(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 May 4, 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 May 4, 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 May 4, 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 May 4, 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 May 4, 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 May 4, 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 May 4, 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 May 4, 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
ii
Certain
Industry Terms
2020 Wildfires
Wildfires in Oregon and Northern California that occurred September of 2020
AFUDC
Allowance for Funds Used During Construction
AUC
Alberta Utilities Commission
BART
Best
Available Retrofit Technology
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
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
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
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 for which the cause has yet to be determined; the damage caused by such wildfires; the extent of the respective Registrant's liability in connection with such wildfires (including the risk that the respective Registrant may be found liable for damages regardless of fault); investigations into such wildfires; the outcome of any legal
proceedings initiated against the respective Registrant; the risk that the respective Registrant is not able to recover costs from insurance or through rates; and the effect on the respective Registrant's reputation of such wildfires, investigations and proceedings;
•the respective Registrant's ability to reduce wildfire threats and improve safety, including the ability to comply with the targets and metrics set forth in its wildfire mitigation plans; to retain or contract for the workforce necessary to execute its wildfire mitigation plans; the effectiveness of its system hardening; ability to achieve vegetation management targets; and the cost of these programs and the timing and outcome of any proceeding to recover such costs through rates;
•the ability to economically obtain insurance coverage, or any insurance coverage at all,
sufficient to cover losses arising from catastrophic events, such as wildfires;
•a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;
•changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;
•the financial condition, creditworthiness and operational stability of the respective Registrant's significant customers and suppliers;
•changes in business strategy or development plans;
iv
•availability,
terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates;
•changes in the respective Registrant's credit ratings;
•risks relating to nuclear generation, including unique operational, closure and decommissioning risks;
•hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;
•the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of
certain contracts;
•the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;
•fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;
•increases in employee healthcare costs;
•the impact of investment performance, certain participant elections such as lump sum distributions and changes in interest rates, legislation, healthcare cost trends, mortality, morbidity on pension and other postretirement benefits expense and funding requirements;
•changes in the residential real estate brokerage, mortgage and franchising industries
and regulations that could affect brokerage, mortgage and franchising transactions;
•the ability to successfully integrate future acquired operations into a Registrant's business;
•the impact of supply chain disruptions and workforce availability on the respective Registrant's ongoing operations and its ability to timely complete construction projects;
•unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;
•the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
•the
impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and
•other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.
Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the SEC, including Part II, Item 1A and other discussions contained in this Form 10-Q. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.
v
Item
1.Financial Statements
Berkshire Hathaway Energy Company and its subsidiaries
Berkshire
Hathaway Energy Company and its subsidiaries
Consolidated Financial Section
3
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the Board of Directors and Shareholders of
Berkshire Hathaway Energy Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of March 31, 2023, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for the three-month periods ended March 31, 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 (loss) to net cash flows from operating activities:
(Gains) losses on marketable securities, net
(i699)
i1,257
Depreciation
and amortization
i1,063
i1,022
Allowance
for equity funds
(i49)
(i38)
Equity
(income) loss, net of distributions
i68
i88
Net
power cost deferrals
(i504)
(i72)
Amortization of
net power cost deferrals
i130
i47
Other
changes in regulatory assets and liabilities
(i26)
(i17)
Deferred
income taxes and investment tax credits, net
(i11)
(i203)
Other,
net
i15
i6
Changes
in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets
i120
i333
Derivative
collateral, net
(i225)
i85
Pension
and other postretirement benefit plans
(i7)
(i11)
Accrued
property, income and other taxes, net
(i177)
(i347)
Accounts
payable and other liabilities
i294
i91
Net
cash flows from operating activities
i1,095
i2,221
Cash
flows from investing activities:
Capital expenditures
(i1,848)
(i1,553)
Purchases
of marketable securities
(i106)
(i170)
Proceeds
from sales of marketable securities
i1,091
i149
Purchases
of U.S. Treasury Bills
(i1,519)
i—
Proceeds
from maturities of U.S. Treasury Bills
i623
i—
Equity
method investments
(i19)
(i17)
Other,
net
i—
i19
Net
cash flows from investing activities
(i1,778)
(i1,572)
Cash
flows from financing activities:
Repayments of BHE senior debt
(i400)
i—
Proceeds
from subsidiary debt
i—
i405
Repayments
of subsidiary debt
(i136)
(i193)
Net
proceeds from (repayments of) short-term debt
i699
(i165)
Distributions
to noncontrolling interests
(i126)
(i117)
Other,
net
(i17)
(i240)
Net
cash flows from financing activities
i20
(i310)
Effect
of exchange rate changes
i1
(i1)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i662)
i338
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
$
i1,155
$
i1,582
The
accompanying notes are an integral part of these consolidated financial statements.
10
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) iGeneral
Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The Company's operations are organized as ieight
business segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company and its subsidiaries ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC and its subsidiaries ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings
Corporation and its subsidiaries ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC and its subsidiaries), BHE Renewables, LLC and its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns ifour utility companies in the U.S. serving customers in i11
states, itwo electricity distribution companies in Great Britain, ifive
interstate natural gas pipeline companies and interests in a liquefied natural gas ("LNG") export, import and storage facility in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, 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 March 31, 2023, and for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31,
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 three-month period ended March 31, 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 the 2022 McKinney fire as discussed in Note 9.
11
(2) iProperty,
Plant and Equipment, Net
i
Property, plant and equipment, net consists of the following (in millions):
As
of
Depreciable
March 31,
December 31,
Life
2023
2022
Regulated assets:
Utility
generation, transmission and distribution systems
i5-i80 years
$
i93,123
$
i92,759
Interstate
natural gas pipeline assets
i3-i80 years
i18,492
i18,328
i111,615
i111,087
Accumulated
depreciation and amortization
(i35,395)
(i34,599)
Regulated
assets, net
i76,220
i76,488
Nonregulated
assets:
Independent power plants
i2-i50
years
i8,514
i8,545
Cove
Point LNG facility
i40 years
i3,416
i3,412
Other
assets
i2-i30 years
i2,680
i2,693
i14,610
i14,650
Accumulated
depreciation and amortization
(i3,493)
(i3,452)
Nonregulated
assets, net
i11,117
i11,198
i87,337
i87,686
Construction
work-in-progress
i6,246
i5,357
Property,
plant and equipment, net
$
i93,583
$
i93,043
/
Construction
work-in-progress includes $i5.8 billion as of March 31, 2023 and $i4.9 billion as of December 31,
2022, related to the construction of regulated assets.
12
(3) 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
gains (losses) recognized on marketable securities held at the reporting date
$
i529
$
(i1,257)
Net
gains recognized on marketable securities sold during the period
i170
i—
Gains
(losses) on marketable securities, net
$
i699
$
(i1,257)
/
13
Cash
and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. iA
reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented 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
i133
i173
Investments
and restricted cash and cash equivalents and investments
i59
i53
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i1,155
$
i1,817
(4) iRecent
Financing Transactions
Credit Facilities
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.
(5) iIncome
Taxes
The effective income tax rate for the three-month period ended March 31, 2022, is i108% and results from a $i507 million
income tax benefit associated with a $i470 million pre-tax loss, primarily relating to a pre-tax unrealized loss of $i1,247 million
on the Company's investment in BYD Company Limited. The $i507 million income tax benefit is primarily comprised of a $i99 million
benefit (i21%) from the application of the statutory income tax rate to the pre-tax loss and a $i339 million
benefit (i72%) 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
(i4)
(i3)
Income
tax effect of foreign income
i7
i3
Effects
of ratemaking
(i3)
i8
Equity
income
(i1)
i3
Noncontrolling
interest
(i2)
i5
Other,
net
i—
(i1)
Effective
income tax rate
(i17)
%
i108
%
/
14
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 three-month periods ended March 31, 2023 and 2022 totaled $i343 million and $i338 million,
respectively.
