1
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i302)
(i133)
Inventories
(i14)
i3
Accrued
property, income and other taxes
i15
i28
Accounts
payable and other liabilities
i326
i97
Net
cash flows from operating activities
i232
i405
Cash
flows from investing activities:
Capital expenditures
(i523)
(i323)
Other,
net
i—
i1
Net
cash flows from investing activities
(i523)
(i322)
Cash
flows from financing activities:
Proceeds from long-term debt
i300
i—
Proceeds
from short-term debt
i20
i—
Contributions
from parent
i25
i—
Dividends
paid
i—
(i13)
Other,
net
(i13)
(i12)
Net
cash flows from financing activities
i332
(i25)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i41
i58
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i45
i36
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i86
$
i94
The
accompanying notes are an integral part of these consolidated financial statements.
116
NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
Nevada
Power Company, together with 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 the 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").
iThe
unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2022 and for the three- and nine-month periods ended September 30, 2022 and 2021. The Consolidated Statements of Comprehensive Income
have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2022 and 2021. The results of operations for the three- and nine-month periods ended September 30, 2022 are not necessarily indicative of the results to be expected for the full year.
iThe preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30, 2022.
(2)iCash
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 funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. iA
reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented in 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):
Other
non-regulated, net of accumulated depreciation and amortization
i45 years
i1
i1
Plant,
net
i6,807
i6,647
Construction
work-in-progress
i414
i244
Property,
plant and equipment, net
$
i7,221
$
i6,891
/
(4) iRecent
Financing Transactions
Long-Term Debt
In October 2022, Nevada Power issued $i400 million of i5.90%
General and Refunding Mortgage bonds, Series GG, due 2053. The net proceeds were used to repay amounts outstanding under its existing revolving credit facility, to fund capital expenditures and for general corporate purposes.
In January 2022, Nevada Power entered into a $i300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate ("SOFR") or a base rate, at Nevada Power's
option, plus a pricing margin. In January 2022, Nevada Power borrowed $i200 million under the facility at an initial interest rate of i0.55%. In May
2022, Nevada Power drew the remaining $i100 million available under the facility at an initial interest rate of i1.24%. Nevada Power used the proceeds
to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
Credit Facilities
In June 2022, Nevada Power amended and restated its existing $i400 million secured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from the London Interbank Offered Rate to SOFR.
(5) iIncome
Taxes
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:
Effects
of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts
and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2021.
118
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for federal income tax has been computed on a separate return basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the nine-month period ended September 30,
2022, Nevada Power received net cash payments for federal income tax from BHE totaling $i20 million. For the nine-month period ended September 30, 2021, Nevada Power made net cash payments for federal income tax to BHE totaling $i38
million.
(6) 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. 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 (in millions):
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal 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.
119
There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.
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 September 30, 2022 a regulatory asset of $i66 million was recorded related to the net derivative liability of $i66 million.
As of December 31, 2021 a regulatory asset of $i113 million was recorded related to the net derivative liability of $i113 million.
/
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 (in millions):
Unit of
September 30,
December
31,
Measure
2022
2021
Electricity purchases
Megawatt hours
i1
i1
Natural
gas purchases
Decatherms
i135
i119
/
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.
120
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 September 30, 2022, 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.
The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $i7
million and $i6 million as of September 30, 2022 and December 31, 2021, 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.
(8) 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 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 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.
121
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):
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 September 30, 2022 and December 31, 2021, 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.
Nevada
Power's 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.
122
i
The
following table reconciles the beginning and ending balances of Nevada Power's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
Changes
in fair value recognized in regulatory assets
(i4)
i6
(i81)
i11
Settlements
i113
(i45)
i128
(i40)
Ending
balance
$
(i66)
$
(i14)
$
(i66)
$
(i14)
/
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. The carrying value of Nevada Power'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 Nevada Power's long‑term debt (in millions):
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.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other
environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
123
(10) iRevenue
from Contracts with Customers
i
The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
Item
2. 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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.
Results
of Operations for the Third Quarter and First Nine Months of 2022 and 2021
Overview
Net income for the third quarter of 2022 was $209 million, a decrease of $8 million, or 4%, compared to 2021 primarily due to $9 million of lower utility margin, $3 million of higher depreciation and amortization, mainly due to higher plant placed in-service, $3 million of higher interest expense, primarily due to higher long-term debt, and unfavorable other, net, mainly due to lower cash surrender value of corporate-owned life insurance policies, partially offset by $8 million of higher interest and dividend income, primarily from carrying charges on regulatory balances. Utility margin decreased primarily due to unfavorable price impacts from changes in sales mix, the unfavorable impact of weather and lower transmission
revenue, partially offset by an increase in the average number of customers and higher regulatory-related revenue deferrals. Energy generated decreased 9% for the third quarter of 2022 compared to 2021 due to lower natural gas-fueled generation. Wholesale electricity sales volumes increased 85% and purchased electricity volumes increased 24%.
Net income for the first nine months of 2022 was $283 million, a decrease of $18 million, or 6%, compared to 2021 primarily due to $15 million of lower utility margin, $11 million of unfavorable other, net, mainly due to lower cash surrender value of corporate-owned life insurance policies, $8 million of higher depreciation and amortization, mainly due to higher plant placed in-service and higher interest expense primarily due to higher long-term debt, partially offset by $18 million of higher interest and dividend income, primarily from carrying
charges on regulatory balances. Utility margin decreased primarily due to unfavorable price impacts from changes in sales mix, the unfavorable impact of weather, lower other retail revenue and lower transmission revenue, partially offset by higher regulatory-related revenue deferrals and an increase in the average number of customers. Energy generated decreased 11% for the first nine months of 2022 compared to 2021 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes increased 91% and purchased electricity volumes increased 23%.
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 electric
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 are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses 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 sales 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.
125
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 (in millions):
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Utility margin:
Operating
revenue
$
1,003
$
802
$
201
25
%
$
2,057
$
1,731
$
326
19
%
Cost
of fuel and energy
538
328
210
64
1,086
745
341
46
Utility margin
465
474
(9)
(2)
971
986
(15)
(2)
Operations
and maintenance
90
88
2
2
230
228
2
1
Depreciation and amortization
106
103
3
3
312
304
8
3
Property
and other taxes
14
12
2
17
39
36
3
8
Operating income
$
255
$
271
$
(16)
(6)
%
$
390
$
418
$
(28)
(7)
%
126
Utility
Margin
A comparison of key operating results related to utility margin is as follows:
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Utility margin (in millions):
Operating
revenue
$
1,003
$
802
$
201
25
%
$
2,057
$
1,731
$
326
19
%
Cost
of fuel and energy
538
328
210
64
1,086
745
341
46
Utility margin
$
465
$
474
$
(9)
(2)
%
$
971
$
986
$
(15)
(2)
%
Sales
(GWhs):
Residential
4,228
4,343
(115)
(3)
%
8,425
8,737
(312)
(4)
%
Commercial
1,589
1,568
21
1
3,859
3,793
66
2
Industrial
1,696
1,611
85
5
4,280
3,978
302
8
Other
50
52
(2)
(4)
142
144
(2)
(1)
Total
fully bundled(1)
7,563
7,574
(11)
—
16,706
16,652
54
—
Distribution only service
792
787
5
1
2,022
1,923
99
5
Total
retail
8,355
8,361
(6)
—
18,728
18,575
153
1
Wholesale
172
93
79
85
507
266
241
91
Total
GWhs sold
8,527
8,454
73
1
%
19,235
18,841
394
2
%
Average
number of retail customers (in thousands)
1,003
988
15
2
%
999
983
16
2
%
Average
revenue per MWh:
Retail - fully bundled(1)
$
127.11
$
100.56
$
26.55
26
%
$
117.34
$
98.54
$
18.80
19
%
Wholesale
$
92.51
$
90.60
$
1.91
2
%
$
56.19
$
61.65
$
(5.46)
(9)
%
Heating
degree days
—
—
—
—
985
1,008
(23)
(2)
%
Cooling degree days
2,351
2,447
(96)
(4)
%
3,722
3,930
(208)
(5)
%
Sources
of energy (GWhs)(2)(3):
Natural gas
4,326
4,776
(450)
(9)
%
9,639
10,857
(1,218)
(11)
%
Renewables
19
19
—
—
53
55
(2)
(4)
Total
energy generated
4,345
4,795
(450)
(9)
9,692
10,912
(1,220)
(11)
Energy purchased
3,373
2,727
646
24
7,606
6,186
1,420
23
Total
7,718
7,522
196
3
%
17,298
17,098
200
1
%
Average
cost of energy per MWh(4):
Energy generated
$
41.04
$
24.71
$
16.33
66
%
$
43.88
$
21.49
$
22.39
*
Energy
purchased
$
106.73
$
76.77
$
29.96
39
%
$
86.88
$
82.53
$
4.35
5
%
* Not
meaningful
(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 183 GWhs and 163 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2022 and 2021, respectively. The average cost of energy per MWh and sources of energy excludes 967 GWhs and 1,095 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 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 $9 million, or 2%, for the third quarter of 2022 compared to 2021 primarily due to:
•$4 million of lower electric retail utility margin due to unfavorable price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, were flat primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and favorable changes in customer usage;
•$4 million of lower energy efficiency program rates (offset in operations and maintenance expense); and
•$4
million of lower transmission revenue.
