(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 2, 2023, 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 2, 2023, 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 2, 2023.
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 2, 2023, 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 2, 2023, 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 2, 2023, 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 2, 2023.
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 2, 2023, 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
The Transaction
The acquisition of 50% limited partner interests in Cove Point LNG, LP from DECP Holdings, Inc., an indirect wholly owned subsidiary of Dominion Energy, Inc.
ii
Certain
Industry Terms
2020 Wildfires
Wildfires in Oregon and Northern California that occurred in September 2020
2022 McKinney Fire
A wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022
AFUDC
Allowance
for Funds Used During Construction
AUC
Alberta Utilities Commission
BART
Best Available Retrofit Technology
CCR
Coal Combustion Residuals
CPUC
California Public Utilities Commission
CSAPR
Cross-State
Air Pollution Rule
D.C. Circuit
United States Court of Appeals for the District of Columbia Circuit
DEAA
Deferred Energy Accounting Adjustment
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
GTA
General Tariff Application
GWh
Gigawatt
Hour
IPUC
Idaho Public Utilities Commission
IRP
Integrated Resource Plan
IUB
Iowa Utilities Board
kV
Kilovolt
LNG
Liquefied
Natural Gas
MATS
Mercury and Air Toxics Standards
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
PCAM
Power Cost Adjustment Mechanism
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, costly 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; the damage caused by such wildfires; the extent of the respective Registrant's liability in connection with such wildfires (including the risk that the respective Registrant may
be found liable for damages regardless of fault); investigations into such wildfires; the outcomes of any legal proceedings 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 of such wildfires, investigations and legal proceedings on the respective Registrant's financial condition and reputation;
•the outcomes of legal actions associated with the 2020 Wildfires and the 2022 McKinney Fire, which could have a material adverse effect on PacifiCorp's financial condition and could limit PacifiCorp's ability to access capital on terms commensurate with historical transactions and could impact PacifiCorp's liquidity, cash flows and capital expenditure plans;
•the respective Registrant's ability to reduce wildfire threats and improve
safety, including the ability to comply with the targets and metrics set forth in its wildfire mitigation plans; to retain or contract for the workforce necessary to execute its wildfire mitigation plans; the effectiveness of its system hardening; ability to achieve vegetation management targets; and the cost of these programs and the timing and outcome of any proceeding to recover such costs through rates;
•the ability to economically obtain insurance coverage, or any insurance coverage at all, sufficient to cover losses arising from catastrophic events, such as wildfires;
•a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;
•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;
iv
•the financial condition, creditworthiness and operational stability of the respective Registrant's significant customers and suppliers;
•changes in business strategy or development plans;
•availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates and credit spreads;
•changes
in the respective Registrant's credit ratings;
•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, 2023, the related consolidated statements of operations, comprehensive income (loss), and changes in equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 30, 2023 and 2022,
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, 2022, 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 24, 2023, 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, 2022, 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:
(Gains) losses on marketable securities, net
(i926)
i1,999
Depreciation
and amortization
i3,072
i3,197
Allowance
for equity funds
(i186)
(i123)
Equity
(income) loss, net of distributions
i274
i249
Net
power cost deferrals
(i722)
(i1,008)
Amortization of net power cost deferrals
i303
i246
Other
changes in regulatory assets and liabilities
(i222)
(i81)
Deferred
income taxes and investment tax credits, net
(i172)
(i350)
Other,
net
(i62)
i53
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade
receivables and other assets
(i224)
(i85)
Derivative
collateral, net
(i201)
i106
Pension
and other postretirement benefit plans
(i10)
(i31)
Accrued
property, income and other taxes, net
(i52)
i501
Accounts
payable and other liabilities
i512
i900
Wildfires
insurance receivable
(i257)
(i161)
Wildfires
liability
i1,854
i225
Net
cash flows from operating activities
i5,860
i7,939
Cash
flows from investing activities:
Capital expenditures
(i6,526)
(i5,385)
Purchases
of marketable securities
(i226)
(i375)
Proceeds from sales
of marketable securities
i2,138
i961
Purchases
of U.S. Treasury Bills
(i3,294)
(i613)
Proceeds
from sales of U.S. Treasury Bills
i1,651
i—
Proceeds
from maturities of U.S. Treasury Bills
i3,034
i—
Equity
method investments
(i12)
(i29)
Other, net
i13
(i28)
Net
cash flows from investing activities
(i3,222)
(i5,469)
Cash
flows from financing activities:
Preferred stock redemptions
i—
(i800)
Preferred
dividends
(i17)
(i33)
Common
stock purchases
i—
(i870)
Proceeds
from BHE senior debt
i—
i986
Repayments
of BHE senior debt
(i400)
i—
Proceeds from subsidiary debt
i3,413
i1,198
Repayments
of subsidiary debt
(i1,868)
(i882)
Net proceeds
from (repayments of) short-term debt
i498
(i540)
Purchase
of Cove Point noncontrolling interest
(i3,300)
i—
Distributions
to noncontrolling interests
(i357)
(i395)
Other,
net
(i43)
(i269)
Net
cash flows from financing activities
(i2,074)
(i1,605)
Effect
of exchange rate changes
i2
(i51)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i566
i814
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i1,817
i1,244
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i2,383
$
i2,058
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 in the U.S., 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 and ione of the largest residential real estate brokerage firms and 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, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month
periods ended September 30, 2023, 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, 2022, 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, 2023, other than the updates associated with the Company's estimates of loss contingencies related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the Wildfires" as discussed in Note 11.
11
(2) iiNew
Accounting Pronouncements/
In March 2023, the FASB issued ASU No. 2023-02, amending FASB ASC Topic 323-740, "Investments—Equity Method and Joint Ventures—Income Taxes" which set forth the conditions needed to apply the proportional amortization method. The amendments in this update permit reporting entities to elect to account for their tax equity investments, regardless of the tax credit program from which the income tax credits are received, using the proportional amortization method if certain conditions are met. This guidance is effective for interim and annual reporting periods beginning after December 15, 2023, with early adoption permitted, and is required to be
adopted either using a modified retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption or a retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the earliest fiscal year presented. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
(3) iBusiness
Acquisitions
On September 1, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of BHE, completed the acquisition of DECP Holdings, Inc.'s (the "Seller"), an indirect wholly owned subsidiary of Dominion Energy, Inc., i50% limited partner interests in Cove Point LNG, LP ("Cove Point")
("The Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 9, 2023 (the "Purchase Agreement"), the Buyer paid $i3.3 billion in cash, plus the pro rata portion of the quarterly distribution made by Cove Point for the third fiscal quarter of 2023. BHE funded the Transaction with cash on hand, including cash realized from the liquidation of certain investments, which was contributed to BHE GT&S. The Buyer now owns an aggregate of i75%
of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, continues to own i100% of the general partner interest, of Cove Point. Prior to the Transaction, BHE owned i100%
of the general partner interest and i25% of the limited partner interests in Cove Point. BHE previously determined it has the power to direct the activities that most significantly impact Cove Point's economic performance as well as the obligation to absorb losses and benefits which could be significant to it and accordingly, consolidated Cove Point. Because BHE controls Cove Point both before and after the Transaction, the changes in BHE's ownership interest in Cove Point were accounted for as an equity transaction and no gain or loss was recognized. In connection
with the Transaction, BHE recognized $i120 million of income taxes in equity primarily attributable to the step up in tax basis of the investment in Cove Point of $i144 million,
partially offset by establishing additional regulatory liabilities related to excess deferred income taxes of $i24 million.
12
(4) 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
2023
2022
Regulated assets:
Utility
generation, transmission and distribution systems
i5-i80 years
$
i93,667
$
i92,759
Interstate
natural gas pipeline assets
i3-i80 years
i18,800
i18,328
i112,467
i111,087
Accumulated
depreciation and amortization
(i35,752)
(i34,599)
Regulated
assets, net
i76,715
i76,488
Nonregulated
assets:
Independent power plants
i2-i50
years
i8,461
i8,545
Cove
Point LNG facility
i40 years
i3,415
i3,412
Other
assets
i2-i30 years
i2,792
i2,693
i14,668
i14,650
Accumulated
depreciation and amortization
(i3,703)
(i3,452)
Nonregulated
assets, net
i10,965
i11,198
i87,680
i87,686
Construction
work-in-progress
i8,947
i5,357
Property,
plant and equipment, net
$
i96,627
$
i93,043
/
Construction
work-in-progress includes $i8.4 billion as of September 30, 2023 and $i4.9 billion as of December 31, 2022, related to the construction of regulated assets.
13
(5) iInvestments
and Restricted Cash and Cash Equivalents and Investments
i
Investments and restricted cash and cash equivalents and investments consists of the following (in millions):
Unrealized (losses) gains recognized on marketable securities held at the reporting date
$
(i97)
$
(i3,168)
$
i573
$
(i2,002)
Net
gains (losses) recognized on marketable securities sold during the period
i21
(i102)
i353
i3
(Losses)
gains on marketable securities, net
$
(i76)
$
(i3,270)
$
i926
$
(i1,999)
/
14
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 on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Investments
and restricted cash and cash equivalents
i283
i173
Investments
and restricted cash and cash equivalents and investments
i53
i53
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i2,383
$
i1,817
(6) iRecent
Financing Transactions
Long-Term Debt
In October 2023, AltaLink, L.P. issued C$i500 million of its i5.463%
Senior Secured Notes due October 2055 and intends to use the net proceeds to repay its short-term indebtedness.
In September 2023, MidAmerican Energy issued $i350 million of its i5.35%
First Mortgage Bonds due January 2034 and $i1 billion of its i5.850% First Mortgage Bonds due September 2054. MidAmerican Energy intends, within i24
months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.
In September 2023, Nevada Power issued $i500 million of its i6.00%
General and Refunding Mortgage Bonds, Series 2023A, due March 2054. Nevada Power used the net proceeds to repay its term loan due January 14, 2024 and short-term borrowings outstanding under Nevada Power's revolving credit facility, fund capital expenditures and for general corporate purposes.
In September 2023, Sierra Pacific issued $i400 million of its i5.90%
General and Refunding Mortgage Bonds, Series 2023A, due March 2054. Sierra Pacific used the net proceeds to repay short-term borrowings incurred under Sierra Pacific's revolving credit facility in connection with the redemption in August 2023 of its i3.375% General and Refunding Mortgage Notes, Series T, due 2023, fund capital expenditures and for general corporate purposes.
In May 2023, PacifiCorp issued $i1.2 billion
of its i5.50% First Mortgage Bonds due May 2054. PacifiCorp intends, within i24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's
Green Financing Framework.
Credit Facilities
In June 2023, BHE amended its existing $i3.5 billion unsecured credit facility expiring in June 2025. The amendment extended the expiration date to June 2026.
In June 2023, PacifiCorp amended its existing $i1.2 billion
unsecured credit facility expiring in June 2025. The amendment increased the lender commitment to $i2.0 billion and extended the expiration date to June 2026. Additionally, in June 2023, PacifiCorp terminated its existing $i800 million
i364-day unsecured credit facility expiring in January 2024.
In June 2023, MidAmerican Energy amended its existing $i1.5 billion unsecured credit facility expiring in June 2025. The amendment extended the expiration date to
June 2026.
15
In June 2023, Nevada Power and Sierra Pacific each amended its existing $i400 million and $i250 million
secured credit facilities expiring in June 2025. The amendments increased the commitment of the lenders to $i600 million and $i400 million, respectively, and extended the expiration
date to June 2026.
In April 2023, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$i200 million ione year revolving credit facility to April 2024, by exercising a ione-year
extension option.
(7) iIncome Taxes
The effective income tax rate for the three-month period ended September 30, 2023, is i532%
and results from a $i777 million income tax benefit associated with a $i146 million
pre-tax loss, primarily related to increases in wildfire loss accruals, net of expected insurance recoveries of $i1,263 million as described in Note 11. The $i777 million benefit is primarily comprised of a $i558 million
benefit (i382%) from income tax credits, an $i82 million benefit (i56%)
from effects of ratemaking, and a $i65 million benefit (i44%) from state income tax.
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 federal 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 (loss) before income tax expense (benefit) is as follows:
State
income tax, net of federal income tax impacts
i44
i—
(i5)
(i2)
Income
tax effect of foreign income
i9
i—
i1
(i4)
Effects
of ratemaking
i56
i5
(i8)
(i18)
Equity
income
i9
i—
(i2)
(i4)
Noncontrolling
interest
i11
i2
(i4)
(i9)
Other,
net
i—
i—
i1
i3
Effective
income tax rate
i532
%
i64
%
(i63)
%
(i178)
%
/
Income
tax credits relate primarily to production tax credits ("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,
2023 and 2022 totaled $i1,258 million and $i1,414 million, respectively.
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, 2023 and 2022 totaling $i1,000
million and $i1,742 million, respectively.
In July 2022, the Company amended its tax allocation agreement with Berkshire Hathaway, which changed how state tax attributes will be settled with respect to state income tax returns that Berkshire Hathaway includes the Company. As a result, the Company no longer expects to receive the cash benefits from the state of Iowa net operating loss carryforward previously recorded as a long-term income tax receivable from Berkshire
Hathaway as a component of BHE's shareholders' equity, and recognized a noncash distribution of $ii744/ million
to retained earnings.
16
(8) 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 on the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $i13 million and $i7 million,
respectively, during 2023. As of September 30, 2023, $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 cost (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 on the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be Łi11 million during 2023. As of September 30, 2023, Łi8 million,
or $i10 million, of contributions had been made to the United Kingdom pension plan.
17
(9) iAsset
Retirement Obligations
MidAmerican Energy estimates its asset retirement obligation ("ARO") liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of expected work. During the nine-month period ended September 30, 2023, MidAmerican Energy recorded an increase of $i88
million for decommissioning its wind-generating facilities, which is a non-cash investing activity and is due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.
(10) 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 receivable of $i8 million as of September 30, 2023 and payable of $i87 million
as of December 31, 2022.
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.
19
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
2023:
Beginning
balance
$
(i174)
$
i11
$
(i59)
$
i6
Changes
included in earnings(1)
(i1)
(i5)
i9
i—
Changes
in fair value recognized in OCI
i—
i—
(i3)
i—
Changes
in fair value recognized in net regulatory assets
(i48)
i—
(i231)
i—
Purchases
i1
i—
i1
i—
Settlements
i138
i—
i199
i—
Ending
balance
$
(i84)
$
i6
$
(i84)
$
i6
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)
(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 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):
The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheets.
Construction Commitments
During the nine-month period ended September 30, 2023, PacifiCorp entered into build transfer agreements totaling $i1.2 billion
through 2025 for the construction of certain wind-powered generating facilities in Wyoming.
During the nine-month period ended September 30, 2023, MidAmerican Energy entered into firm construction commitments totaling $i354 million for the remainder of 2023 through 2024 related to the construction and repowering of wind-powered generating facilities in Iowa.
Fuel Contracts
During
the nine-month period ended September 30, 2023, PacifiCorp entered into certain coal supply agreements totaling $i425 million through 2025.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, hazardous 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.
Lower Klamath Hydroelectric Project
In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility began in June 2023, and removal
of the remaining ithree dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has $i450 million in funding available for dam removal and restoration; $i200 million
collected from PacifiCorp's Oregon and California customers and $i250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may occur above the initial $i450 million
in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $i45 million contingency fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete.
Legal Matters
The Company is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which assert claims for damages in
substantial amounts and are described below. For certain legal actions, parties at times may seek to impose fines, penalties and other costs.
Pursuant to Accounting Standards Codification Topic 450, Contingencies, a provision for a loss contingency is recorded when it is probable a liability is likely to occur and the amount of loss can be reasonably estimated. The Company evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.
21
Wildfire Liability Overview
In
California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could be found liable for all damages.
2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed
to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over i500,000 acres in aggregate. Third-party reports for these wildfires indicate over i2,000
structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.
Investigations into the cause and origin of each wildfire are complex and ongoing and have been or are being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, numerous lawsuits on behalf of plaintiffs related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint in Oregon for which the jury issued a verdict for the i17
named plaintiffs in June 2023 as described below. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. Additionally, certain governmental agencies have informed PacifiCorp that they are contemplating filing actions in connection with certain of the Oregon 2020 Wildfires. Amounts sought in the lawsuits, complaints and demands filed in Oregon and in certain demands made in California total nearly $i8 billion,
excluding any doubling or trebling of damages included in the complaints. Generally, the lawsuits and complaints filed in California do not specify damages sought and are excluded from this amount.
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon (the "James case"). The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon
citizens allegedly impacted by the Santiam Canyon, Echo Mountain Complex, South Obenchain and 242 wildfires. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated the James case with several other cases. While PacifiCorp's pre-trial request for immediate appeal of the class certification was denied, it will have the opportunity to appeal the class issues post-judgment. In April 2023, the jury trial for the James case with respect to i17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the i17
individual plaintiffs and to the class with respect to the ifour wildfires. The jury awarded the i17 named plaintiffs $i90 million
of damages, including $i4 million of economic and property damages, $i68 million of noneconomic damages and $i18 million
of punitive damages based on a i0.25 multiplier of the economic and noneconomic damages. In September 2023, the Multnomah County Circuit Court ordered trial dates for itwo consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber
plaintiffs wherein plaintiffs in each of the ithree trials will present evidence regarding their damages. The trials are scheduled at various dates from January to April 2024. A fourth jury trial is scheduled in May 2024 relating to certain nonclass plaintiffs associated with the Echo Mountain Complex fire. Hearings on PacifiCorp's post-trial motions are scheduled to be held November 9, 2023. Under ORS 82.010, interest at a rate of 9% per annum will accrue on the judgment commencing at the date the judgment is entered unless otherwise specified in the judgment. No judgment has yet
been entered by the Multnomah County Circuit Court. PacifiCorp intends to appeal the jury's findings and damage awards in the James case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.
22
Based on available information to date, PacifiCorp believes it is probable that losses will be incurred associated with the 2020 Wildfires. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.
2022
McKinney Fire
According to the California Department of Forestry and Fire Protection, on July 29, 2022, the 2022 McKinney Fire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California located in PacifiCorp's service territory. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and four fatalities and consumed 60,000 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service, the California Public Utilities Commission, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs
related to the 2022 McKinney Fire. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees, but the amount of damages sought is not specified.
PacifiCorp had previously not considered a loss probable related to the 2022 McKinney Fire; however, based on available information to date, PacifiCorp now believes it is probable a loss will be incurred associated with the 2022 McKinney Fire. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes.
Estimated Losses for the Wildfires
Based on the facts and circumstances
available to PacifiCorp as of the date of this filing, including (i) ongoing cause and origin investigations; (ii) ongoing settlement and mediation discussions; (iii) other litigation matters and upcoming legal proceedings; and (iv) the status of the James case, PacifiCorp increased its accrual by $i1,387 million during the three-month period ended September 30, 2023, bringing its cumulative estimated probable losses associated with the Wildfires to $i2,405 million
through September 30, 2023. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages and noneconomic damages such as personal injury damages and loss of life damages that it is reasonably able to estimate at this time and which is subject to change as additional relevant information becomes available.
i
The following table presents changes in PacifiCorp's liability for estimated losses associated with the Wildfires (in millions):
Until
such time that settlement terms or other conclusions are reached to indicate that payments are expected to occur in the short-term, PacifiCorp's liability for estimated losses associated with the Wildfires is classified as a noncurrent liability on the Consolidated Balance Sheets.
PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $i503 million and $i246 million,
respectively, as of September 30, 2023 and December 31, 2022 and is included in Other assets on the Consolidated Balance Sheets. During the three- and nine-month periods ended September 30, 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $i1,263 million and $i1,671 million,
respectively. During the three- and nine-month periods ended September 30, 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $i— million and $i64 million,
respectively. No additional insurance recoveries beyond those accrued to date are expected to be available.
23
It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued for the Wildfires that could have a material adverse effect on PacifiCorp's financial condition. PacifiCorp is currently unable to reasonably estimate a specific range of possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the class to the James case, the variation in the types of properties and damages and the ultimate outcome of legal actions.
HomeServices Antitrust Cases
HomeServices
is currently defending against ifour antitrust cases, all in federal district courts. In each case, plaintiffs claim HomeServices and certain subsidiaries conspired with co-defendants to artificially inflate real estate commissions by following and enforcing multiple listing service ("MLS") rules that require listing agents to offer a commission split to cooperating agents in order for the property to appear on the MLS ("Cooperative Compensation Rule"). iThree
of the ifour cases are brought on behalf of sellers and ione is brought on behalf of buyers. None of the complaints specify damages sought.
In April 2019, the
Burnett (formerly Sitzer) et al. v. HomeServices of America, Inc. et al. complaint was filed in the U.S. District Court for the Western District of Missouri (the "Burnett case"). This lawsuit, which was certified as a class in April 2022, was originally brought on behalf of named plaintiffs Joshua Sitzer and Amy Winger against the National Association of Realtors ("NAR"), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., RE/MAX, LLC, and Keller Williams Realty, Inc. HSF Affiliates, LLC and BHH Affiliates, LLC, each a subsidiary of HomeServices, were subsequently added as defendants. Rhonda Burnett became a lead class plaintiff in June 2021. The jury trial commenced on October 16, 2023, and the jury returned a verdict for the plaintiffs on October 31, 2023, finding that the named defendants participated
in a conspiracy to follow and enforce the Cooperative Compensation Rule, which had the purpose or effect of raising, inflating, or stabilizing broker commission rates paid by home sellers. The jury further found that the class plaintiffs had proved damages in the amount of $i1.8 billion. Federal law authorizes trebling of damages and the award of pre-judgment interest and attorney fees. Joint and several liability applies for the co-defendants. Prior to the trial, Anywhere Real Estate (formerly Realogy Holdings Corp.) and RE/MAX, LLC reached settlement agreements with the plaintiffs, which have
not yet been approved by the court. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri. HomeServices intends to vigorously appeal on multiple grounds the jury's findings and damage award in the Burnett case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.
Based on available information to date, HomeServices believes losses are likely to occur as a result of the jury verdict in the Burnett case and that such damages could be up to $i5.4 billion,
excluding attorneys' fees, prejudgment interest and other costs subject to determination by the court. Under the current circumstances, HomeServices is currently unable to reasonably estimate such losses due to, among other reasons, the joint and several nature of the liability and the early stage of the appeals process; therefore, no loss has been accrued as of the date of this filing. While HomeServices intends to vigorously appeal any final judgment, the outcome of such appeals, if adverse, could have a material adverse effect on HomeServices’ financial condition.
It is also reasonably possible HomeServices will incur losses from the ithree
remaining antitrust cases that could have a material adverse effect on HomeServices’ financial condition. HomeServices is currently unable to reasonably estimate a specific range of possible losses that could be incurred due to, among other reasons, the lack of information about the size of the plaintiff class and potential damages, as well as the joint and several nature of potential liability of the defendants.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
24
(12) 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 14 (in millions):
(1)The
BHE and Other reportable segment represents amounts related principally to other corporate entities, corporate functions and intersegment eliminations.
Real Estate Services
The following table summarizes the Company's real estate services Customer Revenue by line of business (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, 2023, by reportable segment (in millions):
Performance
obligations expected to be satisfied:
Less than 12 months
More than 12 months
Total
BHE Pipeline Group
$
i2,972
$
i20,278
$
i23,250
BHE
Transmission
i164
i—
i164
Total
$
i3,136
$
i20,278
$
i23,414
/
(13) 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. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts,
which were previously reported in BHE and Other, have been changed to reflect this activity in BHE Renewables. 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 corporate entities, corporate functions and intersegment eliminations.
Income
(loss) before income tax expense (benefit) and equity income (loss) by country:
U.S.
$
(i271)
$
(i2,068)
$
i1,462
$
i395
United
Kingdom
i68
i118
i274
i344
Canada
i48
i43
i135
i135
Australia
i11
i11
i13
i12
Other
(i2)
i1
(i2)
(i2)
Total
income (loss) before income tax expense (benefit) and equity income (loss) by country
$
(i146)
$
(i1,895)
$
i1,882
$
i884
i
The
following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2023 (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 and operated businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway that, as of November 2, 2023, owned 92% of BHE's voting common stock. The balance of BHE's voting common stock is privately held by a limited group of investors.
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 in the U.S., interests in an 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 and one of the largest residential real estate brokerage firms and 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 corporate entities, corporate functions and intersegment eliminations. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been changed to reflect this activity in BHE Renewables.
31
Results of Operations for the Third Quarter and First Nine Months of 2023 and 2022
Overview
Operating
revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):
Third
Quarter
First Nine Months
2023
2022
Change
2023
2022
Change
Operating revenue:
PacifiCorp
$
1,676
$
1,635
$
41
3
%
$
4,487
$
4,246
$
241
6
%
MidAmerican
Funding
964
1,148
(184)
(16)
2,643
3,050
(407)
(13)
NV Energy
1,518
1,334
184
14
3,636
2,926
710
24
Northern
Powergrid
314
359
(45)
(13)
975
1,019
(44)
(4)
BHE Pipeline Group
804
964
(160)
(17)
2,795
2,855
(60)
(2)
BHE
Transmission
196
177
19
11
593
543
50
9
BHE Renewables
519
506
13
3
1,349
1,320
29
2
HomeServices
1,212
1,405
(193)
(14)
3,383
4,284
(901)
(21)
BHE
and Other
(33)
(28)
(5)
(18)
(116)
(101)
(15)
(15)
Total operating revenue
$
7,170
$
7,500
$
(330)
(4)
%
$
19,745
$
20,142
$
(397)
(2)
%
Earnings
(loss) on common shares:
PacifiCorp
$
(652)
$
409
$
(1,061)
*
$
(665)
$
622
$
(1,287)
*
MidAmerican
Funding
321
300
21
7
803
745
58
8
NV Energy
278
270
8
3
402
392
10
3
Northern
Powergrid
66
100
(34)
(34)
173
282
(109)
(39)
BHE Pipeline Group
175
234
(59)
(25)
731
755
(24)
(3)
BHE
Transmission
59
59
—
—
181
183
(2)
(1)
BHE Renewables(1)
160
176
(16)
(9)
445
585
(140)
(24)
HomeServices
25
29
(4)
(14)
25
134
(109)
(81)
BHE
and Other
54
(2,427)
2,481
*
438
(1,809)
2,247
*
Total earnings (loss) on common shares
$
486
$
(850)
$
1,336
*
$
2,533
$
1,889
$
644
34
%
(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 increased $1,336 million for the third quarter of 2023 compared to 2022. Included in these results was a pre-tax loss in the third quarter of 2023 of $69 million ($54 million after-tax) compared to a pre-tax loss in the third quarter of 2022 of $3,258 million ($2,574 million after-tax) related to the Company's investment in BYD Company Limited ("BYD"). Excluding the impact of this item, adjusted earnings on common shares for the third quarter of 2023 was $540 million, a decrease of $1,184 million, or 69%, compared to adjusted earnings on common shares for the third quarter of 2022 of $1,724 million.
Earnings
on common shares increased $644 million for the first nine months of 2023 compared to 2022. Included in these results was a pre-tax gain in the first nine months of 2023 of $915 million ($723 million after-tax) compared to a pre-tax loss in the first nine months of 2022 of $1,948 million ($1,539 million after-tax) related to the Company's investment in BYD. Excluding the impact of this item, adjusted earnings on common shares for the first nine months of 2023 was $1,810 million, a decrease of $1,618 million, or 47%, compared to adjusted earnings on common shares for the first nine months of 2022 of $3,428 million.