Income tax effect on foreign income includes, among other items, a deferred income tax charge of $i82 million recognized in March 2023 related to the July 2022 enactment of a new Energy Profits Levy 25% income tax in the United Kingdom effective May 26, 2022, through December 31, 2025, as well as an increase in the tax rate from
25% to 35% effective January 1, 2023, through March 31, 2028, enacted in January 2023.
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 made iino/
payments for federal income taxes to Berkshire Hathaway for the three-month periods ended March 31, 2023 and 2022.
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.
(6) iEmployee Benefit Plans
Domestic Operations
i
Net
periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):
Amounts
other than the service cost for pension and other postretirement benefit plans are recorded in other, net 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 March 31, 2023, $i3 million and $i1
million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
15
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 March 31, 2023, Łi3 million,
or $i4 million, of contributions had been made to the United Kingdom pension plan.
(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 three-month period ended March 31, 2023, MidAmerican Energy recorded an increase of $i88
million for decommissioning its wind-generating facilities due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.
(8) 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.
16
i
The
following table presents the Company's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
(1)Represents
netting under master netting arrangements and a net cash collateral payable of $i12 million and $i87 million
as of March 31, 2023 and December 31, 2022, respectively.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally
developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of the underlying
forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.
18
The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or
net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
i
The following table reconciles the beginning and ending balances
of the Company's financial assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions). Transfers out of Level 3 occur primarily due to increased price observability.
Three-Month Periods
Ended March 31,
Interest
Commodity
Rate
Derivatives
Derivatives
2023:
Beginning
balance
$
(i59)
$
i6
Changes
included in earnings(1)
i9
i9
Changes
in fair value recognized in OCI
(i3)
i—
Changes
in fair value recognized in net regulatory assets
(i98)
i—
Settlements
i1
i—
Ending
balance
$
(i150)
$
i15
2022:
Beginning
balance
$
(i151)
$
i19
Changes
included in earnings(1)
(i56)
(i6)
Changes
in fair value recognized in OCI
i5
i—
Changes
in fair value recognized in net regulatory assets
(i60)
i—
Settlements
i23
i—
Ending
balance
$
(i239)
$
i13
(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
In April 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 three-month period ended March 31, 2023, MidAmerican Energy entered into firm construction commitments totaling $i183 million for the remainder of 2023 through 2024 related to the construction of wind-powered generating facilities in Iowa.
Fuel Contracts
During
the three-month period ended March 31, 2023, PacifiCorp entered into certain coal supply and transportation agreements totaling $i247 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 is anticipated to begin in 2023, and removal of the remaining three 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 arising out of the normal course of business. Plaintiffs occasionally seek
punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
Wildfire Liability Overview
A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of 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.
20
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 proximately caused by negligence, including real and personal property and natural resource damages; fire suppression costs; personal injury and loss of life damages; and interest.
2020 Wildfires
In
September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over i500,000
acres in aggregate. Third-party reports for these wildfires indicate over i2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $i150 million.
Investigations
into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the 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 have been filed in Oregon and California, including a class action complaint in Oregon, on behalf of plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. Final determinations of liability, however, will only be made following the completion
of comprehensive investigations and litigation processes.
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of litigation and recent settlements, PacifiCorp has accrued cumulative estimated probable losses associated with the 2020 Wildfires of $i877 million through March 31, 2023. PacifiCorp's cumulative accrual includes estimates of losses for fire suppression
costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available.
It is reasonably possible PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the variation in those types of properties and lack of available details. To the extent losses beyond the amounts
accrued are incurred, additional insurance coverage is expected to be available to cover a portion of the losses.
i
The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires (in millions):
PacifiCorp's
receivable for expected insurance recoveries associated with the probable losses was $i287 million and $i246 million, respectively, as of March 31,
2023 and December 31, 2022. During the three-month periods ended March 31, 2023 and 2022 PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $i359 million and $i— million,
respectively, and are recorded in operations and maintenance on the Consolidated Statements of Operations.
2022 McKinney Fire
According to the California Department of Forestry and Fire Protection, on July 29, 2022, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. 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.
Due
to the preliminary nature of the investigation PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $i31 million, net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp
is unable to estimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $i103 million, to cover potential losses.
As of the date of this filing, multiple lawsuits have been filed in
California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages that include property damages, economic and noneconomic losses, punitive damages, exemplary damages, attorneys' fees and other damages but the amount of damages sought are not specified. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
22
(10) iRevenue
from Contracts with Customers
Energy Products and Services
i
The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business, including a reconciliation to the Company's reportable segment information included in Note 12 (in millions):
(1)The
BHE and Other reportable segment represents amounts related principally to other corporate entities, corporate functions and intersegment eliminations.
/
23
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 March 31, 2023, by reportable segment (in millions):
Performance
obligations expected to be satisfied:
Less than 12 months
More than 12 months
Total
BHE Pipeline Group
$
i2,786
$
i20,146
$
i22,932
BHE
Transmission
i490
i—
i490
Total
$
i3,276
$
i20,146
$
i23,422
/
(11) iComponents
of Accumulated Other Comprehensive Loss, Net
i
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income tax (in millions):
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, and BHE Transmission, whose business includes operations in Canada. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. 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.
$
i819
$
(i654)
United
Kingdom
i113
i139
Canada
i43
i46
Australia
i5
i—
Other
(i1)
(i1)
Total
income (loss) before income tax expense (benefit) and equity income (loss) by country
$
i979
$
(i470)
i
The
following table shows the change in the carrying amount of goodwill by reportable segment for the three-month period ended March 31, 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. As of May 4, 2023, Berkshire Hathaway and family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, owned 92% and 8%, respectively, of BHE's voting common stock.
Berkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River),
BHE Transmission (which consists of BHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in the U.S., one of which owns a LNG export, import and storage facility, an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, one of the largest residential real estate brokerage firms in the U.S. and one of the largest residential real estate brokerage franchise networks in the U.S. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies.
The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other 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.
28
Results of Operations for the First Quarter of 2023 and 2022
Overview
Operating
revenue and earnings (loss) on common shares for the Company's reportable segments are summarized as follows (in millions):
First Quarter
2023
2022
Change
Operating
revenue:
PacifiCorp
$
1,484
$
1,297
$
187
14
%
MidAmerican
Funding
920
1,005
(85)
(8)
NV Energy
999
693
306
44
Northern
Powergrid
354
315
39
12
BHE Pipeline Group
1,173
1,035
138
13
BHE
Transmission
205
183
22
12
BHE Renewables
393
336
57
17
HomeServices
875
1,207
(332)
(28)
BHE
and Other
(57)
(41)
(16)
39
Total operating revenue
$
6,346
$
6,030
$
316
5
%
Earnings
(loss) on common shares:
PacifiCorp
$
(120)
$
130
$
(250)
*
MidAmerican
Funding
249
241
8
3
NV Energy
34
29
5
17
Northern
Powergrid
11
111
(100)
(90)
BHE Pipeline Group
369
322
47
15
BHE
Transmission
64
62
2
3
BHE Renewables(1)
79
145
(66)
(46)
HomeServices
(34)
21
(55)
*
BHE
and Other
329
(1,206)
1,535
*
Total earnings (loss) on common shares
$
981
$
(145)
$
1,126
*
(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 $1,126 million for the first quarter of 2023 compared to 2022. Included in these results was a pre-tax gain in the first quarter of 2023 of $717 million ($567 million after-tax) compared to a pre-tax loss in the first quarter of 2022 of $1,247 million ($985 million after-tax) related to the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first quarter of 2023 was $414 million, a decrease of $426 million, or 51%, compared to adjusted earnings on common shares for the first quarter of 2022 of $840 million.