The decrease in utility margin was offset by:
•$3 million of higher regulatory-related revenue deferrals.
Operations and maintenance increased $2 million, or 2%, for the third quarter of 2022 compared to 2021 primarily due to higher plant operations and maintenance expenses, partially offset by lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $3 million, or 3%, for the third quarter of 2022 compared to 2021 primarily due to higher plant placed in-service.
Interest
expense increased $3 million, or 8%, for the third quarter of 2022 compared to 2021 primarily due to higher long-term debt.
Interest and dividend income increased $8 million for the third quarter of 2022 compared to 2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net decreased $1 million, or 25%, for the third quarter of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies.
Income tax expense decreased $2 million, or 7%, for the third quarter of 2022 compared to 2021 and the effective tax rate was 11% for 2022
and 2021.
First Nine Months of 2022 Compared to First Nine Months of 2021
Utility margin decreased $15 million, or 2%, for the first nine months of 2022 compared to 2021 primarily due to:
•$9 million of lower energy efficiency program rates (offset in operations and maintenance expense);
•$8 million of lower electric retail utility margin due to unfavorable price impacts from changes in the sales mix, offset by higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 0.8% primarily due to an increase in the average number of customers and favorable changes in customer usage, offset by the unfavorable impact of weather;
•$3
million of lower other retail revenue; and
•$3 million lower transmission revenue.
The decrease in utility margin was offset by:
•$8 million of higher regulatory-related revenue deferrals.
Operations and maintenance increased by $2 million, or 1%, for the first nine months of 2022 compared to 2021 primarily due to higher earnings sharing and higher plant operations and maintenance expenses, offset by lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $8 million, or 3%, for the first nine months of 2022 compared to 2021
primarily due to higher plant placed in-service.
Interest expense increased $3 million, or 3%, for the first nine months of 2022 compared to 2021 primarily due to higher long-term debt.
128
Interest and dividend income increased $18 million for the first nine months of 2022 compared to 2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net decreased $11 million, or 79%, for the first nine months of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned
life insurance policies.
Liquidity and Capital Resources
As of September 30, 2022, Nevada Power's total net liquidity was as follows (in millions):
Cash and cash equivalents
$
73
Credit
facility
400
Less -
Short-term debt
(200)
Letters of credit
(17)
Net credit facility
183
Total
net liquidity
$
256
Credit facility:
Maturity date
2025
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2022 and 2021 were $232 million and $405 million, respectively. The change was primarily due to higher payments related to fuel and energy 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 and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2022 and 2021 were $(523) million and $(322) 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 nine-month periods ended September 30, 2022 and 2021 were $332 million and $(25) million, respectively. The change was primarily due to higher proceeds from the issuance of long-term debt, contributions from NV Energy, Inc., higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc.
Long-Term Debt
In October 2022, Nevada Power issued $400 million of 5.90% General and Refunding Mortgage bonds, Series GG, due 2053. The net proceeds were used to repay amounts outstanding under its existing revolving credit facility, to fund capital expenditures and for general corporate purposes.
In
January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. In May 2022, Nevada Power drew the remaining $100 million available under the facility at an initial interest rate of 1.24%. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
129
Debt Authorizations
Nevada
Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $3.8 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective shelf registration statement with the SEC to issue up to $2.6 billion of general and refunding mortgage securities through November 2025.
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 its secured revolving credit facility, 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 regulatory approvals, Nevada Power's credit ratings, investors' judgment of risk 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 customer 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.
Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
Nine-Month
Periods
Annual
Ended September 30,
Forecast
2021
2022
2022
Electric distribution
$
137
$
173
$
245
Electric
transmission
38
61
115
Solar generation
7
47
89
Other
141
242
437
Total
$
323
$
523
$
886
Nevada
Power received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission. Nevada Power has included estimates from its latest IRP filing in its forecast capital expenditures for 2022. These estimates may change as a result of the RFP process. 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. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission
line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Solar generation investment 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. Commercial operation is expected by the end of 2023.
130
•Other
includes both growth projects and operating expenditures consisting of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of September 30, 2022, there have been no material changes in cash requirements from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2021, other than those disclosed in Note 4 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Regulatory
Matters
Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Nevada Power's current regulatory matters.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species 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 consolidated financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2021. There
have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2021.
131
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
132
PART I
Item
1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries
("Sierra Pacific") as of September 30, 2022, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2022 and 2021, and of cash flows for the nine-month periods ended September 30, 2022 and 2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously
audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Sierra Pacific as of December 31, 2021, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This
interim financial information is the responsibility of Sierra Pacific's management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Adjustments
to reconcile net income to net cash flows from operating activities:
Depreciation and amortization
i110
i107
Allowance
for equity funds
(i5)
(i5)
Changes
in regulatory assets and liabilities
(i9)
(i30)
Deferred
income taxes and amortization of investment tax credits
i22
i10
Deferred
energy
(i203)
(i95)
Amortization of deferred energy
i66
i12
Other,
net
i3
(i1)
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i32)
(i25)
Inventories
(i11)
i9
Accrued
property, income and other taxes
(i9)
i3
Accounts
payable and other liabilities
i74
i21
Net
cash flows from operating activities
i106
i113
Cash
flows from investing activities:
Capital expenditures
(i278)
(i196)
Net
cash flows from investing activities
(i278)
(i196)
Cash
flows from financing activities:
Proceeds from long-term debt
i248
i—
Long-term
debt reacquired
(i265)
i—
Net
(repayment of) proceeds from short-term debt
(i39)
i82
Dividends
paid
(i70)
i—
Contributions
from parent
i340
i—
Other,
net
(i5)
(i5)
Net
cash flows from financing activities
i209
i77
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i37
(i6)
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i16
i26
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i53
$
i20
The
accompanying notes are an integral part of these consolidated financial statements.
137
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
Sierra Pacific Power Company, together with 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").
iThe
unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2022 and for the three- and nine-month periods ended September 30, 2022 and 2021. The Consolidated Statements of Comprehensive Income
have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2022 and 2021. The results of operations for the three- and nine-month periods ended September 30, 2022 are not necessarily indicative of the results to be expected for the full year.
iThe preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Sierra Pacific's accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30, 2022.
(2)iCash
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 funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. iA
reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented in 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):
In June 2022, Sierra Pacific purchased $i60 million of its variable-rate tax-exempt Gas & Water Facilities Refunding Revenue Bonds, Series 2016B, due 2036, as required by the bond indenture. Sierra Pacific is holding this bond and can re-offer it at a future date.
In May 2022, Sierra Pacific
issued $i250 million of i4.71% General and Refunding Mortgage bonds, Series W, due 2052. The net proceeds were used to repay the outstanding $i200
million unsecured loan with NV Energy, Inc., repay amounts outstanding under its existing revolving credit facility and for general corporate purposes.
In April 2022, Sierra Pacific entered into a $i200 million unsecured loan with NV Energy payable upon demand. The net proceeds were used to purchase certain tax-exempt refunding revenue bond obligations that were subject to mandatory purchase by Sierra Pacific in April 2022. The loan has an underlying variable interest rate based on 30-day U.S. dollar
deposits offered on the London Interbank Offer Rate ("LIBOR") market plus a spread of i0.75%.