32
The increases in earnings on common shares for the third quarter and for the first nine months of 2023 compared to 2022
were primarily due to the following:
•The Utilities' earnings decreased $1,032 million for the third quarter and $1,219 million for the first nine months of 2023 compared to 2022, largely due to increases in wildfire loss accruals, net of expected insurance recoveries, higher operations and maintenance expense, increased interest expense and lower electric utility margin. These items were offset by lower depreciation and amortization expense, higher allowances for equity and borrowed funds used during construction, increased interest and dividend income and favorable changes in the cash surrender value of corporate-owned life insurance policies. Electric retail customer volumes decreased 0.6% for the first nine months of 2023 compared to 2022, primarily due to the unfavorable impact of weather, partially offset by an increase in the average number of customers and higher customer usage;
•Northern
Powergrid's earnings decreased $34 million for the third quarter and $109 million for the first nine months of 2023 compared to 2022, primarily due to unfavorable operating performance at CE Gas, increased non-service benefit plan costs and income tax expense related to the enactment of a new Energy Profits Levy income tax. Units distributed declined 4.7% for the first nine months of 2023 compared to 2022 due to the unfavorable impact of weather and lower customer usage;
•BHE Pipeline Group's earnings decreased $59 million for the third quarter and $24 million for the first nine months of 2023 compared to 2022, largely due to higher operations and maintenance expense, favorable income tax adjustments recognized at BHE GT&S in 2022 and lower earnings at Cove Point as a result of increased scheduled maintenance days in 2023, partially offset by the impact of a general rate case, with interim rates
effective January 1, 2023, subject to refund, at Northern Natural Gas;
•BHE Renewables' earnings decreased $16 million for the third quarter and $140 million for the first nine months of 2023 compared to 2022, primarily due to lower earnings from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts, lower natural gas and geothermal earnings for the first nine months due to maintenance outages and higher development costs, lower solar earnings from lower generation and lower earnings from wind tax equity investments due to lower PTCs, partially offset by higher earnings from owned wind projects primarily due to favorable derivative contract valuations and gains on the extinguishment of debt;
•HomeServices' earnings decreased
$4 million for the third quarter and $109 million for the first nine months of 2023 compared to 2022, primarily due to lower earnings from brokerage, settlement and mortgage services, reflecting the impact of rising interest rates and a corresponding decline in home sales; and
•BHE and Other's earnings increased $2,481 million for the third quarter and $2,247 million for the first nine months of 2023 compared to 2022, mainly due to $2,520 million and $2,262 million, respectively, of favorable comparative changes in fair value related to the Company's investment in BYD, partially offset by lower federal income tax credits recognized on a consolidated basis.
Reportable Segment Results
PacifiCorp
Operating
revenue increased $41 million for the third quarter of 2023 compared to 2022, primarily due to higher retail revenue of $76 million, partially offset by lower wholesale and other revenue of $35 million, primarily due to lower average wholesale market prices and volumes. Retail revenue increased primarily due to price impacts of $111 million from higher average retail rates largely due to tariff changes, partially offset by $36 million from lower retail volumes. Retail customer volumes decreased 2.3%, primarily due to the unfavorable impact of weather, partially offset by an increase in the average number of customers and higher customer usage.
Earnings decreased $1,061 million for the third quarter of 2023 compared to 2022, primarily due to an increase in wildfire loss accruals, net of expected insurance recoveries, of $1,263 million, higher operations and maintenance expense of $67
million, lower utility margin of $42 million, increased interest expense of $35 million due to debt issuances in December 2022 and May 2023 and an unfavorable income tax benefit from lower PTCs recognized of $19 million and the effects of ratemaking of $10 million. These items were partially offset by higher allowances for equity and borrowed funds used during construction of $31 million and increased interest and dividend income of $13 million. Operations and maintenance expense increased due to higher wildfire mitigation and vegetation management costs, increased general and plant maintenance costs, increased insurance premiums and higher legal expenses. Utility margin decreased primarily due to higher purchased power and thermal generation costs, lower retail volumes and lower average wholesale market prices and volumes, partially offset by higher retail rates and favorable deferred net power costs.
33
Operating
revenue increased $241 million for the first nine months of 2023 compared to 2022, primarily due to higher retail revenue of $293 million, partially offset by lower wholesale revenue and other revenue of $52 million, primarily due to lower volumes, partially offset by higher average wholesale market prices. Retail revenue increased primarily due to price impacts of $300 million from higher average retail rates largely due to tariff changes and product mix, partially offset by $7 million from lower volumes. Retail customer volumes decreased 0.5%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers.
Earnings decreased $1,287 million for the first nine months of 2023 compared to 2022, primarily due to an increase in wildfire loss accruals, net of expected insurance recoveries, of $1,607 million, higher operations
and maintenance expense of $179 million, increased interest expense of $80 million due to debt issuances in December 2022 and May 2023 and lower utility margin of $2 million. These items were partially offset by higher allowances for equity and borrowed funds used during construction of $81 million, increased interest and dividend income of $44 million and a favorable income tax benefit from valuation changes on state net operating loss carryforwards, partially offset by lower PTCs recognized of $8 million. Operations and maintenance expense increased due to higher wildfire mitigation and vegetation management costs, increased general and plant maintenance costs, higher legal expenses and increased insurance premiums. Utility margin decreased primarily due to higher purchased power and thermal generation costs and lower wholesale volumes, partially offset by higher retail rates, favorable deferred net power costs and higher average wholesale market prices.
MidAmerican
Funding
Operating revenue decreased $184 million for the third quarter of 2023 compared to 2022, primarily due to lower electric operating revenue of $140 million and lower natural gas operating revenue of $45 million. Electric operating revenue decreased due to lower wholesale and other revenue of $115 million and lower retail revenue of $25 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale per-unit prices of $87 million and lower wholesale volumes of $25 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $29 million (fully offset in expense, primarily cost of sales), partially offset by $3 million from higher retail volumes. Electric retail customer volumes increased 0.9%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather. Natural gas operating
revenue decreased due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $51 million (fully offset in cost of sales), partially offset by higher average rates of $4 million.
Earnings increased $21 million for the third quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $128 million and higher allowances for equity and borrowed funds used during construction of $7 million, partially offset by lower electric utility margin of $70 million and an unfavorable income tax benefit, primarily from the effects of ratemaking of $25 million and lower PTCs recognized of $8 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Electric utility margin decreased primarily due
to the lower wholesale and retail revenues, partially offset by lower purchased power and thermal generation costs.
Operating revenue decreased $407 million for the first nine months of 2023 compared to 2022, primarily due to lower electric operating revenue of $221 million and lower natural gas operating revenue of $189 million. Electric operating revenue decreased due to lower wholesale and other revenue of $188 million and lower retail revenue of $33 million. Electric wholesale and other revenue decreased mainly due to lower average wholesale per-unit prices of $133 million and lower wholesale volumes of $53 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of $42 million (fully offset in expense, primarily cost of sales), partially offset by $5 million from higher retail volumes and price impacts of $4 million from changes in
sales mix. Electric retail customer volumes increased 1.1%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $187 million (fully offset in cost of sales) and the unfavorable impact of weather of $9 million, partially offset by higher average rates of $5 million.
Earnings increased $58 million for the first nine months of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $195 million, favorable changes in the cash surrender value of corporate-owned life insurance policies of $34 million and a one-time gain on the sale of an investment of $13 million, partially offset by lower electric utility margin of $80 million, an unfavorable income tax benefit, largely
from the effects of ratemaking of $24 million and lower PTCs recognized of $21 million, and higher operations and maintenance expense of $33 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Electric utility margin decreased primarily due to the lower wholesale and retail revenues, partially offset by lower purchased power and thermal generation costs. Operations and maintenance expense increased mainly due to increased administrative and other costs, higher general and plant maintenance costs and unfavorable property insurance costs.
34
NV Energy
Operating
revenue increased $184 million for the third quarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $177 million and higher natural gas operating revenue of $7 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $175 million and increased base tariff general rates of $15 million at Sierra Pacific, partially offset by lower customer volumes of $19 million. Electric retail customer volumes decreased 3.0%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers.
Earnings increased $8 million for the third quarter of 2023 compared to 2022, primarily due to higher allowances for equity and borrowed funds
used during construction of $13 million, lower operations and maintenance expense of $7 million, favorable interest and dividend income of $5 million, mainly from carrying charges on higher deferred energy balances, and higher electric utility margin of $2 million, partially offset by higher depreciation and amortization expense of $11 million and increased interest expense of $10 million due to higher outstanding long-term debt balances and higher average interest rates. Operations and maintenance expense decreased primarily due to a favorable change in earnings sharing at Nevada Power. Electric utility margin increased primarily due to higher base tariff general rates at Sierra Pacific, partially offset by lower retail customer volumes. Depreciation and amortization expense increased largely due to additional assets placed in-service.
Operating revenue increased $710 million for the
first nine months of 2023 compared to 2022, primarily due to higher electric operating revenue of $643 million and higher natural gas operating revenue of $67 million largely from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $610 million, increased base tariff general rates of $42 million at Sierra Pacific and higher transmission and wholesale revenue of $7 million, partially offset by lower customer volumes of $36 million. Electric retail customer volumes decreased 2.3%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers.
Earnings increased $10 million for the first nine months of 2023 compared to 2022, primarily due to favorable interest
and dividend income of $33 million, mainly from carrying charges on higher deferred energy balances, higher electric utility margin of $32 million, increased allowances for equity and borrowed funds used during construction of $27 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $13 million, partially offset by higher depreciation and amortization expense of $37 million, increased interest expense of $34 million due to higher outstanding long-term debt balances and higher average interest rates and higher operations and maintenance expense of $27 million. Electric utility margin increased primarily due to higher base tariff general rates at Sierra Pacific and higher transmission and wholesale revenue, partially offset by lower retail customer volumes. Depreciation and amortization expense increased largely due to additional assets placed in-service. Operations and maintenance expense increased primarily due to higher
general and plant maintenance costs and higher customer service operations costs, partially offset by a favorable change in earnings sharing at Nevada Power.
Northern Powergrid
Operating revenue decreased $45 million for the third quarter of 2023 compared to 2022, primarily due to lower revenue at CE Gas of $45 million and lower distribution revenue of $30 million, partially offset by $22 million from the weaker U.S. dollar and higher non-regulated contracting revenue of $6 million. CE Gas revenue decreased due to lower gas production volumes and prices from a gas project that commenced commercial operation in March 2022. Distribution revenue decreased primarily due to lower recoveries of Supplier of Last Resort payments of $28 million (largely offset in cost of sales).
Earnings
decreased $34 million for the third quarter of 2023 compared to 2022, primarily due to unfavorable operating performance at CE Gas of $49 million, partially offset by favorable income tax expense from adjustments to the Energy Profits Levy income tax and $4 million from the weaker U.S. dollar. The unfavorable operating performance at CE Gas was largely due to lower gas production volumes and prices from a gas project that commenced commercial operation in March 2022.
35
Operating revenue decreased $44 million for the first nine months of 2023 compared to 2022, primarily due to lower revenue at CE Gas of $36 million, lower distribution revenue of $23 million and $7 million from the stronger U.S. dollar, partially offset by higher non-regulated
contracting revenue of $18 million. CE Gas revenue decreased due to lower gas production volumes and prices from a gas project that commenced commercial operation in March 2022, partially offset by a solar project that commenced commercial operations in June 2022. Distribution revenue decreased primarily due to lower recoveries of Supplier of Last Resort payments of $18 million (largely offset in cost of sales) and a 4.7% decline in units distributed of $11 million, largely due to the unfavorable impact of weather and lower customer usage, partially offset by higher tariff rates of $8 million.
Earnings decreased $109 million for the first nine months of 2023 compared to 2022, primarily due to unfavorable operating performance at CE Gas of $41 million, unfavorable income tax expense related to the enactment of a new Energy Profits Levy income tax and increased non-service benefit plan
costs of $26 million. The unfavorable operating performance at CE Gas was largely due to lower gas production volumes and prices from a gas project that commenced commercial operation in March 2022, partially offset by a solar project that commenced commercial operations in June 2022.
BHE Pipeline Group
Operating revenue decreased $160 million for the third quarter of 2023 compared to 2022, primarily due to lower operating revenue of $155 million at BHE GT&S. The decrease in operating revenue at BHE GT&S was primarily due to lower non-regulated revenue of $86 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices and lower LNG revenue of $68 million at Cove Point.
Earnings decreased $59 million
for the third quarter of 2023 compared to 2022, primarily due to lower earnings of $68 million at BHE GT&S, partially offset by higher earnings of $21 million at Northern Natural Gas, mainly from higher transportation revenue. The decrease at BHE GT&S was largely due to favorable income tax adjustments recognized in 2022, higher operations and maintenance expense of $28 million, mainly due to increases in technology, pension and outside services costs, and lower earnings at Cove Point as a result of increased scheduled maintenance days in 2023.
Operating revenue decreased $60 million for the first nine months of 2023 compared to 2022, primarily due to lower operating revenue of $150 million at BHE GT&S, partially offset by higher operating revenue of $98 million at Northern Natural Gas. The decrease in operating revenue at BHE GT&S was primarily due to lower nonregulated revenue
of $177 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices, lower LNG revenue of $36 million at Cove Point and lower volumes at EGTS primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $26 million, partially offset by an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $45 million and an increase in variable revenue related to natural gas storage park and loan activity of $22 million at EGTS. The increase in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $80 million and higher transportation revenue of $60 million from higher rates, partially offset by lower gas sales of $51 million (largely offset in cost of sales) from system balancing activities.
Earnings
decreased $24 million for the first nine months of 2023 compared to 2022, primarily due to lower earnings of $92 million at BHE GT&S, partially offset by higher earnings of $78 million at Northern Natural Gas. The decrease at BHE GT&S was due to favorable income tax adjustments recognized in 2022, increased cost of gas of $74 million from operational and system balancing fuel activities at EGTS prior to the effective date of the new fuel tracker and the unfavorable revaluation of volumes retained at EGTS due to lower natural gas prices and higher operations and maintenance expense of $60 million, partially offset by the favorable rate case settlement at EGTS in 2022 of $51 million and the variable revenue increase related to natural gas storage park and loan activity at EGTS. Operations and maintenance expense increased at BHE GT&S mainly due to higher technology, pension and outside services costs. The increase at Northern Natural Gas was due to the impacts
of the general rate case of $54 million and the higher transportation revenue, partially offset by higher operations and maintenance expense of $27 million, an increase in depreciation and amortization expense of $11 million and unfavorable margin on gas sales from system balancing activities of $9 million.
BHE Transmission
Operating revenue increased $19 million for the third quarter of 2023 compared to 2022, primarily due to $14 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $5 million from the stronger U.S. dollar.
Earnings for the third quarter of 2023 were equal to 2022, primarily
due to the higher non-regulated revenue at BHE Canada offset by losses from non-regulated wind-powered generating facilities acquired in November 2022.
36
Operating revenue increased $50 million for the first nine months of 2023 compared to 2022, primarily due to $56 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $26 million from the stronger U.S. dollar.
Earnings decreased $2 million for the first nine months of 2023 compared to 2022, primarily due to $7 million from the stronger U.S. dollar, partially offset by the
higher non-regulated revenue at BHE Canada.
BHE Renewables
Operating revenue increased $13 million for the third quarter of 2023 compared to 2022, primarily due to higher natural gas and geothermal revenues of $39 million, primarily due to favorable pricing, and higher wind revenues of $8 million, partially offset by lower natural gas and electric retail energy services revenue of $13 million and lower solar revenue of $11 million, primarily from lower generation. Wind revenue increased mainly due to favorable changes in the valuations of certain derivative contracts. Retail energy services revenue decreased mainly due to unfavorable natural gas pricing and electric retail volumes, partially offset by favorable natural gas volumes and electricity pricing.
Earnings
decreased $16 million for the third quarter of 2023 compared to 2022, primarily due to lower wind earnings of $24 million, lower earnings of $7 million from the retail energy services business, largely due to lower retail gas and electric revenue, and lower solar earnings of $6 million, primarily due to lower generation, partially offset by higher natural gas and geothermal earnings of $22 million. Wind earnings decreased due to lower earnings from tax equity investments of $41 million due to lower PTCs, partially offset by higher earnings at owned wind projects of $17 million, primarily due to lower interest expense from the extinguishment of debt and favorable derivative contract valuations. Natural gas and geothermal earnings increased primarily due to favorable pricing, partially offset by higher geothermal development costs and maintenance outages.
Operating revenue increased $29 million
for the first nine months of 2023 compared to 2022, primarily due to higher wind revenue of $75 million and higher natural gas and geothermal revenue of $31 million, primarily due to favorable pricing, partially offset by lower solar revenues of $46 million, primarily from lower generation, and lower natural gas and electric retail energy services revenue of $11 million. Wind revenue increased primarily due to favorable changes in the valuations of certain derivative contracts of $90 million, partially offset by lower generation of $21 million. Retail energy services revenue decreased mainly due to unfavorable natural gas pricing, partially offset by an increase in natural gas volumes and favorable changes in the valuation of derivative contracts.
Earnings decreased $140 million for the first nine months of 2023 compared to 2022, primarily due to lower earnings of $105 million from the
retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts, lower natural gas and geothermal earnings of $35 million, primarily due to maintenance outages and higher geothermal development costs, and lower solar earnings of $34 million, largely from lower generation, partially offset by higher wind earnings of $39 million. Wind earnings were favorable due to increased earnings from owned projects of $98 million, partially offset by lower earnings from tax equity investments of $59 million due to lower PTCs. Earnings from owned projects were higher primarily due to favorable derivative contract valuations and from gains on the extinguishment of debt, partially offset by a decrease in operating revenue from lower generation.
HomeServices
Operating revenue
decreased $193 million for the third quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $187 million from a 15% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales.
Earnings decreased $4 million for the third quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $11 million, partially offset by higher earnings from mortgage services of $4 million. Earnings declined due to the decrease in closed brokerage transaction volume, partially offset by favorable operating expenses primarily due to lower compensation costs.
Operating revenue decreased $901 million for the first nine months of 2023 compared to 2022, primarily due to lower brokerage and
settlement services revenue of $824 million and lower mortgage revenue of $70 million. The decrease in brokerage and settlement services revenue resulted from a 22% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 33% decrease in funded volume, primarily due to rising interest rates.
37
Earnings decreased $109 million for the first nine months of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $87 million and mortgage services of $18 million. Earnings declined due to the decrease in closed transaction and mortgage funded volumes, partially offset by favorable operating expenses primarily
due to lower compensation costs.
BHE and Other
Operating revenue decreased $5 million for the third quarter of 2023 and $15 million for the first nine months of 2023 compared to 2022, due to changes in intersegment eliminations.
Earnings increased $2,481 million for the third quarter of 2023 compared to 2022, primarily due to the Company's investment in BYD, including the $2,520 million favorable comparative change in fair value and $28 million of higher net interest and dividend income, partially offset by $56 million of lower federal income tax credits recognized on a consolidated basis and higher BHE corporate interest expense from an April 2022 debt issuance.
Earnings
increased $2,247 million for the first nine months of 2023 compared to 2022, primarily due to the Company's investment in BYD, including the $2,262 million favorable comparative change in fair value and $103 million of higher net interest and dividend income, favorable changes in the cash surrender value of corporate-owned life insurance policies of $40 million and $12 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway. These items were partially offset by $102 million of lower federal income tax credits recognized on a consolidated basis and higher BHE corporate interest expense from an April 2022 debt issuance.
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,
2022 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of September 30, 2023, the Company's total net liquidity was as follows (in millions):
BHE
Pipeline
MidAmerican
NV
Northern
BHE
Group and
BHE
PacifiCorp
Funding
Energy
Powergrid
Canada
HomeServices
Other
Total
Cash
and cash equivalents
$
397
$
98
$
700
$
78
$
30
$
71
$
296
$
377
$
2,047
Credit
facilities(1)
3,500
2,000
1,509
1,000
334
792
2,355
—
11,490
Less:
Short-term
debt
(747)
(165)
—
—
(91)
(36)
(578)
—
(1,617)
Tax-exempt
bond support and letters of credit
—
(249)
(306)
—
—
(1)
—
—
(556)
Net
credit facilities
2,753
1,586
1,203
1,000
243
755
1,777
—
9,317
Total
net liquidity
$
3,150
$
1,684
$
1,903
$
1,078
$
273
$
826
$
2,073
$
377
$
11,364
Credit
facilities:
Maturity dates
2026
2026
2024, 2026
2026
2025
2024,
2026, 2027
2023, 2024, 2026
(1)Includes $91 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.
38
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022,
were $5.9 billion and $7.9 billion, respectively. The decrease was primarily due to unfavorable operating results, the timing of payments related to fuel and energy costs and a decrease in income tax receipts, partially offset by 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, 2023 and 2022, were $(3.2) billion and $(5.5) billion, respectively.
The change was primarily due to higher proceeds from sales and maturities, net of purchases, of U.S. Treasury Bills totaling $2.0 billion and higher proceeds from sales, net of purchases, of marketable securities of $1.3 billion, partially offset by higher capital expenditures of $1.1 billion. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2023, was $(2.1) billion. Sources of cash totaled $3.9 billion and consisted of proceeds from subsidiary debt issuances totaling $3.4 billion and net proceeds from short-term debt totaling $498 million. Uses of cash totaled $6.0 billion and consisted mainly of $3.3 billion for
the purchase of Cove Point noncontrolling interest, repayments of subsidiary debt totaling $1.9 billion, repayments of BHE senior debt totaling $400 million and distributions to noncontrolling interests of $357 million.
For a discussion of business acquisitions and recent financing transactions, refer to Note 3 and Note 6, respectively, 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, 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.
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.
39
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
2022
2023
2023
Capital expenditures by business:
PacifiCorp
$
1,481
$
2,250
$
3,322
MidAmerican
Funding
1,404
1,339
1,878
NV Energy
801
1,386
2,006
Northern Powergrid
614
405
556
BHE
Pipeline Group
800
827
1,338
BHE Transmission
143
159
220
BHE Renewables
100
111
264
HomeServices
31
30
38
BHE
and Other(1)
11
19
20
Total
$
5,385
$
6,526
$
9,642
Capital
expenditures by type:
Wind generation
$
582
$
1,109
$
1,658
Electric distribution
1,297
1,639
2,224
Electric
transmission
1,174
1,226
2,094
Natural gas transmission and storage
640
649
957
Solar generation
332
305
387
Electric
battery and pumped hydro storage
7
123
261
Other
1,353
1,475
2,061
Total
$
5,385
$
6,526
$
9,642
(1)BHE
and Other represents amounts related principally to other entities 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 $460 million and $39 million for the nine-month periods ended September 30, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican
Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $171 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $48 million and $422 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $21 million for the remainder of 2023. 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.
◦Construction of new wind-powered generating facilities and construction
at existing wind-powered generating facility sites acquired from third parties at PacifiCorp totaling $540 million and $21 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $260 million for the remainder of 2023 and is primarily for the Rock Creek I and Rock Creek II projects to be constructed in Wyoming totaling 590 MWs that are expected to be placed in-service in 2024 and 2025.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $13 million and $45 million for the nine-month period ended September 30, 2023September 30, 2022.
Planned spending for the repower of wind-powered facilities totals $37 million for the remainder of 2023.
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•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 enhancements 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 investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $536 million and $643 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $411 million for the remainder of 2023.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have received approval from the PUCN to build a 350-mile, 525-kV transmission line connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen
substation; a 235-mile, 525-kV transmission line 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Expenditures for the expansion program and other growth projects totaled $141 million and $91 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026 through 2028 and other growth projects totals $76 million for the remainder of 2023.
◦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, 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 LNG 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 PacifiCorp totaling 377 MWs of new generation and are expected to be placed in-service in 2026. Planned spending totals $3 million for the remainder of 2023.
◦Construction and operation of solar-powered generating facilities at MidAmerican Energy, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the nine-month periods ended September 30, 2023 and 2022, solar generation spending totaled $11 million and $103 million, respectively. Planned spending totals $10 million for the remainder of 2023.
◦Construction
of a solar-powered generating facility at Nevada Power totaling $175 million and $47 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending totals $29 million for the remainder of 2023. 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 or early 2024.
◦Construction of a solar-powered generating facility at BHE Renewables totaling $28 million and $22 million for the nine-month periods ended September 30, 2023 and 2022. Planned spending totals $31 million for the remainder of
2023. Construction includes expenditures for a 48-MW solar photovoltaic facility with an additional 48 MWs of co-located battery storage that will be developed in Rosamond, California. Commercial operations is expected by the end of 2024.
41
•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:
◦Construction at the Nevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada and a 220-MW grid-tied battery energy storage system that will be developed on the site of the retired Reid Gardner generating station in Clark County,
Nevada, both with commercial operation expected by the end of 2023 or early 2024. Also, a 200-MW battery energy storage system that will be developed on the site of the Valmy generating station in Humboldt County, Nevada with commercial operation expected by the end of 2025. Total spending for the nine-month period ended September 30, 2023, was $106 million with planned spending of $136 million for the remainder of 2023.
•Other 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, 2023, 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, 2022, other than those disclosed in Note 11 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
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, 2022, and new regulatory matters occurring in 2023.
PacifiCorp
Utah
In May 2023, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2022. The filing requested a rate increase of $98 million, or 4.6%, which was effective on an interim basis July 1, 2023.
Oregon
In July 2022, PacifiCorp filed an application requesting approval of an automatic adjustment clause with a balancing account to recover
costs associated with implementing PacifiCorp's wildfire protection plan in Oregon. Per formal rulemaking at the OPUC, the wildfire protection plan was changed to be known as the wildfire mitigation plan, resulting in the requested automatic adjustment clause being referred to as the Wildfire Mitigation Plan Automatic Adjustment Clause ("WMP AAC"). In December 2022, a stipulation with certain parties was filed agreeing to the establishment of an automatic adjustment clause. In May 2023, the OPUC approved the stipulation, which resulted in an overall annual increase of $20 million, or 1.6%, effective May 24, 2023 for estimated 2022 incremental operation and maintenance costs in excess of those reflected in base rates as a result of the last general rate case. In June 2023, PacifiCorp filed its WMP AAC to recover remaining 2022 deferred operations and maintenance costs, projected incremental 2023 operations and maintenance
costs and capital costs incremental to amounts previously included in general rate case filings. The filing requested a rate increase of $27 million over the existing amount approved in May 2023, to become effective November 5, 2023. When combined with the previously approved increase, the rate schedule would be set to recover $47 million. In October 2023, in response to discussions with the OPUC staff, PacifiCorp requested the effective date for the WMP AAC shift to December 13, 2023, to allow more time for the OPUC staff to review the filing.
In April 2023, PacifiCorp filed its transition adjustment mechanism ("TAM") requesting approval to update net power costs for 2024. The filing requested a rate increase of $164 million, or 9.5%, to become effective January
1, 2024. In July 2023, PacifiCorp updated its filing to reduce the requested rate increase to $131 million to reflect changes in PacifiCorp's forecast net power costs for 2024. In September 2023, a stipulation with certain intervening parties was filed settling substantially all issues in the 2024 TAM and in October 2023, the OPUC issued an order approving the stipulation. A final update to be filed in November 2023 will determine the rate increase effective January 1, 2024.
42
In May 2023, PacifiCorp filed its 2022 PCAM requesting recovery of the difference between actual power costs and base power costs established in the 2022 TAM. The filing requested recovery of $131 million, which
PacifiCorp proposed to recover over a two-year period with interest, resulting in a rate increase of $69 million, or 4.0%, effective January 1, 2024. In October 2023, a stipulation was filed providing for the requested amounts. As established in the stipulation, if the combined January 1, 2024 rate increase for residential customers from all January 1 rate changes is greater than 15%, PacifiCorp will delay the rate effective date of the 2022 PCAM for residential customers to April 1, 2024.