The
increase in earnings on common shares for the first quarter of 2023 compared to 2022 were primarily due to the following:
•The Utilities' earnings decreased $237 million for the first quarter of 2023 compared to 2022, primarily from higher operations and maintenance expense, largely due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires. The higher operations and maintenance expense was partially offset by favorable electric utility margin, higher allowances for equity and borrowed funds used during construction, increases in the cash surrender value of corporate-owned life insurance policies and a favorable income tax benefit from valuation allowance changes on state net operating loss carryforwards. Electric retail customer volumes increased 2.6% for the first quarter of 2023 compared to 2022, driven by higher customer usage and an increase in
the average number of customers;
29
•Northern Powergrid's earnings decreased $100 million for the first quarter of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax. Units distributed declined 4.8% due to the unfavorable impact of weather and lower customer usage;
•BHE Pipeline Group's earnings increased $47 million for the first quarter of 2023 compared to 2022, largely due to a favorable general rate case settlement at EGTS in 2022 and the impacts of a general rate case, with interim rates effective January 1, 2023,
subject to refund, at Northern Natural Gas;
•BHE Renewables' earnings decreased $66 million for the first quarter of 2023 compared to 2022, primarily due to unfavorable changes in unrealized positions on derivative contracts due to lower forward electricity price curves;
•HomeServices' earnings decreased $55 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services and from mortgage services, reflecting the impact of rising interest rates and a corresponding decline in home sales; and
•BHE and Other's earnings increased $1,535 million for the first quarter of 2023 compared to 2022, primarily due to the $1,552 million favorable comparative change related to the Company's investment in BYD Company
Limited.
Reportable Segment Results
PacifiCorp
Operating revenue increased $187 million for the first quarter of 2023 compared to 2022, primarily due to higher retail revenue of $159 million and higher wholesale and other revenue of $28 million, primarily from higher average wholesale market prices, partially offset by lower wholesale volumes. Retail revenue increased primarily due to price impacts of $107 million from higher average retail rates largely due to tariff changes and product mix and $52 million from higher volumes. Retail customer volumes increased 3.3%, primarily due to the favorable impact of weather, higher customer usage and an increase in the average number of customers.
Earnings
decreased $250 million for the first quarter of 2023 compared to 2022, primarily due to higher operations and maintenance expense of $428 million, partially offset by higher utility margin of $38 million, higher allowances for equity and borrowed funds used during construction of $21 million and a favorable income tax benefit from valuation allowance changes on state net operating loss carryforwards. Operations and maintenance expense was unfavorable primarily due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $359 million, higher wildfire mitigation and vegetation management costs, and higher general and plant maintenance costs. Utility margin increased primarily due to higher retail rates and volumes, favorable deferred net power costs and higher average wholesale market prices, partially offset by higher purchased power and thermal generation costs and lower wholesale volumes.
MidAmerican
Funding
Operating revenue decreased $85 million for the first quarter of 2023 compared to 2022, primarily due to lower natural gas operating revenue of $70 million and lower electric operating revenue of $17 million. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $61 million (fully offset in cost of sales) and the unfavorable impact of weather of $5 million. Electric operating revenue decreased due to lower wholesale and other revenue of $33 million, partially offset by higher retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower wholesale volumes of $22 million and lower average wholesale per-unit prices of $13 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $14 million
(largely offset in expense, primarily cost of sales). Electric retail customer volumes increased 1.0%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.
Earnings increased $8 million for the first quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $17 million, a one-time gain on the sale of an investment of $13 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $12 million, partially offset by higher operations and maintenance expense of $13 million, lower natural gas utility margin of $8 million and lower electric utility margin of $7 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Operations and maintenance expense
increased due to higher general and plant maintenance costs and unfavorable property insurance costs. Natural gas utility margin decreased primarily due to the unfavorable impact of weather. Electric utility margin decreased primarily due to lower wholesale revenue, partially offset by higher retail revenue and lower purchased power costs.
30
NV Energy
Operating revenue increased $306 million for the first quarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $260 million and higher natural gas operating revenue of $44 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 $229 million, higher customer volumes of $8 million, increased base tariff general rates of $8 million at Sierra Pacific and favorable transmission and wholesale revenue of $7 million. Electric retail customer volumes increased 2.9%, primarily due to the favorable impact of weather and an increase in the average number of customers.
Earnings increased $5 million for the first quarter of 2023 compared to 2022, primarily due to higher electric utility margin of $31 million and favorable interest and dividend income of $16 million, mainly from carrying charges on higher deferred energy balances, partially offset by higher operations and maintenance expenses of $24 million, unfavorable depreciation and amortization expense of $13 million and increased interest expense of $12 million due
to higher outstanding long-term debt balances. Electric utility margin increased primarily due to higher electric retail customer volumes, increased base tariff general rates at Sierra Pacific and higher transmission and wholesale revenue. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service.
Northern Powergrid
Operating revenue increased $39 million for the first quarter of 2023 compared to 2022, primarily due to higher distribution revenue of $41 million and higher revenue at CE Gas of $29 million, partially offset by $37 million from the stronger U.S. dollar. Distribution revenue increased primarily
due to the recovery of Supplier of Last Resort payments of $43 million (fully offset in cost of sales) and higher tariff rates of $10 million. Also impacting distribution revenue was a 4.8% decline in units distributed, largely due to the unfavorable impact of weather and lower customer usage, of $11 million. CE Gas revenue increased from a gas project that commenced commercial operation in March 2022 and a solar project that commenced commercial operation in July 2022.
Earnings decreased $100 million for the first quarter of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax. Earnings were also impacted by unfavorable distribution-related operating and depreciation expenses of $11 million and increased non-service benefit plan costs of $10 million, partially offset
by favorable operating performance at CE Gas of $8 million from the gas and solar projects that commenced commercial operations in 2022.
BHE Pipeline Group
Operating revenue increased $138 million for the first quarter of 2023 compared to 2022, primarily due to higher operating revenue of $71 million at Northern Natural Gas and $55 million at BHE GT&S. 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 $63 million and higher transportation revenue of $34 million from higher rates in the Field Area, partially offset by lower gas sales of $25 million (largely offset in cost of sales) from system balancing activities. The increase in operating
revenue at BHE GT&S was primarily due to an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $42 million, higher LNG revenue of $16 million at Cove Point, and an increase in variable revenue related to park and loan activity of $10 million at EGTS, partially offset by lower non-regulated revenue of $22 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices.
Earnings increased $47 million for the first quarter of 2023 compared to 2022, largely due to higher earnings at Northern Natural Gas of $28 million and higher earnings at BHE GT&S of $14 million. The increase at Northern Natural Gas is due to the impacts of a general rate case of $16 million and higher transportation revenue in the Field Area, partially offset by higher operations and maintenance expense. The increase
at BHE GT&S is due to a favorable general rate case settlement at EGTS in 2022 and higher equity earnings at Iroquois Gas Transmission System, partially offset by higher operations and maintenance expense and increased cost of gas from the unfavorable revaluation of volumes retained, due to lower natural gas prices.