In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $i30 million
of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $i25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $i25 million
of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $i75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $i20 million
of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $i30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.
Credit Facilities
In June 2022, Sierra Pacific amended and restated
its existing $i250 million secured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from LIBOR to the Secured Overnight Financing Rate.
139
(5)iIncome
Taxes
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:
Effects
of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2020.
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for federal income tax has been computed on a separate return basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the nine-month periods ended September 30, 2022 and 2021, Sierra Pacific made iino/
net cash payments for federal income tax to BHE.
(6) 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 contributed $i1 million to the Non-Qualified Pension Plans and $i2
million to the Other Postretirement Plans for the nine-month period ended September 30, 2022. 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 (in millions):
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 Note 8 for additional information on derivative contracts.
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 September 30, 2022 a net regulatory asset of $i17 million was recorded related to the net derivative liability of $i17
million. As of December 31, 2021 a net regulatory asset of $i33 million was recorded related to the net derivative liability of $i33
million.
/
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 (in millions):
Unit of
September 30,
December
31,
Measure
2022
2021
Electricity purchases
Megawatt hours
i1
i1
Natural
gas purchases
Decatherms
i64
i53
/
141
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 September 30, 2022, 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.
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 September 30, 2022 and December 31, 2021, 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.
(8) 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 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 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.
142
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 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.
i
The following table reconciles the beginning and ending balances of Sierra Pacific's commodity derivative assets and liabilities measured at fair value on a recurring
basis using significant Level 3 inputs (in millions):
Changes
in fair value recognized in regulatory assets
i1
i4
(i25)
i8
Settlements
i36
(i16)
i41
(i15)
Ending
balance
$
(i17)
$
i—
$
(i17)
$
i—
/
143
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. The carrying value of Sierra Pacific'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 Sierra Pacific's long-term debt (in millions):
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 consolidated financial results.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected
species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
144
(10) iRevenue
from Contracts with Customers
i
The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 11 (in millions):
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.
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.
/
146
Item 2. 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 unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.
Results of Operations for the Third Quarter and First Nine Monthsof 2022 and 2021
Overview
Net
income for the third quarter of 2022 was $59 million, a decrease of $3 million, or 5%, compared to 2021 primarily due to $10 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses, $2 million of higher depreciation and amortization, primarily due to higher plant in-service and higher other expense, partially offset by $11 million of higher electric utility margin. Electric utility margin increased primarily due to higher transmission and wholesale revenue and an increase in the average number of customers, partially offset by unfavorable price impacts from changes in sales mix and unfavorable changes in customer usage. Energy generated decreased 12% for the third quarter of 2022 compared to 2021 primarily due to lower natural gas- and coal-fueled generation. Wholesale electricity sales volumes decreased 10% and purchased electricity volumes increased 4%.
Net
income for the first nine months of 2022 was $100 million, a decrease of $7 million, or 7%, compared to 2021 primarily due to $21 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher earnings sharing, $6 million of unfavorable other, net, mainly due to lower cash surrender value of corporate-owned life insurance policies, $3 million of higher depreciation and amortization, primarily due to higher plant in-service and higher income tax expense, partially offset by $20 million of higher electric utility margin and $6 million of 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 regulatory-related revenue deferrals and an increase in the average number of customers, partially offset by the unfavorable impact of weather, unfavorable price impacts from changes
in sales mix and unfavorable changes in customer usage. Energy generated decreased 15% for the first nine months of 2022 compared to 2021 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes increased 17% and purchased electricity volumes increased 4%.
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 customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses 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 running the business and a measure of comparability to others in the industry.
147
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 (in millions):
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Electric utility margin:
Operating
revenue
$
310
$
266
$
44
17
%
$
767
$
636
$
131
21
%
Cost
of fuel and energy
153
120
33
28
406
295
111
38
Electric utility margin
157
146
11
8
%
361
341
20
6
%
Natural
gas utility margin:
Operating revenue
20
16
4
25
%
100
75
25
33
%
Natural
gas purchased for resale
10
6
4
67
60
35
25
71
Natural gas utility margin
10
10
—
—
%
40
40
—
—
%
Utility
margin
167
156
11
7
%
401
381
20
5
%
Operations
and maintenance
50
40
10
25
%
138
117
21
18
%
Depreciation and amortization
37
35
2
6
110
107
3
3
Property
and other taxes
6
6
—
—
18
18
—
—
Operating income
$
74
$
75
$
(1)
(1)
%
$
135
$
139
$
(4)
(3)
%
148
Electric
Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
Third
Quarter
First Nine Months
2022
2021
Change
2022
2021
Change
Utility margin (in millions):
Operating
revenue
$
310
$
266
$
44
17
%
$
767
$
636
$
131
21
%
Cost
of fuel and energy
153
120
33
28
406
295
111
38
Utility margin
$
157
$
146
$
11
8
%
$
361
$
341
$
20
6
%
Sales
(GWhs):
Residential
834
828
6
1
%
2,070
2,125
(55)
(3)
%
Commercial
910
897
13
1
2,388
2,362
26
1
Industrial
712
989
(277)
(28)
2,188
2,786
(598)
(21)
Other
3
4
(1)
(25)
10
11
(1)
(9)
Total
fully bundled(1)
2,459
2,718
(259)
(10)
6,656
7,284
(628)
(9)
Distribution only service
700
403
297
74
2,037
1,220
817
67
Total
retail
3,159
3,121
38
1
8,693
8,504
189
2
Wholesale
184
204
(20)
(10)
589
504
85
17
Total
GWhs sold
3,343
3,325
18
1
%
9,282
9,008
274
3
%
Average
number of retail customers (in thousands)
372
366
6
2
%
370
365
5
1
%
Average
revenue per MWh:
Retail - fully bundled(1)
$
114.38
$
91.05
$
23.33
26
%
$
105.18
$
80.56
$
24.62
31
%
Wholesale
$
93.37
$
48.32
$
45.05
93
%
$
67.18
$
53.39
$
13.79
26
%
Heating
degree days
37
41
(4)
(10)
%
2,735
2,737
(2)
—
%
Cooling degree days
1,133
997
136
14
%
1,347
1,366
(19)
(1)
%
Sources
of energy (GWhs)(2)(3):
Natural gas
1,283
1,463
(180)
(12)
%
2,980
3,678
(698)
(19)
%
Coal
335
373
(38)
(10)
840
838
2
—
Renewables(4)
8
8
—
—
21
27
(6)
(22)
Total
energy generated
1,626
1,844
(218)
(12)
3,841
4,543
(702)
(15)
Energy purchased
1,432
1,383
49
4
4,055
3,905
150
4
Total
3,058
3,227
(169)
(5)
%
7,896
8,448
(552)
(7)
%
Average
cost of energy per MWh(5):
Energy generated
$
29.41
$
23.64
$
5.77
24
%
$
43.56
$
24.11
$
19.45
81
%
Energy
purchased
$
73.26
$
55.46
$
17.80
32
%
$
58.92
$
47.52
$
11.40
24
%
(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 — GWhs and 2 GWhs of coal and — GWhs and 6 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2022 and 2021, respectively. The average cost of energy per MWh and sources of energy excludes — GWhs and 2 GWhs of coal and — GWhs and 6 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2022 and 2021, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) Includes the Fort Churchill Solar Array which was under lease by Sierra Pacific until it was acquired in December 2021.
(5) The average
cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
149
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
Electric utility margin increased$11 million, or 8%, for the third quarter of 2022 compared to 2021 primarily due to:
•$5 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;
•$4 million of higher transmission and wholesale revenue; and
•$1
million of higher electric retail utility margin primarily due to higher customer volumes, offset by unfavorable price impacts from changes in the sales mix. Retail customer volumes increased by 1.2% primarily due to an increase in the average number of customers, partially offset by unfavorable changes in customer usage.
Operations and maintenance increased $10 million, or 25%, for the third quarter of 2022 compared to 2021 primarily due to higher regulatory-approved cost recovery for the ON Line reallocation of $5 million (offset in operating revenue) and higher plant operations and maintenance expenses.
Depreciation and amortization increased $2 million, or 6%, for the third quarter of 2022 compared to 2021 primarily due to higher plant placed in-service.