Wyoming
In March 2023, PacifiCorp filed a general rate case requesting a rate increase of $140 million, or 21.6%, to become effective January
1, 2024. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities. In September 2023, PacifiCorp filed updated testimony that included updated net power costs and increased insurance premium costs associated with wildfire liability coverage. As a result of the updates, the requested rate increase has been revised to $137 million, or 21.1%.
In April 2023, PacifiCorp filed its energy cost adjustment and renewable energy credit and sulfur dioxide revenue credit mechanisms to recover deferred net power costs from 2022. The combined filing requested a rate increase of $49 million, or 7.4%, which was effective on an interim basis July 1, 2023. In October 2023, PacifiCorp filed rebuttal testimony updating the energy cost adjustment
mechanism calculation. As a result of the updates, the requested combined rate increase has been revised to $42 million, or 6.3%, to be effective at the time of a Wyoming Public Service Commission order or February 15, 2024, whichever date comes first.
Washington
In March 2023, PacifiCorp filed a general rate case requesting a two-year rate plan with a rate increase of $27 million, or 6.6%, to become effective March 1, 2024, and a second rate increase of $28 million, or 6.5%, to become effective March 1, 2025. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered
generating facilities. In October 2023, PacifiCorp filed updated testimony that included updated net power costs, increased insurance premium costs and removal of some capital projects. As a result of the updates, the requested rate increases have been revised to $19 million, or 4.6%, to become effective March 1, 2024, and $22 million, or 5.2%, to become effective March 1, 2025.
In June 2023, PacifiCorp filed its PCAM to recover deferred net power costs from 2022. The filing requested recovery of over $71 million, which PacifiCorp proposed to recover over a two-year period with interest, resulting in a rate increase of $37 million, or 9.5%, to become effective January 1, 2024.
Idaho
In
October 2022, PacifiCorp filed an application for authority to implement the residential rate modernization plan. The plan proposes a five-year transition to increase the monthly customer service charge from $8.00 to $29.25 per month with a corresponding reduction to the energy rate, eliminates the tiered rates, and adjusts the on-peak off-peak period for time-of-day customers. In response to concerns about the combined impact of the proposed changes, PacifiCorp proposed a modification to, rather than elimination of, the tiered rates. In May 2023, the IPUC issued an order approving PacifiCorp's request to increase the customer service charge over five years, to adjust peak periods for time-of-day customers, and to modify the tiered rate structure. The changes to the residential rates became effective June 1, 2023.
California
In
May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to establish a memorandum account to track the change in rates beginning January 1, 2023, until the new rates become effective upon the issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in February 2023 with a slight adjustment of an overall rate increase of $27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling requesting additional information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum accounts. In March 2023, the CPUC split the general rate case into two tracks. The first track addresses the general rate case with an expected decision
from the CPUC in late 2023, and the second track addresses the wildfire memorandum accounts with a decision expected in late 2024. In October 2023, PacifiCorp filed updated testimony in the first track that removed the costs considered in the second track, as directed by the CPUC. The updated testimony clarified that the rate increase for the first track is $22 million, or 20.1%.
43
In September 2023, PacifiCorp filed its 2024 combined energy cost adjustment clause ("ECAC") and greenhouse gas related costs ("GHG") application requesting an overall rate increase of $30 million, or 25.0%, effective March 1, 2024. Approximately $36 million of the increase is attributed to the
ECAC rate, which is offset by $6 million decrease to the GHG rate.
Deferral Accounting Treatment for Increased Costs Associated with Wildfires
In June 2023, PacifiCorp filed deferral applications with the UPSC, the OPUC, the Wyoming Public Service Commission, the WUTC and the IPUC to track the costs associated with third-party liability from litigation due to the 2020 Wildfires. The deferred accounting applications enable PacifiCorp to preserve its ability to seek recovery in the future in the event the outcome could potentially impact its financial stability. The applications state that PacifiCorp is not seeking recovery of these costs from customers at this time and does not expect to determine if it will seek recovery until the appeals process has concluded. In August 2023, PacifiCorp filed a motion
to withdraw without prejudice with the UPSC, and in September 2023, PacifiCorp filed a notice of withdrawal without prejudice with the IPUC. These filings preserve the ability of PacifiCorp to file for deferred accounting treatment when the actual liability costs are more certain.
In June 2023, PacifiCorp filed an application with the CPUC for authority to establish a Wildfire Expense Memorandum Account to track the costs associated with third-party liability from litigation due to the 2020 Wildfires, increased insurance premium costs associated with wildfire coverage and costs associated with potential liability for future catastrophic wildfires.
In August 2023, PacifiCorp filed deferral applications with the UPSC, the OPUC, the WUTC and the IPUC for costs associated with increased insurance premium
costs arising from the impacts to the commercial insurance markets that have occurred due to wildfire liability risk.
MidAmerican Energy
Iowa
In June 2023, MidAmerican Energy filed a request with the IUB for an increase in its Iowa retail natural gas rates, which would increase revenue by $39 million annually. If approved, the requested rates would increase retail customer's bills by an average of 6.1%. Interim rates of $31 million annually, or an average increase to customer's bills of 4.8%, were effective in June 2023. On September 6, 2023, the IUB issued a procedural schedule with hearing set to begin on January 9, 2024.
South
Dakota
In May 2022, MidAmerican Energy filed a request with the South Dakota Public Utilities Commission ("SDPUC") for a $7 million, or 6.4%, annual increase in South Dakota retail natural gas rates. In March 2023, MidAmerican Energy filed a settlement agreement between all parties allowing a total increase of $6 million, or 5.5%, annual increase in South Dakota retail natural gas rates, upon completion of the capital investment phase-in adjustment clause. On March 31, 2023, the SDPUC issued an order approving the settlement agreement with final rates effective April 1, 2023.
44
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 Wind PRIME generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind generation and nearly 200 MWs of solar generation. Wind PRIME is projected to allow MidAmerican Energy to generate renewable energy greater than or equal to all of its Iowa retail customers' annual energy needs. MidAmerican Energy expects to be eligible for 100% PTCs under current tax law for the Wind PRIME projects. In December 2022, MidAmerican Energy, the Iowa Office of Consumer Advocate and the Iowa Business Energy Coalition filed a non-unanimous settlement with the IUB. On April
27, 2023, the IUB issued its final order regarding the application and found that MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application, but rejected the settlement and proposed its own principles for the project. MidAmerican Energy reviewed the order and filed a motion for reconsideration or rehearing on May 17, 2023. On June 15, 2023, the IUB granted the motion for reconsideration and rehearing. On July 14, 2023 the IUB issued a new procedural schedule and set rehearing for October 10, 2023. In August 2023, MidAmerican Energy, the Iowa Office of Consumer Advocate and the Environmental Intervenors filed a revised non-unanimous settlement with the IUB that included a rate of return of 10.75%. The settlement
would also benefit customers by providing a rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. On October 10, 2023, the IUB completed the rehearing. MidAmerican Energy expects the IUB to issue an order on the revised non-unanimous settlement by the end of 2023.
45
Iowa Transmission Legislation
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning
authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law provides MidAmerican Energy, as an incumbent electric transmission owner, the legal right to construct, own and maintain transmission lines in MidAmerican Energy's service territory that have been approved by the MISO (or another federally registered planning authority) and are eligible to receive regional cost allocation. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for the construction of eligible electric transmission lines that it intends to construct, own and maintain. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of
the cost to construct the eligible electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the eligible electric transmission line. In October 2020, national transmission interests filed a lawsuit that challenged the law on state constitutional grounds. The suit argues that the law was enacted in violation of the "single-subject" provision of Iowa's state constitution because it was "log-rolled" into a late session appropriations bill and violates the equal protection provision of the Iowa constitution. The State of Iowa defended the law, and MidAmerican Energy and ITC Midwest both intervened and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of standing, and the national transmission interests appealed. In June 2022, the Iowa Court of Appeals upheld the district court's decision, after which the national transmission interests asked the
Iowa Supreme Court to reconsider. In November 2022, the Iowa Supreme Court granted the motion to reconsider. On March 24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower courts, held the national transmission interests had standing, and remanded the case to the district court to consider the state constitutional claims on their merits. The opinion also imposed a temporary injunction that stayed enforcement of the law pending a decision on the merits. On April 7, 2023, the State of Iowa, acting individually, and MidAmerican Energy and ITC Midwest, acting jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19, 2023, the national transmission interests filed a reply that (1) expressed its opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to hold that
the injunction specifically applied to and precluded advancement of MidAmerican Energy's Long Range Transmission Projects ("LRTP") Tranche 1 projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on the constitutional claims on the merits without further briefing or argument. On April 26, 2023, the Iowa Supreme Court issued an order that denied the petitions for rehearing without comment and made minor, non-substantive changes to the decision, with no changes to the injunction. On May 30, 2023, the Iowa Supreme Court remanded the case to the district court for further proceedings on the merits, where the national transmission interests have filed a motion for summary judgment. The State of Iowa, MidAmerican Energy and ITC Midwest collaborated to resist the motion and submit a cross motion for summary judgment. The Iowa district court held a
hearing on the motions for summary judgment on September 29, 2023, and asked the parties to file draft orders addressing remedies should the court determine the statute is invalid. In October 2023, all parties filed the draft orders addressing remedies that were requested by the Iowa district court. A decision is expected by late November 2023. To this point, MISO has taken no action to reverse or disrupt its approval of MidAmerican Energy's LRTP Tranche 1 projects. This matter only potentially affects the manner in which MidAmerican Energy would secure the right to construct transmission lines that are eligible for regional cost allocation and are otherwise subject to competitive bidding under the MISO tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing rights to construct any other transmission lines, including lines required to serve new or expanded retail load, connect new generators or
meet reliability criteria.
NV Energy (Nevada Power and Sierra Pacific)
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, all parties to the proceedings relating to the joint application entered into a Stipulation to delay the procedural schedule. The Nevada Utilities made a supplemental filing on December
30, 2022. In March 2023, the proceedings relating to the joint application were postponed to May 2023. In April 2023, the Nevada Utilities filed a notice with the PUCN requesting to withdraw the joint application to merge into a single corporate entity and vacate the current procedural schedule, and executed a termination of the related merger agreement. In May 2023, the PUCN issued an order vacating the procedural schedules and hearing.
46
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 proposed 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. In March 2023, the PUCN issued an order approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on the program management and contingency budget amounts. The unapproved programs have been deferred for approval in future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs. In April 2023, interveners filed a petition for reconsideration of the PUCN's March 2023 Order. In May 2023, the PUCN granted in part and denied in part the petition for reconsideration and affirmed
the March 2023 Order.
Deferred Energy Accounting Adjustment Rate
In May 2023, the Nevada Utilities filed an application with the PUCN for approval to adjust the DEAA rates in excess of the maximum allowable adjustment to provide a discounted rate to customers effective July 1, 2023. In June 2023, the Nevada Utilities filed a stipulation signed by interveners that resolved all matters in the dockets opened for the application. In June 2023, the PUCN accepted the stipulation and granted the application as modified. The rate reduction for customers was effective July 1, 2023. In August 2023, the Nevada Utilities' filed a notice to implement quarterly changes to the BTER and DEAA rates within the maximum allowable
adjustment returning to an ordinary level of adjustment. In October 2023, the PUCN approved the BTER and DEAA rates effective October 1, 2023.
Regulatory Rate Review
In June 2023, Nevada Power filed a regulatory rate review with the PUCN that requested an annual revenue increase of $93 million, or 3.3%. In addition, a filing was made to revise depreciation rates based on a study, the results of which are reflected in the proposed revenue requirements. An order is expected by the end of 2023 and, if approved, would be effective January 1, 2024. In August, 2023, Nevada Power filed an updated certification filing that requested an annual revenue increase of $96 million, or 3.3%. Parties to the review filed
testimony and evidence in August and September 2023. Hearings in the cost of capital and revenue requirement phases were held in October 2023. The hearings in the rate design phase are scheduled for November 2023. An order is expected by the end of 2023 and, if approved, rates would be effective January 1, 2024.
Northern Powergrid Distribution Companies
Ofgem has completed the price control review that resulted in a new price control effective April 1, 2023. The license modifications that give effect to the price control were published by Ofgem on February 3, 2023, and were subject to appeal to the Competition and Markets Authority ("CMA") if an appeal was
filed by March 3, 2023. On March 2, 2023, Northern Powergrid sought permission from the CMA to appeal against the license modifications that give effect to the RIIO-ED2 price control. The appeal relates to two specific areas:
•Ofgem's misallocation of allowances that is inconsistent with efficient costs; and
•Ofgem's approach to determine rewards for the Business Plan Incentive.
The permission for the appeal was granted by the CMA, which confirmed its Final Determination on September 21, 2023. The CMA upheld Northern Powergrid's appeal in relation to Ofgem's misallocation of allowances that is inconsistent with efficient costs. The CMA found
that GEMA's decision was unlawful on the grounds of irrationality. The CMA has remitted the matter back to Ofgem to determine and implement a remedy, with the result having the potential to increase Northern Powergrid's cost allowances for the period April 2023 to March 2028 up to Ł160 million in 2020/21 prices. Ofgem successfully defended its decision not to grant Northern Powergrid a reward under its Business Plan Incentive mechanism.
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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 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 transmission 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, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation
expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 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 and storage reservation rates. In January 2023, the FERC approved Northern Natural Gas filing to implement its interim rates effective January 1, 2023, subject to refund and the outcome of hearing procedures. In June 2023, a settlement agreement was filed with the FERC resolving all pending issues in the rate case and providing for increased service rates and increased depreciation rates for onshore transmission plant from 2.30% to 2.49%. Market Area transportation reservation rates increased 32.5%, Field Area transportation reservation rates increased 20.5% and storage reservation rates increased 13.0% from the rates that were in effect in 2022. The settlement also provides for a Section 4 and Section 5 rate action moratorium through June 30, 2024, subject to certain
exceptions. The settlement rates were implemented May 1, 2023, and the Company's provision for rate refunds for January 2023 through April 2023, including accrued interest, totaled $92 million. In September 2023, the FERC approved the settlement agreement and the rate refunds to customers were processed in October 2023.
BHE Transmission
AltaLink
2024-2025 General Tariff Application
In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total transmission tariffs of C$902.3 million and C$908.6 million for 2024 and 2025, respectively. The application also requested the approval
to reinstate C$98.9 million cost of removal to rate base which was not previously approved, based on additional information filed.
In July 2023, AltaLink requested the AUC to suspend the schedule for its 2024-2025 GTA until August 31, 2023. AltaLink required the schedule delay to amend its application in response to the unprecedented wildfire events that AltaLink experienced in Alberta, Canada in May and June 2023. In August 2023, AltaLink filed an amendment to its 2024-2025 GTA. The amendment increased AltaLink's Wildfire Mitigation Plan capital expenditures from C$16.0 million to C$38.5 million in 2024 and from C$14.6 million to C$38.4 million for 2025. AltaLink's total amended transmission tariffs for 2024 and 2025 are C$903.5 million and C$911.9 million, respectively. AltaLink also plans to file an application with the AUC later this
year to recover all costs incurred as a result of the May and June 2023 wildfire events.
Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the 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 generic cost of capital proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial markets. In June 2022, the AUC initiated the second stage to explore a formula-based
approach to determine the return on equity for 2024 and future test periods.
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In February 2023, AltaLink and other stakeholders filed evidence. AltaLink filed expert evidence recommending a 10.3% return on equity, on a recommended equity ratio of 40%. Other utilities filed similar recommendations. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the Industrial Power Consumers Association of Alberta recommended returns on equity ranging from 6.75% to 7.7% and equity ratios ranging from 35% to 37%. AltaLink's expert witness, as well as all other utility experts, submitted that they are generally not in favor of implementing a formulaic adjustment mechanism for allowed return on equity due to the challenges in maintaining
the Fair Return Standard through formulaic adjustments. The interveners are generally in favor of a formula.
In October 2023, the AUC issued its decision on the Generic Cost of Capital for 2024 and beyond for Alberta's regulated electric and gas utilities, approving a set equity ratio and a formula to determine return on equity. The AUC set the deemed equity ratio at 37% and set a notional return on equity of 9.00%, which is subject to formulaic adjustments utilizing 30-year Government of Canada bond yields and Canadian utility spreads. In November 2023, the AUC will set and provide utilities with the approved return on equity for 2024 and will provide the same in November of each year going forward.
Environmental
Laws and Regulations
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many 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, 2022, and new environmental matters occurring in 2023.
Air Quality Regulations
The Clean Air Act, as well as state laws and regulations impacting air emissions, provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. These laws and regulations continue to be promulgated and implemented and will impact the operation of BHE's generating facilities and require them to reduce emissions at those facilities to comply with the requirements. In addition, the potential adoption of state or federal clean energy standards, which include low-carbon, non-carbon and renewable electricity generating
resources, may also impact electricity generators and natural gas providers.
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Greenhouse Gas Standards
In May 2023, the EPA proposed rules addressing greenhouse gas emissions from new and reconstructed natural gas-fueled combustion turbines (Clean Air Act Section 111(b) rule) and existing coal- and gas- or oil-fueled steam units and natural gas-fueled combustion turbines (Clean Air Act Section 111(d) rule). The proposed requirements for existing units would take effect January 1, 2030, through state implementation plans. Requirements for new combustion turbines are subcategorized based on capacity factor,
where low-load units would be required to meet an emissions limit, intermediate-load units would be required to use a blend of low-emitting hydrogen and natural gas and base-load units would be required to utilize carbon capture and sequestration technology or a high-percentage blend of low-emitting hydrogen. Requirements for existing gas- and oil-fueled steam units are also subcategorized based on capacity factor, where low-load units would be subject to routine maintenance to demonstrate no increase in emissions, intermediate-load units would be subject to an emission limit of 1,500 pounds of CO2 / MWh-gross and base-load units would be subject to an emission limit of 1,300 pounds of CO2 / MWh-gross. Control equipment requirements for existing combustion turbines only apply to large, high load turbines that are greater than 300MW in capacity and operate at a greater than
50% capacity factor. These units would be required to begin utilizing carbon capture and sequestration with a 90% capture rate by 2035 or use a blend of low-emitting hydrogen starting in 2032. Requirements for existing coal-fueled units are subcategorized based on retirement date. Units with earlier retirement dates would be subject to less stringent requirements while units that commit to later retirement dates would be subject to annual capacity factor limits or natural gas co-firing requirements. Units that will continue operating after December 31, 2039, would be required to utilize carbon capture and sequestration with a 90% carbon capture rate. Clean Air Act Section 111 establishes a cooperative approach between the EPA and the states. The EPA establishes nationwide standards based on the best system of emissions reductions it identifies for a source category. States are then expected to develop plans to implement those standards at affected units. States may adopt
the EPA's standards or develop state-specific standards that achieve the same air quality results. The EPA accepted comments on the proposal through August 8, 2023. The relevant Registrants operate facilities that may be affected by these proposals. Until the EPA takes final action on the proposals, the states submit any required SIPs and litigation is exhausted, the relevant Registrants cannot determine the impacts of the proposed rule.
Mercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16,
2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015, with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects and unit retirements to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014,
the U.S. Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. In June 2015, the U.S. Supreme Court reversed and remanded the MATS rule, finding that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. In December 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from generating facilities under Section 112; however, the EPA proposed to retain the emission standards and other requirements
of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled generating facilities from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding, which were stayed pending the EPA's plans to revisit the finding. On January 31, 2022, the EPA proposed several actions relating to the MATS. The EPA proposed to restore the appropriate and necessary finding to regulate generating facilities under Clean Air Act Section 112. The EPA finalized its restoration of the MATS appropriate and necessary finding in February 2023.
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On
April 5, 2023, the EPA released a proposal to revise several aspects of the MATS rule following the agency's review of the 2020 Residual Risk and Technology Review. The EPA proposes two specific standard changes - one applicable to all covered units and one specific to the existing lignite subcategory. The EPA proposes a more stringent standard for emissions of filterable particulate matter, the surrogate standard for non-mercury metals for coal-fueled electric generating units. The EPA proposes to reduce the filterable particulate matter emission standard by two-thirds based on a demonstration that 91% of coal-based capacity, which has not been identified as retiring before the proposed compliance period, has an emission rate at or below the proposed limit. The EPA also proposes to require continuous emissions monitoring for filterable particulate matter to demonstrate compliance with the revised standard. Compliance
would be due no later than three years after the effective date of a final rule and the EPA accepted comments on the proposal through June 23, 2023. The relevant Registrants are not included in the lignite subcategory. The relevant Registrants have identified that compliance can be achieved with existing controls. Until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.
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. In addition, the EPA must approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. On April 15, 2022 the EPA issued its final rule approving Iowa's SIP as meeting the good neighbor provisions for the 2015 ozone standard. On May 24, 2022, the EPA proposed to disapprove the Utah and Wyoming interstate ozone SIPs. On January
30, 2023, the EPA entered into a stipulated extension to the deadline for action on the Wyoming SIP, setting a new deadline of December 15, 2023. The EPA explained that the extra time is needed to fully consider updated air quality information and public comments. The EPA is also reevaluating SIPs for Tennessee and Arizona. On February 13, 2023, the EPA published final disapproval of the 19 SIPs proposed in April 2022, setting the stage to include those states in the federal implementation plan described under the Cross-State Air Pollution Rule. The EPA also deferred action on the SIPs for Wyoming, Tennessee and Arizona in the final rule. Separately, on March 28, 2022, the EPA proposed determinations as to whether certain areas have achieved levels of ground-level ozone pollution that meet the 2008 and 2015 ozone NAAQS.
Relevant to Registrants, the Southern Wasatch Front in Utah and Yuma, Arizona are proposed to have met the 2015 ozone standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch Front in Utah are proposed to have not met the 2015 ozone standard and to be reclassified as Moderate Non-Attainment, and 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.
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Cross-State Air Pollution Rule
The EPA promulgated an initial
rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern U.S. to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 Eastern and Midwestern states. In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key industry regulated by the rule and will be subject to emissions allowance trading beginning
in summer 2023. The final rule shifted the maximum daily backstop rate for coal-fueled generating units, which drives the installation of new controls or curtailment, to take effect in 2030 instead of 2027. PacifiCorp's Hunter Units 1-3 and Huntington Units 1-2, which do not have SCR controls, are impacted by the rule. PacifiCorp's 2023 IRP selected the installation of SNCR on the Hunter and Huntington Units by 2026 as part of the preferred portfolio. The level of NOx allowances for the Utah units remains similar to 2021 levels, with significant reductions for the coal units beginning in 2026. The daily limit, which takes effect in 2030, will further restrict operation of coal-fueled units without SCR. NV Energy's fossil-fueled units are also covered by the final rule. North Valmy Units 1 and 2, which do not have SCR, will require additional controls or reduced operations during the ozone season if operated beyond 2025.
Nevada's regional haze SIP has an enforceable retirement date for North Valmy Units 1 and 2 of December 31, 2028, and NV Energy's IRP identified a December 31, 2025, retirement date for the units. The EPA's updated modeling suggests that Arizona, Iowa and Kansas may be significantly contributing to nonattainment in downwind states. The EPA intends to undertake additional assessment of its modeling for these states and will determine if it is necessary to address obligations for these states in future actions. The EPA also deferred final action for Wyoming, pending further review of updated air quality and contribution modeling and analysis. Additional notice and comment rulemaking, such as a supplemental rule, would be required to rescind Iowa's approved SIP and incorporate additional states into the program. The states of Nevada, Utah and Wyoming challenged the EPA's
denials and deferral, respectively, of their interstate ozone transport SIPs in the Ninth, Tenth and D.C. Circuit. PacifiCorp also filed petitions with the court opposing the EPA's action in Utah and Wyoming. At the time of filing, at least 11 other states have challenged the EPA's action to disapprove SIPs in seven different regional federal courts of appeal. Stays have been granted by six circuit courts for SIP disapprovals in 12 states. Relevant to Registrants, the states of Nevada, Texas and Utah were granted stays. The final Good Neighbor Rule was published June 5, 2023 and took effect August 4, 2023. The EPA issued several interim final rules stating that the federal rule will not take effect in states in which the SIP disapprovals have been deferred or stayed. The EPA published its proposed approval of Wyoming's SIP on August
14, 2023 and accepted comments through September 13, 2023. In addition to litigation over SIP disapprovals, there are numerous appeals of the final Good Neighbor Rule pending in four different circuit courts, and at least four motions to stay the final rule have been filed in four different circuit courts. On September 25, 2023, the D.C. Circuit denied the motion to stay the Good Neighbor Rule filed by several state and industry parties. The denial means that states that do not have stays on their SIP disapprovals are subject to the Good Neighbor Rule. The states of Ohio, Indiana and West Virginia filed a request for stay of the Good Neighbor Rule with the U.S. Supreme Court on October 13, 2023. Several industry groups representing utilities as well as pipeline, paper, cement and other industries affected by the rule
filed supportive requests for stay on the same day. Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants cannot be determined.
For the first time, the EPA included additional sectors beyond the electric generation sector in the 2023 expanded CSAPR program. Relevant to the Registrants, this includes the pipeline transportation of natural gas. Requirements for that sector focus on emissions reductions from reciprocating internal combustion engines involved in the transport of natural gas and take effect in 2026. There is no access to allowance trading for the non-electric generation sectors. The EPA excluded emergency engines and engines that do not operate during the ozone season, included a facility-wide averaging plan and eased requirements for monitoring in the final rule. Northern Natural Gas operates 18 affected
units; BHE GT&S operates 157 affected units; and Kern River is not affected by the final rule.
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 periodic SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
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In
June 2019, the state of Utah incorporated a BART alternative into its SIP for regional haze planning period one. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA approved the SIP revision with the BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. The EPA defended the SIP, and PacifiCorp and the state of Utah intervened in the litigation in support of the EPA. Oral arguments in HEAL
Utah v. EPA were held March 21, 2023. On August 14, 2023, the Tenth Circuit denied the petition to vacate Utah's first planning period regional haze plan.
The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. The EPA's final action on other parts of the Wyoming SIP in 2014 approved the state's plan to have PacifiCorp install low-NOx
burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls by 2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental groups also filed an appeal of the EPA's final action. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak,
pending further action by the Tenth Circuit in the appeal. The parties worked to mediate claims under the Wyoming regional haze requirements until the abatement on litigation was lifted in September 2022. Opening briefs were submitted in October 2022. In the litigation, 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 Naughton Units 1 and 2 should have been subject to an SCR requirement. Oral argument was held May 16, 2023. PacifiCorp argued that the Naughton claims are moot but that a court ruling on the Wyodak claims is necessary because the EPA's federal plan complies with the Clean Air Act. On August 15, 2023, the Tenth Circuit remanded the Wyodak portion of Wyoming's state plan to EPA for further review. For
Naughton Units 1 and 2, the court determined EPA properly approved Wyoming's Naughton determination and denied environmental groups' petition. Separately, on February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree, PacifiCorp must convert Jim Bridger Units 1 and 2 to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. The EPA and PacifiCorp executed an administrative order on consent June
9, 2022, covering compliance for Jim Bridger Units 1 and 2 under the regional haze rule. The federal order contains the same emission and operating limits as the Wyoming consent decree and adds federal approval of the compliance pathway outlined in the state consent decree, including revision of the SIP to include conversion of Jim Bridger Units 1 and 2 to natural gas. On December 30, 2022, the Wyoming Air Quality Division submitted the state-approved revised regional haze SIP requiring natural gas conversion of Jim Bridger Units 1 and 2 to the EPA for approval. The plan revision replaces a previous requirement for SCR at the units. The Wyoming Air Quality Division also issued an air permit for the natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. PacifiCorp submitted a notice of compliance to the EPA on March
9, 2023, to certify completion of the Jim Bridger administrative compliance order through completion of the requirements to comply with Wyoming's consent decree and revised SIP submission. PacifiCorp remains subject to the compliance terms of the Wyoming consent decree as it works to convert Jim Bridger Units 1 and 2 to natural gas. The EPA is in on-going discussions with Wyoming to finalize a determination on the SIP revisions, with a decision anticipated by the end of 2023.