BHE Transmission
Operating revenue increased $22 million for the first quarter of 2023 compared to 2022, primarily due to $26 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 $12 million from the stronger U.S. dollar.
31
Earnings
increased $2 million for the first quarter of 2023 compared to 2022, primarily due to $6 million of incremental earnings at non-regulated wind-powered generating facilities acquired in November 2022, partially offset by $3 million from the stronger U.S. dollar.
BHE Renewables
Operating revenue increased $57 million for the first quarter of 2023 compared to 2022, primarily due to higher wind revenues of $60 million, largely due to favorable changes in the valuation of certain derivative contracts, and higher natural gas and electric retail energy services revenue of $23 million, partially offset by lower solar revenues of $20 million from lower generation due to weather events in California. Natural gas and electric retail energy services revenue increased due to higher electric volumes and favorable
natural gas and electric pricing, partially offset by lower natural gas volumes.
Earnings decreased $66 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings of $79 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $40 million, primarily due to maintenance outages, and lower solar earnings of $18 million from lower generation due to weather events in California. These items were partially offset by higher wind earnings of $74 million, largely due to favorable changes in the valuation of certain derivative contracts and higher earnings from tax equity investments of $28 million due to lower equity losses and higher production tax credits.
HomeServices
Operating revenue decreased $332 million for the first quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $293 million and lower mortgage revenue of $34 million. The decrease in brokerage and settlement services revenue resulted from a 29% 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 41% decrease in funded volume, primarily due to rising interest rates.
Earnings decreased $55 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $38 million and mortgage services of $12 million, largely from the decrease in funded volumes from rising interest rates. Earnings at brokerage
and settlement services declined due to the decrease in closed transaction volume, partially offset by favorable operating expenses primarily due to lower compensation costs.
BHE and Other
Operating revenue decreased $16 million for the first quarter of 2023 compared to 2022, due to higher intersegment eliminations.
Earnings increased $1,535 million for the first quarter of 2023 compared to 2022, primarily due to the $1,552 million favorable comparative change related to the Company's investment in BYD Company Limited, favorable changes in the cash surrender value of corporate-owned life insurance policies of $14 million and $8 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 higher BHE corporate interest expense from an April 2022 debt issuance and $17 million of lower federal income tax credits recognized on a consolidated basis.
32
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 March 31,
2023, the Company's total net liquidity was as follows (in millions):
BHE
Pipeline
MidAmerican
NV
Northern
BHE
Group and
BHE
PacifiCorp
Funding
Energy
Powergrid
Canada
HomeServices
Other
Total
Cash
and cash equivalents
$
173
$
19
$
58
$
21
$
18
$
64
$
216
$
394
$
963
Credit
facilities(1)
3,500
2,000
1,509
650
295
795
2,725
—
11,474
Less:
Short-term
debt
(755)
—
—
(83)
(49)
(127)
(805)
—
(1,819)
Tax-exempt
bond support and letters of credit
—
(249)
(363)
—
—
(1)
—
—
(613)
Net
credit facilities
2,745
1,751
1,146
567
246
667
1,920
—
9,042
Total
net liquidity
$
2,918
$
1,770
$
1,204
$
588
$
264
$
731
$
2,136
$
394
$
10,005
Credit
facilities:
Maturity dates
2025
2024, 2025
2023, 2025
2025
2025
2023,
2026, 2027
2023, 2024, 2026
(1)Includes $48 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $1.1 billion and $2.2 billion, respectively. The decrease was primarily due to changes in working
capital and regulatory assets and unfavorable operating results.
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 three-month periods ended March 31, 2023 and 2022, were $(1.8) billion and $(1.6) billion, respectively. The change was primarily due to higher purchases, net of proceeds from maturities, of U.S. Treasury Bills totaling $896 million and higher capital expenditures of $295 million, partially offset
by higher proceeds from sales of marketable securities of $942 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
33
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2023, was $20 million. Sources of cash totaled $699 million and consisted of net proceeds from short-term debt. Uses of cash totaled $679 million and consisted mainly of repayments of BHE senior debt totaling $400 million, repayments of subsidiary debt totaling $136 million and distributions to noncontrolling interests of $126 million.
Net
cash flows from financing activities for the three-month period ended March 31, 2022, was $(310) million. Sources of cash totaled $405 million and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $715 million and consisted mainly of repayments of subsidiary debt totaling $193 million, net repayments of short-term debt totaling $165 million and distributions to noncontrolling interests of $117 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.
34
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):
Three-Month
Periods
Annual
Ended March 31,
Forecast
2022
2023
2023
Capital expenditures by business:
PacifiCorp
$
374
$
643
$
3,662
MidAmerican
Funding
459
382
2,324
NV Energy
272
437
1,751
Northern Powergrid
169
124
597
BHE
Pipeline Group
205
169
1,431
BHE Transmission
47
43
191
BHE Renewables
19
29
269
HomeServices
12
11
46
BHE
and Other(1)
(4)
10
12
Total
$
1,553
$
1,848
$
10,283
Capital
expenditures by type:
Wind generation
$
153
$
105
$
2,172
Electric distribution
388
477
2,071
Electric
transmission
261
291
2,063
Natural gas transmission and storage
103
65
1,097
Solar generation
51
40
236
Electric
battery and pumped hydro storage
1
40
236
Other
596
830
2,408
Total
$
1,553
$
1,848
$
10,283
(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 $75 million and $3 million for the three-month periods ended March 31, 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 $1,025 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $5 million and $120 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $16 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 $14 million and $6 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $807 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $25 million for the three-month period ended March 31, 2022. Planned spending for the repower of wind-powered facilities totals $50 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 $110 million
and $96 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $898 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, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma 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 $42 million and $30 million for the three-month periods ended March 31, 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 $88 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 $12 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 three-month periods ended March 31, 2023 and 2022 solar generation spend totaled $9 million and $44 million, respectively. Planned spending totals $1 million for the remainder of 2023.
◦Construction of a solar-powered generating facility at Nevada Power totaling $31 million and $7 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending totals
$175 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.
•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. 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 three-month period ended March 31, 2023, was $39 million with planned spending of $159 million for the remainder of 2023.
36
•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 March 31, 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 9 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%, effective on an interim basis July 1, 2023.
Oregon
In April 2023, PacifiCorp filed its transition
adjustment mechanism 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.
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 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%, to become effective on an interim basis July 1, 2023.
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.
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 an expected decision in early 2024.
37
MidAmerican Energy
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.
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 that includes a rate of return of 11.0%. The settlement would benefit customers by providing an immediate rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. The IUB conducted a hearing on the application and proposed settlement during the week of February 20, 2023. On April 27, 2023, the IUB issued its final order regarding the application. The IUB 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 is reviewing the order and assessing options for rejection or motion to reconsider. MidAmerican Energy must either accept or reject the order, or file a motion for reconsideration within 20 days and no later than May 17, 2023.
38
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. No earlier than May 18, 2023, the Iowa Supreme Court will remand the case to the district court for further proceedings on the merits. 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.
39
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.
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 and the appeal is expected to conclude in the fourth quarter of 2023 in accordance with the timetable required of the CMA. The outcome of this appeal may increase the revenue available to the Company if the CMA amends the price control determination.
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. Procedural hearings are scheduled to begin June 14, 2023.