Interest
and dividend income increased $2 million, or 67%, for the third quarter of 2022 compared to 2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net decreased $2 million, or 67%, for the third quarter of 2022 compared to 2021 primarily due to higher pension costs.
150
First Nine Months of 2022 Compared to First Nine Months of 2021
Electric utility margin increased$20 million,
or 6%, for the first nine months of 2022 compared to 2021 primarily due to:
•$10 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;
•$7 million of higher transmission and wholesale revenue;
•$3 million of higher regulatory-related revenue deferrals; and
•$2 million of higher energy efficiency implementation rates.
The increase in utility margin was offset by:
•$2
million of lower energy efficiency program rates (offset in operations and maintenance expense) and
•$1 million of lower electric retail utility margin due to unfavorable price impacts from changes in sales mix, offset by higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 2.2% primarily due to an increase in the average number of customers, offset by the unfavorable impact of weather and unfavorable changes in customer usage.
Operations and maintenance increased $21 million, or 18%, for the first nine months of 2022 compared to 2021 primarily due to higher regulatory-approved cost recovery for the ON Line reallocation of $10 million (offset in operating revenue), higher plant operations and maintenance expenses of $7 million and higher
earnings sharing, partially offset by lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $3 million, or 3%, for the first nine months of 2022 compared to 2021 primarily due to higher plant placed in-service.
Interest and dividend income increased $6 million, or 100%, for the first nine months of 2022 compared to 2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net decreased $6 million, or 67%, for the first nine months of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies and
higher pension costs.
Income tax expense increased $2 million, or 15%, for the first nine months of 2022 compared to 2021 and the effective tax rate was 13% for 2022 and 11% for 2021. The effective tax rate increased primarily due to the effects of ratemaking.
Liquidity and Capital Resources
As of September 30, 2022, Sierra Pacific's total net liquidity was as follows (in millions):
Cash
and cash equivalents
$
46
Credit facility
250
Less:
Short-term debt
(120)
Net credit facility
130
Total
net liquidity
$
176
Credit facility:
Maturity date
2025
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2022 and 2021 were $106 million and $113 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.
151
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 and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2022 and 2021 were $(278) million and $(196) 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 nine-month periods ended September 30, 2022 and 2021 were $209 million and $77 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and higher 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.
Long-Term Debt
In June 2022, Sierra Pacific purchased $60 million of its variable-rate tax-exempt Gas & Water
Facilities Refunding Revenue Bonds, Series 2016B, due 2036, as required by the bond indenture. Sierra Pacific is holding this bond and can re-offer it at a future date.
In May 2022, Sierra Pacific issued $250 million of 4.71% General and Refunding Mortgage bonds, Series W, due 2052. The net proceeds were used to repay the outstanding $200 million unsecured loan with NV Energy, Inc., repay amounts outstanding under its existing revolving credit facility and for general corporate purposes.
In April 2022, Sierra Pacific entered into a $200 million unsecured loan with NV Energy payable upon demand. The net proceeds were used to purchase certain tax-exempt refunding revenue bond obligations that were subject to mandatory purchase by Sierra Pacific in April 2022. The loan has an underlying variable interest rate based
on 30-day U.S. dollar deposits offered on the London Interbank Offered Rate market plus a spread of 0.75%.
In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased
these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.
Debt Authorizations
Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $1.9 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.
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 its secured revolving credit facility, 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 regulatory approvals, Sierra Pacific's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
152
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 customer 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.
Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
Nine-Month
Periods
Annual
Ended September 30,
Forecast
2021
2022
2022
Electric
distribution
$
66
$
84
$
128
Electric transmission
50
69
91
Other
80
125
184
Total
$
196
$
278
$
403
Sierra
Pacific received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2022. These estimates may change as a result of the RFP process. 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. In this project, the company has received approval from
the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve
existing and expected demand.
Material Cash Requirements
As of September 30, 2022, there have been no material changes in cash requirements from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2021, other than those disclosed in Note 4 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Regulatory Matters
Sierra Pacific is subject
to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's current regulatory matters.
153
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species 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 consolidated financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information
regarding environmental laws and regulations.
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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition
- unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2021. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2021.
154
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
155
PART
I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Eastern Energy Gas Holdings, LLC
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Eastern
Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of September 30, 2022, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2022 and 2021, and of cash flows for the nine-month periods ended September 30, 2022 and 2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We
have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Eastern Energy Gas as of December 31, 2021, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This
interim financial information is the responsibility of Eastern Energy Gas' management. We are a public accounting firm registered with the 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 reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Adjustments
to reconcile net income to net cash flows from operating activities:
Losses (gains) on other items, net
i2
(i9)
Depreciation
and amortization
i241
i244
Allowance
for equity funds
(i5)
(i5)
Equity
income, net of distributions
(i46)
(i1)
Changes
in regulatory assets and liabilities
i37
(i2)
Deferred
income taxes
i99
i135
Other,
net
i7
(i11)
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i81)
i13
Derivative
collateral, net
(i3)
i7
Accrued
property, income and other taxes
i8
(i61)
Accounts
payable and other liabilities
i53
i37
Net
cash flows from operating activities
i1,035
i867
Cash
flows from investing activities:
Capital expenditures
(i252)
(i291)
Repayment
of notes by affiliates
i31
i269
Notes
to affiliates
(i363)
(i170)
Other,
net
(i11)
(i9)
Net
cash flows from investing activities
(i595)
(i201)
Cash
flows from financing activities:
Repayments of long-term debt
i—
(i500)
Repayment
of notes payable to affiliates, net
i—
(i9)
Proceeds
from equity contributions
i—
i256
Distributions
to noncontrolling interests
(i388)
(i353)
Other,
net
(i4)
(i1)
Net
cash flows from financing activities
(i392)
(i607)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i48
i59
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i39
i48
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i87
$
i107
The
accompanying notes are an integral part of these consolidated financial statements.
162
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
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 transportation pipeline 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. Eastern Energy Gas owns i100% of the general partner interest and i25%
of the limited partnership interest in Cove Point. 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 transportation pipeline. 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").
iThe unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP")
for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2022 and for the three- and nine-month periods ended September 30, 2022 and 2021. The results of operations for the three- and nine-month periods ended September 30, 2022 are not necessarily indicative of the results to be expected for the full year.
iThe
preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Eastern Energy Gas' accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30,
2022.
163
(2) iProperty, Plant and Equipment, Net
iProperty,
plant and equipment, net consists of the following (in millions):
As of
September 30,
December 31,
Depreciable Life
2022
2021
Utility
Plant:
Interstate natural gas pipeline assets
i18 - i48
years
$
i8,825
$
i8,675
Intangible
plant
i5 - i20 years
i107
i110
Utility
plant in-service
i8,932
i8,785
Accumulated
depreciation and amortization
(i3,002)
(i2,901)
Utility
plant in-service, net
i5,930
i5,884
Nonutility
Plant:
LNG facility
i40 years
i4,509
i4,475
Intangible
plant
i14 years
i25
i25
Nonutility
plant in-service
i4,534
i4,500
Accumulated
depreciation and amortization
(i516)
(i423)
Nonutility
plant in-service, net
i4,018
i4,077
Plant,
net
i9,948
i9,961
Construction
work-in-progress
i240
i239
Property,
plant and equipment, net
$
i10,188
$
i10,200
/
Construction
work-in-progress includes $i208 million and $i209
million as of September 30, 2022 and December 31, 2021, respectively, related to the construction of utility plant.
(3) iRegulatory Matters
In September 2021, Eastern
Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. 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 transportation 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, resolving EGTS' general rate case for its FERC-jurisdictional services and providing
for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transportation and storage 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. As of September 30, 2022, EGTS' provision for rate refund for April 2022 through September 2022 totaled $i56 million and was included in current regulatory liabilities on the Consolidated Balance Sheet. FERC approval of the settlement is expected late 2022 or early 2023.
164
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 allowance for funds used during construction. 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 allowance for funds used during construction, which resulted in a reduction to the estimated charge of $i11 million
($i8 million after-tax) that was recorded in operations and maintenance expense in its Consolidated Statements of Operations in the second quarter of 2021. In September 2021, the FERC approved EGTS' accounting entries and supporting documentation.