The state of Colorado first planning period regional haze SIP requires SCR equipment at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are in-service. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to
require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021, with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in its 2023
IRP.
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Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA and received completeness determinations in August 2022. The EPA has not yet made determinations on these plans. It was required to make final determinations on the SIPs by August 2023. On August 25, 2022, the EPA promulgated a finding of failure to submit a SIP for the regional haze second planning period for 15 states, including Iowa. The finding establishes a two-year deadline for the agency to promulgate FIPs to address the requirements, unless prior to promulgating a FIP, the state submits, and the agency approves, a SIP meeting the requirements. The finding says
the agency intends to continue to work with states in developing approvable SIP submittals in a timely manner. The Iowa Department of Natural Resources continues to work with the EPA on development of its SIP. On February 13, 2023, Iowa issued a draft SIP and accepted comment on the draft plan through March 16, 2023. Iowa proposes to require operational improvements to existing control equipment at MidAmerican Energy's Louisa Generation Station and Walter Scott Jr. Energy Center - Unit 3. Iowa anticipates submitting a final plan to the EPA in fall 2023.
Water Quality Standards
In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating
sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. In November 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule took effect in December 2020. The final rule changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport water, revises the voluntary incentives program for flue gas desulfurization wastewater, and adds subcategories for high-flow units, low utilization units, and those that will transition away from coal combustion by 2028. While most of the issues raised by this rule are already being addressed through the CCR rule and are not expected to impose significant additional requirements, the Dave Johnston generating facility is impacted by the rule's bottom ash handling requirements at Units
1 and 2. The generating facility submitted notice to the Wyoming Department of Environmental Quality that it will either achieve a cessation of coal combustion at Units 1 and 2 by December 31, 2028, or install bottom ash transport treatment technology by December 31, 2025. On March 8, 2023, the EPA proposed additional changes to the effluent limitations guidelines to replace the 2020 rule and provide stricter limits for bottom ash transport water, flue gas desulfurization wastewater and coal combustion residual leachate. The relevant Registrants use a combination of zero discharge, enrollment in cessation-of-coal subcategory and dry bottom ash handling to manage the affected wastestreams. As a result, significant impacts are not anticipated. However, until the EPA takes final action on the proposal, the full impacts of
the rule cannot be determined. The EPA accepted public comments through May 30, 2023, and intends to finalize a rule by spring 2024.
In March 2023, the latest changes to the definition of "waters of the U.S.," a rule that determines which waters are regulated under the federal Clean Water Act, took effect. Under this rule, tributaries, many wetlands, intrastate lakes, intrastate ponds, intrastate streams and some impoundments must meet either test from the 2006 Rapanos plurality decision to be considered a water of the U.S. That is, a water must be relatively permanent and have a continuous surface connection to an included waterbody (the "relatively permanent" test) or it must significantly affect the biological, physical or chemical integrity of a traditional navigable water,
territorial seas or interstate waters (the "significant nexus" test). The rule was challenged in multiple courts. On May 23, 2023, the U.S. Supreme Court issued a decision in Sackett v. EPA, a case that challenged the Clean Water Act's applicability to certain wetlands. In its decision, the U.S. Supreme Court significantly narrowed protections for wetlands and intermittent streams under the federal Clean Water Act. The U.S. Supreme Court unanimously rejected the significant nexus test as unworkable. A divided U.S. Supreme Court determined that jurisdiction applies to waters that are adjacent to traditional interstate navigable waters and that have a continuous surface connection with that traditional interstate navigable waters. In light of the Sackett decision, the EPA secured stays of litigation over its definitional
rule in two of three pending challenges in order to conduct rulemaking to conform to the U.S. Supreme Court's decision. On September 8, 2023, the EPA issued a new rule conforming to the U.S. Supreme Court's decision.
Coal Ash Disposal
In April 2015, the EPA released a final rule to regulate the management and disposal of coal combustion residuals (CCR) under the RCRA. The rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts will need to be closed unless they can meet the more stringent regulatory requirements.
54
At
the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed
or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017, and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated 10 evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.
Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit, resulting in settlement
of some of the issues and subsequent regulatory action by the EPA. The EPA finalized the first phase of the CCR rule amendments in July 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted the EPA's request to remand the rule and left the October 31, 2020, deadline in place while the agency undertakes a new rulemaking
establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 rule has not been finalized. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of 2016. The federal permit rule has not been finalized.
In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking comment on and information related to issues relevant to development of regulations for legacy impoundments. On May 18, 2023, the EPA proposed the legacy surface impoundments rule and accepted comment on
the proposal through July 17, 2023. The proposal encompasses legacy surface impoundments, which are inactive surface impoundments at inactive facilities; and CCR management units, which include CCR surface impoundments and landfills that closed prior to October 19, 2015, inactive CCR landfills, and other areas where CCR has been or is managed directly on the land. CCR management units include all units meeting that definition at active CCR facilities, as well as those at inactive facilities with one or more legacy surface impoundment. EPA proposes the impose substantially the same regulatory obligations for both legacy surface impoundments and CCR management units as are applicable to currently regulated units, including groundwater monitoring and corrective action. All legacy surface impoundments and CCR management units would be required to initiate closure, including
reclosure, within one year after the rule is finalized. The EPA has indicated it intends to finalize the legacy surface impoundment rule by spring 2024.
The EPA includes lists of potential legacy surface impoundments and CCR management units in the rulemaking docket and those lists include several BHE facilities. The EPA also specifically identifies PacifiCorp's Huntington Power Plant and NV Energy's Reid Gardner Generating Station as potential CCR management unit damage cases based on the EPA's review of compliance information. BHE corrected the record in comments that: (1) The north and south ash ponds at MidAmerican's Riverside Generating Station are incorrectly classified as legacy impoundments rather than CCR management units; (2) historical impoundments, which were closed according to state requirements and no longer contain CCR or liquids, should be removed from the list of CCR
management units; (3) the EPA erroneously identified NV Energy's Reid Gardner Generating Station and the Old Landfill at PacifiCorp's Huntington generating facility as potential damage cases; and (4) two impoundments at PacifiCorp's former Carbon generating facility are incorrectly included on the list of legacy impoundments because PacifiCorp never managed or disposed of CCR materials in wastewater ponds at the former Carbon generating facility.
Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.
55
In August 2020, the EPA finalized its Holistic Approach to Closure: Part A
rule ("Part A rule"). This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule established a new deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure. The Part A rule also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023; and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and complete ash pond closure activities by October 17, 2028. PacifiCorp developed a demonstration for the development of alternative capacity for the Jim Bridger facility's FGD Pond 2 and a demonstration for closure of the Naughton facility and ash pond and submitted them to the
EPA in November 2020. On January 11, 2022, the EPA deemed these submittals complete but has not taken additional action on them. No other Registrants used the provisions of the Part A rule.
Notwithstanding the status of the final CCR rule, citizens' suits have been filed against regulated entities seeking judicial relief for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately released or connected to surface water. In addition, actions have been filed against regulated entities seeking to require that surface impoundments containing CCR be subject to closure by removal rather than being allowed to effectuate closure in place as provided under the final rule.
The Registrants are not a party to these lawsuits and until they are resolved, the Registrants cannot predict the impact on overall compliance obligations.
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, 2022. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2022.
56
PacifiCorp and its subsidiaries
Consolidated
Financial Section
57
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, 2023, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flowsfor the nine-month periods ended September 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, 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 (loss) income to net cash flows from operating activities:
Depreciation and amortization
i843
i836
Allowance
for equity funds
(i101)
(i47)
Net
power cost deferrals
(i578)
(i262)
Amortization of net power cost deferrals
i156
i67
Other
changes in regulatory assets and liabilities
(i101)
(i90)
Deferred
income taxes and amortization of investment tax credits
(i320)
i48
Other,
net
i1
i15
Changes in other operating assets and liabilities:
Trade
receivables, other receivables and other assets
(i133)
(i47)
Inventories
(i45)
i3
Derivative
collateral, net
(i87)
i28
Prepaid
expenses
(i56)
(i25)
Accrued
property, income and other taxes, net
i165
i180
Accounts
payable and other liabilities
i392
i361
Wildfires
insurance receivable
(i257)
(i161)
Wildfires
liability
i1,854
i225
Net
cash flows from operating activities
i1,067
i1,752
Cash
flows from investing activities:
Capital expenditures
(i2,250)
(i1,481)
Other,
net
i5
i4
Net
cash flows from investing activities
(i2,245)
(i1,477)
Cash
flows from financing activities:
Proceeds from long-term debt
i1,189
i—
Repayments
of long-term debt
(i401)
(i104)
Proceeds from short-term debt
i165
i—
Dividends
paid
(i300)
(i100)
Other, net
(i4)
(i2)
Net
cash flows from financing activities
i649
(i206)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i529)
i69
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i674
i186
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i145
$
i255
The
accompanying notes are an integral part of these consolidated financial statements.
63
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, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income (Loss) have been omitted as net income (loss) materially equals comprehensive income (loss) for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 30,
2023, 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, 2022, 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, 2023, other than the updates associated with PacifiCorp's estimates of loss contingencies related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and a wildfire that began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California in July 2022 (the "2022 McKinney Fire"), referred to together as "the Wildfires" as discussed in Note 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. iA
reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Restricted
cash and cash equivalents included in other current assets
i11
i7
Restricted
cash included in other assets
i36
i26
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i145
$
i674
64
(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
2023
2022
Utility plant:
Generation
i15
- i59 years
$
i13,814
$
i13,726
Transmission
i60
- i90 years
i8,140
i8,051
Distribution
i20
- i75 years
i8,840
i8,477
Intangible
plant(1) and other
i5 - i75 years
i2,810
i2,755
Utility
plant in-service
i33,604
i33,009
Accumulated
depreciation and amortization
(i11,649)
(i11,093)
Utility
plant in-service, net
i21,955
i21,916
Nonregulated,
net of accumulated depreciation and amortization
i14 - i95 years
i18
i18
i21,973
i21,934
Construction
work-in-progress
i4,126
i2,496
Property,
plant and equipment, net
$
i26,099
$
i24,430
(1)Computer
software costs included in intangible plant are initially assigned a depreciable life of i5 to i10 years.
/
(4) iRecent
Financing Transactions
Long-Term Debt
In May 2023, PacifiCorp issued $i1.2 billion of its i5.50%
First Mortgage Bonds due May 2054. PacifiCorp intends, within i24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.
Credit Facilities
In June 2023, PacifiCorp amended its existing $i1.2 billion
unsecured credit facility expiring in June 2025. The amendment increased the lender commitment to $i2.0 billion and extended the expiration date to June 2026. Additionally, in June 2023, PacifiCorp terminated its existing $i800 million
i364-day unsecured credit facility expiring in January 2024.
Common Shareholders' Equity
In January 2023, PacifiCorp declared a common stock dividend of $i300 million, paid in February 2023, to
PPW Holdings LLC.
(5) iIncome Taxes
The effective income tax rate for the three-month period ended September 30, 2023, is i35%
and results from a $i345 million income tax benefit associated with a $i997 million
pre-tax loss, primarily related to increases in wildfire loss accruals, net of expected insurance recoveries of $i1,263 million as described in Note 9. The $i345 million income tax benefit is primarily comprised of a $i210 million
benefit (i21%) from the application of the federal statutory income tax rate to the pre-tax loss, a $i64 million benefit (i6%)
from federal income tax credits, a $i37 million benefit (i4%) from state income tax and a $i36 million
benefit (i4%) from effects of ratemaking.
65
The effective income tax rate for the nine-month period ended September 30, 2023 is i42%
and results from a $i485 million income tax benefit associated with a $i1,151 million
pre-tax loss, primarily related to increases in wildfire loss accruals, net of expected insurance recoveries of $i1,671 million as described in Note 9. The $i485 million income tax benefit is primarily comprised of a $i242 million
benefit (i21%) from the application of the federal statutory income tax rate to the pre-tax loss, a $i119 million benefit (i10%)
from federal income tax credits, a $i70 million benefit (i6%) from effects of ratemaking and a $i44 million
benefit (i4%) from state income tax.
i
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income
(loss) before income tax expense (benefit) is as follows:
State
income tax, net of federal income tax benefit
i4
i4
i4
i4
Federal
income tax credits
i6
(i22)
i10
(i22)
Effects
of ratemaking(1)
i4
(i13)
i6
(i12)
Valuation
allowance
i—
i—
i1
i1
Other
i—
i—
i—
i1
Effective
income tax rate
i35
%
(i10)
%
i42
%
(i7)
%
(1)Effects
of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
/
Income tax credits relate primarily to production tax credits ("PTC") 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 three-month periods ended September 30, 2023 and 2022, totaled $i64 million and $i83 million,
respectively. PTCs recognized for the nine-month periods ended September 30, 2023 and 2022, totaled $i119 million and $i127 million,
respectively.
For the nine-month period ended September 30, 2023, PacifiCorp released an $i11 million valuation allowance related to state net operating loss carryforwards. For the nine-month period ended September 30, 2022, PacifiCorp recorded an $i8 million
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, 2023 and 2022, PacifiCorp received net cash payments for federal and state income tax from BHE totaling $i255 million
and $i194 million, respectively. As of September 30, 2023, net income taxes payable to BHE were $i12 million. As of December 31,
2022, net income taxes receivable from BHE were $i84 million.
66
(6) iEmployee
Benefit Plans
i
Net periodic benefit cost (credit) 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 on 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 2023. As of September 30, 2023, $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.
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.
67
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, 2023, a regulatory liability of $i50 million was recorded related to the net derivative asset of $i50 million.
As of December 31, 2022, a regulatory liability of $i270 million was recorded related to the net derivative asset of $i270 million.
(2)As
of December 31, 2022, PacifiCorp had an additional $i12 million cash collateral payable that was not required to be netted against total derivatives.
/
i
The
following table reconciles the beginning and ending balances of PacifiCorp's net regulatory (liabilities) assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory (liabilities) assets, as well as amounts reclassified to earnings (in millions):
Changes
in fair value recognized in regulatory (liabilities) assets
(i9)
(i79)
i83
(i296)
Net
gains (losses) reclassified to operating revenue
i—
i7
(i8)
(i4)
Net
(losses) gains reclassified to energy costs
(i32)
i129
i145
i187
Ending
balance
$
(i50)
$
(i166)
$
(i50)
$
(i166)
/
68
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
2023
2022
Electricity purchases, net
Megawatt hours
i2
i2
Natural
gas purchases
Decatherms
i126
i127
/
Credit
Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains
third‑party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features"). These agreements and other agreements that do not refer to specified
rating-dependent threshold levels may provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2023, PacifiCorp's issuer credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $i32 million
and $i48 million as of September 30, 2023 and December 31, 2022, respectively, for which PacifiCorp had posted collateral of $i5 million
and $i— million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2023 and December 31, 2022, PacifiCorp would have been required to post $i7 million
and $i3 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(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).
69
•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 $i3 million and $i78 million
as of September 30, 2023 and December 31, 2022, respectively. As of December 31, 2022, PacifiCorp had an additional $i12 million cash collateral payable that was not required to be netted against total derivatives.
/
Derivative
contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. A discounted cash flow valuation method was used to estimate fair value. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent
energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness
and duration of contracts. Refer to Note 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.
70
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):
PacifiCorp has the following firm commitments that are not reflected on the Consolidated Balance Sheets.
Construction Commitments
During the nine-month period ended September 30, 2023, PacifiCorp entered into build transfer agreements totaling $i1.2 billion
through 2025 for the construction of certain wind-powered generating facilities in Wyoming.
Fuel Contracts
During the nine-month period ended September 30, 2023, PacifiCorp entered into certain coal supply agreements totaling $i425 million through 2025.
Environmental Laws and Regulations
PacifiCorp
is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, wildfire prevention and mitigation and other environmental matters that have the potential to impact its current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Lower Klamath Hydroelectric Project
In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns
the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility began in June 2023, and removal of the remaining ithree dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has $i450 million
in funding available for dam removal and restoration; $i200 million collected from PacifiCorp's Oregon and California customers and $i250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may
occur above the initial $i450 million in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $i45 million contingency fund and equally share any
additional costs above that amount to ensure dam removal and restoration is complete.
Legal Matters
PacifiCorp is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may seek to impose fines, penalties and other costs.
71
Pursuant to Accounting Standards Codification Topic 450, Contingencies, a provision
for a loss contingency is recorded when it is probable a liability is likely to occur and the amount of loss can be reasonably estimated. PacifiCorp evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.
Wildfires Overview
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements
that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could be found liable for all damages.
2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln
County, Oregon; and Klamath County, Oregon, burning over i500,000 acres in aggregate. Third-party reports for these wildfires indicate over i2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.
Investigations
into the cause and origin of each wildfire are complex and ongoing and have been or are being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, numerous lawsuits on behalf of plaintiffs related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint in Oregon for which the jury issued a verdict for the i17
named plaintiffs in June 2023 as described below. The plaintiffs seek damages for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. Additionally, certain governmental agencies have informed PacifiCorp that they are contemplating filing actions in connection with certain of the Oregon 2020 Wildfires. Amounts sought in the lawsuits, complaints and demands filed in Oregon and in certain demands made in California total nearly $i8 billion,
excluding any doubling or trebling of damages included in the complaints. Generally, the lawsuits and complaints filed in California do not specify damages sought and are excluded from this amount.
72
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon (the "James case"). The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020,
by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain Complex, South Obenchain and 242 wildfires. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated the James case with several other cases. While PacifiCorp's pre-trial request for immediate appeal of the class certification was denied, it will have the opportunity to appeal the class issues post-judgment. In April 2023, the jury trial for the James case with respect to i17
named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the i17 individual plaintiffs and to the class with respect to the ifour wildfires. The jury awarded the i17
named plaintiffs $i90 million of damages, including $i4 million of economic and property damages, $i68 million
of noneconomic damages and $i18 million of punitive damages based on a i0.25 multiplier of the economic and noneconomic damages. In September 2023, the Multnomah County Circuit Court ordered trial dates for itwo
consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the ithree trials will present evidence regarding their damages. The trials are scheduled at various dates from January to April 2024. A fourth jury trial is scheduled in May 2024 relating to certain nonclass plaintiffs associated with the Echo Mountain Complex fire. Hearings on PacifiCorp's post-trial motions are scheduled to be held November 9, 2023. Under ORS 82.010, interest at a rate of 9% per annum will accrue on the
judgment commencing at the date the judgment is entered unless otherwise specified in the judgment. No judgment has yet been entered by the Multnomah County Circuit Court. PacifiCorp intends to appeal the jury's findings and damage awards in the James case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.
Based on available information to date, PacifiCorp believes it is probable that losses will be incurred associated with the 2020 Wildfires. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.
2022 McKinney Fire
According
to the California Department of Forestry and Fire Protection, on July 29, 2022, the 2022 McKinney Fire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California located in PacifiCorp's service territory. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and four fatalities and consumed 60,000 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service, the California Public Utilities Commission, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages for economic losses, noneconomic losses, including
mental suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees, but the amount of damages sought is not specified.
PacifiCorp had previously not considered a loss probable related to the 2022 McKinney Fire; however, based on available information to date, PacifiCorp now believes it is probable a loss will be incurred associated with the 2022 McKinney Fire. Final determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar processes.
Estimated Losses for the Wildfires
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, including (i) ongoing cause and origin
investigations; (ii) ongoing settlement and mediation discussions; (iii) other litigation matters and upcoming legal proceedings; and (iv) the status of the James case, PacifiCorp increased its accrual by $i1,387 million during the three-month period ended September 30, 2023, bringing its cumulative estimated probable losses associated with the Wildfires to $i2,405 million
through September 30, 2023. PacifiCorp's cumulative accrual includes estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages and noneconomic damages such as personal injury damages and loss of life damages that it is reasonably able to estimate at this time and which is subject to change as additional relevant information becomes available.
73
i
The
following table presents changes in PacifiCorp's liability for estimated losses associated with the Wildfires (in millions):
Until
such time that settlement terms or other conclusions are reached to indicate that payments are expected to occur in the short-term, PacifiCorp's liability for estimated losses associated with the Wildfires is classified as a noncurrent liability on the Consolidated Balance Sheets.
PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $i503 million and $i246 million,
respectively, as of September 30, 2023 and December 31, 2022, and is included in Other assets on the Consolidated Balance Sheets. During the three- and nine-month periods ended September 30, 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $i1,263 million and $i1,671 million,
respectively. During the three- and nine-month periods ended September 30, 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the Wildfires of $i— million and $i64 million,
respectively. No additional insurance recoveries beyond those accrued to date are expected to be available.
It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued for the Wildfires that could have a material adverse effect on PacifiCorp's financial condition. PacifiCorp is currently unable to reasonably estimate a specific range of possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the class to the James case, the variation in the types of properties and damages and the ultimate outcome of legal actions.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and
the sale or transfer of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.
(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 2023 and 2022
Overview
Net loss for the third quarter of 2023 was $652 million, a decrease of $1,061 million compared to 2022 net income of $409 million. The decrease in net income was primarily due to an increase in estimated losses of $1,263 million associated with the 2020 Wildfires and the 2022 McKinney Fire, net of expected insurance recoveries, higher operations and maintenance expense and lower utility margin, partially offset by higher income tax benefit. Utility margin decreased $42 million primarily due to higher purchased electricity costs from higher prices and volumes, higher coal-fueled generation prices, lower retail revenue volumes, lower wholesale revenue volumes and prices, lower wheeling revenue and lower gas-fueled generation
volumes, partially offset by higher retail revenue prices, higher net power costs deferrals, lower coal-fueled generation volumes and lower gas-fueled generation prices. Retail customer volumes decreased 2%, primarily due to unfavorable weather-related impacts and lower industrial usage, partially offset by higher commercial customer usage and an increase in the average number of customers. Energy generated decreased 8% for the third quarter of 2023 compared to 2022 primarily due to lower coal-fueled and hydro-powered generation volumes, partially offset by higher natural gas-fueled and wind-powered generation volumes. Wholesale electricity sales volumes decreased 12% and purchased electricity volumes increased 16%.
Net loss for the first nine months of 2023 was $666 million, a decrease of $1,287 million compared to 2022 net income of $621 million. The decrease in net income was primarily
due to an increase in estimated losses of $1,607 million associated with the 2020 Wildfires and the 2022 McKinney Fire, net of expected insurance recoveries and increased operations and maintenance expense, partially offset by higher income tax benefit and lower other expense. Utility margin was unfavorable $2 million, primarily due to higher purchased electricity costs from higher prices and volumes, higher coal-fueled generation prices, lower wholesale revenue volumes, higher natural gas-fueled generation costs from higher volumes and prices and lower wheeling revenue, partially offset by higher average retail rates, higher net power cost deferrals, lower coal-fueled generation volumes and higher wholesale market prices. Retail customer volumes were flat, primarily due to lower industrial and irrigation customer usage and unfavorable impacts of weather, partially offset by higher commercial customer usage and an increase in the average number of customers. Energy generated
decreased 12% for the first nine months of 2023 compared to 2022 primarily due to lower coal-fueled, wind-powered and hydroelectric generation volumes, partially offset by higher natural gas-fueled generation volumes. Wholesale electricity sales volumes decreased 39% and purchased electricity volumes increased 29%.
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.
75
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
2023
2022
Change
2023
2022
Change
Utility margin:
Operating
revenue
$
1,676
$
1,635
$
41
3
%
$
4,487
$
4,246
$
241
6
%
Cost
of fuel and energy
664
581
83
14
1,740
1,497
243
16
Utility margin
1,012
1,054
(42)
(4)
2,747
2,749
(2)
—
Operations
and maintenance
356
289
67
23
1,056
877
179
20
Wildfires losses, net of recoveries
1,263
—
1,263
*
1,671
64
1,607
*
Depreciation
and amortization
285
277
8
3
843
836
7
1
Property and other taxes
51
51
—
—
156
161
(5)
(3)
Operating
(loss) income
$
(943)
$
437
$
(1,380)
(316)
%
$
(979)
$
811
$
(1,790)
(221)
%
* Not
meaningful
76
Utility Margin
A comparison of key operating results related to utility margin is as follows:
Third
Quarter
First Nine Months
2023
2022
Change
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
1,676
$
1,635
$
41
3
%
$
4,487
$
4,246
$
241
6
%
Cost
of fuel and energy
664
581
83
14
1,740
1,497
243
16
Utility margin
$
1,012
$
1,054
$
(42)
(4)
%
$
2,747
$
2,749
$
(2)
—
%
Sales
(GWhs):
Residential
4,813
5,035
(222)
(4)
%
13,724
13,653
71
1
%
Commercial
5,559
5,343
216
4
15,336
14,526
810
6
Industrial,
irrigation and other
4,974
5,337
(363)
(7)
13,627
14,709
(1,082)
(7)
Total retail
15,346
15,715
(369)
(2)
42,687
42,888
(201)
—
Wholesale
912
1,037
(125)
(12)
2,338
3,835
(1,497)
(39)
Total
sales
16,258
16,752
(494)
(3)
%
45,025
46,723
(1,698)
(4)
%
Average
number of retail customers (in thousands)
2,072
2,040
32
2
%
2,065
2,033
32
2
%
Average
revenue per MWh:
Retail
$
100.55
$
93.38
$
7.17
8
%
$
96.48
$
89.19
$
7.29
8
%
Wholesale
$
61.14
$
84.28
$
(23.14)
(27)
%
$
68.70
$
55.37
$
13.33
24
%
Heating
degree days
174
91
83
91
%
6,692
6,572
120
2
%
Cooling
degree days
2,344
2,021
323
16
%
2,800
2,432
368
15
%
Sources
of energy (GWhs)(1):
Coal
7,150
8,606
(1,456)
(17)
%
16,299
21,777
(5,478)
(25)
%
Natural
gas
3,876
3,684
192
5
10,939
9,546
1,393
15
Wind(2)
1,191
1,051
140
13
4,719
5,260
(541)
(10)
Hydroelectric
and other(2)
509
555
(46)
(8)
2,432
2,572
(140)
(5)
Total energy generated
12,726
13,896
(1,170)
(8)
34,389
39,155
(4,766)
(12)
Energy
purchased
4,677
4,047
630
16
14,187
10,987
3,200
29
Total
17,403
17,943
(540)
(3)
%
48,576
50,142
(1,566)
(3)
%
Average
cost of energy per MWh:
Energy generated(3)
$
24.85
$
21.60
$
3.25
15
%
$
23.13
$
20.74
$
2.39
12
%
Energy
purchased
$
115.30
$
97.72
$
17.58
18
%
$
82.43
$
68.82
$
13.61
20
%
(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 decreased $42 million for the third quarter of 2023 compared to 2022 primarily due to:
•$144 million of higher purchased electricity costs from higher average market prices and higher volumes;
•$32 million decrease in wholesale revenue primarily due to lower average market prices and wholesale volumes;
•$20 million of higher coal-fueled generation costs primarily due to higher average prices, partially offset by lower volumes; and
•$3 million of lower other revenue primarily due to lower wheeling revenue, partially offset by higher renewable energy
credit sales.