40
BHE Transmission
AltaLink
2024-2025
General Tariff Application
In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total total transmission tariffs of C$902.3 million and C$908.6 million for 2024 and 2025, respectively, which extends AltaLink's previous five-year commitment to maintain its tariff at or below C$904 million from 2019 to 2023 for another year. The application also requests the approval to reinstate C$98.9 million cost of removal to rate base which was not previously approved, based on additional information filed.
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 GCOC proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial markets due to the COVID-19 pandemic. In June 2022, the AUC initiated the second stage to explore a formula-based approach to determine the return on equity for 2024 and future test periods.
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. The AUC expects to conclude the second stage of the GCOC proceeding in the third quarter of 2023.
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.
41
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.
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 will accept comments on the proposal for 60 days following its publication in the Federal Register. 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.
42
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 have access 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 non-SCR 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 units without adequate controls. 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 Utah and Wyoming challenged the EPA's denial and deferral, respectively, of their interstate ozone transport SIPs in the Tenth Circuit Court of Appeals. PacifiCorp also filed petitions with the court opposing the EPA's action in both states. At the time of filing, at least six other states have challenged the EPA's action to disapprove SIPs in different regional federal Courts of Appeal. Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants cannot be determined.
The EPA included additional sectors in the 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. 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 SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
In June 2019, the state of Utah incorporated a BART alternative into its SIP for regional haze planning period one. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA approved the SIP revision with the BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. On January
19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. The EPA defended the SIP, and PacifiCorp and the state of Utah intervened in the litigation. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. A final decision from the court is expected by fall 2023. The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for the regional haze second planning period on June 6, 2022. The SIP sets mass-based NOx emissions limits and rate-based SO2 limits for PacifiCorp's Hunter and Huntington generating facilities to ensure reasonable visibility progress
for the second planning period. The state submitted the SIP to the EPA in August 2022 and the EPA determined the submission was complete August 22, 2022. The EPA is required to make a determination on the Utah SIP by August 2023.
43
The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014.
The EPA's final action on the Wyoming SIP in 2014 approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls by 2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental
groups also filed an appeal of the EPA's final action. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The parties worked to mediate claims under the Wyoming regional haze requirements until the abatement on litigation was lifted in September 2022. 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 a SCR requirement. Oral argument will be held May 16, 2023. PacifiCorp has claimed the Naughton claims are moot but that a court ruling on the Wyodak claims is necessary to determine whether the EPA's federal plan complies with the Clean Air Act.
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 fall 2023. Wyoming submitted a SIP for the second round of regional haze planning to the EPA in August 2022 and the EPA determined the submission was complete that same month. Wyoming determined that no additional controls are necessary on any Wyoming resources to make reasonable progress under the regional haze rules. The EPA is required to make a determination on the Wyoming SIP by August 2023.
The state of Colorado 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.
44
Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA in August 2022. The EPA has 18 months to approve or disapprove all or parts of the states' plans. On August 25, 2022, the EPA promulgated a finding of failure to submit a SIP for the regional haze second planning period for 15 states, including Iowa. The finding establishes a two-year deadline for the agency to promulgate FIPs to address the
requirements, unless prior to promulgating a FIP, the state submits, and the agency approves, a SIP meeting the requirements. The finding says the agency intends to continue to work with states in developing approvable SIP submittals in a timely manner. The Iowa Department of Natural Resources continues to work with the EPA on development of its SIP. 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 summer 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 will accept public comments through May 30, 2023, and intends to finalize a rule by spring 2024.
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.
45
PacifiCorp
and its subsidiaries
Consolidated Financial Section
46
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 March 31, 2023, the related consolidated statements of operations, changes in shareholders' equity, and cash flowsfor the three-month periods ended March 31, 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
i279
i280
Allowance
for equity funds
(i27)
(i13)
Net
power cost deferrals
(i136)
(i14)
Amortization of
net power cost deferrals
i36
i11
Other
changes in regulatory assets and liabilities
(i6)
(i6)
Deferred
income taxes and amortization of investment tax credits
(i75)
i19
Other,
net
(i2)
i4
Changes
in other operating assets and liabilities:
Trade receivables, other receivables and other assets
i37
i59
Inventories
(i17)
(i5)
Derivative
collateral, net
(i78)
i22
Accrued
property, income and other taxes, net
(i11)
i15
Accounts
payable and other liabilities
i459
i35
Net
cash flows from operating activities
i339
i537
Cash
flows from investing activities:
Capital expenditures
(i643)
(i374)
Other,
net
(i1)
i3
Net
cash flows from investing activities
(i644)
(i371)
Cash
flows from financing activities:
Repayments of long-term debt
(i9)
(i9)
Dividends
paid
(i300)
i—
Other,
net
(i2)
(i2)
Net
cash flows from financing activities
(i311)
(i11)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i616)
i155
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
$
i58
$
i341
The
accompanying notes are an integral part of these consolidated financial statements.
52
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 March 31, 2023, and for the three-month periods ended March 31, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 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 three-month period ended March 31, 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 the 2022 McKinney fire 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
i8
i7
Restricted
cash included in other assets
i31
i26
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i58
$
i674
53
(3) iProperty,
Plant and Equipment, Net
i
Property, plant and equipment, net consists of the following (in millions):
As
of
March 31,
December 31,
Depreciable Life
2023
2022
Utility plant:
Generation
i15
- i59 years
$
i13,721
$
i13,726
Transmission
i60
- i90 years
i8,063
i8,051
Distribution
i20
- i75 years
i8,578
i8,477
Intangible
plant(1) and other
i5 - i75 years
i2,758
i2,755
Utility
plant in-service
i33,120
i33,009
Accumulated
depreciation and amortization
(i11,256)
(i11,093)
Utility
plant in-service, net
i21,864
i21,916
Nonregulated,
net of accumulated depreciation and amortization
i14 - i95
years
i18
i18
i21,882
i21,934
Construction
work-in-progress
i2,813
i2,496
Property,
plant and equipment, net
$
i24,695
$
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
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 March 31, 2023 of i48% results from a $i110 million
income tax benefit associated with a $i230 million pre-tax loss primarily resulting from the $i359 million
pre-tax loss associated with the 2020 Wildfires described in Note 9. The $i110 million income tax benefit is primarily comprised of a $i48 million
benefit (i21%) from the application of the federal statutory income tax rate to the pre-tax loss and a $i29 million
benefit (i13%) from federal income tax credits.
i
A reconciliation
of the federal statutory income tax rate to the effective income tax rate applicable to (loss) income before income tax expense (benefit) is as follows:
State
income tax, net of federal income tax benefit
i4
i3
Federal
income tax credits
i13
(i20)
Effects
of ratemaking(1)
i6
(i11)
Valuation
allowance
i5
i6
Other
(i1)
i3
Effective
income tax rate
i48
%
i2
%
(1)Effects
of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
/
54
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 March 31, 2023 and 2022, totaled $i29 million and $i26 million,
respectively.
For the three-month period ended March 31, 2023, PacifiCorp released an $i11 million valuation allowance related to state net operating loss carryforwards. For the three-month period ended March 31, 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. As
of March 31, 2023 and December 31, 2022, federal and state income taxes receivable from BHE were $i119 million and $i84 million,
respectively.
(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 March 31, 2023, $i1 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.
55
PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest
rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices. Refer to Note 8 for additional information on derivative contracts.
i
The
following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
(1)PacifiCorp's
commodity derivatives are generally included in rates. As of March 31, 2023, a regulatory liability of $i109 million was recorded related to the net derivative asset of $i109 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.