(4) iInvestments
and Restricted Cash and Cash Equivalents
i
Investments and restricted cash and cash equivalents consists of the following (in millions):
Total
investments and restricted cash and cash equivalents
$
i444
$
i429
Reflected
as:
Current assets
$
i29
$
i17
Noncurrent
assets
i415
i412
Total
investments and restricted cash and cash equivalents
$
i444
$
i429
/
Equity
Method Investments
Eastern Energy Gas, through a subsidiary, owns i50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut.
As of both September 30, 2022 and December 31, 2021, 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 received distributions from its investments of $i34 million and $i30
million for the nine-month periods ended September 30, 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 in its Consolidated Statements of Operations.
165
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 presented in 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
i29
i17
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i87
$
i39
(5) iIncome
Taxes
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:
State
income tax, net of federal income tax benefit
i6
i2
i5
i2
Equity
interest
i4
i1
i2
i1
Effects
of ratemaking
i—
(i1)
(i1)
(i1)
Noncontrolling
interest
(i10)
(i11)
(i10)
(i11)
Other,
net
i—
i—
i—
i1
Effective
income tax rate
i21
%
i12
%
i17
%
i13
%
/
For
the period ended September 30, 2022, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by an absence of tax on income attributable to Cove Point's i75% noncontrolling interest.
(6) iEmployee
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 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 Eastern Energy Gas. Eastern Energy Gas contributed $i10 million
to the MidAmerican Energy Company Retirement Plan and $i2 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month period ended September 30, 2022. 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. As of both September 30, 2022 and December 31, 2021, 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 $ii95/
million.
166
(7) 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.
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.
167
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.
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. The carrying value of Eastern Energy Gas' 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 Eastern Energy Gas' long-term debt (in millions):
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.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental
matters that have the potential to impact Eastern Energy Gas' current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
168
(9) iRevenue from Contracts
with Customers
i
The following table summarizes Eastern Energy Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):
(1)Other
revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" and includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts.
/
Remaining Performance Obligations
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 September 30, 2022 (in millions):
Performance obligations expected to be satisfied
Less
than 12 months
More than 12 months
Total
Eastern Energy Gas
$
i1,824
$
i16,301
$
i18,125
/
(10) 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 tax (in millions):
Item
2.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 Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.
Results
of Operations for the Third Quarter and First Nine Months of 2022 and 2021
Overview
Net income attributable to Eastern Energy Gas for the third quarter of 2022 was $151 million, an increase of $82 million compared to 2021. Net income increased primarily due to higher margins from EGTS' regulated gas transportation and storage operations of $53 million, a benefit from the settlement of regulated tax matters in the Iroquois rate case of $45 million and an increase in Cove Point liquefied natural gas variable revenue and additional liquefied natural gas service as a result of decreased scheduled outage days of $15 million, partially offset by an increase in income tax expense of $43 million primarily due to higher pre-tax income.
Net
income attributable to Eastern Energy Gas for the first nine months of 2022 was $348 million, an increase of $130 million, or 60%, compared to 2021. Net income increased primarily due to higher margins from EGTS' regulated gas transportation and storage operations of $91 million, a benefit from the settlement of regulated tax matters in the Iroquois rate case of $45 million and an increase in Cove Point liquefied natural gas variable revenue and additional liquefied natural gas service as a result of decreased scheduled outage days of $24 million, partially offset by an increase in income tax expense of $61 million primarily due to higher pre-tax income.
Operating
revenue increased $91 million, or 20%, for the third quarter of 2022 compared to 2021, primarily due to an increase in Cove Point liquefied natural gas variable revenue of $30 million and additional liquefied natural gas service as a result of decreased scheduled outage days of $29 million, an increase in regulated gas transportation and storage services revenues due to the settlement of EGTS' general rate case of $41 million and an increase in variable revenue related to park and loan activity of $4 million, partially offset by a decrease in regulated gas sales of $14 million for operational and system balancing purposes due to decreased volumes.
Excess gas increased $21 million for the third quarter of 2022 compared to 2021, primarily due to a decrease in volumes sold of $18 million and favorable valuations of system gas of $7 million,
partially offset by an unfavorable change to operational and system balancing volumes of $3 million.
Operations and maintenance decreased $8 million, or 6%, for the third quarter of 2022 compared to 2021, primarily due to a decrease in post-retirement benefit related costs of $3 million, lower corporate charges of $3 million and lower long-term incentive plan expenses of $2 million.
Depreciation and amortization decreased $7 million, or 8%, for the third quarter of 2022 compared to 2021, primarily due to the settlement of depreciation rates in EGTS' general rate case of $9 million, partially offset by higher plant placed in-service of $2 million.
Property and other taxes
decreased $2 million, or 5%, for the third quarter of 2022 compared to 2021, primarily due to lower estimated 2022 tax assessments.
Interest expense increased$4 million, or 13%, for the third quarter of 2022 compared to 2021, primarily due to debt swap gain amortization in 2021.
Income tax expense increased $43 million for the third quarter of 2022 compared to 2021 and the effective tax rate was 21% for 2022 and 12% for 2021. The effective tax rate increased primarily due to the revaluation of deferred taxes from changes in Pennsylvania's income tax rates.
Equity income increased $44 million for the
third quarter of 2022 compared to 2021, primarily due to a benefit from the settlement of regulated tax matters in the Iroquois rate case.
170
Net income attributable to noncontrolling interests increased $46 million, or 46%, for the third quarter of 2022 compared to 2021, primarily due to an increase in Cove Point liquefied natural gas variable revenue and additional liquefied natural gas service as a result of decreased scheduled outage days.
First Nine Months of 2022 Compared to First Nine Months of 2021
Operating revenue increased $154 million, or 11%, for the first
nine months of 2022 compared to 2021, primarily due to an increase in Cove Point liquefied natural gas variable revenue of $68 million and additional liquefied natural gas service as a result of decreased scheduled outage days of $29 million, an increase in regulated gas transportation and storage services revenues due to the settlement of EGTS' general rate case of $66 million, an increase in variable revenue related to park and loan activity of $15 million and a $7 million increase from the West Loop transmission pipeline being placed into service in the third quarter of 2021, partially offset by a decrease in regulated gas sales of $31 million for operational and system balancing purposes due to decreased volumes.
Excess gas increased $33 million for the first nine months of 2022 compared to 2021, primarily due to a decrease in volumes sold of $32 million and
favorable valuations of system gas of $25 million, partially offset by an unfavorable change to operational and system balancing volumes of $23 million.
Operations and maintenance decreased $3 million, or 1%, for the first nine months of 2022 compared to 2021, primarily due to lower long-term incentive plan expenses of $7 million, bank and legal fees recorded in 2021 related to Eastern Energy Gas' debt exchange of $4 million and a decrease in post-retirement benefit related costs of $2 million, partially offset by a 2021 benefit from the finalization of entries for the disallowance of capitalized AFUDC of $11 million.
Depreciation and amortization decreased $3 million, or 1%, for the first nine months of 2022 compared to 2021, primarily due to the settlement
of depreciation rates in EGTS' general rate case of $15 million, partially offset by higher plant placed in-service of $12 million.
Property and other taxes decreased $13 million, or 11%, for the first nine months of 2022 compared to 2021, primarily due to lower than estimated 2021 tax assessments.
Interest expense decreased$10 million, or 8%, for the first nine months of 2022 compared to 2021, primarily due to the repayment of $500 million of long-term debt in the second quarter of 2021.
Income tax expense increased $61 million, or 87%, for the first nine months of 2022 compared to 2021 and the effective
tax rate was 17% for 2022 and 13% 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 $49 million for the first nine months of 2022 compared to 2021, primarily due to a benefit from the settlement of regulated tax matters in the Iroquois rate case.
Net income attributable to noncontrolling interests increased $73 million, or 24%, for the first nine months of 2022 compared to 2021, primarily due to an increase in Cove Point liquefied natural gas variable revenue and additional liquefied natural gas service as a result of decreased scheduled outage days.