The decreases above were partially offset by:
•$78 million of higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms;
•$76 million increase in retail revenue due to higher average prices, partially offset by lower volumes. Retail customer volumes decreased 2.3%, primarily due to unfavorable weather-related impacts across the service territory, primarily in Utah and Oregon, lower industrial customer usage across all states, except Oregon, partially offset by higher Utah and Oregon commercial customer usage and an increase in the average number of residential and commercial customers across all states, except California; and
•$4
million of lower natural gas-fueled generation costs primarily due to lower average market prices, partially offset by higher volumes.
Operations and maintenance increased $67 million, or 23% for the third quarter of 2023 compared to 2022 primarily due to $23 million increase in vegetation management costs (including the impacts of deferrals and amortizations), $17 million increase in plant operations and maintenance costs, $8 million due to increased insurance premiums, $6 million increase in DSM amortization expense driven by higher spend in Oregon, Utah and Washington (offset in retail revenue) and $4 million of higher legal fees, primarily related to wildfire matters.
Wildfire losses, net of recoveries increased $1,263 million for the third quarter of 2023 compared to 2022 primarily due to
increase in estimated losses, net of expected insurance recoveries, associated with the 2020 Wildfires and the 2022 McKinney Fire.
Interest expense increased $35 million, or 33%, for the third quarter of 2023 compared to 2022 primarily due to higher average long-term debt balances and higher average long-term debt interest rates.
Allowance for borrowed and equity funds increased $31 million for the third quarter of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.
Interest and dividend income increased $13 million for the third quarter of 2023 compared to 2022 primarily due to the recording of interest
on higher deferred net power cost balances and higher investment income due to higher average interest rates on temporary cash investment balances.
Income tax benefit increased $308 million for the third quarter of 2023 compared to 2022 and the effective tax rate was 35% for 2023 and (10)% for 2022. The $308 million increase is primarily due to the increase in the accruals, net of expected insurance recoveries for the 2020 Wildfires and the 2022 McKinney Fire, partially offset by lower PTCs from PacifiCorp's wind-powered generating facilities and lower benefit from the effects of ratemaking.
First Nine Months of 2023 compared to First Nine Months of 2022
Utility
margin decreased $2 million for the first nine months of 2023 compared to 2022 primarily due to:
•$413 million of higher purchased electricity costs from higher average market prices and higher volumes;
•$70 million of higher natural gas-fueled generation costs due to higher volumes and higher average market prices; and
•$52 million decrease in wholesale revenue primarily due to lower volumes, partially offset by higher average market prices.
78
The decreases above were partially offset by:
•$293
million increase in retail revenue due to higher average prices, partially offset by lower retail volumes. Retail customer volumes decreased 0.5%, primarily due to lower industrial and irrigation customer usage and unfavorable weather-related impacts across eastern states, mainly in Utah, partially offset by higher commercial and residential customer usage across eastern states, primarily in Utah and Wyoming, higher Oregon commercial customer usage, increase in average number of residential and commercial customers across all states, except California and favorable impacts of weather in Oregon.
•$227 million higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms; and
•$20 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher
average prices.
Operations and maintenance increased $179 million, or 20%, for the first nine months of 2023 compared to 2022 primarily due to $60 million increase in vegetation management costs (including the impacts of deferrals and amortizations), $33 million increase in plant operations and maintenance costs, $21 million increase in DSM amortization expense driven by higher spend in Oregon, Utah and Washington (offset in retail revenue), $21 million of higher legal fees primarily related to wildfires matters, $14 million increase in insurance premiums, $7 million of higher bad debt expense and $7 million higher labor and employee-related expenses.
Wildfire losses, net of recoveries increased $1,607 million for the first nine months of 2023 compared to 2022 primarily due to increase in estimated
losses, net of expected insurance recoveries, associated with the 2020 Wildfires and the 2022 McKinney Fire.
Property and other taxes decreased $5 million, or 3%, for the first nine months of 2023 compared to 2022 primarily due to lower property tax rates in Utah, partially offset by higher franchise taxes in Oregon and higher property taxes in Wyoming.
Interest expense increased $80 million, or 25%, for the first nine months of 2023 compared to 2022 primarily due to higher average long-term debt balances, higher average long-term debt interest rates and higher interest expense on transmission-related deposits.
Allowance for borrowed and equity funds increased$81 million for the first nine months of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.
Interest and dividend income increased $44 million for the first nine months of 2023 compared to 2022 primarily due to the recording of interest on higher deferred net power cost balances and higher investment income due to higher average interest rates on temporary cash investment balances.
Other, net increased $16 million for the first nine months of 2023 compared to 2022 primarily due to higher cash surrender values of Supplemental Executive Retirement Plan life insurance policies driven by market increases and a favorable change in deferred compensation and long-term incentive plan investments
primarily due to market movements (offset in operations and maintenance expense).
Income tax benefit increased $442 million for the first nine months of 2023 compared to 2022 and the effective tax rate was 42% for 2023 and (7)% for 2022. The $442 million increase is primarily due to the increase in the accruals, net of expected insurance recoveries for the 2020 Wildfires and the 2022 McKinney Fire, higher benefit from the effects of ratemaking, release of a valuation allowance on state net operating loss carryforwards in 2023 compared to the establishment of a state valuation allowance in 2022, partially offset by lower PTCs from PacifiCorp's wind-powered generating facilities.
79
Liquidity
and Capital Resources
As of September 30, 2023, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents
$
98
Credit facilities
2,000
Less:
Short-term
debt
(165)
Tax-exempt bond support and letters of credit
(249)
Net credit facilities
1,586
Total net liquidity
$
1,684
Credit facilities:
Maturity
dates
2026
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022 were $1,067 million and $1,752 million, respectively. The decrease is primarily due to higher wholesale and fuel purchases, higher operating expense payments and collateral returned to counterparties, partially offset by higher collections from retail customers.
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 made for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022 were $(2,245) million and $(1,477) million, respectively. The change is primarily due to an increase in capital expenditures of $769 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, 2023 were
$649 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $1.2 billion and from the borrowing of short-term debt of $165 million. Uses of cash consisted primarily of $401 million for the repayment of long-term debt and $300 million for common stock dividends paid to PPW Holdings LLC.
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.
Short-term Debt
Regulatory authorities limit PacifiCorp to $2.0 billion of short-term debt. As of September 30,
2023, PacifiCorp had $165 million of short-term debt outstanding at a weighted average interest rate of 5.53%. As of December 31, 2022, PacifiCorp had no short-term debt outstanding.
Debt Authorizations
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $3.8 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2026.
80
Common
Shareholders' Equity
In January 2023, PacifiCorp declared a common stock dividend of $300 million, paid in February 2023, 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, including regulatory filings for Certificates of Public Convenience and Necessity; outcomes of legal actions associated with the 2020 Wildfires and the 2022 McKinney Fire; 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.
PacifiCorp'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
2022
2023
2023
Wind generation
$
21
$
550
$
818
Electric
distribution
487
649
890
Electric transmission
832
763
1,333
Solar generation
—
1
8
Electric
battery and pumped hydro storage
6
3
5
Other
135
284
268
Total
$
1,481
$
2,250
$
3,322
PacifiCorp
has included estimates for new renewable and carbon free generation resources, conversion of certain coal-fueled units to natural gas-fueled units, energy storage assets and associated transmission assets in its forecast capital expenditures based on its IRP. These estimates are likely to change as a result of the associated RFP process. PacifiCorp's historical and forecast capital expenditures include the following:
•Wind generation includes both growth projects and operating expenditures. Growth projects include construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties totaling $540 million and $21 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the construction
of additional wind-powered generating facilities and those at acquired sites totals $260 million for the remainder of 2023 and is primarily for the Rock Creek I and Rock Creek II projects to be constructed in Wyoming totaling 590 MWs that are expected to be placed in-service in 2024 and 2025.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures include spending on wildfire mitigation. Expenditures for wildfire mitigation totaled $177 million and $98 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for wildfire mitigation totals $36 million for the remainder of 2023. The remaining investments primarily relate to expenditures for new connections and distribution operations.
81
•Electric
transmission includes both growth projects and operating expenditures. Transmission growth investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $536 million and $643 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $411 million for the remainder of 2023.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $128 million and $115 million for the nine-month periods ended September 30, 2023 and 2022, respectively.
Planned information technology spending totals $52 million for the remainder of 2023. The remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.
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 March 2023, PacifiCorp filed its 2023 IRP in Idaho, Oregon and Wyoming. The March 2023 filing was considered informational in Utah. PacifiCorp filed its 2023 IRP (Amended Final) report on May 31, 2023, following a 60-day extended comment period.
The 2023 IRP is off cycle with regard to Washington's four-year IRP cycle and has instead been filed in that state as the "Washington Two-Year Progress Report," aligned with the Clean Energy Transformation Act requirements. In October, the WUTC approved a multi-party settlement agreement that resolved challenges to the Clean Energy Implementation Plan.
PacifiCorp
has drafted a petition requesting that the WUTC approve an alternative IRP filing schedule, which would extend the existing timeline of each of several filing deadlines by three months to align with the filing schedules of the other five states within PacifiCorp's six-state territory. This is pertinent to maintaining a March 31, 2025 filing date for the 2025 IRP and all key dependent filing dates.
Requests for Proposals
PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands and regulatory policy changes. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load 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.
PacifiCorp's most recent RFP, the 2022 All-Source ("2022AS") RFP, was issued to market in April 2022. In September 2023, PacifiCorp suspended its 2022AS RFP. No final shortlist will be announced while the RFP is paused. Pursuant to Section 2.E of the 2022AS RFP, PacifiCorp reserves the right, without limitation or qualification and in its sole discretion, to reject any or all bids, and to terminate or suspend this RFP in whole or in part at any time.
Key drivers behind PacifiCorp's decision to pause the RFP included:
•A federal court's stay of the
EPA's proposed ozone transport rule.
•Ongoing rulemaking by the EPA regarding greenhouse gas emissions.
•Wildfire risk and associated liability across PacifiCorp's six-state service area and throughout the West.
•Evolving extreme weather risks that necessitate further decision-making regarding PacifiCorp's operational and resource requirements.
82
Material Cash Requirements
As of September 30, 2023,
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, 2022, 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 air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict
the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in 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, pension and other postretirement benefits, income taxes, revenue recognition-unbilled revenue and wildfire loss contingencies. 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, 2022. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2022. Refer to Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for updates regarding the wildfire loss contingency estimates.
83
MidAmerican
Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
84
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, 2023, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, 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
i670
i865
Amortization
of utility plant to other operating expenses
i25
i26
Allowance
for equity funds
(i40)
(i41)
Deferred
income taxes and investment tax credits, net
i106
i11
Settlements of asset retirement
obligations
(i20)
(i55)
Other,
net
i44
i40
Changes in other operating assets and liabilities:
Trade
receivables and other assets
i175
(i10)
Inventories
(i56)
(i38)
Pension
and other postretirement benefit plans
(i1)
i4
Accrued
property, income and other taxes, net
i93
i197
Accounts
payable and other liabilities
(i37)
i46
Net
cash flows from operating activities
i1,761
i1,801
Cash
flows from investing activities:
Capital expenditures
(i1,339)
(i1,404)
Purchases
of marketable securities
(i165)
(i306)
Proceeds from sales
of marketable securities
i150
i299
Other,
net
i14
i12
Net
cash flows from investing activities
(i1,340)
(i1,399)
Cash
flows from financing activities:
Common stock dividends
(i1,000)
(i50)
Proceeds
from long-term debt
i1,338
i—
Repayments
of long-term debt
(i316)
(i2)
Other,
net
(i2)
i—
Net
cash flows from financing activities
i20
(i52)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i441
i350
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i268
i239
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i709
$
i589
The
accompanying notes are an integral part of these financial statements.
90
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, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the nine-month period ended September 30,
2023, 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,
2022, 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, 2023.
(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 on the Statements of Cash Flows is outlined below and disaggregated by the line items
in which they appear on the Balance Sheets (in millions):
Restricted
cash and cash equivalents in other current assets
i9
i10
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i709
$
i268
91
(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
2023
2022
Utility plant:
Generation
i20-i62
years
$
i17,550
$
i18,582
Transmission
i55-i80
years
i2,758
i2,662
Electric
distribution
i15-i80 years
i5,163
i4,931
Natural
gas distribution
i30-i75 years
i2,239
i2,144
Utility
plant in-service
i27,710
i28,319
Accumulated
depreciation and amortization
(i7,674)
(i8,024)
Utility
plant in-service, net
i20,036
i20,295
Nonregulated
property, net of accumulated depreciation and amortization
i20-i50 years
i6
i6
i20,042
i20,301
Construction
work-in-progress
i1,479
i790
Property,
plant and equipment, net
$
i21,521
$
i21,091
/
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 nine-month periods ended September 30, 2023 and 2022, $i12 million and $i211 million,
respectively, is reflected in depreciation and amortization expense on the Statements of Operations.
(4)iRecent Financing Transactions
Long-Term Debt
In September 2023, MidAmerican Energy issued $i350 million
of its i5.35% First Mortgage Bonds due January 2034 and $i1 billion of its i5.850%
First Mortgage Bonds due September 2054. MidAmerican Energy intends, within i24 months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing Framework.
Credit Facilities
In June 2023, MidAmerican Energy amended its existing $i1.5 billion
unsecured credit facility expiring in June 2025. The amendment extended the expiration date to June 2026.
(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 expense (benefit) is as follows:
State
income tax, net of federal income tax impacts
(i8)
(i21)
(i9)
(i21)
Effects
of ratemaking
(i5)
(i13)
(i5)
(i12)
Other,
net
(i1)
i3
(i1)
i1
Effective
income tax rate
(i40)
%
(i79)
%
(i136)
%
(i233)
%
/
92
Income
tax credits relate primarily to production tax credits ("PTC") 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 the remaining 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, 2023 and 2022, totaled $i484 million and $i505 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 $i698 million and $i757 million
for the nine-month periods ended September 30, 2023 and 2022, 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 on the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans during 2023 are expected to be $i7 million and $i2 million,
respectively. As of September 30, 2023, $i5 million and $i2 million of contributions had been made to the pension and other postretirement
benefit plans, respectively.
93
(7) iAsset Retirement Obligations
MidAmerican Energy estimates its asset retirement obligation ("ARO") liabilities based upon detailed engineering calculations
of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of expected work. During the nine-month period ended September 30, 2023, MidAmerican Energy recorded an increase of $i88 million for decommissioning its wind-generating
facilities, which is a non-cash investing activity and is due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.
(8) 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 $i12 million and $i— million
as of September 30, 2023 and December 31, 2022, respectively.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
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 net regulatory assets
(i9)
(i2)
(i36)
i42
Settlements
i8
(i10)
i16
(i23)
Ending
balance
$
(i15)
$
i14
$
(i15)
$
i14
/
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 has the following firm commitments that are not reflected on the Balance Sheets.
Construction Commitments
During the nine-month period ended September 30, 2023, MidAmerican Energy entered into firm construction commitments totaling $i354
million for the remainder of 2023 through 2024 related to the construction and repowering of wind-powered generating facilities in Iowa.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Legal Matters
MidAmerican Energy is party to a variety of legal actions arising out of
the normal course of business. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.
Transmission Rates
MidAmerican Energy's wholesale transmission rates are set annually using formula rates approved by the Federal Energy Regulatory Commission ("FERC") subject to true-up for actual cost of service. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the base return on equity ("ROE") used to determine rates in effect prior to September 2016 no longer be found just and reasonable and sought to reduce the base ROE. In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion vacating all orders related to the complaints
and remanding them back to the FERC. MidAmerican Energy cannot predict the ultimate outcome of these matters or the amount of refunds, if any, and accordingly, has reversed its previously accrued liability for potential refunds of amounts collected under the higher ROE during the periods covered by the complaints.
96
(10) 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 12 (in millions):
In January and September 2023, MidAmerican Energy paid $i100 million and $i900 million, respectively, in cash dividends to its parent company, MHC.
97
(12) iSegment
Information
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 natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and 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, 2023, the related consolidated statements of operations and changes in member's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 30,
2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, 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
i670
i865
Amortization
of utility plant to other operating expenses
i25
i26
Allowance
for equity funds
(i40)
(i41)
Deferred
income taxes and investment tax credits, net
i106
i11
Settlements
of asset retirement obligations
(i20)
(i55)
Other,
net
i31
i42
Changes in other operating assets and liabilities:
Trade
receivables and other assets
i166
(i12)
Inventories
(i56)
(i38)
Pension
and other postretirement benefit plans
(i1)
i4
Accrued
property, income and other taxes, net
i94
i197
Accounts
payable and other liabilities
(i41)
i42
Net
cash flows from operating activities
i1,737
i1,786
Cash
flows from investing activities:
Capital expenditures
(i1,339)
(i1,404)
Purchases
of marketable securities
(i165)
(i306)
Proceeds from
sales of marketable securities
i150
i299
Proceeds
from sale of investment
i12
i—
Other,
net
i14
i12
Net
cash flows from investing activities
(i1,328)
(i1,399)
Cash
flows from financing activities:
Distributions to member
(i992)
i—
Proceeds
from long-term debt
i1,338
i—
Repayments
of long-term debt
(i316)
(i2)
Net change in note payable to affiliate
i1
(i34)
Other,
net
(i2)
(i1)
Net
cash flows from financing activities
i29
(i37)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i438
i350
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i271
i240
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i709
$
i590
The
accompanying notes are an integral part of these consolidated financial statements.
104
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, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the nine-month period
ended September 30, 2023, 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, 2022, 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, 2023.
(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 on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Restricted
cash and cash equivalents in other current assets
i9
i10
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i709
$
i271
(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.
105
(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 expense (benefit) is as follows:
State
income tax, net of federal income tax impacts
(i8)
(i22)
(i9)
(i24)
Effects
of ratemaking
(i5)
(i13)
(i5)
(i13)
Other,
net
(i1)
i2
(i1)
i3
Effective
income tax rate
(i41)
%
(i84)
%
(i136)
%
(i251)
%
/
Income
tax credits relate primarily to production tax credits ("PTC") 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 the remaining 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, 2023 and 2022, totaled $i484 million and $i505 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 $i700
million and $i761 million for the nine-month periods ended September 30, 2023 and 2022, respectively.
(6) iEmployee
Benefit Plans
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.
(7) iAsset Retirement Obligations
Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements.
(8) iFair
Value Measurements
Refer to Note 8 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. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.
(10) iRevenue
from Contracts with Customers
Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements.
(11) iMember's Equity
In January and September 2023, MidAmerican Funding paid $i100
million and $i892 million. respectively, in cash distributions to its parent company, BHE.
(12) 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 natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and 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.
108
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 2023 and 2022
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the third quarter of 2023 was $324 million, an increase of $19 million, or 6%, compared to 2022, primarily due to lower depreciation and amortization expense, higher allowance for borrowed and equity funds, higher gas utility margin and favorable other, net, partially offset by lower electric utility margin, lower income tax benefit, higher interest expense, higher operations and maintenance expense and higher property and other taxes. The decrease in depreciation and amortization expense was primarily due to lower Iowa revenue sharing. Electric retail customer volumes increased 1%, primarily due to
higher customer usage for certain industrial customers, partially offset by the unfavorable impact of weather. Energy generated decreased 3%, due to lower wind-powered generation, partially offset by higher natural gas- and coal-fueled generation; and energy purchased increased 5%. Wholesale electricity sales volumes decreased 13% due to unfavorable market conditions. Natural gas retail customer volumes decreased 3% due to the unfavorable impact of weather.
MidAmerican Energy's net income for the first nine months of 2023 was $802 million, an increase of $46 million, or 6%, compared to 2022, primarily due to lower depreciation and amortization expense, favorable other, net, higher nonregulated utility margin and higher allowance for borrow and equity funds, partially offset by lower electric utility margin, lower income tax benefit, higher operations and maintenance expense, higher interest
expense, higher property and other taxes and lower natural gas utility margin. The decrease in depreciation and amortization expense was primarily due to lower Iowa revenue sharing. Electric retail customer volumes increased 1%, primarily due to higher customer usage for certain industrial customers, partially offset by the unfavorable impact of weather. Energy generated decreased 5%, due to lower wind-powered generation, partially offset by higher natural gas- and coal-fueled generation; and energy purchased increased 5%. Wholesale electricity sales volumes decreased 13% due to unfavorable market conditions. Natural gas retail customer volumes decreased 11% due to the unfavorable impact of weather.
MidAmerican Funding -
MidAmerican Funding's net income for the third quarter of 2023 was $321 million,
an increase of $21 million, or 7%, compared to 2022. MidAmerican Funding's net income for the first nine months of 2023 was $803 million, an increase of $58 million, or 8%, compared to 2022. The variance in net income was primarily due to the changes in MidAmerican Energy's earnings discussed above and a one-time gain on the sale of an investment of $10 million.
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.
109
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
2023
2022
Change
2023
2022
Change
Electric utility margin:
Operating
revenue
$
869
$
1,009
$
(140)
(14)
%
$
2,121
$
2,342
$
(221)
(9)
%
Cost
of fuel and energy
165
235
(70)
(30)
393
534
(141)
(26)
Electric utility margin
704
774
(70)
(9)
%
1,728
1,808
(80)
(4)
%
Natural
gas utility margin:
Operating revenue
93
138
(45)
(33)
%
516
705
(189)
(27)
%
Natural
gas purchased for resale
47
97
(50)
(52)
329
515
(186)
(36)
Natural gas utility margin
46
41
5
12
%
187
190
(3)
(2)
%
Utility
margin
750
815
(65)
(8)
%
1,915
1,998
(83)
(4)
%
Other
operating revenue
2
1
1
100
%
6
3
3
100
%
Operations
and maintenance
214
210
4
2
635
602
33
5
Depreciation and amortization
210
338
(128)
(38)
670
865
(195)
(23)
Property
and other taxes
39
38
1
3
121
114
7
6
Operating
income
$
289
$
230
$
59
26
%
$
495
$
420
$
75
18
%
110
Electric
Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
Third
Quarter
First Nine Months
2023
2022
Change
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
869
$
1,009
$
(140)
(14)
%
$
2,121
$
2,342
$
(221)
(9)
%
Cost
of fuel and energy
165
235
(70)
(30)
393
534
(141)
(26)
Utility margin
$
704
$
774
$
(70)
(9)
%
$
1,728
$
1,808
$
(80)
(4)
%
Sales
(GWhs):
Residential
2,038
2,056
(18)
(1)
%
5,310
5,461
(151)
(3)
%
Commercial
1,065
1,055
10
1
3,012
3,021
(9)
—
Industrial
4,403
4,335
68
2
12,870
12,463
407
3
Other
430
422
8
2
1,231
1,231
—
—
Total
retail
7,936
7,868
68
1
22,423
22,176
247
1
Wholesale
2,839
3,267
(428)
(13)
11,133
12,738
(1,605)
(13)
Total
sales
10,775
11,135
(360)
(3)
%
33,556
34,914
(1,358)
(4)
%
Average
number of retail customers (in thousands)
821
813
8
1
%
819
812
7
1
%
Average
revenue per MWh:
Retail
$
97.40
$
101.53
$
(4.13)
(4)
%
$
81.74
$
84.10
$
(2.36)
(3)
%
Wholesale
$
25.41
$
55.68
$
(30.27)
(54)
%
$
19.59
$
31.12
$
(11.53)
(37)
%
Heating
degree days
12
67
(55)
(82)
%
3,466
4,059
(593)
(15)
%
Cooling degree days
818
838
(20)
(2)
%
1,211
1,259
(48)
(4)
%
Sources
of energy (GWhs)(1):
Wind and other(2)
3,955
4,528
(573)
(13)
%
17,652
20,182
(2,530)
(13)
%
Coal
4,064
3,990
74
2
8,397
7,830
567
7
Nuclear
982
987
(5)
(1)
2,771
2,770
1
—
Natural
gas
806
624
182
29
1,719
1,255
464
37
Total energy generated
9,807
10,129
(322)
(3)
30,539
32,037
(1,498)
(5)
Energy
purchased
1,247
1,189
58
5
3,652
3,466
186
5
Total
11,054
11,318
(264)
(2)
%
34,191
35,503
(1,312)
(4)
%
Average
cost of energy per MWh:
Energy generated(3)
$
9.94
$
12.60
$
(2.66)
(21)
%
$
7.37
$
8.03
$
(0.66)
(8)
%
Energy
purchased
$
54.99
$
90.62
$
(35.63)
(39)
%
$
46.17
$
79.97
$
(33.80)
(42)
%
(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.
111
Natural Gas Utility Margin
A comparison of key operating
results related to natural gas utility margin is as follows:
Third
Quarter
First Nine Months
2023
2022
Change
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
93
$
138
$
(45)
(33)
%
$
516
$
705
$
(189)
(27)
%
Natural
gas purchased for resale
47
97
(50)
(52)
329
515
(186)
(36)
Utility margin
$
46
$
41
$
5
12
%
$
187
$
190
$
(3)
(2)
%
Throughput
(000's Dths):
Residential
2,589
2,798
(209)
(7)
%
33,179
37,397
(4,218)
(11)
%
Commercial
1,435
1,492
(57)
(4)
15,810
17,551
(1,741)
(10)
Industrial
1,186
1,097
89
8
4,042
4,406
(364)
(8)
Other
12
4
8
200
59
55
4
7
Total
retail sales
5,222
5,391
(169)
(3)
53,090
59,409
(6,319)
(11)
Wholesale sales
6,295
5,556
739
13
20,698
22,700
(2,002)
(9)
Total
sales
11,517
10,947
570
5
73,788
82,109
(8,321)
(10)
Natural gas transportation service
25,246
20,901
4,345
21
78,661
74,705
3,956
5
Total
throughput
36,763
31,848
4,915
15
%
152,449
156,814
(4,365)
(3)
%
Average
number of retail customers (in thousands)
791
781
10
1
%
792
784
8
1
%
Average
revenue per retail Dth sold
$
12.88
$
16.48
$
(3.60)
(22)
%
$
8.13
$
9.10
$
(0.97)
(11)
%
Heating
degree days
18
84
(66)
(79)
%
3,659
4,303
(644)
(15)
%
Average
cost of natural gas per retail Dth sold
$
6.10
$
10.38
$
(4.28)
(41)
%
$
5.24
$
6.42
$
(1.18)
(18)
%
Combined
retail and wholesale average cost of natural gas per Dth sold
Electric utility margin decreased $70 million, or 9%, for the third quarter of 2023 compared to 2022, primarily due to:
•a $90 million decrease in wholesale utility margin due to lower margins per unit of $72 million from lower market prices, and lower volumes of $18 million or 13.1%; partially offset by
•a $21 million increase in retail utility margin primarily due to $19 million, net of energy costs, from higher recoveries through bill riders (offset in
operations and maintenance expense and income tax benefit); and $8 million from higher customer usage; partially offset by $5 million due to the unfavorable impact of weather; and $2 million from lower wind-turbine performance settlements. Retail customer volumes increased 0.9%.
Natural gas utility margin increased $5 million, or 12%, for the third quarter of 2023 compared to 2022, primarily due to:
•a $4 million increase from higher average rates mainly due to the South Dakota and Iowa natural gas general rate cases; and
•a $1 million increase from higher natural gas transportation margin.
112
Operations
and maintenance increased $4 million, or 2%, for the third quarter of 2023 compared to 2022 primarily due to higher technology costs of $4 million, higher nuclear power generation costs of $3 million and higher administrative and other costs of $3 million, partially offset by lower gas distribution costs of $4 million and lower electric distribution and transmission costs of $2 million.
Depreciation and amortization decreased $128 million, or 38%, for the third quarter of 2023 compared to 2022 primarily due to $119 million from lower Iowa revenue sharing accruals, and $14 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $3 million from lower depreciation expense deferrals in 2023 and $2 million from wind-powered generating facilities
and other plant placed in-service.