/
56
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
(i10)
(i168)
Net
losses reclassified to operating revenue
(i6)
(i3)
Net
gains reclassified to energy costs
i177
i29
Ending
balance
$
(i109)
$
(i195)
/
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
March 31,
December 31,
Measure
2023
2022
Electricity purchases, net
Megawatt hours
i3
i2
Natural
gas purchases
Decatherms
i158
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 either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to
demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2023, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $i56 million
and $i48 million as of March 31, 2023 and December 31, 2022, respectively, for which PacifiCorp had posted collateral of $ii— million/,
in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of March 31, 2023 and December 31, 2022, PacifiCorp would have been required to post $i20 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.
57
(8) iFair Value
Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.
•Level
2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.
i
The
following table presents PacifiCorp's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
(1)Represents
netting under master netting arrangements and a net cash collateral payable of $i12 million and $i78 million
as of March 31, 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.
/
58
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.
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
In April 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 three-month period ended March 31, 2023, PacifiCorp entered into certain coal supply and transportation agreements totaling $i247 million through 2025.
59
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 is anticipated to begin in 2023, and removal of the remaining three 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 arising out of the normal course of business. Plaintiffs occasionally seek
punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
Wildfires Overview
A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. 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.
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 proximately caused by negligence, including real and personal property and natural resource damages; fire suppression costs; personal injury and loss of life damages; and interest.
2020 Wildfires
In
September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over i500,000
acres in aggregate. Third-party reports for these wildfires indicate over i2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $i150 million.
Investigations
into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the 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.
60
As of the date of this filing, numerous lawsuits have been filed in Oregon and California, including a class action complaint in Oregon, on behalf of plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California
with allegations similar to those made in the aforementioned lawsuits. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of litigation and recent settlements, PacifiCorp has accrued cumulative estimated probable losses associated with the 2020 Wildfires of $i877 million
through March 31, 2023. PacifiCorp's cumulative accrual includes estimates of losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available.
It is reasonably possible PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number
of properties and parties involved and the variation in those types of properties and lack of available details. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover a portion of the losses.
i
The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires (in millions):
PacifiCorp's
receivable for expected insurance recoveries associated with the probable losses was $i287 million and $i246 million, respectively, as of March 31,
2023 and December 31, 2022. During the three-month periods ended March 31, 2023 and 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $i359 million and $i— million,
respectively, and are recorded in operations and maintenance on the Consolidated Statements of Operations.
2022 McKinney Fire
According to the California Department of Forestry and Fire Protection, on July 29, 2022, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. 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.
Due
to the preliminary nature of the investigation PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $i31 million, net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp
is unable to estimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $i103 million, to cover potential losses.
61
As
of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages that include property damages, economic and noneconomic losses, punitive damages, exemplary damages, attorneys' fees and other damages but the amount of damages sought are not specified. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
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 First Quarter of 2023 and 2022
Overview
Net loss for the first quarter of 2023 was $120 million, a decrease of $250 million compared to 2022 net income of $130 million. The decrease in net income was primarily due to increased operations and maintenance expense, largely due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $359 million, higher wildfire mitigation costs, including vegetation management and higher plant operations and maintenance costs, partially offset by higher income tax benefit, higher utility margin and lower other expense. Utility margin increased primarily due to higher retail prices and volumes, higher net power cost deferrals, higher average wholesale market prices and lower coal-fueled generation
volumes, partially offset by higher purchased electricity costs from higher prices and volumes, higher natural gas-fueled generation costs from higher prices and volumes, lower wholesale volumes and higher coal-fueled generation prices. Retail customer volumes increased 3.3% primarily due to favorable impacts of weather, an increase in the average number of customers and an increase in commercial and residential customer usage, partially offset by a decrease in industrial customer usage. Energy generated decreased 7% for the first quarter 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 47% and purchased electricity volumes increased 28%.
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.
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):
First
Quarter
2023
2022
Change
Utility margin:
Operating
revenue
$
1,484
$
1,297
$
187
14
%
Cost of fuel and energy
614
465
149
32
Utility
margin
870
832
38
5
Operations and maintenance
705
277
428
155
Depreciation
and amortization
279
280
(1)
—
Property and other taxes
53
59
(6)
(10)
Operating
(loss) income
$
(167)
$
216
$
(383)
(177)
%
63
Utility
Margin
A comparison of key operating results related to utility margin is as follows:
First
Quarter
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
1,484
$
1,297
$
187
14
%
Cost of fuel and energy
614
465
149
32
Utility
margin
$
870
$
832
$
38
5
%
Sales
(GWhs):
Residential
5,102
4,764
338
7
%
Commercial
4,983
4,550
433
10
Industrial,
irrigation and other
4,209
4,523
(314)
(7)
Total retail
14,294
13,837
457
3
Wholesale
825
1,553
(728)
(47)
Total
sales
15,119
15,390
(271)
(2)
%
Average
number of retail customers (in thousands)
2,057
2,025
32
2
%
Average
revenue per MWh:
Retail
$
93.82
$
85.46
$
8.36
10
%
Wholesale
$
86.45
$
39.12
$
47.33
121
%
Heating
degree days
5,205
4,745
460
10
%
Cooling
degree days
—
5
(5)
(100)
%
Sources
of energy (GWhs)(1):
Coal
5,555
6,911
(1,356)
(20)
%
Natural
gas
3,955
3,115
840
27
Wind(2)
2,083
2,392
(309)
(13)
Hydroelectric
and other(2)
812
984
(172)
(17)
Total energy generated
12,405
13,402
(997)
(7)
Energy
purchased
4,128
3,223
905
28
Total
16,533
16,625
(92)
(1)
%
Average
cost of energy per MWh:
Energy generated(3)
$
28.35
$
18.83
$
9.52
51
%
Energy
purchased
$
77.72
$
55.49
$
22.23
40
%
(1)GWh amounts are net of energy used by the related generating facilities.
(2) All
or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of Renewable Energy Credits or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
Utility margin increased $38 million, or 5%, for the
first quarter of 2023 compared to 2022 primarily due to:
•$159 million increase in retail revenue due to higher average prices and higher volumes. Retail customer volumes increased 3.3% primarily due to favorable impacts of weather, mainly in Oregon, an increase in the average number of customers and an increase in commercial and residential customer usage, partially offset by a decrease in industrial customer usage across all states except Idaho;
•$97 million of higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms;
•$17 million of higher other revenue primarily due to higher wheeling revenue and higher revenues associated with sales of greenhouse gas allowances;
•$11
million increase in wholesale revenue primarily due to higher average market prices, partially offset by lower volumes; and
•$9 million of lower coal-fueled generation costs primarily due to lower volumes, partially offset by higher average prices.
The increases above were partially offset by:
•$142 million of higher purchased electricity costs from higher average market prices and higher volumes; and
•$109 million of higher natural gas-fueled generation costs due to higher average market prices and higher volumes.
Operations and maintenance increased $428 million for the first quarter of 2023 compared to 2022 primarily
due to a $359 million increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires, $23 million of higher wildfire mitigation costs, including vegetation management and amortization of amounts previously deferred in Oregon, $21 million of higher general and plant maintenance costs, $10 million of higher labor and benefit expenses, and $8 million of higher demand-side management amortization expense (offset in retail revenue).
Property and other taxes decreased $6 million, or 10%, for the first quarter of 2023 compared to 2022 primarily due to lower property tax rates in Utah.