Liquidity
and Capital Resources
As of September 30, 2022, Eastern Energy Gas' total net liquidity was $458 million as follows (in millions):
Cash and cash equivalents
$
58
Intercompany revolving credit agreement
400
Total
net liquidity
$
458
Intercompany revolving credit agreement:
Maturity date
2023
171
Operating Activities
Net cash flows from operating activities for the nine-month periods
ended September 30, 2022 and 2021 were $1.0 billion and $867 million, respectively. The change is primarily due to the timing of income tax payments, the impacts from the proposed rates in effect April 1, 2022 for the EGTS general rate case and other working capital adjustments.
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 for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods
ended September 30, 2022 and 2021 were $(595) million and $(201) million, respectively. The change is primarily due to a decrease in repayments of loans by affiliates of $238 million and an increase in loans to its parent under an intercompany revolving credit agreement of $193 million, partially offset by a decrease in capital expenditures of $39 million.
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2022 were $(392) million and consisted primarily of distributions to noncontrolling interests from Cove Point.
Net
cash flows from financing activities for the nine-month period ended September 30, 2021 were $(607) million. Sources of cash totaled $256 million and consisted of proceeds from equity contributions, that primarily 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 $863 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $353 million and repayment of notes to affiliates of $9 million.
Future Uses of Cash
Eastern Energy Gas 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, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments, debt retirements and other capital requirements. The availability and terms under which Eastern Energy Gas and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, Eastern Energy Gas' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the natural gas transportation pipeline and storage and LNG export, import and storage industries.
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 customer 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, are as follows (in millions):
Nine-Month
Periods
Annual
Ended September 30,
Forecast
2021
2022
2022
Natural gas transmission and storage
$
15
$
36
$
47
Other
276
216
324
Total
$
291
$
252
$
371
172
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 non-regulated and routine capital expenditures for natural gas transmission, storage and liquefied natural gas terminalling infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of September 30, 2022, there have been no material changes in cash requirements from the information provided in Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2021, other than natural gas supply and transportation cash requirements increasing
$87 million, primarily due to rate increases for pipeline transportation and storage purchase obligations as a result of a recent rate case.
Regulatory Matters
Eastern Energy Gas is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Eastern Energy Gas' current regulatory matters.
Environmental Laws and Regulations
Eastern Energy Gas is subject
to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Eastern Energy Gas' 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 consolidated financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets and income taxes. For additional discussion of Eastern Energy Gas' critical accounting estimates, see Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2021. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2021.
173
Eastern Gas
Transmission and Storage, Inc. and its subsidiaries
Consolidated Financial Section
174
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the Board of Directors of
Eastern Gas Transmission and Storage, Inc.
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Eastern Gas Transmission and Storage, Inc. and subsidiaries ("EGTS") as of September 30, 2022, the related consolidated statements of operations, comprehensive income, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2022 and 2021, and of cash flows for the nine-month periods ended September 30, 2022 and 2021,
and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of EGTS as of December 31, 2021 and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated July 7, 2022 we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of EGTS' management. We are a public accounting firm registered with the 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 reviews in accordance with standards
of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Adjustments
to reconcile net income to net cash flows from operating activities:
Losses (gains) on other items, net
i1
(i11)
Depreciation
and amortization
i115
i123
Allowance
for equity funds
(i3)
(i5)
Changes
in regulatory assets and liabilities
i35
i1
Deferred
income taxes
i58
i61
Other,
net
i5
(i4)
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i10)
i14
Receivables
from affiliates
i3
(i27)
Pension
and other postretirement benefit plans
i—
i3
Accrued
property, income and other taxes
(i1)
(i16)
Accounts
payable and other liabilities
i31
i37
Accounts
payable to affiliates
i7
i1
Net
cash flows from operating activities
i448
i301
Cash
flows from investing activities:
Capital expenditures
(i179)
(i233)
Repayment
of notes by affiliates
i11
i—
Notes
to affiliates
(i8)
i—
Other,
net
(i9)
i3
Net
cash flows from investing activities
(i185)
(i230)
Cash
flows from financing activities:
Repayment of notes payable to affiliates, net
(i53)
(i78)
Proceeds
from equity contributions
i—
i20
Dividends
paid
(i172)
(i18)
Other,
net
i—
i5
Net
cash flows from financing activities
(i225)
(i71)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i38
i—
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i26
i23
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i64
$
i23
The
accompanying notes are an integral part of these consolidated financial statements.
181
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
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 pipeline and underground storage. EGTS' operations include transmission pipelines 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.
iThe
unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's ("SEC") rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2022 and for the three- and nine-month periods ended September 30, 2022 and 2021. The results of operations for the
three- and nine-month periods ended September 30, 2022 are not necessarily indicative of the results to be expected for the full year.
iThe preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited
Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements for the three years ended December 31, 2021 included in EGTS' Form S-4 (SEC Registration No. 333-266049), as amended, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in EGTS' accounting policies or its assumptions regarding significant accounting estimates during the nine-month period ended September 30, 2022.
(2) iProperty,
Plant and Equipment, Net
iProperty, plant and equipment, net consists of the following (in millions):
As
of
September 30,
December 31,
Depreciable Life
2022
2021
Interstate natural gas pipeline and storage assets
i18
- i48 years
$
i6,625
$
i6,517
Intangible
plant
i11 - i21 years
i73
i74
Plant
in-service
i6,698
i6,591
Accumulated
depreciation and amortization
(i2,411)
(i2,339)
Plant
in-service, net
i4,287
i4,252
Construction
work-in-progress
i188
i188
Property,
plant and equipment, net
$
i4,475
$
i4,440
/
182
(3) iRegulatory
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' previous general rate case was settled in 1998. 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 transportation 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, resolving EGTS' general rate case for its FERC-jurisdictional services and providing
for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transportation and storage 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. As of September 30, 2022, EGTS' provision for rate refund for April 2022 through September 2022 totaled $i56 million and was included in current regulatory liabilities on the Consolidated Balance Sheet. FERC approval of the settlement is expected late 2022 or early 2023.
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 allowance for funds used during construction. 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 allowance for funds used during construction, 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 in its Consolidated Statements of Operations in the second quarter of 2021. In September 2021, the FERC approved EGTS' accounting entries and supporting documentation.
(4) iInvestments
and Restricted Cash and Cash Equivalents
i
Investments and restricted cash and cash equivalents consists of the following (in millions):
Total
investments and restricted cash and cash equivalents
$
i41
$
i28
Reflected
as:
Current assets
$
i28
$
i15
Noncurrent
assets
i13
i13
Total
investments and restricted cash and cash equivalents
$
i41
$
i28
/
183
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 presented in 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
$
i64
$
i26
(5) 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 in 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.
(6) iIncome Taxes
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:
State
income tax, net of federal income tax benefit
i11
i6
i8
i7
Effects
of ratemaking
i—
(i4)
i—
(i3)
Debt
exchange
i—
i—
i—
i2
Other,
net
i1
i1
i—
(i1)
Effective
income tax rate
i33
%
i24
%
i29
%
i26
%
/
184
(7) iEmployee
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 contributed $i9
million to the MidAmerican Energy Company Retirement Plan and $i2 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month period ended September 30, 2022. 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. As of both September 30, 2022 and December 31, 2021, EGTS' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $ii85/
million.
(8) 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).
•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.
185
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 (in millions):
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.
Environmental Laws and Regulations
EGTS is subject to federal, state and local laws and regulations regarding climate change, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species 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.
186
(10) iRevenue from Contracts with Customers
i
The
following table summarizes EGTS' revenue from contracts with customers ("Customer Revenue") by regulated and other, with further disaggregation of regulated by line of business (in millions):
(1)Other
revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" and includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts.
/
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 September 30, 2022 (in millions):
Performance obligations expected to be satisfied
Less than 12
months
More than 12 months
Total
EGTS
$
i895
$
i3,910
$
i4,805
/
187
Item
2.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 Part I, Item 1 of this Form 10-Q. EGTS' actual results in the future could differ significantly from the historical results.
Results
of Operations for the Third Quarter and First Nine Months of 2022 and 2021
Overview
Net income for the third quarter of 2022 was $81 million, an increase of $39 million, or 93%, compared to 2021. Net income increased primarily due to higher margins from regulated gas transportation and storage operations of $53 million and a decrease in depreciation due to the settlement of depreciation rates in EGTS' general rate case of $9 million, partially offset by an increase in income tax expense of $26 million primarily due to higher pre-tax income.