Property and other taxes increased $1 million, or 3%, for the third quarter of 2023 compared to 2022 primarily due to $2 million from higher wind turbine property taxes, partially offset by $1 million from lower replacement taxes.
Interest expense increased $6 million, or 8%, for the third quarter of 2023 compared to 2022 due to higher interest expense from a September 2023 long-term debt issuance and higher interest rates on variable rate long-term debt.
Allowance for borrowed and equity funds increased $7 million, or 47%, for the third quarter of 2023 compared to 2022 due to higher construction work-in-progress
balances related to wind-powered generation.
Other, net increased $2 million, or 50%, for the third quarter of 2023 compared to 2022 primarily due to higher interest income from higher interest rates and higher cash surrender values of corporate-owned life insurance policies, partially offset by higher non-service employee benefit plans cost.
Income tax benefit decreased $43 million, or 32%, for the third quarter of 2023 compared to 2022 primarily due to $30 million of higher federal and state income tax expense largely from higher pretax income and $8 million from lower PTCs recognized due to lower wind generation. PTCs for the third quarter of 2023 and 2022 totaled $109 million and $117 million, respectively.
MidAmerican
Funding -
Income tax benefit decreased $44 million, or 32%, for the third quarter of 2023 compared to 2022 principally due to the changes in MidAmerican Energy's income tax benefit discussed above.
First Nine Months of 2023 Compared to First Nine Months of 2022
MidAmerican Energy -
Electric utility margin decreased $80 million, or 4%, for the first nine months of 2023 compared to 2022, due to:
•a $145 million
decrease in wholesale utility margin due to lower margins per unit of $108 million from lower market prices, and lower volumes of $37 million or 12.6%; partially offset by
•a $67 million increase in retail utility margin primarily due to $58 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); $23 million from higher customer usage; and $4 million due to price impacts from changes in sales mix; partially offset by $18 million from the unfavorable impact of weather. Retail customer volumes increased 1.1%.
Natural gas utility margin decreased $3 million, or 2%, for the first nine months of 2023 compared to 2022 primarily due to:
•a $9 million
decrease from the unfavorable impact of weather; partially offset by
•a $4 million increase from higher average rates mainly due to the South Dakota and Iowa natural gas general rate cases; and
•a $2 million increase from natural gas transportation margin.
Operations and maintenance increased $33 million, or 5%, for the first nine months of 2023 compared to 2022 primarily due to higher technology costs of $10 million, higher benefits costs of $8 million, higher administrative and other costs of $8 million, higher nuclear power generation costs of $6 million, higher other power generation costs of $6 million and higher property insurance costs of $4 million, partially offset by lower electric distribution and transmission costs
of $5 million and lower gas distribution costs of $4 million.
113
Depreciation and amortization decreased $195 million, or 23%, for the first nine months of 2023 compared to 2022 primarily due to $200 million from lower Iowa revenue sharing accruals and $40 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $36 million from new wind-powered generating facilities and other plant placed in-service and $9 million from lower depreciation expense deferrals in 2023.
Property and other taxes increased $7 million,
or 6%, for the first nine months of 2023 compared to 2022 primarily due to $5 million from higher wind turbine property taxes and $2 million from higher replacement taxes.
Interest expense increased $11 million, or 5%, for the first nine months of 2023 compared to 2022 due to higher interest expense from a September 2023 long-term debt issuance and higher interest rates on variable rate long-term debt.
Allowance for borrowed and equity funds increased $1 million, or 2%, for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress balances related to wind-powered generation.
Other, net increased $48 million,
or 436%, for the first nine months of 2023 compared to 2022 primarily due to favorable investment earnings, largely attributable to higher cash surrender values of corporate-owned life insurance policies, and higher interest income from higher interest rates.
Income tax benefit decreased $67 million, or 13%, for the first nine months of 2023 compared to 2022 primarily due to $46 million of higher federal and state income tax expense largely from higher pretax income, and $21 million from lower PTCs recognized due to lower wind generation. PTCs for the first nine months of 2023 and 2022 totaled $484 million and $505 million, respectively.
MidAmerican Funding -
Income tax benefit
decreased $70 million, or 13%, for the first nine months of 2023 compared to 2022 principally due to the changes in MidAmerican Energy's income tax benefit discussed above and higher pretax income from a one-time gain on the sale of an investment.
Liquidity and Capital Resources
As of September 30, 2023, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
MidAmerican
Energy:
Cash and cash equivalents
$
700
Credit facilities, maturing 2024 and 2026
1,505
Less:
Tax-exempt bond support
(306)
Net
credit facilities
1,199
MidAmerican Energy total net liquidity
$
1,899
MidAmerican Funding:
MidAmerican Energy total net liquidity
$
1,899
MHC,
Inc. credit facility, maturing 2024
4
MidAmerican Funding total net liquidity
$
1,903
114
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $1,761 million and $1,801 million,
respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $1,737 million and $1,786 million, respectively. Cash flows from operating activities reflect lower income tax receipts and higher payments to vendors, partially offset by the cash impacts of utility margins for MidAmerican Energy's regulated electric and natural gas businesses and lower asset retirement obligation settlements.
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 made for each payment date.
Investing Activities
MidAmerican
Energy's net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022, were $(1,340) million and $(1,399) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022, were $(1,328) million and $(1,399) 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, 2023 and 2022 were $20 million and $(52) million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2023 and 2022, were $29 million and $(37) million, respectively. Proceeds from long-term debt reflect MidAmerican Energy's issuance in September 2023 of $350 million of its 5.350% First Mortgage Bonds due January 2034 and $1 billion of its 5.850% First Mortgage Bonds due September 2054. In January 2023 and September 2023, MidAmerican Funding paid $100 million and $892 million, respectively, in cash
distributions to its sole member, BHE. In 2023, MidAmerican Energy repaid $316 million of long-term debt. In 2022, MidAmerican Funding made payments of $34 million 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 2026. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable
interest rate based on the Secured Overnight Financing Rate, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
Long-term Debt and Preferred Stock
MidAmerican Energy currently has an effective shelf registration statement with the SEC to issue an additional $1.9 billion of long-term debt securities and preferred stock through March 10, 2026. MidAmerican Energy has authorization from the FERC to issue, through June 30, 2025, long-term debt securities up to an aggregate of $1.65 billion and preferred stock up to an aggregate of $500
million. MidAmerican Energy has authorization from the Illinois Commerce Commission through May 25, 2025, to issue long-term debt securities up to an aggregate of $1.6 billion and preferred stock up to an aggregate of $500 million.
115
Future Uses of Cash
MidAmerican Energy and MidAmerican Funding have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities and other sources. These sources are expected to provide
funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
MidAmerican Energy has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to 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.
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
2022
2023
2023
Wind generation
$
515
$
546
$
790
Electric
distribution
206
251
321
Electric transmission
78
150
191
Solar generation
103
11
21
Other
502
381
555
Total
$
1,404
$
1,339
$
1,878
MidAmerican
Energy's capital expenditures provided above consist of the following:
•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction of wind-powered generating facilities totaling $460 million and $39 million for the nine-month periods ended September 30, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $171 million for the remainder of 2023.
◦Repowering
of wind-powered generating facilities totaling $48 million and $422 million for the nine-month periods ended September 30, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $21 million for the remainder of 2023. 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.
•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.
•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party
generator requirements and replacement of existing facilities to maintain system reliability.
•Solar generation includes the construction and operation of solar-powered generating facilities, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the nine-month periods ended September 30, 2023 and 2022, solar generation spending totaled $11 million and $103 million, respectively. Planned spending totals $10 million for the remainder of 2023.
116
•Other includes primarily routine projects 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, 2023, 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, 2022.
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.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact MidAmerican Energy's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including
fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and financial results.
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,
2022. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2022.
117
Nevada Power Company and its subsidiaries
Consolidated Financial Section
118
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, 2023, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, 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
i323
i312
Allowance
for equity funds
(i14)
(i8)
Changes
in regulatory assets and liabilities
(i31)
(i9)
Deferred
income taxes and amortization of investment tax credits
(i18)
i48
Deferred
energy
(i184)
(i543)
Amortization of deferred energy
i70
i113
Other,
net
i—
i11
Changes in other operating assets and liabilities:
Trade
receivables and other assets
(i191)
(i302)
Inventories
(i34)
(i14)
Accrued
property, income and other taxes
i68
i15
Accounts
payable and other liabilities
i153
i326
Net
cash flows from operating activities
i423
i232
Cash
flows from investing activities:
Capital expenditures
(i1,102)
(i523)
Proceeds
from repayment of affiliate note receivable
i100
i—
Net
cash flows from investing activities
(i1,002)
(i523)
Cash
flows from financing activities:
Proceeds from long-term debt
i494
i300
Repayments
of long-term debt
(i300)
i—
Net proceeds from short-term
debt
i—
i20
Contributions
from parent
i400
i25
Other,
net
(i15)
(i13)
Net
cash flows from financing activities
i579
i332
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i—
i41
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i60
i45
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i60
$
i86
The
accompanying notes are an integral part of these consolidated financial statements.
123
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, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. 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, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 30, 2023, 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, 2022, 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, 2023.
(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 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 on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Nonregulated,
net of accumulated depreciation and amortization
i45 years
i1
i1
i7,169
i6,921
Construction
work-in-progress
i1,100
i485
Property,
plant and equipment, net
$
i8,269
$
i7,406
/
(4) iRecent
Financing Transactions
Long-Term Debt
In September 2023, Nevada Power issued $i500 million of its i6.000% General and
Refunding Mortgage Bonds, Series 2023A, due March 2054. Nevada Power used the net proceeds to repay its term loan due January 14, 2024 and short-term borrowings outstanding under Nevada Power's revolving credit facility, fund capital expenditures and for general corporate purposes.
In March 2023, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $ii40/
million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017A, due 2032; $ii13/ million
of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017B, due 2039; and $ii40/ million
of its Clark County, Nevada Revenue Bonds, Series 2017, due 2036. The Coconino Series 2017A bond was offered at a fixed rate of i4.125% and the Coconino Series 2017B and Clark Series 2017 bonds were offered at a fixed rate of ii3.750/%.
Credit
Facilities
In June 2023, Nevada Power amended its existing $i400 million secured credit facility expiring in June 2025. The amendment increased the commitment of the lenders to $i600 million
and extended the expiration date to June 2026.
(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 (benefit) is as follows:
Effects
of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to 2017 tax reform pursuant to an order issued by the PUCN effective January 1, 2021.
125
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 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, 2023 and 2022,
respectively, Nevada Power received net cash payments for federal income tax from BHE totaling $i17 million and $i20 million, respectively.
(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 and natural gas market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased
power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Nevada Power may from time to time enter
into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.
126
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, 2023 a regulatory asset of $i58 million was recorded related to the net derivative liability of $i58 million.
As of December 31, 2022 a regulatory asset of $i52 million was recorded related to the net derivative liability of $i52 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
2023
2022
Electricity purchases
Megawatt hours
i1
i2
Natural
gas purchases
Decatherms
i162
i109
/
Credit
Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting
agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels "credit-risk-related contingent features") or provide the right for
counterparties to demand "adequate assurance" if there is a material adverse change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2023, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
127
The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $i9
million and $i5 million as of September 30, 2023 and December 31, 2022, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(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.
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, 2023 and December 31, 2022, 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.
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
(i31)
(i4)
(i150)
(i81)
Settlements
i99
i113
i144
i128
Ending
balance
$
(i58)
$
(i66)
$
(i58)
$
(i66)
/
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 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.
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business.
Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
(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 2023 and 2022
Overview
Net income for the third quarter of 2023 was $211 million, an increase of $2 million, compared to 2022 primarily due to higher capitalized interest and allowance for equity funds, mainly due to higher construction work-in-progress, lower operations and maintenance expenses, mainly due to lower earnings sharing, favorable interest and dividend income, mainly from higher carrying charges on regulatory balances, and lower income tax expense, mainly due to lower pretax income. The increase is partially offset by higher interest expense, primarily due to higher long-term debt and average interest rate, lower utility margin and higher depreciation and amortization, mainly due to higher plant placed in-service. Utility margin
decreased primarily due to lower retail customer volumes and lower transmission and wholesale revenue, partially offset by higher regulatory-related revenue deferrals. Retail customer volumes, including distribution only service customers, decreased 3% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated decreased 8% for the third quarter of 2023 compared to 2022 primarily due to lower natural-gas fueled generation. Wholesale electricity sales volumes decreased 63% and purchased electricity volumes increased 1%.
Net income for the first nine months of 2023 was $281 million, a decrease of $2 million, compared to 2022 primarily due to higher interest expense, mainly due to higher long-term debt and higher average interest rate, lower utility margin, higher depreciation and amortization, mainly due to higher plant placed in-service,
and higher operations and maintenance expenses. The decrease is partially offset by favorable interest and dividend income, mainly from higher carrying charges on regulatory balances, higher capitalized interest and allowance for equity funds, mainly due to higher construction work-in-progress, favorable cash surrender value of corporate-owned life insurance policies and lower income tax expense, mainly due to lower pretax income. Utility margin decreased primarily due to lower retail customer volumes, partially offset by higher regulatory-related revenue deferrals and higher other retail revenue. Retail customer volumes, including distribution only service customers, decreased 2% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Operations and maintenance expenses increased primarily due to increased plant operations and maintenance expenses, higher technology costs and higher customer service operations expenses,
partially offset by lower earnings sharing. Energy generated increased 6% for the first nine months of 2023 compared to 2022 primarily due to higher natural-gas fueled generation. Wholesale electricity sales volumes decreased 62% and purchased electricity volumes decreased 11%.
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.
131
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
2023
2022
Change
2023
2022
Change
Utility margin:
Operating
revenue
$
1,145
$
1,003
$
142
14
%
$
2,525
$
2,057
$
468
23
%
Cost
of fuel and energy
688
538
150
28
1,565
1,086
479
44
Utility margin
457
465
(8)
(2)
960
971
(11)
(1)
Operations
and maintenance
85
90
(5)
(6)
236
230
6
3
Depreciation and amortization
109
106
3
3
323
312
11
4
Property
and other taxes
14
14
—
—
42
39
3
8
Operating income
$
249
$
255
$
(6)
(2)
%
$
359
$
390
$
(31)
(8)
%
132
Utility
Margin
A comparison of key operating results related to utility margin is as follows:
Third
Quarter
First Nine Months
2023
2022
Change
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
1,145
$
1,003
$
142
14
%
$
2,525
$
2,057
$
468
23
%
Cost
of fuel and energy
688
538
150
28
1,565
1,086
479
44
Utility margin
$
457
$
465
$
(8)
(2)
%
$
960
$
971
$
(11)
(1)
%
Sales
(GWhs):
Residential
3,993
4,228
(235)
(6)
%
7,897
8,425
(528)
(6)
%
Commercial
1,497
1,589
(92)
(6)
3,745
3,859
(114)
(3)
Industrial
1,716
1,696
20
1
4,414
4,280
134
3
Other
46
50
(4)
(8)
133
142
(9)
(6)
Total
fully bundled(1)
7,252
7,563
(311)
(4)
16,189
16,706
(517)
(3)
Distribution only service
879
792
87
11
2,185
2,022
163
8
Total
retail
8,131
8,355
(224)
(3)
18,374
18,728
(354)
(2)
Wholesale
63
172
(109)
(63)
193
507
(314)
(62)
Total
GWhs sold
8,194
8,527
(333)
(4)
%
18,567
19,235
(668)
(3)
%
Average
number of retail customers (in thousands)
1,018
1,003
15
1
%
1,014
999
15
2
%
Average
revenue per MWh:
Retail - fully bundled(1)
$
154.23
$
127.11
$
27.12
21
%
$
151.33
$
117.34
$
33.99
29
%
Wholesale
$
55.88
$
92.51
$
(36.63)
(40)
%
$
66.80
$
56.19
$
10.61
19
%
Heating
degree days
—
—
—
—
1,383
985
398
40
%
Cooling degree days
2,277
2,351
(74)
(3)
%
3,401
3,722
(321)
(9)
%
Sources
of energy (GWhs)(2)(3):
Natural gas
3,989
4,326
(337)
(8)
%
10,183
9,639
544
6
%
Renewables
17
19
(2)
(11)
51
53
(2)
(4)
Total
energy generated
4,006
4,345
(339)
(8)
10,234
9,692
542
6
Energy purchased
3,416
3,373
43
1
6,752
7,606
(854)
(11)
Total
7,422
7,718
(296)
(4)
%
16,986
17,298
(312)
(2)
%
Average
cost of energy per MWh(2)(4):
Energy generated
$
35.61
$
41.04
$
(5.43)
(13)
%
$
60.30
$
43.88
$
16.42
37
%
Energy
purchased
$
159.42
$
106.73
$
52.69
49
%
$
140.31
$
86.88
$
53.43
61
%
(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 214 GWhs and 183 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2023 and 2022, respectively. The average cost of energy per MWh and sources of energy excludes 676 GWhs and 967 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2023 and 2022, 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 $8 million, or 2%, for the third quarter of 2023 compared to 2022 primarily due to:
•$16 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 2.7% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and
•$2 million of lower transmission and wholesale revenue.
The decrease in utility margin was partially offset by:
•$5
million of higher energy efficiency program rates (offset in operations and maintenance expense) and
•$4 million of higher regulatory-related revenue deferrals.
Operations and maintenance decreased $5 million, or 6%, for the third quarter of 2023 compared to 2022 primarily due to lower earnings sharing, partially offset by higher energy efficiency program costs (offset in operating revenue), higher customer service operations expenses, higher technology costs and increased plant operations and maintenance expenses.
Depreciation and amortization increased $3 million, or 3%, for the third quarter of 2023 compared to 2022 primarily due to higher plant placed in-service.
Interest
expense increased $8 million, or 20%, for the third quarter of 2023 compared to 2022 primarily due to higher long-term debt and higher average interest rate.
Capitalized interest increased $6 million for the third quarter of 2023 compared to 2022 primarily due to higher construction work-in-progress.
Allowance for equity funds increased $3 million for the third quarter of 2023 compared to 2022 primarily due to higher construction work-in-progress.
Interest and dividend income increased $5 million or 38% for the third quarter of 2023 compared to 2022 primarily due to favorable interest income, mainly from carrying charges
on regulatory balances.
Other, net decreased $2 million or 67% for the third quarter of 2023 compared to 2022 primarily due to higher non-service pension costs.
Income tax expense decreased $4 million, or 16%, for the third quarter of 2023 compared to 2022 primarily due to lower pretax income. The effective tax rate was 9% in 2023 and 11% in 2022 and decreased primarily due to the effects of ratemaking.
First Nine Months of 2023 Compared to First Nine Months of 2022
Utility margin decreased
$11 million, or 1%, for the first nine months of 2023 compared to 2022 primarily due to:
•$34 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 1.9% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers.
The decrease in utility margin was offset by:
•$11 million of higher energy efficiency program rates (offset in operations and maintenance expense);
•$9 million of higher regulatory-related revenue deferrals; and
•$4 million of higher other retail revenue.
Operations
and maintenance increased by $6 million, or 3%, for the first nine months of 2023 compared to 2022 primarily due to higher energy efficiency program costs (offset in operating revenue), increased plant operations and maintenance expenses, higher technology costs and higher customer service operations expenses, partially offset by lower earnings sharing.
Depreciation and amortization increased $11 million, or 4%, for the first nine months of 2023 compared to 2022 primarily due to higher plant placed in-service.
134
Property and other taxes increased $3 million, or 8%, for the first
nine months of 2023 compared to 2022 primarily due to a decrease in the amount of abatements available and an increase in commerce and franchise tax from higher revenue.
Interest expense increased $29 million, or 25%, for the first nine months of 2023 compared to 2022 primarily due to higher long-term debt and higher average interest rate.
Capitalized interest increased$12 million for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress.
Allowance for equity funds increased $6 million, or 75% for the first nine months of 2023 compared to 2022 primarily
due to higher construction work-in-progress.
Interest and dividend income increased $28 million or 90% for the first nine months of 2023 compared to 2022 primarily due to favorable interest income, mainly from carrying charges on regulatory balances.
Other, net increased $6 million for the first nine months of 2023 compared to 2022 primarily due to favorable cash surrender value of corporate-owned life insurance policies, partially offset by higher non-service pension costs.
Income tax expense decreased $6 million, or 17%, for the first nine months of 2023 compared to 2022 primarily due to lower pretax income. The effective tax rate was 9% in 2023
and 11% in 2022 and decreased primarily due to the effects of ratemaking.
Liquidity and Capital Resources
As of September 30, 2023, Nevada Power's total net liquidity was as follows (in millions):
Cash and cash equivalents
$
44
Credit
facility
600
Total net liquidity
$
644
Credit facility:
Maturity
date
2026
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $423 million and $232 million, respectively. The change was primarily due to higher collections from customers and increased customer and vendor deposits, partially offset by higher payments related to fuel and energy costs, the timing of payments for operating costs and higher interest payments.
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 made for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022, were $(1,002) million and $(523) million, respectively. The change was primarily due to increased capital expenditures, offset by the repayment of an affiliate note receivable. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-month periods ended September 30, 2023 and 2022,
were $579 million and $332 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and higher proceeds from the issuance of long-term debt, offset by higher repayments of long-term debt and lower proceeds from short-term debt.
135
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 $600 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 an additional $2.1 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.
Nevada
Power'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
2022
2023
2023
Electric
distribution
$
173
$
257
$
355
Electric transmission
61
110
183
Solar generation
47
257
286
Electric
battery storage
1
104
240
Other
241
374
520
Total
$
523
$
1,102
$
1,584
Nevada
Power received PUCN approval through its previous IRP filings for an increase in solar generation and electric transmission and through the fourth amendment to its 2021 Joint IRP filing for the addition of peaking turbines at a generating facility. Nevada Power has included estimates from its previous and latest IRP filings in its forecast capital expenditures for 2023. 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. Nevada Power has received approval from the PUCN to build a 350-mile, 525-kV transmission line connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
136
•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 or early 2024.
•Electric battery storage includes two growth projects consisting of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023 or early 2024. The second project is a 220-MW grid-tied battery energy storage system that will be developed on the site of the retired Reid Gardner generating facility in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Other includes both growth projects and operating expenditures. Growth projects primarily consist of an additional 400 MW of
peaking combustion turbines that will be developed at the Silverhawk generating facility in Clark County, Nevada. Commercial operation is expected by the third quarter of 2024. Operating expenditures consist of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
2021 Joint Integrated Resource Plan
In August 2023, the Nevada Utilities filed its Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part (1) to convert the existing coal fueled plant at North Valmy Generating Station to a cleaner natural gas fueled plant (2) to purchase, install, and operate a company-owned 400 MW solar plant along with
a 400 MW, four-hour battery storage system in Northern Nevada; (3) to continue operation of Tracy units 4 and 5 to 2049; (4) to purchase development assets for the 149 MW photovoltaic and 149 MW battery energy storage system Crescent Valley Solar project; (5) to construct the Esmeralda and Amargosa substations transformers; and (6) to construct the necessary infrastructure in the Apex Area Master Plan. The Nevada Utilities seek approval of approximately $1.8 billion in total costs of new projects of which Nevada Power's share is approximately $1.0 billion with an order expected in 2024.
Material Cash Requirements
As of September 30, 2023, 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, 2022, 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 air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer
to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
137
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, 2022. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2022.
138
Sierra
Pacific Power Company and its subsidiaries
Consolidated Financial Section
139
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, 2023, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 30, 2023 and 2022,
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, 2022, 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 24, 2023, 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, 2022, 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
i138
i110
Allowance
for equity funds
(i10)
(i5)
Changes
in regulatory assets and liabilities
i6
(i9)
Deferred
income taxes and amortization of investment tax credits
(i38)
i22
Deferred
energy
i40
(i203)
Amortization of deferred energy
i77
i66
Other,
net
i—
i3
Changes in other operating assets and liabilities:
Trade
receivables and other assets
(i2)
(i32)
Inventories
(i31)
(i11)
Accrued
property, income and other taxes
(i1)
(i9)
Accounts
payable and other liabilities
i16
i74
Net
cash flows from operating activities
i306
i106
Cash
flows from investing activities:
Capital expenditures
(i284)
(i278)
Net
cash flows from investing activities
(i284)
(i278)
Cash
flows from financing activities:
Proceeds from long-term debt
i394
i248
Repayments
of long-term debt
(i250)
i—
Long-term debt reacquired
i—
(i265)
Net
repayments of short-term debt
i—
(i39)
Dividends
paid
(i100)
(i70)
Contributions from parent
i—
i340
Repayments
of affiliate note payable
(i70)
i—
Other, net
(i6)
(i5)
Net
cash flows from financing activities
(i32)
i209
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i10)
i37
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i56
i16
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i46
$
i53
The
accompanying notes are an integral part of these consolidated financial statements.
144
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, 2023, and for the three- and nine-month periods ended September 30, 2023 and 2022. 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, 2023 and 2022. The results of operations for the three- and nine-month periods ended September 30, 2023, 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, 2022, 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, 2023.
(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 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 on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
During
2022, Sierra Pacific revised its electric and gas depreciation rates effective January 2023 based on the results of a new depreciation study, the most significant impact of which was shorter average service lives for intangible software. The net effect of this change along with various changes to the average service lives of other utility plant groups will increase depreciation and amortization expense by $i19 million annually
based on depreciable plant balances at the time of the change.
(4) iRecent Financing Transactions
Long-Term Debt
In September 2023, Sierra Pacific issued $i400 million
of its i5.900% General and Refunding Mortgage Bonds, Series 2023A, due March 2054. Sierra Pacific used the net proceeds to repay short-term borrowings incurred under Sierra Pacific's revolving credit facility in connection with the redemption in August 2023 of its i3.375%
General and Refunding Mortgage Notes, Series T, due 2023, fund capital expenditures and for general corporate purposes.
Credit Facilities
In June 2023, Sierra Pacific amended its existing $i250 million secured credit facility expiring in June 2025. The amendment increased the commitment of the lenders to $i400 million
and extended the expiration date to June 2026.
(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 (benefit) is as follows:
Effects
of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to 2017 tax reform 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 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 period ended September 30, 2023, Sierra Pacific made net cash payments for federal income tax to BHE totaling $i54
million. For the nine-month period ended September 30, 2022, Sierra Pacific made ino 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 $i3
million to the Other Post Retirement Plans for the nine-month period ended September 30, 2023. 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.
147
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, 2023 a net regulatory asset of $i12 million was recorded related to the net derivative liability of $i12
million. As of December 31, 2022 a net regulatory asset of $i13 million was recorded related to the net derivative liability of $i13
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
2023
2022
Electricity purchases
Megawatt hours
i—
i1
Natural
gas purchases
Decatherms
i70
i52
/
Credit
Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product
netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
148
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, 2023, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
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, 2023 and December 31, 2022, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(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.
149
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):
Derivative
contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Sierra Pacific transacts. When quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market
data exists for these contracts, Sierra Pacific uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Sierra Pacific's nonperformance risk on its liabilities, which as of September 30, 2023 and December 31, 2022, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.
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.
150
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
(i8)
i1
(i45)
(i25)
Settlements
i32
i36
i46
i41
Ending
balance
$
(i12)
$
(i17)
$
(i12)
$
(i17)
/
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 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.
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal
course of business. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
151
(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.
/
153
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 2023 and 2022
Overview
Net
income for the third quarter of 2023 was $64 million, an increase of $5 million, or 8%, compared to 2022 primarily due to higher utility margin, higher allowance for equity funds, primarily due to increased construction work-in-progress, partially offset by higher depreciation and amortization, mainly due to increased plant placed in-service and higher regulatory amortizations. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, partially offset by lower customer volumes and lower transmission and wholesale revenue. Electric retail customer volumes, including distribution only service customers, decreased by 4% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated decreased 12% for the third quarter of 2023 compared to 2022 primarily due to lower coal-fueled generation and lower natural gas-fueled generation.