Interest expense increased $18 million, or 17%, for the first quarter of 2023 compared to 2022 primarily due to higher average long-term debt
balances.
Allowance for borrowed and equity funds increased $21 million for the first quarter of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.
Interest and dividend income increased $12 million for the first quarter of 2023 compared to 2022 primarily due to higher investment income due to higher average interest rates and the recording of interest on higher deferred net power cost balances.
Other, net increased $6 million for the first quarter 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 primarily due to market movements (offset in operations and maintenance expense).
Income tax (benefit) expense decreased $112 million to a benefit of $110 million for the first quarter of 2023 compared to an expense of $2 million for the first quarter of 2022 and the effective tax rate was 48% for 2023 and 2% for 2022. The $112 million decrease in income tax expense to an income tax benefit is primarily due to the increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires during the first quarter of 2023 and the release of a valuation allowance on state net operating loss carryforwards in the first quarter of 2023 compared to the establishment of a state valuation allowance in 2022.
65
Liquidity
and Capital Resources
As of March 31, 2023, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents
$
19
Credit facilities
2,000
Less:
Tax-exempt
bond support and letters of credit
(249)
Net credit facilities
1,751
Total net liquidity
$
1,770
Credit facilities:
Maturity dates
2024,
2025
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $339 million and $537 million, respectively. The decrease is primarily due to higher wholesale and fuel purchases, collateral returned to counterparties and operations and maintenance expenses, 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 three-month periods ended March 31, 2023 and 2022, were $(644) million and $(371) million, respectively. The change is primarily due to an increase in capital expenditures of $269 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2023, were $(311) million. Uses of cash consisted primarily of $300 million for common stock dividends paid to PPW Holdings LLC and $9 million for the repayment
of long-term debt.
Net cash flows from financing activities for the three-month period ended March 31, 2022, were $(11) million. Uses of cash consisted substantially of $9 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 March 31, 2023, and December 31, 2022, PacifiCorp had no short-term debt outstanding.
Debt Authorizations
PacifiCorp
currently has regulatory authority from the OPUC and the Idaho Public Utilities Commission to issue an additional $5 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 2023.
Common Shareholders' Equity
In January 2023, PacifiCorp declared a common stock dividend of $300 million, paid in February 2023, to PPW Holdings LLC.
66
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; 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):
Three-Month
Periods
Annual
Ended March 31,
Forecast
2022
2023
2023
Wind generation
$
8
$
17
$
833
Electric
distribution
139
177
781
Electric transmission
156
169
1,484
Solar generation
—
—
19
Electric
battery and pumped hydro storage
1
1
24
Other
70
279
521
Total
$
374
$
643
$
3,662
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 2021 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 $14 million and $6 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the construction
of additional wind-powered generating facilities and those at acquired sites totals $807 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 includes spend on wildfire mitigation. Expenditures for wildfire mitigation totaled $33 million and $22 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for wildfire mitigation totals $162 million for the remainder of 2023. The remaining investments primarily relate to expenditures for new connections and distribution operations.
•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 $110 million and $96 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $898 million for the remainder of 2023.
67
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $46 million and $45 million for the three-month
periods ended March 31, 2023 and 2022, respectively. Planned information technology spending totals $180 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 September 2021, PacifiCorp filed its 2021 IRP with its state commissions and subsequently filed its 2021 IRP Update in March and April 2022. Reviews of the 2021 IRP by the Wyoming Public Service Commission and the WUTC are ongoing.
In March 2023, PacifiCorp filed its 2023 IRP in Idaho, Oregon and Wyoming. A 60-day post-filing extended comment period has been added to the 2023 IRP to provide opportunity for additional stakeholder feedback. PacifiCorp will consider feedback during the first
30 days and then prepare an addendum, if warranted, to the filed IRP on May 30, 2023.
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. The March 2023 filing is considered informational in Utah, pending the potential addendum to be filed in May 2023.
Requests for Proposals
PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load or state-specific
compliance obligations. Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.
PacifiCorp's 2022 All-Source RFP was issued to market in April 2022. In December 2022, PacifiCorp bid 12 eligible self-build (benchmark) resources and in March 2023, PacifiCorp received 302 bids from 74 developers and 93 different projects sites across six states. A final shortlist is expected later in 2023 with resources contracted by December 2023. PacifiCorp anticipates a similar all-source RFP will be required in connection with the 2023 IRP.
Material Cash Requirements
As
of March 31, 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.
68
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.
69
MidAmerican
Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
70
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 March 31, 2023, the related statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 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
i234
i250
Amortization
of utility plant to other operating expenses
i8
i9
Allowance
for equity funds
(i11)
(i15)
Deferred
income taxes and investment tax credits, net
i32
i16
Settlements
of asset retirement obligations
(i6)
(i7)
Other,
net
i8
i10
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i131
i42
Inventories
(i3)
i49
Pension
and other postretirement benefit plans
(i3)
i3
Accrued
property, income and other taxes, net
(i263)
(i244)
Accounts
payable and other liabilities
(i81)
i3
Net
cash flows from operating activities
i288
i360
Cash
flows from investing activities:
Capital expenditures
(i382)
(i459)
Purchases
of marketable securities
(i48)
(i105)
Proceeds
from sales of marketable securities
i42
i102
Other,
net
i4
i1
Net
cash flows from investing activities
(i384)
(i461)
Cash
flows from financing activities:
Common stock dividend
(i100)
i—
Repayments
of long-term debt
(i7)
(i1)
Other,
net
(i1)
i1
Net
cash flows from financing activities
(i108)
i—
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i204)
(i101)
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
$
i64
$
i138
The
accompanying notes are an integral part of these financial statements.
76
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 March 31, 2023, and for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31,
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 three-month period ended March 31, 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
i7
i10
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i64
$
i268
77
(3) iProperty,
Plant and Equipment, Net
iProperty, plant and equipment, net consists of the following (in millions):
As
of
March 31,
December 31,
Depreciable Life
2023
2022
Utility plant:
Generation
i20-i62
years
$
i18,385
$
i18,582
Transmission
i55-i80
years
i2,672
i2,662
Electric
distribution
i15-i80 years
i4,983
i4,931
Natural
gas distribution
i30-i75 years
i2,166
i2,144
Utility
plant in-service
i28,206
i28,319
Accumulated
depreciation and amortization
(i8,210)
(i8,024)
Utility
plant in-service, net
i19,996
i20,295
Nonregulated
property, net of accumulated depreciation and amortization
i20-i50
years
i6
i6
i20,002
i20,301
Construction
work-in-progress
i979
i790
Property,
plant and equipment, net
$
i20,981
$
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 three-month periods ended March 31, 2023 and 2022, $i20 million
and $i42 million, respectively, is reflected in depreciation and amortization expense on the Statement of Operations.
(4) 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
(i18)
(i21)
Effects
of ratemaking
(i8)
(i8)
Other,
net
i2
i—
Effective
income tax rate
(i521)
%
(i542)
%
/
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 other income tax expense. Wind- and solar-powered generating facilities are eligible for the credits for i10
years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the three-month periods ended March 31, 2023 and 2022, totaled $i202 million and $i203 million,
respectively.
78
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 made net cash payments for income tax to BHE totaling $i1 million
and $i— million for the three-month periods ended March 31, 2023 and 2022, respectively.
(5) iEmployee
Benefit Plans
MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.
i
Net periodic benefit cost
(credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
Amounts
other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans during 2023 are expected to be $i7 million and $i2 million,
respectively. As of March 31, 2023, $i2 million and $i1 million
of contributions had been made to the pension and other postretirement benefit plans, respectively.