Net income for the first nine months of 2022 was $207 million, an increase of $83 million, or 67%, compared to 2021. Net income increased primarily due to higher margins from regulated
gas transportation and storage operations of $91 million, a decrease in depreciation due to the settlement of depreciation rates in EGTS' general rate case of $15 million, a decrease in post-retirement benefit related costs of $12 million, lower than estimated 2021 tax assessments of $11 million and lower interest expense of $10 million primarily due to lower interest rates, partially offset by an increase in income tax expense of $43 million primarily due to higher pre-tax income and a 2021 benefit from the finalization of entries for the disallowance of capitalized AFUDC of $11 million.
Operating revenue increased
$31 million, or 15%, for the third quarter of 2022 compared to 2021, primarily due to an increase in regulated gas transportation and storage services revenues due to the settlement of EGTS' general rate case of $41 million and an increase in variable revenue related to park and loan activity of $4 million, partially offset by a decrease in regulated gas sales of $14 million for operational and system balancing purposes due to decreased volumes.
Excess gas increased $22 million for the third quarter of 2022 compared to 2021, primarily due to a decrease in volumes sold of $18 million and favorable valuations of system gas of $7 million, partially offset by an unfavorable change to operational and system balancing volumes of $3 million.
Operations and maintenance
decreased $6 million, or 7%, for the third quarter of 2022 compared to 2021, primarily due to a decrease in post-retirement benefit related costs of $3 million and lower long-term incentive plan expenses of $2 million.
Depreciation and amortization decreased $8 million, or 19%, for the third quarter of 2022 compared to 2021, primarily due to the settlement of deprecation rates in EGTS' general rate case of $9 million, partially offset by higher plant placed in-service of $1 million.
Property and other taxes decreased $2 million, or 12%, for the third quarter of 2022 compared to 2021, primarily due to lower estimated 2022 tax assessments.
Income tax expense increased
$26 million for the third quarter of 2022 compared to 2021 and the effective tax rate was 33% for 2022 and 24% for 2021. The effective tax rate increased primarily due to the revaluation of deferred taxes from changes in Pennsylvania's income tax rates.
First Nine Months of 2022 Compared to First Nine Months of 2021
Operating revenue increased $55 million, or 9%, for the first nine months of 2022 compared to 2021, primarily due to an increase in regulated gas transportation and storage services revenues due to the settlement of EGTS' general rate case of $66 million, an increase in variable revenue related to park and loan activity of $15 million and a $7 million increase from the West Loop transmission pipeline being placed into service in the third quarter of 2021, partially offset by
a decrease in regulated gas sales of $31 million for operational and system balancing purposes due to decreased volumes.
Excess gas increased $36 million for the first nine months of 2022 compared to 2021, primarily due to a decrease in volumes sold of $32 million and favorable valuations of system gas of $25 million, partially offset by an unfavorable change to operational and system balancing volumes of $23 million.
188
Operations and maintenance decreased $24 million, or 9%, for the first nine months of 2022 compared to 2021, primarily due to a decrease in post-retirement benefit related costs of $12
million, lower long-term incentive plan expenses of $7 million and bank and legal fees recorded in 2021 related to the debt exchange with Eastern Energy Gas of $4 million.
Depreciation and amortization decreased $8 million, or 7%, for thefirst nine months of 2022 compared to 2021, primarily due to the settlement of depreciation rates in EGTS' general rate case of $15 million, partially offset by higher plant placed in-service of $7 million.
Property and other taxes decreased $11 million, or 22%, for the first nine months of 2022 compared to 2021, primarily due to lower than estimated 2021 tax assessments.
Disallowance and
abandonment of utility plant decreased $11 million for the first nine months of 2022 compared to 2021 due to a 2021 benefit from the finalization of entries for the disallowance of capitalized AFUDC.
Interest expense decreased$10 million, or 17%, for the first nine months of 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 decreased $5 million for the first nine months of 2022 compared to 2021, primarily due to losses on marketable securities.
Income tax expense increased $43 million, or 100%, for the first nine months of 2022 compared to 2021 and the effective tax rate was 29% for 2022 and 26% for 2021.
Liquidity and Capital Resources
As of September 30, 2022, EGTS' total net liquidity was $421 million as follows (in millions):
Cash
and cash equivalents
$
36
Intercompany revolving credit agreement
400
Less:
Notes payable to affiliates
15
Net intercompany revolving
credit agreement
385
Total net liquidity
$
421
Intercompany revolving credit agreement:
Maturity date
2023
Operating
Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2022 and 2021 were $448 million and $301 million, respectively. The change is primarily due to the impacts from the proposed rates in effect April 1, 2022 for the EGTS general rate case 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 elected and assumptions for each payment date.
Investing Activities
Net
cash flows from investing activities for the nine-month periods ended September 30, 2022 and 2021 were $(185) million and $(230) million, respectively. The change is primarily due to a decrease in capital expenditures of $54 million and repayments of loans by affiliates of $11 million, partially offset by loans to affiliates of $8 million and an increase in plant removal costs of $4 million.
189
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2022
were $(225) million and consisted of dividends paid to Eastern Energy Gas of $172 million and net repayment of notes payable to Eastern Energy Gas of $53 million.
Net cash flows from financing activities for the nine-month period ended September 30, 2021 were $(71) million. Sources of cash totaled $25 million and consisted primarily of $20 million in proceeds from equity contributions from Eastern Energy Gas. Uses of cash totaled $96 million and consisted of net repayment of notes payable to Eastern Energy Gas of $78 million and dividends paid to Eastern Energy Gas of $18 million.
Future Uses of Cash
EGTS 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, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments, debt retirements and other capital requirements. The availability and terms under which EGTS has access to external financing depends on a variety of factors, including regulatory approvals, EGTS' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the natural gas transportation pipeline and storage 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 customer 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, are as follows (in millions):
Nine-Month
Periods
Annual
Ended September 30,
Forecast
2021
2022
2022
Natural gas transmission and storage
$
9
$
30
$
40
Other
224
149
205
Total
$
233
$
179
$
245
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 and 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
As of September 30, 2022, there have been no material changes in cash requirements from the information
provided in Management's Discussion and Analysis of Financial Condition and Results of Operations for the year ended December 31, 2021 included in EGTS' Form S-4 (SEC Registration No. 333-266049), as amended, other than natural gas supply and transportation cash requirements increasing $87 million, primarily due to rate increases for pipeline transportation and storage purchase obligations as a result of a recent rate case.
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Regulatory Matters
EGTS
is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding EGTS' current regulatory matters.
Environmental Laws and Regulations
EGTS is subject to federal, state and local laws and regulations regarding climate change, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact EGTS' 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. EGTS 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 EGTS is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
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. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets and income taxes. For additional discussion of EGTS' critical accounting estimates, see Management's Discussion and Analysis of Financial Condition and Results of Operations included in EGTS' Form S-4 (SEC Registration No. 333-266049),
as amended. There have been no significant changes in EGTS' assumptions regarding critical accounting estimates since December 31, 2021.
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Item 3.Quantitative and Qualitative Disclosures About Market Risk
For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2021 and the Quantitative
and Qualitative Disclosure About Market Risk section included in EGTS' Form S-4 (SEC Registration No. 333-266049), as amended. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2021, except as noted below. Refer to Note 7 of the Notes to Consolidated Financial Statements of PacifiCorp, Note 7 of the Notes to Consolidated Financial Statements of Nevada Power and Note 7 of the Notes to Consolidated Financial Statements of Sierra Pacific in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of September 30, 2022.
Eastern Energy Gas' and 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 September 30, 2022, Eastern Energy Gas' and EGTS' credit exposure totaled $107 million. Of this amount, investment grade counterparties, including those internally rated, represented 97%, with two investment grade counterparties representing 54%.
Item 4.Controls and Procedures
At the end of the period covered by this Quarterly Report on Form 10-Q, 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 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 Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States 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 September 30, 2022 that has materially affected, or is reasonably likely to materially affect, its internal control over financial
reporting.