Wholesale electricity sales volumes decreased 39% and purchased electricity volumes increased 28%.
Net income for the first nine months of 2023 was $111 million, an increase of $11 million, or 11%, compared to 2022 primarily due to higher utility margin, higher interest and dividend income, primarily from carrying charges on regulatory balances and higher allowances for borrowed and equity funds, primarily due to increased construction work-in-progress, partially offset by higher depreciation and amortization, mainly due to increased plant placed in-service and higher regulatory amortizations, and increased operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and increased customer service operations expenses. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective
January 2023 and higher transmission and wholesale revenue, partially offset by lower customer volumes. Electric retail customer volumes, including distribution only service customers, decreased by 3% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated decreased 2% for the first nine months of 2023 compared to 2022 primarily due to lower coal-fueled generation offset by higher natural gas-fueled generation. Wholesale electricity sales volumes decreased 20% and purchased electricity volumes decreased 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.
154
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
2023
2022
Change
2023
2022
Change
Electric utility margin:
Operating
revenue
$
345
$
310
$
35
11
%
$
942
$
767
$
175
23
%
Cost
of fuel and energy
178
153
25
16
538
406
132
33
Electric utility margin
167
157
10
6
%
404
361
43
12
%
Natural
gas utility margin:
Operating revenue
27
20
7
35
%
167
100
67
67
%
Natural
gas purchased for resale
17
10
7
70
123
60
63
*
Natural gas utility margin
10
10
—
—
%
44
40
4
10
%
Utility
margin
177
167
10
6
%
448
401
47
12
%
Operations
and maintenance
47
50
(3)
(6)
%
152
138
14
10
%
Depreciation and amortization
46
37
9
24
138
110
28
25
Property
and other taxes
6
6
—
—
19
18
1
6
Operating income
$
78
$
74
$
4
5
%
$
139
$
135
$
4
3
%
* Not
meaningful
155
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
Third
Quarter
First Nine Months
2023
2022
Change
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
345
$
310
$
35
11
%
$
942
$
767
$
175
23
%
Cost
of fuel and energy
178
153
25
16
538
406
132
33
Utility margin
$
167
$
157
$
10
6
%
$
404
$
361
$
43
12
%
Sales
(GWhs):
Residential
752
834
(82)
(10)
%
2,023
2,070
(47)
(2)
%
Commercial
847
910
(63)
(7)
2,303
2,388
(85)
(4)
Industrial
693
712
(19)
(3)
2,010
2,188
(178)
(8)
Other
3
3
—
—
9
10
(1)
(10)
Total
fully bundled(1)
2,295
2,459
(164)
(7)
6,345
6,656
(311)
(5)
Distribution only service
744
700
44
6
2,082
2,037
45
2
Total
retail
3,039
3,159
(120)
(4)
8,427
8,693
(266)
(3)
Wholesale
113
184
(71)
(39)
473
589
(116)
(20)
Total
GWhs sold
3,152
3,343
(191)
(6)
%
8,900
9,282
(382)
(4)
%
Average
number of retail customers (in thousands)
376
372
4
1
%
375
370
5
1
%
Average
revenue per MWh:
Retail - fully bundled(1)
$
141.30
$
114.38
$
26.92
24
%
$
137.85
$
105.18
$
32.67
31
%
Wholesale
$
97.06
$
93.37
$
3.69
4
%
$
88.84
$
67.18
$
21.66
32
%
Heating
degree days
56
37
19
51
%
3,294
2,735
559
20
%
Cooling degree days
956
1,133
(177)
(16)
%
1,091
1,347
(256)
(19)
%
Sources
of energy (GWhs)(2):
Natural gas
1,200
1,283
(83)
(6)
%
3,161
2,980
181
6
%
Coal
225
335
(110)
(33)
578
840
(262)
(31)
Renewables
8
8
—
—
21
21
—
—
Total
energy generated
1,433
1,626
(193)
(12)
3,760
3,841
(81)
(2)
Energy purchased
1,832
1,432
400
28
3,882
4,055
(173)
(4)
Total
3,265
3,058
207
7
%
7,642
7,896
(254)
(3)
%
Average
cost of energy per MWh(3):
Energy generated
$
31.94
$
29.41
$
2.53
9
%
$
64.29
$
43.56
$
20.73
48
%
Energy
purchased
$
72.52
$
73.26
$
(0.74)
(1)
%
$
76.34
$
58.92
$
17.42
30
%
(1) Fully
bundled includes sales to customers for combined energy, transmission and distribution services.
(2) GWh amounts are net of energy used by the related generating facilities.
(3) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
156
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
Electric utility margin increased$10 million, or 6%, for the third quarter of 2023 compared to 2022 primarily due to:
•$13 million of higher electric retail utility margin primarily due to higher retail rates from the 2022 regulatory rate review with new rates effective January 2023, offset by lower retail customer volumes. Retail customer volumes, including distribution only service
customers, decreased 3.8% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers.
The increase in electric utility margin was offset by:
•$2 million of lower transmission and wholesale revenue.
Operations and maintenance decreased $3 million, or 6%, for the third quarter of 2023 compared to 2022 primarily due to lower regulatory-approved amortization from the recovery for the ON Line reallocation (offset in operating revenue) and lower plant operations and maintenance expenses, partially offset by lower regulatory credits from the deferral of the ON Line lease cost reallocation in 2022.
Depreciation and amortization increased $9
million, or 24%, for the third quarter of 2023 compared to 2022 primarily due to increased plant placed in-service and higher regulatory amortizations.
Allowance for equity funds increased $4 million for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress.
Income tax expense increased $2 million, or 25%, for the third quarter of 2023 compared to 2022 primarily due to higher pretax income. The effective tax rate was 14% in 2023 and 12% in 2022.
157
First
Nine Months of 2023 Compared to First Nine Months of 2022
Electric utility margin increased$43 million, or 12%, for the first nine months of 2023 compared to 2022 primarily due to:
•$41 million of higher electric retail utility margin primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 3.1% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and
•$4
million of higher transmission and wholesale revenue.
Natural gas utility margin increased $4 million, or 10%, for the first nine months of 2023 compared to 2022 primarily due to higher customer volumes from the favorable impact of weather.
Operations and maintenance increased $14 million, or 10%, for the first nine months of 2023 compared to 2022 primarily due to increased plant operations and maintenance expenses, lower regulatory credits from the deferral of the ON Line lease cost reallocation in 2022 and higher customer service operations expenses, partially offset by lower regulatory-approved amortization from the recovery for the ON Line reallocation (offset in operating revenue).
Depreciation and amortization
increased $28 million, or 25%, for the first nine months of 2023 compared to 2022 primarily due to higher plant placed in-service and higher regulatory amortizations.
Interest expense increased $5 million, or 12%, for the first nine months of 2023 compared to 2022 primarily due to higher long-term debt and higher average interest rate.
Allowance for borrowed funds increased $3 million for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress.
Allowance for equity funds increased $5 million for the first nine months of 2023 compared to 2022 primarily due to higher construction work-in-progress.
Interest
and dividend income increased $6 million, or 50%, for the first nine months of 2023 compared to 2022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Income tax expense increased $2 million, or 13%, for the first nine months of 2023 compared to 2022 primarily due to higher pretax income. The effective tax rate was 13% in 2023 and 2022.
Liquidity and Capital Resources
As of September 30, 2023, Sierra Pacific's total net liquidity was as follows (in millions):
Cash
and cash equivalents
$
39
Credit facility
400
Total
net liquidity
$
439
Credit facility:
Maturity date
2026
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022, were $306 million and $106 million, respectively. The change was primarily due to higher collections from customers and the timing of payments for operating
costs, partially offset by increased income tax payments, higher payments related to fuel and energy costs, decreased customer deposits and higher interest payments.
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 made for each payment date.
158
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022, were $(284) million and $(278) 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, 2023 and 2022, were $(32) million and $209 million, respectively. The change was primarily due to lower contributions from NV Energy, Inc., higher repayments of long-term debt, higher repayments of an affiliate note payable and higher dividends paid to NV Energy, Inc., partially offset by lower long-term debt reacquired, higher proceeds from the issuance of long-term debt and lower repayments of short-term debt.
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 $400 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.
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.
Sierra Pacific'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
2022
2023
2023
Electric
distribution
$
84
$
120
$
179
Electric transmission
69
67
104
Solar generation
—
1
2
Electric
battery storage
—
2
2
Other
125
94
135
Total
$
278
$
284
$
422
159
Sierra
Pacific received PUCN approval through its previous 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 2023. 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. Sierra Pacific has received approval from the PUCN to
build a 350-mile, 525-kV transmission line connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. 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.
2021
Joint Integrated Resource Plan
In August 2023, the Nevada Utilities filed its Joint Application for approval of the Fifth Amendment to the 2021 Joint Integrated Resource Plan. The Fifth Amendment seeks, in part (1) to convert the existing coal fueled plant at North Valmy Generating Station to a cleaner natural gas fueled plant (2) to purchase, install, and operate a company-owned 400 MW solar plant along with a 400 MW, four-hour battery storage system in Northern Nevada; (3) to continue operation of Tracy units 4 and 5 to 2049; (4) to purchase development assets for the 149 MW photovoltaic and 149 MW battery energy storage system Crescent Valley Solar project; (5) to construct the Esmeralda and Amargosa substations transformers; and (6) to construct the necessary infrastructure in the Apex Area Master Plan. The Nevada Utilities seek approval of approximately $1.8 billion in total costs
of new projects of which Sierra Pacific's share is approximately $0.8 billion with an order expected in 2024.
Material Cash Requirements
As of September 30, 2023, there have been no material changes outside the normal course of business in material 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, 2022.
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.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines,
injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
160
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, 2022. There
have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2022.
161
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
162
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, 2023, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2023 and 2022, and of cash flows for the nine-month periods ended September 30, 2023 and 2022, 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, 2022, 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 24, 2023, 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, 2022, 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:
(Gains) losses on other items, net
(i5)
i2
Depreciation
and amortization
i240
i241
Allowance for equity funds
(i6)
(i5)
Equity
loss (income), net of distributions
i16
(i46)
Changes
in regulatory assets and liabilities
(i97)
i37
Deferred
income taxes
i267
i99
Other, net
(i3)
i7
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i84
(i48)
Receivables
from affiliates
i10
i33
Gas
balancing activities
i22
(i48)
Derivative
collateral, net
i1
(i3)
Accrued
property, income and other taxes
(i194)
i8
Accounts
payable to affiliates
i9
(i18)
Accounts
payable and other liabilities
(i2)
i53
Net
cash flows from operating activities
i982
i1,035
Cash
flows from investing activities:
Capital expenditures
(i241)
(i252)
Proceeds
from assignment of shale development rights
i8
i—
Repayment
of notes by affiliates
i734
i31
Notes
to affiliates
(i198)
(i363)
Other,
net
(i2)
(i11)
Net
cash flows from investing activities
i301
(i595)
Cash
flows from financing activities:
Repayments of long-term debt
(i250)
i—
Proceeds
from equity contributions
i2,876
i—
Purchase
of Cove Point noncontrolling interest
(i3,300)
i—
Distributions
to noncontrolling interests
(i353)
(i388)
Distributions to parent
(i226)
i—
Other,
net
i—
(i4)
Net
cash flows from financing activities
(i1,253)
(i392)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i30
i48
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i95
i39
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i125
$
i87
The
accompanying notes are an integral part of these consolidated financial statements.
169
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 transmission systems and underground storage operations in the eastern region of the U.S. and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. On September 1, 2023, Eastern Energy Gas completed its acquisition of i50% of the limited partner interests in
Cove Point from Dominion Energy, Inc. ("DEI"), and accordingly, owns an aggregate of i75% of the limited partner interests and continues to own i100% of the general partner interest of 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 transmission system. Eastern Energy Gas is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc.
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, 2023 and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month
periods ended September 30, 2023 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, 2022 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, 2023.
(2) iBusiness
Acquisitions
On September 1, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), a wholly owned subsidiary of Eastern Energy Gas, completed the acquisition of DECP Holdings, Inc.'s (the "Seller"), an indirect wholly owned subsidiary of Dominion Energy, Inc., i50% limited partner interests in Cove Point ("The Transaction").
Under the terms of the Purchase and Sale Agreement, dated July 9, 2023 (the "Purchase Agreement"), the Buyer paid $i3.3 billion in cash, plus the pro rata portion of the quarterly distribution made by Cove Point for the third fiscal quarter of 2023. Eastern Energy Gas funded the Transaction through cash provided by BHE GT&S, LLC, which included an equity contribution of $i2.9 billion
and the repayment of affiliated notes of $i474 million. The Buyer now owns an aggregate of i75%
of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, continues to own i100% of the general partner interest, of Cove Point. Prior to the Transaction, Eastern Energy Gas owned i100%
of the general partner interest and i25% of the limited partner interests in Cove Point. Eastern Energy Gas previously determined it has the power to direct the activities that most significantly impact Cove Point's economic performance as well as the obligation to absorb losses and benefits which could be significant to it and accordingly, consolidated Cove Point. Because Eastern Energy Gas controls Cove Point both before and after the Transaction, the changes in Eastern Energy Gas' ownership interest in Cove Point were accounted for as an equity transaction
and no gain or loss was recognized. In connection with the Transaction, Eastern Energy Gas recognized $i120 million of income taxes in equity primarily attributable to the step up in tax basis of the investment in Cove Point of $i144 million,
partially offset by establishing additional regulatory liabilities related to excess deferred income taxes of $i24 million.
170
(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
2023
2022
Utility plant:
Interstate natural gas transmission and storage assets
i21
- i51 years
$
i9,197
$
i8,922
Intangible
plant
i5 - i17 years
i117
i113
Utility
plant in-service
i9,314
i9,035
Accumulated
depreciation and amortization
(i3,162)
(i3,039)
Utility
plant in-service, net
i6,152
i5,996
Nonutility
plant:
LNG facility
i40 years
i4,525
i4,522
Intangible
plant
i14 years
i25
i25
Nonutility
plant
i4,550
i4,547
Accumulated
depreciation and amortization
(i634)
(i542)
Nonutility
plant, net
i3,916
i4,005
i10,068
i10,001
Construction
work-in-progress
i276
i201
Property,
plant and equipment, net
$
i10,344
$
i10,202
/
Construction
work-in-progress includes $i260 million and $i181 million as of September 30,
2023 and December 31, 2022, respectively, related to the construction of utility plant.
Assignment of Shale Development Rights
In June 2023, Eastern Gas Transmission and Storage, Inc. ("EGTS") conveyed development rights to a natural gas producer for approximately i6,500 acres of Utica Shale and Point Pleasant Formation underneath one of its natural gas storage fields and received proceeds of $i8 million
and an overriding royalty interest in gas produced from the acreage. This transaction resulted in an $i8 million ($i6 million
after-tax) gain, included in operations and maintenance expense in its Consolidated Statements of Operations.
(4) 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 proposed an annual
cost-of-service of approximately $i1.1 billion, and requested increases in various rates, including general system storage rates by i85% and general system transmission rates
by i60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual
firm transmission and storage services revenues of approximately $i160 million and a decrease in annual depreciation expense of approximately $i30
million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $i91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.
171
(5) 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
$
i295
$
i308
Reflected
as:
Other current assets
$
i31
$
i30
Noncurrent
assets
i264
i278
Total
investments and restricted cash and cash equivalents
$
i295
$
i308
/
Equity
Method Investments
Eastern Energy Gas, through subsidiaries, owns i50% of Iroquois, which owns and operates an interstate natural gas transmission system located in the states of New York and Connecticut.
As of September 30, 2023 and December 31, 2022, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in net assets
by $ii130/ million.
The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas received distributions from its investments of $i59 million and $i34 million
for the nine-month periods ended September 30, 2023 and 2022, respectively. In the third quarter of 2022, in connection with the settlement of regulated tax matters in the Iroquois rate case, Eastern Energy Gas released a long-term regulatory liability and recognized a $i45 million benefit that was recorded in equity income (loss) in its Consolidated Statements of Operations.
172
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 on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Restricted
cash and cash equivalents included in other current assets
i31
i30
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i125
$
i95
(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 (benefit) is as follows:
State
income tax, net of federal income tax benefit
(i8)
i6
(i1)
i5
Equity
interest
i1
i4
i1
i2
Effects
of ratemaking
i—
i—
i—
(i1)
Noncontrolling
interest
(i10)
(i10)
(i10)
(i10)
Other,
net
(i1)
i—
i—
i—
Effective
income tax rate
i3
%
i21
%
i11
%
i17
%
/
For
the period ended September 30, 2023, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by the change in the state apportionment and its impact on Eastern Energy Gas' deferred tax liability, as well as the Transaction's impact on certain combined state filing adjustments. An additional rate driver was the absence of tax on income attributable to Cove Point's i25% noncontrolling
interest.
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' 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 current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $i241 million and $i16 million
as of September 30, 2023 and December 31, 2022, respectively. The increase in the income tax receivable is primarily due to the bonus deprecation deduction being taken on the step-up of tax basis on non-regulated assets as a result of the Transaction.
173
(7) 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 $i6 million
and $i10 million to the MidAmerican Energy Company Retirement Plan for the nine-month periods ended September 30, 2023 and 2022, respectively, and $i1 million
and $i2 million to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month periods ended September 30, 2023 and 2022, respectively. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to Eastern Energy Gas were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory
assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net. As of September 30, 2023 and December 31, 2022, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $ii51/
million.
(8) 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.
174
i
The
following table presents Eastern Energy Gas' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Eastern
Energy Gas' investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Eastern Energy Gas transacts. When quoted prices for identical contracts are not available, Eastern Energy Gas uses forward price curves. Forward price curves represent Eastern Energy Gas' estimates of the prices at which a buyer or seller could
contract today for delivery or settlement at future dates. Eastern Energy Gas bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by Eastern Energy Gas. Market price quotations are generally readily obtainable for the applicable term of Eastern Energy Gas' outstanding derivative contracts; therefore, Eastern Energy Gas' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, Eastern Energy Gas uses forward price curves derived from internal models based
on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
175
Eastern Energy Gas' long-term debt is carried at cost 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 subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Eastern Energy Gas is party to a variety of legal actions arising out of the normal course of business. Eastern Energy Gas does not believe that such normal and routine litigation will have a material impact
on its consolidated financial results.
(10) 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.
/
Eastern Energy Gas has recognized contract liabilities of $i28 million and $i80
million as of September 30, 2023 and December 31, 2022, respectively, due to the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern Energy Gas recognizes revenue as it fulfills its obligations to provide services to its customers. During the nine-month period ended September 30, 2023, Eastern Energy Gas recognized revenue of $i51 million from the beginning contract liability balance.
176
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, 2023 (in millions):
Performance
obligations expected to be satisfied
Less than 12 months
More than 12 months
Total
Eastern Energy Gas
$
i1,657
$
i14,744
$
i16,401
/
(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):
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 2023 and 2022
Overview
Net income attributable to Eastern Energy Gas for the third quarter of 2023 was $92 million, a decrease of $59 million, or 39%, compared to 2022. Net income decreased primarily due to a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case, lower margin from EGTS' regulated gas transmission and storage operations of $38 million, an increase in operations and maintenance expense excluding Cove Point of $23 million and lower net income at Cove Point as a result of increased scheduled maintenance days in 2023 of $12 million, partially offset by lower income tax expense primarily due to lower pre-tax income.
Net
income attributable to Eastern Energy Gas for the first nine months of 2023 was $313 million, a decrease of $35 million, or 10%, compared to 2022. Net income decreased primarily due to a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case, lower margin from EGTS' regulated gas transmission and storage operations of $30 million, an increase in salaries, wages and benefits and higher technology and related charges, partially offset by lower income tax expense primarily due to lower pre-tax income and interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement.
Operating
revenue decreased $72 million, or 13%, for the third quarter of 2023 compared to 2022, primarily due to a decrease in Cove Point LNG variable revenue of $41 million, decreased LNG service as a result of increased scheduled maintenance days of $29 million, a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $9 million and a decrease in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $5 million, partially offset by derivative losses in 2022 of $6 million and an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $5 million.
Cost of (excess) gas was an expense of $6 million for the third
quarter of 2023 compared to a credit of $24 million for the third quarter of 2022. The change is primarily from a decrease in other operational and system balancing fuel activities prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $25 million and an increase in volumes sold of $5 million.
Operations and maintenance increased $40 million, or 34%, for the third quarter of 2023 compared to 2022, primarily due to an increase in outside services of $12 million, an increase in the cost of materials of $11 million, an increase in salaries, wages and benefits of $7 million, Cove Point planned outage costs of $6 million and higher technology and related charges of $5 million.
Depreciation and amortization increased
$4 million, or 5%, for the third quarter of 2023 compared to 2022, primarily due to a 2022 amortization true-up as a result of the settlement of depreciation rates in EGTS' general rate case of $2 million and higher plant placed in-service of $2 million.
Interest and dividend income increased $5 million for the third quarter of 2023 compared to 2022, primarily due to income from money market mutual fund investments of $3 million and interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement of $2 million.
Income tax expense decreased $59 million, or 92%, for the third quarter of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 3% for 2023
and 21% for 2022. The effective tax rate decreased primarily due to the impacts from the Transaction and various changes in the state effective rate.
Equity income decreased $47 million, or 90%, for the third quarter of 2023 compared to 2022, primarily due to a benefit in 2022 from the settlement of regulated tax matters in the Iroquois rate case.
178
Net income attributable to noncontrolling interests decreased $68 million, or 47%, for the third quarter of 2023 compared to 2022, primarily due to lower net income attributable to Cove Point of $63 million and the acquisition of DEI's 50% noncontrolling interest
in Cove Point of $5 million.
First Nine Months of 2023 Compared to First Nine Months of 2022
Operating revenue increased $16 million, or 1%, for the first nine months of 2023 compared to 2022, primarily due to an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $45 million, increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022 of $42 million, an increase in variable revenue related to park and loan activity of $22 million and derivative losses in 2022 of $13 million, partially offset by a decrease in Cove Point LNG variable revenue
of $49 million, decreased LNG service as a result of increased scheduled maintenance days of $29 million and a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $26 million.
Cost of (excess) gas was an expense of $31 million for the first nine months of 2023 compared to a credit of $46 million for the first nine months of 2022. The change is primarily from a decrease from other operational and system balancing fuel activities prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $39 million, the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of $35 million, and an increase in volumes sold of $5 million.
Operations
and maintenance increased $75 million, or 21%, for the first nine months of 2023 compared to 2022, primarily due to an increase in salaries, wages and benefits of $25 million, higher technology and related charges of $16 million, an increase in outside services of $12 million, Cove Point planned outage costs of $6 million and various other immaterial items, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.
Property and other taxes decreased $3 million, or 3%, for the first nine months of 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.
Interest and dividend income increased $25 million for the first nine months
of 2023 compared to 2022, primarily due to interest income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement of $17 million and income from money market mutual fund investments of $8 million.
Income tax expense decreased $56 million, or 43%, for the first nine months of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 11% for 2023 and 17% for 2022. The effective tax rate decreased primarily due to the impacts from the Transaction and various changes in the state effective rate.
Equity income decreased $37 million, or 46%, for the first nine months of 2023 compared to 2022, primarily due to a benefit in 2022 from the settlement of regulated tax matters
in the Iroquois rate case of $45 million, offset by higher earnings from Iroquois due to favorable negotiated rate agreements and hedges of $8 million.
Net income attributable to noncontrolling interests decreased $48 million, or 13%, for the first nine months of 2023 compared to 2022, primarily due to lower net income attributable to Cove Point of $43 million and the acquisition of DEI's 50% noncontrolling interest in Cove Point of $5 million.
Liquidity and Capital Resources
As of September 30, 2023, Eastern Energy Gas' total
net liquidity was as follows (in millions):
Cash and cash equivalents
$
94
Intercompany revolving credit agreement
400
Total
net liquidity
$
494
Intercompany revolving credit agreement:
Maturity date
2024
179
Operating Activities
Net cash flows from operating activities for the nine-month periods
ended September 30, 2023 and 2022 were $982 million and $1.0 billion, respectively. The change is primarily due to the timing of income tax payments and the repayment of EGTS rate refunds to customers, partially offset by other changes in working capital.
The timing of Eastern Energy Gas' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods elected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2023
and 2022 were $301 million and $(595) million, respectively. The change is primarily due to an increase in repayments of loans by affiliates of $703 million, a decrease in loans to its parent under an intercompany revolving credit agreement of $165 million, a decrease in capital expenditures of $11 million and proceeds from the assignment of shale development rights of $8 million.
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2023 were $(1.3) billion. Uses of cash totaled $4.1 billion and consisted of $3.3 billion for the purchase of Cove Point noncontrolling interest, distributions to noncontrolling interests from Cove Point of $352 million,
repayment of long-term debt of $250 million and distributions to its indirect parent, BHE, of $227 million. Sources of cash totaled $2.9 billion and consisted of proceeds from equity contributions to fund the Transaction.
For a discussion of business acquisitions, refer to Note 2 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, 2022 were $(392) million and consisted primarily of distributions to noncontrolling interests from Cove Point.
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 transmission 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, new growth projects and the timing of growth projects; 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.
180
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
2022
2023
2023
Natural gas transmission and storage
$
36
$
17
$
32
Other
216
224
338
Total
$
252
$
241
$
370
Natural
gas transmission and storage primarily includes growth capital expenditures related to planned regulated projects. Other includes primarily nonregulated and routine capital expenditures for natural gas transmission, storage and LNG terminalling infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of September 30, 2023, 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, 2022.
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 air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with
the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Eastern Energy Gas is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in 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, 2022. There have been no significant changes in Eastern Energy
Gas' assumptions regarding critical accounting estimates since December 31, 2022.
181
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Consolidated Financial Section
182
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, 2023, 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, 2023 and 2022, and of cash flows for the nine-month periods ended September 30, 2023 and 2022, 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, 2022 and the related consolidated statements of operations, comprehensive income (loss), changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023 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, 2022, 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:
(Gains) losses on other items, net
(i8)
i1
Depreciation
and amortization
i112
i115
Allowance for equity funds
(i4)
(i3)
Changes
in regulatory assets and liabilities
(i79)
i35
Deferred
income taxes
i50
i58
Other, net
(i5)
i5
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i35
i34
Receivables
from affiliates
i5
i3
Gas
balancing activities
i26
(i47)
Accrued
property, income and other taxes
(i21)
(i1)
Accounts
payable and other liabilities
i24
i34
Accounts
payable to affiliates
i11
i7
Net
cash flows from operating activities
i317
i448
Cash
flows from investing activities:
Capital expenditures
(i163)
(i179)
Proceeds
from assignment of shale development rights
i8
i—
Repayment
of notes by affiliates
i—
i11
Notes
to affiliates
i—
(i8)
Other,
net
(i4)
(i9)
Net
cash flows from investing activities
(i159)
(i185)
Cash
flows from financing activities:
Repayment of notes payable to affiliates, net
(i21)
(i53)
Dividends
paid
(i141)
(i172)
Net
cash flows from financing activities
(i162)
(i225)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i4)
i38
Cash
and cash equivalents and restricted cash and cash equivalents at beginning of period
i45
i26
Cash
and cash equivalents and restricted cash and cash equivalents at end of period
$
i41
$
i64
The
accompanying notes are an integral part of these consolidated financial statements.