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PART II
Item 1.Legal Proceedings
Berkshire Hathaway Energy and PacifiCorp
On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne
James et al. v. PacifiCorp et al., Case No. 20CV33885, Circuit Court, Multnomah County, Oregon. 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. 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, Two Four Two and Santiam Canyon fires, as well as to add claims for noneconomic damages. The amended complaint alleges 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 the following damages for the plaintiffs and the putative class: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal property and other economic losses of not less than $600 million; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (v) double the damages for the costs of litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The plaintiffs demand a trial by jury and have reserved their right to further amend the complaint to allege claims for punitive damages. In May 2022, the Multnomah Circuit Court granted issue class certification and consolidated this case with others as described below. PacifiCorp requested
an immediate appeal of the issue class certification before the Oregon Court of Appeals.
On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21CV33595, Multnomah County, Oregon, in which two complaints, Case No. 21CV09339 and Case No. 21CV09520, previously filed in Circuit Court, Marion County, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek fire, which the plaintiffs allege began on or around September
7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs
demand a trial by jury and have reserved their right to amend the complaint with an intent to add a claim for punitive damages. In May 2022, this case was consolidated with others as described below.
In May 2022, the Multnomah Circuit Court granted plaintiffs' motion to consolidate Shylo Salter et al. v. PacifiCorp, Case No. 21CV33595 (described above) and Amy Allen, et al. v. PacifiCorp, Case No. 20CV37430 ("Allen") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). Plaintiffs' motion to bifurcate issues for trial between class-wide liability and individual damages was also granted. The Allen case was filed by five individuals as amended in September 2021 claiming in excess of $32 million in economic
and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest.
In June 2022, an amended complaint against PacifiCorp was filed, captioned Tim Goforth et al. v. PacifiCorp, Case No. 20CV37637, Douglas County, Oregon, in which a previously filed complaint associated with the Archie Creek, Susan Creek and Smith Springs Road fires in Douglas County in September 2020 was amended to add punitive damages. The complaint alleges (i) PacifiCorp's conduct not only constituted common law negligence but gross negligence and contributed to or was the cause of ignition and spread of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence,
inverse condemnation. The complaint seeks the following damages: (i) economic and property damages of $11 million under a determination of negligence or inverse condemnation and subject to doubling under Oregon statute if applicable; (ii) doubling of those economic and property damages to $22 million under a determination of gross negligence; (iii) damages for injuries in excess of $47 million; (iv) punitive damages not to exceed 10 times the amount of non-economic damages awarded; (v) all costs of the lawsuit; (vi) pre- and post-judgment interest as allowed by law; and (vii) attorneys' fees and other costs.
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On August 26, 2022, a putative class action complaint seeking declaratory
and equitable relief against PacifiCorp was filed, captioned Margaret Dietrich et al. v. PacifiCorp, Case No. 22CV29187, Circuit Court, Multnomah County, Oregon. The complaint was filed by two Oregon residents individually and on behalf of a class initially 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, Beachie Creek, Lionshead, Echo Mountain Complex, Two Four Two or South Obenchain fires in September 2020. The complaint was amended on September 6, 2022, to seek damages of over $900 million that were originally demanded on August 4, 2022, pursuant to Oregon Rule of Civil
Procedure 32 H. The amended complaint alleges: (i) negligence due to alleged failure to comply with certain Oregon statutes and administrative rules; (ii) gross negligence due to alleged conscious indifference to or reckless disregard for the probable consequences of defendant's actions or inactions; (iii) private nuisance; (iv) public nuisance; (v) trespass; (vi) inverse condemnation; (vii) accounting/injunction; (viii) negligent infliction of emotional distress. The amended complaint seeks the following: (i) an order certifying the matter as a class action; (ii) economic damages not less than $400 million; (iii) double the amount of economic and property damages to the extent applicable under Oregon statute; (iv) reasonable costs of reforestation activities; (v) doubling and trebling of certain other damages to the extent applicable under certain Oregon statutes; (vi) noneconomic damages not less than $500 million; (vii) prejudgment interest; (viii) an order requiring
an accounting with respect to the amount of damages; (ix) an order enjoining PacifiCorp from leaving power lines energized in areas of Oregon experiencing extremely critical fire conditions; (x) an award of reasonable attorney fees, costs, investigation costs, disbursements and expert witness fees; and (xi) other relief the court finds appropriate. The plaintiffs and proposed class demand a trial by jury.
On September 1, 2022, a complaint against PacifiCorp was filed, captioned Martin Klinger et al. v. PacifiCorp, Case No. 22CV29674, Multnomah County, Oregon ("Klinger"). The complaint was filed by Oregon residents or Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On
September 1, 2022, a complaint against PacifiCorp was filed, captioned Aaron Macy-Wyngarden et al. v. PacifiCorp, Case No. 22CV29684, Multnomah County, Oregon ("Macy-Wyngarden"). The complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.
On September 1, 2022, a complaint against PacifiCorp was filed, captioned Jeremiah E. Bowen et al. v. PacifiCorp, Case No. 22CV29681, Multnomah County, Oregon ("Bowen"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires.
The allegations made and damages sought are described below.
On September 1, 2022, a complaint against PacifiCorp was filed, captioned James Weathers et al. v. PacifiCorp, Case No. 22CV29683, Multnomah County, Oregon ("Weathers"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 6, 2022, a complaint against PacifiCorp was filed, captioned Blair Barnholdt et al. v. PacifiCorp, Case No. 22CV30097, Multnomah County, Oregon ("Barnholdt"). The complaint was filed by Oregon residents or
Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 7, 2022, a complaint against PacifiCorp was filed, captioned Willard K. Pratt et al. v. PacifiCorp, Case No. 22CV30217, Multnomah County, Oregon ("Pratt"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 7, 2022, a complaint against PacifiCorp was filed, captioned April Thompson et al. v. PacifiCorp, Case No.
22CV30451, Multnomah County, Oregon ("Thompson"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 22, 2022, a complaint against PacifiCorp was filed, captioned Zachary Bogle et al. v. PacifiCorp, Case No. 22CV29717, Multnomah County, Oregon ("Bogle"). The complaint was filed by Oregon residents who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.
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The
Klinger, Macy-Wyngarden, Bowen, Weathers, Barnholdt, Pratt, Thompson and Bogle complaints each 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; and (v) inverse condemnation. The Klinger, Macy-Wyngarden, Bowen, Weathers, Barnholdt, Pratt, Thompson and Bogle complaints each seek the following damages: (i) economic and property related damages of $83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of earnings capacity,
evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and (vii) pre-judgment interest. The plaintiffs for each Klinger, Macy-Wyngarden, Bowen, Weathers, Barnholdt, Pratt, Thompson and Bogle request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages.
Other individual lawsuits alleging similar claims have been filed in Oregon and California related to the 2020 Wildfires, including multiple complaints filed in California for the September 2020 Slater Fire. Multiple complaints have also been filed in California for the 2022 McKinney fire. The complaints filed in California do not specify damages sought. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 8 of
the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.
PacifiCorp
On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22CV09346, Circuit Court, Douglas County, Oregon. The complaint was filed by nine businesses and public pension plans that own and/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 alleges (i) PacifiCorp's conduct constituted not only common law negligence but also gross negligence and that such conduct contributed to or caused the ignition and spread of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence, inverse condemnation. The complaint seeks the following damages as amended: (i) economic and property damages in excess of $195 million under a determination of negligence or inverse condemnation; (ii) doubling of those economic damages to in excess of $390 million under a determination of gross negligence pursuant to Oregon statutes; (iii) all costs of the lawsuit; (iv) prejudgment and post-judgment interest as allowed by law; and (v) attorneys' fees and other costs.
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Item
1A.Risk Factors
There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2021, except as disclosed below. There has been no material change to EGTS' risk factors from those disclosed in EGTS' Form S-4 (SEC Registration No. 333-266049), as amended.
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, such as Russia's invasion of Ukraine in February 2022 and the resulting economic sanctions on Russia and the sale of Russian natural gas and petroleum, as well as the existing and potential further responses from Russia or other countries to such sanctions and military actions, could adversely affect global and regional economies and financial markets. For instance,
the current ban on imports of Russian 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 its 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.
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
Not
applicable.
Item 3.Defaults Upon Senior Securities
Not applicable.
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 Wall Street Reform and Consumer Protection Act is included in Exhibit
95 to this Form 10-Q.
Item 5.Other Information
Not applicable.
Item 6.Exhibits
The following is a list of exhibits filed as part of this Quarterly Report.
The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2022, 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.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