189
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 systems and underground storage. EGTS' operations include transmission assets located in Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. EGTS also operates one of the nation's largest underground natural gas storage systems located in New York, Pennsylvania and West Virginia. EGTS is a wholly owned subsidiary of Eastern Energy Gas Holdings, LLC ("Eastern Energy Gas"), which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc.
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, 2023 and for the three- and nine-month periods ended September 30, 2023 and 2022. The results of operations for the three- and nine-month
periods ended September 30, 2023 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 EGTS' Annual Report on Form 10-K for the year ended December 31, 2022 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, 2023.
(2) 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
2023
2022
Interstate natural gas transmission and storage assets
i28
- i50 years
$
i6,946
$
i6,724
Intangible
plant
i12 - i19 years
i81
i79
Plant
in-service
i7,027
i6,803
Accumulated
depreciation and amortization
(i2,533)
(i2,440)
i4,494
i4,363
Construction
work-in-progress
i205
i141
Property,
plant and equipment, net
$
i4,699
$
i4,504
/
Assignment
of Shale Development Rights
In June 2023, EGTS conveyed development rights to a natural gas producer for approximately i6,500 acres of Utica Shale and Point Pleasant Formation underneath one of its natural gas storage fields and received proceeds of $i8 million
and an overriding royalty interest in gas produced from the acreage. This transaction resulted in an $i8 million ($i6 million
after-tax) gain, included in operations and maintenance expense in its Consolidated Statements of Operations.
190
(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 proposed an annual cost-of-service of approximately $i1.1 billion, and requested increases in various rates, including general system storage rates by i85%
and general system transmission rates by i60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS'
rates result in an increase to annual firm transmission and storage services revenues of approximately $i160 million and a decrease in annual depreciation expense of approximately $i30
million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $i91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.
(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
$
i47
$
i43
Reflected
as:
Current assets
$
i29
$
i29
Noncurrent
assets
i18
i14
Total
investments and restricted cash and cash equivalents
$
i47
$
i43
/
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 on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i41
$
i45
191
(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 (benefit) is as follows:
State
income tax, net of federal income tax benefit
i6
i11
i5
i8
Other,
net
i—
i1
i—
i—
Effective
income tax rate
i27
%
i33
%
i26
%
i29
%
/
(6) 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 $i5 million and $i9 million
to the MidAmerican Energy Company Retirement Plan for the nine-month periods ended September 30, 2023 and 2022, respectively, and $i1 million and $i2 million
to the MidAmerican Energy Company Welfare Benefit Plan for the nine-month periods ended September 30, 2023 and 2022, respectively. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to EGTS were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. As of September 30, 2023 and December 31, 2022, EGTS' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities
on the Consolidated Balance Sheets was $ii47/
million.
(7) 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.
192
i
The following table
presents EGTS' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
EGTS'
investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which EGTS transacts. When quoted prices for identical contracts are not available, EGTS uses forward price curves. Forward price curves represent EGTS' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. EGTS
bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by EGTS. Market price quotations are generally readily obtainable for the applicable term of EGTS' outstanding derivative contracts; therefore, EGTS' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, EGTS uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative
contracts is a function of underlying forward commodity prices, related volatility, counterparty creditworthiness and duration of contracts.
EGTS' long-term debt is carried at cost 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 subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. EGTS believes it is in material compliance with all applicable laws and regulations.
Legal Matters
EGTS is party to a variety of legal actions arising out of the normal course of business. EGTS does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
(9) 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, 2023 (in millions):
Performance obligations expected to be satisfied
Less than 12
months
More than 12 months
Total
EGTS
$
i764
$
i3,171
$
i3,935
/
194
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 2023 and 2022
Overview
Net income for the third quarter of 2023 was $44 million, a decrease of $37 million, or 46%, compared to 2022. Net income decreased primarily due to lower margin from regulated gas transmission and storage operations of $38 million, an increase in outside services, higher technology and related charges and an increase in salaries, wages and benefits, partially offset by lower income tax expense primarily due to lower pre-tax income.
Net income for the first nine months of 2023 was $171 million, a decrease of $36 million, or 17%, compared to 2022. Net income decreased primarily due to lower margin from regulated gas transmission and storage
operations of $30 million, higher technology and related charges and an increase in salaries, wages and benefits, partially offset by lower income tax expense primarily due to lower pre-tax income.
Operating revenue decreased $7 million, or 3%, for the third quarter of 2023 compared to 2022, primarily due to a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $9 million and a decrease in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate
case of $5 million, partially offset by derivative losses in 2022 of $6 million and an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $5 million.
Cost of (excess) gas was an expense of $6 million for the third quarter of 2023 compared to a credit of $25 million for the third quarter of 2022. The change is primarily from a decrease in other operational and system balancing fuel activities prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $25 million and an increase in volumes sold of $5 million.
Operations and maintenance increased $19 million, or 24%, for the third quarter of 2023 compared to 2022, primarily due to an increase in outside
services of $9 million, higher technology and related charges of $5 million and an increase in salaries, wages and benefits of $3 million.
Depreciation and amortization increased $4 million, or 12%, for the third quarter of 2023 compared to 2022, primarily due to a 2022 amortization true-up as a result of the settlement of depreciation rates in EGTS' general rate case of $2 million and higher plant placed in-service of $2 million.
Income tax expense decreased $23 million, or 59%, for the third quarter of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 27% for 2023 and 33% for 2022. The effective tax rate decreased primarily due to the reduction in the state effective rate.
First
Nine Months of 2023 Compared to First Nine Months of 2022
Operating revenue increased $50 million, or 7%, for the first nine months of 2023 compared to 2022, primarily due to an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $45 million, an increase in variable revenue related to park and loan activity of $22 million, derivative losses in 2022 of $13 million and an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $5 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $26 million.
195
Cost
of (excess) gas was an expense of $31 million for the first nine months of 2023 compared to a credit of $49 million for the first nine months of 2022. The change is primarily from a decrease from other operational and system balancing fuel activities prior to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $39 million, the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of $35 million, and an increase in volumes sold of $5 million.
Operations and maintenance increased $43 million, or 17%, for the first nine months of 2023 compared to 2022, primarily due to higher technology and related charges of $15 million, an increase in salaries, wages and benefits of $12 million, an increase in outside services of $9 million
and various other immaterial items, partially offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.
Depreciation and amortization decreased $3 million, or 3%, for thefirst nine months of 2023 compared to 2022, primarily due to the settlement of depreciation rates in EGTS' general rate case of $6 million, partially offset by higher plant placed in-service of $3 million.
Property and other taxes decreased $4 million, or 10%, for the first nine months of 2023 compared to 2022, primarily due to lower than estimated 2022 tax assessments.
Other, net was
income of $2 million for the first nine months of 2023 compared to expense of $2 million for the first nine months of 2022. The change is primarily from gains on marketable securities of $3 million and income from money market mutual fund investments of $2 million.
Income tax expense decreased $27 million, or 31%, for the first nine months of 2023 compared to 2022, primarily due to lower pre-tax income and the effective tax rate was 26% for 2023 and 29% for 2022. The effective tax rate decreased primarily due to the reduction in the state effective rate.
Liquidity and Capital Resources
As
of September 30, 2023, EGTS' total net liquidity was as follows (in millions):
Cash and cash equivalents
$
12
Intercompany revolving credit agreement
400
Less:
Notes
payable to affiliates
15
Net intercompany revolving credit agreement
385
Total net liquidity
$
397
Intercompany credit agreement:
Maturity
date
2024
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2023 and 2022 were $317 million and $448 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers and other changes in working capital.
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 made for each payment date.
196
Investing
Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2023 and 2022 were $(159) million and $(185) million, respectively. The change is primarily due to a decrease in capital expenditures of $16 million, proceeds from the assignment of shale development rights of $8 million and a decrease in loans to affiliates of $8 million, partially offset by a decrease in repayments of loans by affiliates of $11 million.
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2023 were $(162)
million and consisted of dividends paid to Eastern Energy Gas of $141 million and net repayment of notes payable to Eastern Energy Gas of $21 million.
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.
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 transmission 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, new growth projects and the timing of growth projects; 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
2022
2023
2023
Natural gas transmission and storage
$
30
$
11
$
23
Other
149
152
213
Total
$
179
$
163
$
236
Natural
gas transmission and storage includes primarily growth capital expenditures related to planned regulated projects. Other includes primarily pipeline integrity work, automation and controls upgrades, underground storage, corrosion control, unit exchanges, compressor modifications and projects related to Pipeline Hazardous Materials Safety Administration natural gas storage rules. The amounts also include EGTS' asset modernization program, which includes projects for vintage pipeline replacement, compression replacement, pipeline assessment and underground storage integrity.
Material Cash Requirements
As of September 30, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of EGTS' Annual Report on Form 10-K for the
year ended December 31, 2022.
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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 air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. 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 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 Item 7 of EGTS' Annual Report on Form 10-K for the year ended December 31, 2022. There have been no significant changes in EGTS' assumptions regarding critical accounting estimates since December 31, 2022.
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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, 2022. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2022. 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, 2023.
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, 2023 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
The following disclosures reflect
material updates to legal proceedings and should be read in conjunction with Item 3 of Berkshire Hathaway Energy's and PacifiCorp's Annual Reports on Form 10-K for the year ended December 31, 2022.
BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
Multiple lawsuits, complaints and demands alleging similar claims have been filed in Oregon and California related to the Labor Day 2020 Wildfires, certain of which have been described below. Amounts sought in the lawsuits, complaints and demands filed in Oregon and in certain demands made in California total nearly $8 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the lawsuits and complaints filed in California do not specify damages sought and are excluded from this amount.
Multiple complaints have also been filed in California for the 2022 McKinney Fire. 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 11 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.
Jeanyne James et al. v. PacifiCorp and Consolidated Cases
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885,
in Multnomah County Circuit Court, Oregon ("James"). The complaint was filed by Oregon residents and businesses who sought to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain Complex, South Obenchain, 242 and Santiam Canyon fires, as well as to add claims for noneconomic damages. The amended complaint alleged that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020, and that PacifiCorp acted with gross negligence, among other things. The amended complaint sought the following damages for the
plaintiffs and the 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 demanded a trial by jury and reserved their right to further amend the complaint to allege claims for punitive damages. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated this case with others as described below. Plaintiffs' motion to bifurcate issues for trial between class-wide liability and individual
damages was also granted. PacifiCorp requested an immediate appeal of the issue class certification before the Oregon Court of Appeals. While in January 2023, the Oregon Court of Appeals denied PacifiCorp's request for immediate appeal of the class certification, PacifiCorp will appeal the class issues as a matter of right when the issues are finally decided by the Multnomah County Circuit Court. In February 2023, the plaintiffs filed a motion to amend the complaint to add punitive damages in an unspecified amount. On March 23, 2023, the plaintiffs filed an amended complaint seeking punitive damages with permission of the Multnomah County Circuit Court. Plaintiffs sought punitive damages at a five times multiplier to the amount of compensatory damages awarded. On April 24, 2023, the jury trial began in Multnomah County Circuit Court for the 17 named plaintiffs. In June
2023, the jury issued its verdict finding PacifiCorp liable to the 17 individual plaintiffs and to the class with respect to the four wildfires. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic and property damages, $68 million of noneconomic damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages. Under ORS 477.089, the economic and property damages awarded may be subject to doubling. In September 2023, the Multnomah County Circuit Court ordered trial dates for two consolidated jury trials including approximately 10 class members each and a third trial for certain commercial timber plaintiffs wherein plaintiffs in each of the three trials will present evidence regarding their damages. The trials are scheduled at various dates from January to April 2024. Hearings on PacifiCorp's post-trial motions are scheduled to be held November
9, 2023. Under ORS 82.010, interest at a rate of 9% per annum will accrue on the judgment commencing at the date the judgment is entered unless otherwise specified in the judgment. No judgment has yet been entered by the Multnomah County Circuit Court. PacifiCorp intends to appeal the jury's findings and damage awards in the James case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.
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On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21CV33595, ("Salter"), in Multnomah County Circuit Court,
Oregon, in which two complaints, Case No. 21CV09339 and Case No. 21CV09520, previously filed in Marion County Circuit Court, 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 to add a claim for punitive damages. In May 2022, the Salter case was consolidated with the James case (described above).
In October 2020, the case Amy Allen, et al. v. PacifiCorp, Case No. 20CV37430
("Allen") was filed in Multnomah County Circuit Court, Oregon. The Allen case was filed by five individuals as amended in September 2021 claiming in excess of $32 million in economic and noneconomic damages related to the Beachie Creek fire, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest. In May 2022, the Allen case was consolidated with the James case (described above).
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 ("Dietrich"), in Multnomah County Circuit Court, 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 Canyon, Beachie Creek, Lionshead, Echo Mountain Complex, 242 or South Obenchain fires. The complaint was amended on September 6, 2022, to add a claim for damages of over $900 million. The amended complaint adds four more individual plaintiffs and modifies the class definition to cover only the Santiam Canyon, Echo Mountain Complex, 242, and South Obenchain fires. 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; and (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 December 19, 2022, the Dietrich case was consolidated into James (described above) and is currently stayed.
On April 26, 2022, a complaint against PacifiCorp was filed, captioned Cady et al. v. PacifiCorp, Case No. 22CV13946 ("Cady"), in Multnomah County Circuit Court, Oregon. The Cady case was filed by 21 individuals as amended in April 2022 claiming $10 million in economic and noneconomic damages in connection with the Echo Mountain Complex fire, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest. On September
2, 2022, a complaint against PacifiCorp was filed, captioned Logan et al. v. PacifiCorp, Case No. 22CV29859 ("Logan"), in Multnomah County Circuit Court, Oregon. The Logan case was filed by five individuals claiming $10 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. The Logan and Cady complaints each allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires and assert claims for: (i) negligence; (ii) trespass; (iii) nuisance; and (iv) inverse condemnation. The Cady and Logan cases have been consolidated with James (described above) and a jury trial is scheduled for May 2024.
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On
October 14, 2022, the Multnomah County Circuit Court consolidated 21st Century Centennial Insurance Company, et al. v. PacifiCorp, Case No. 22CV26326 ("21st Century") and Allstate Vehicle and Property Insurance Company, et al. v. PacifiCorp, Case No. 22CV29976 ("Allstate") into James (described above). The 21st Century and Allstate complaints were each filed in Multnomah County Circuit Court, Oregon by subrogated insurance carriers alleging claims of (i) negligence, (ii) gross negligence, and (iii) inverse condemnation resulting from the September 2020 Santiam Canyon, Echo Mountain Complex, 242 and South Obenchain fires. The 21st Century case was filed in August 2022 by 177 insurance carriers seeking $20 million in damages. The Allstate case was filed in September 2022 by 11 insurance carriers seeking $40 million
in damages. In May 2023, PacifiCorp and the subrogated insurance carriers entered into a settlement agreement.
On October 17, 2022, the Multnomah County Circuit Court consolidated Michael Bell, et al. v. PacifiCorp, Case No. 22CV30450 ("Bell") into James (described above). The Bell case was filed in Multnomah County Circuit Court, Oregon on September 7, 2022, by 59 plaintiffs seeking $35 million in damages for claims of (i) negligence, (ii) trespass, (iii) nuisance, and (iv) inverse condemnation.
On October 19, 2022, the Multnomah County Circuit Court consolidated Freres Timber,
Inc. v. PacifiCorp, Case No. 22CV29694 ("Freres") into James (described above). The Freres case was filed in Multnomah County Circuit Court, Oregon on September 1, 2022, by one plaintiff and seeks $40 million for claims of (i) negligence, (ii) gross negligence, and (iii) inverse condemnation.
On December 6, 2022, CW Specialty Lumber, Inc., et al. v. PacifiCorp, Case No. 22CV41640 ("CW Specialty") was filed in Multnomah County Circuit Court, Oregon by two plaintiffs seeking $29 million in damages for claims of (i) negligence, (ii) gross negligence, (iii) trespass, and (iv) inverse condemnation. The CW Specialty case has been consolidated with James (described above).
Roseburg
Resources Co et al. v. PacifiCorp and Consolidated Cases
On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22CV09346 ("Roseburg") in Douglas County Circuit Court, Oregon. The complaint was filed by nine businesses and public pension plans that own or operate timberlands or possess property in Douglas County who allege damages, losses and injuries associated with their timberlands as a result of the French Creek, Archie Creek, Susan Creek and Smith Springs Road fires in Douglas County in September 2020. The complaint 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 statute; (iii) all costs of the lawsuit; (iv) prejudgment interest of $43 million and post-judgment interest as allowed by law; and (v) attorneys' fees of $105 million and other costs.
On November 1, 2022, three complaints were filed against PacifiCorp, captioned Moore et al. v. PacifiCorp, No. 22CV37302; Blodgett et al. v. PacifiCorp,
No. 22CV37306; and Ellis et al. v. PacifiCorp, No. 22CV37304. Three additional cases were filed December 5, 2022, captioned Tague et al. v. PacifiCorp, No. 22CV41242; Long, et al. v. PacifiCorp, No. 22CV41283; and Moyers et al. v. PacifiCorp, No. 22CV41293. On January 6, 2023, an additional complaint was filed against PacifiCorp captioned Meyer et al. v. PacifiCorp, No. 23CV00748. On January 17, 2023, seven additional cases were filed, captioned Foster et al. v. PacifiCorp, No. 23CV02142; Hall et al. v. PacifiCorp,
No. 23CV02184; Joneset al. v. PacifiCorp, No. 23CV02110; Price et al. v. PacifiCorp, No. 23CV02175; Minottet al. v. PacifiCorp, No. 23CV02203; Webbet al. v. PacifiCorp, No. 23CV02202; and Keithet al. v. PacifiCorp, No. 23CV02200. On January 24, 2023, three additional cases were filed captioned Kiddet al. v. PacifiCorp, No. 23CV03318; Parkeret
al. v. PacifiCorp, No. 23CV03317; and Diazet al. v. PacifiCorp, No. 23CV03313.
These complaints were filed in Douglas County Circuit Court, Oregon with substantially similar allegations as those of Roseburg with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral ruling, the Douglas County Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues, along with the above-mentioned Roseburg; the precise scope of the trial will be determined in a later order. Collectively, these eighteen cases seek in excess of $1,300 million in damages, inclusive of the $573 million Roseburg case. On February 14, 2023,
the Douglas County Circuit Court ordered that all plaintiffs' claims for inverse condemnation be dismissed; a written order is forthcoming.
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Ashley Andersen et al. v. PacifiCorp and Consolidated Cases
On September 1, 2022, multiple complaints against PacifiCorp were filed in Multnomah County Circuit Court, Oregon, captioned Martin Klinger et al. v. PacifiCorp, Case No. 22CV29674 ("Klinger"), Jeremiah E. Bowen et al. v. PacifiCorp, Case No. 22CV29681 ("Bowen") and James
Weathers et al. v. PacifiCorp, Case No. 22CV29683 ("Weathers"). The complaints were filed by Oregon residents and 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 6, 2022, a complaint against PacifiCorp was filed, captioned Blair Barnholdt et al. v. PacifiCorp, Case No. 22CV30097, in Multnomah County Circuit Court, 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, multiple complaints against PacifiCorp were filed in Multnomah County Circuit Court, Oregon, captioned Estate of Nancy Darlene Hunter, et al. v. PacifiCorp, Case No. 22CV30214 ("Hunter"), Willard K. Pratt et al. v. PacifiCorp, Case No. 22CV30217 ("Pratt") and April Thompson et al. v. PacifiCorp, Case No. 22CV30451 ("Thompson"). The complaints were 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.
The above-described Klinger, Bowen, Weathers, Barnholdt, Hunter, Pratt and Thompson cases were consolidated with Sparkset al. v. PacifiCorp, Case No. 21CV48022 ("Sparks")and Russieet al. v. PacifiCorp, Case No. 22CV15840 ("Russie") into Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen"). The Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson 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, Bowen, Weathers, Barnholdt, Pratt and Thompson 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, Bowen, Weathers, Barnholdt, Pratt and Thompson request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages. The Hunter complaint seeks $50 million in damages and alleges claims for: (i) negligence, (ii) trespass, (iii), nuisance, (iv) inverse condemnation, and (v) wrongful death. The Andersen case was filed by 50 individuals as amended in August 2022
seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest. The Sparks case was filed by 17 individuals in December 2021 claiming $125 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- judgment interest. The Russie case was filed by 45 individuals as amended in September 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest.
Judith O'Keefe v. PacifiCorp and Consolidated Cases
On September 1, 2022, a complaint
against PacifiCorp was filed, captioned Aaron Macy-Wyngarden et al. v. PacifiCorp, Case No. 22CV29684, in Multnomah County Circuit Court, 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 22, 2022, a complaint against PacifiCorp was filed, captioned Zachary Bogle et al. v. PacifiCorp, Case No. 22CV29717, in Multnomah County Circuit Court, 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 Macy-Wyngarden 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 Macy-Wyngarden 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 Macy-Wyngarden and Bogle request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages.
The Macy-Wyngarden and Bogle cases were consolidated with Ruthie Dodge et al. v. PacifiCorp, Case No. 22CV30222 ("Dodge") into Judith O'Keefe v. PacifiCorp, Case No. 21CV15857 ("O'Keefe"). The Dodge case was filed in Multnomah County Circuit Court,
Oregon on September 8, 2022, by two plaintiffs seeking $9 million in damages for claims of negligence, trespass, nuisance, and inverse condemnation. The O'Keefe lawsuit was filed in Multnomah County Circuit Court, Oregon on April 23, 2021, by one individual seeking $2 million in damages for claims for negligence, nuisance, and trespass.
United States and State of Oregon – Loss and Damages to Federal and State Lands
PacifiCorp received a notice of indebtedness from the U.S. Department of Agriculture Forest Service ("USFS") indicating that PacifiCorp owes the U.S. $356 million for fire suppression costs, natural resource damages and burned area emergency response costs incurred by the USFS associated
with the September 2020 Slater fire in California. The notice further indicates that the alleged amounts owed may not include all environmental damages to which the USFS may be entitled and which the U.S. may seek to recover if further action is taken to resolve the debt. Additional charges for interest, penalties and administrative costs may also be sought associated with amounts considered overdue.
PacifiCorp received correspondence from the U.S. Department of Justice ("USDOJ"), representing the U.S. Department of the Interior, Bureau of Land Management, Bureau of Indian Affairs, Department of Agriculture and Forest Service, regarding the potential recovery of certain costs and damages alleged to have occurred to federal lands from the September 2020 Archie Creek and Susan Creek fires. The USDOJ estimates the costs and damages relating to reforestation, damaged timber and improvements,
coordination with hydropower license, suppression costs and other assessment, cleanup and rehabilitation costs and damages at approximately $640 million. The amounts alleged for natural resource damage from these fires do not include environmental damages that the United States could potentially seek to recover if this matter was fully litigated, nor do they include multipliers which the agencies are allegedly entitled to collect under pertinent federal regulations, under which, for example, minimum damages for trespass to timber managed by the U.S. Department of Interior are twice the fair market value of the resource at the time of the trespass, or three times if the violation was willful.
PacifiCorp also received correspondence from the Oregon Department of Justice ("ODOJ"), representing the State of Oregon, regarding the potential recovery of losses and damages to state lands
from the Archie Creek and Susan Creek fires. The ODOJ estimates losses and damages relating to the sheltering of, and assistance to, affected Oregonians, fire control and extinguishment costs, 39 acres of Oregon forestland, losses and damages at the Rock Creek Fish Hatchery, road and highway damages, and other costs, at approximately $96 million.
PacifiCorp is actively cooperating with both the USDOJ and ODOJ on resolving these alleged claims, including through the pursuit of alternative dispute resolution means.
BERKSHIRE HATHAWAY ENERGY
HomeServices, a subsidiary of Berkshire Hathaway Energy, is currently defending against four antitrust cases, all in federal district courts. In each case, plaintiffs claim HomeServices
and certain subsidiaries conspired with co-defendants to artificially inflate real estate commissions by following and enforcing multiple listing service ("MLS") rules that require listing agents to offer a commission split to cooperating agents in order for the property to appear on the MLS ("Cooperative Compensation Rule"). Three of the four cases are brought on behalf of sellers and one is brought on behalf of buyers. None of the complaints specify damages sought. The cases are captioned as follows.
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In April 2019, the Burnett (formerly Sitzer) et al. v. HomeServices of America, Inc. et al., Case No. 19CV332, complaint was filed in the U.S. District Court for the Western
District of Missouri (the "Burnett case"). This lawsuit, which was certified as a class in April 2022, was originally brought on behalf of named plaintiffs Joshua Sitzer and Amy Winger against the National Association of Realtors ("NAR"), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., RE/MAX, LLC, and Keller Williams Realty, Inc. HSF Affiliates, LLC and BHH Affiliates, LLC, each a subsidiary of HomeServices, were subsequently added as defendants. Rhonda Burnett became a lead class plaintiff in June 2021. The jury trial commenced on October 16, 2023, and the jury returned a verdict for the plaintiffs on October 31, 2023, finding that the named defendants participated in a conspiracy to follow and enforce the Cooperative Compensation Rule, which had the purpose or effect of raising, inflating, or stabilizing broker commission
rates paid by home sellers. The jury further found that the class plaintiffs had proved damages in the amount of $1.8 billion. Federal law authorizes trebling of damages and the award of pre-judgment interest and attorney fees. Joint and several liability applies for the co-defendants. Prior to the trial, Anywhere Real Estate (formerly Realogy Holdings Corp.) and RE/MAX, LLC reached settlement agreements with the plaintiffs, which have not yet been approved by the court. Final judgment has not yet been entered by the U.S. District Court for the Western District of Missouri. HomeServices intends to vigorously appeal on multiple grounds the jury's findings and damage award in the Burnett case, including whether the case can proceed as a class action. The appeals process and further actions could take several years.
On March 6, 2019, the
Christopher Moehrl v. National Association of Realtors, et al. & Sawbill Strategic, Inc. v. HomeServices of America, Inc. et al., Case Nos. 19CV01610 and 19CV2544, (together "Moehrl") complaint was filed in the U.S. District Court for the Northern District of Illinois. This certified class action lawsuit was brought on behalf of named plaintiff Christopher Moehrl against the NAR, Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., HSF Affiliates, LLC, BHH Affiliates, LLC, Long & Foster Companies, Inc. (also a HomeServices subsidiary), RE/MAX, LLC and Keller Williams Realty, Inc.
In December 2020, the Nosalek (formerly Bauman) v. HomeServices of America, Inc. et al., Case No. 20CV1244, complaint was filed in the U.S. District Court for the District of Massachusetts.
This putative class action lawsuit was originally filed on behalf of named plaintiffs Gary Bauman, Mary Jane Bauman, and Jennifer Nosalek against the MLS Property Information Network, Inc. (MassPIN), Anywhere Real Estate (formerly Realogy Holdings Corp.), HomeServices of America, Inc., BHH Affiliates, LLC, HSF Affiliates, LLC, RE/MAX, LLC, Keller Williams Realty, Inc. and additional named defendants. In October 2021, the Baumans voluntarily dismissed themselves from the case, removing them as class representatives.
In January 2021, the Batton (formerly Leeder) v. HomeServices of America, Inc. et al., Case No. 21CV00430, complaint was filed in the U.S. District Court for the Northern District of Illinois. This putative class action lawsuit was originally brought on behalf of former named plaintiff Judah Leeder against the NAR, HomeServices
of America, Inc. HSF Affiliates, LLC, BHH Affiliates, LLC, Long & Foster Companies, Inc., Anywhere Real Estate (formerly Realogy Holdings Corp.), RE/MAX, LLC and Keller Williams Realty, Inc. Mya Batton replaced Leeder as class representative in July 2022.
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, 2022.
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
205
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, 2023, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.
104
Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.
210
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.