(6) 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 three-month period ended March 31, 2023, MidAmerican Energy recorded an increase of $i88 million for
decommissioning its wind-generating facilities due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.
79
(7) iFair Value Measurements
The carrying
value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.
•Level
2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.
i
The
following table presents MidAmerican Energy's financial assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
(1)Represents
netting under master netting arrangements and a net cash collateral receivable of $i5 million and $i— million
as of March 31, 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
(i13)
i13
Settlements
i3
(i4)
Ending
balance
$
(i5)
$
i4
/
81
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 three-month period ended March 31, 2023, MidAmerican Energy entered into firm construction commitments totaling $i183
million for the remainder of 2023 through 2024 related to the construction 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. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.
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.
82
(9) iRevenue
from Contracts with Customers
i
The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 11 (in millions):
In January 2023, MidAmerican Energy paid $i100 million in cash dividends to its parent company, MHC.
83
(11) 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 March 31, 2023, the related consolidated statements of operations, changes in member's equity, and cash flows for the three-month periods ended March 31, 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
i234
i250
Amortization
of utility plant to other operating expenses
i8
i9
Allowance
for equity funds
(i11)
(i15)
Deferred
income taxes and investment tax credits, net
i32
i16
Settlements
of asset retirement obligations
(i6)
(i7)
Other,
net
(i5)
i10
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i123
i43
Inventories
(i3)
i49
Pension
and other postretirement benefit plans
(i3)
i3
Accrued
property, income and other taxes, net
(i261)
(i245)
Accounts
payable and other liabilities
(i85)
(i1)
Net
cash flows from operating activities
i272
i353
Cash
flows from investing activities:
Capital expenditures
(i382)
(i459)
Purchases
of marketable securities
(i48)
(i105)
Proceeds
from sales of marketable securities
i42
i102
Proceeds
from sale of investment
i12
i—
Other,
net
i5
i1
Net
cash flows from investing activities
(i371)
(i461)
Cash
flows from financing activities:
Distribution to member
(i100)
i—
Repayments
of long-term debt
(i7)
(i1)
Net
change in note payable to affiliate
i—
i8
Other,
net
(i1)
i—
Net
cash flows from financing activities
(i108)
i7
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i207)
(i101)
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
$
i64
$
i139
The
accompanying notes are an integral part of these consolidated financial statements.
90
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 March 31, 2023, and for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31,
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 three-month period ended March 31, 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
i6
i10
Total
cash and cash equivalents and restricted cash and cash equivalents
$
i64
$
i271
(3) iProperty,
Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.
91
(4) 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
(i13)
(i24)
Effects
of ratemaking
(i6)
(i9)
Other,
net
(i2)
i—
Effective
income tax rate
(i430)
%
(i630)
%
/
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 other income tax expense. Wind- and solar-powered generating facilities are eligible for the credits for i10
years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the three-month periods ended March 31, 2023 and 2022, totaled $i202 million and $i203 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 made iino/
cash payments for income tax to BHE for each of the three-month periods ended March 31, 2023 and 2022.
(5) iEmployee Benefit Plans
Refer to Note 5 of MidAmerican Energy's Notes
to Financial Statements.
(6) iAsset Retirement Obligations
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.
(7) iFair
Value Measurements
Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. iThe
following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):
MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.
(9) iRevenue
from Contracts with Customers
Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.
(10) iMember's Equity
In January 2023, MidAmerican
Funding paid a $i100 million cash distribution to its parent company, BHE.
(11) 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.
94
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 First Quarter of 2023 and 2022
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the first quarter of 2023 was $242 million, a decrease of $2 million, or 1%, compared to 2022, primarily due to higher operations and maintenance expense, lower natural gas utility margin, lower electric utility margin, lower allowance for equity funds, lower income tax benefit, higher property and other taxes and higher interest expense, offset by favorable other, net and lower depreciation and amortization expense. 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 9%, due
to lower wind-powered and coal-fueled generation, and energy purchased increased 17%. Wholesale electricity sales volumes decreased 18% due to unfavorable market conditions. Natural gas retail customer volumes decreased 10% due to the unfavorable impact of weather.
MidAmerican Funding -
MidAmerican Funding's net income for the first quarter of 2023 was $249 million, an increase of $8 million, or 3%, compared to 2022. The variance in net income was primarily due to a one-time gain on the sale of an investment of $10 million, partially offset by the changes in MidAmerican Energy's earnings discussed above.
Non-GAAP Financial Measure
Management utilizes various
key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.
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.
95
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):
First
Quarter
2023
2022
Change
Electric utility margin:
Operating
revenue
$
591
$
608
$
(17)
(3)
%
Cost of fuel and energy
115
125
(10)
(8)
Electric
utility margin
476
483
(7)
(1)
%
Natural
gas utility margin:
Operating revenue
326
396
(70)
(18)
%
Natural
gas purchased for resale
236
298
(62)
(21)
Natural gas utility margin
90
98
(8)
(8)
%
Utility
margin
566
581
(15)
(3)
%
Other
operating revenue
3
1
2
*
Operations
and maintenance
205
192
13
7
Depreciation and amortization
234
250
(16)
(6)
Property
and other taxes
42
40
2
5
Operating
income
$
88
$
100
$
(12)
(12)
%
* Not meaningful.
96
Electric
Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
First
Quarter
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
591
$
608
$
(17)
(3)
%
Cost of fuel and energy
115
125
(10)
(8)
Utility
margin
$
476
$
483
$
(7)
(1)
%
Sales
(GWhs):
Residential
1,793
1,853
(60)
(3)
%
Commercial
1,018
1,013
5
—
Industrial
4,102
3,979
123
3
Other
409
403
6
1
Total
retail
7,322
7,248
74
1
Wholesale
4,352
5,325
(973)
(18)
Total
sales
11,674
12,573
(899)
(7)
%
Average
number of retail customers (in thousands)
818
810
8
1
%
Average
revenue per MWh:
Retail
$
67.02
$
65.10
$
1.92
3
%
Wholesale
$
17.56
$
20.65
$
(3.09)
(15)
%
Heating
degree days
2,992
3,315
(323)
(10)
%
Sources
of energy (GWhs)(1):
Wind and other(2)
7,377
8,290
(913)
(11)
%
Coal
2,116
2,359
(243)
(10)
Nuclear
927
920
7
1
Natural
gas
344
234
110
47
Total energy generated
10,764
11,803
(1,039)
(9)
Energy
purchased
1,123
962
161
17
Total
11,887
12,765
(878)
(7)
%
Average
cost of energy per MWh:
Energy generated(3)
$
6.09
$
5.56
$
0.53
10
%
Energy
purchased
$
43.72
$
62.04
$
(18.32)
(30)
%
(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.
97
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
First
Quarter
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
326
$
396
$
(70)
(18)
%
Natural gas purchased for resale
236
298
(62)
(21)
Utility
margin
$
90
$
98
$
(8)
(8)
%
Throughput
(000's Dths):
Residential
24,393
27,099
(2,706)
(10)
%
Commercial
11,352
12,460
(1,108)
(9)
Industrial
1,483
1,844
(361)
(20)
Other
34
35
(1)
(3)
Total
retail sales
37,262
41,438
(4,176)
(10)
Wholesale sales
10,407
12,232
(1,825)
(15)
Total
sales
47,669
53,670
(6,001)
(11)
Natural gas transportation service
29,585
31,313
(1,728)
(6)
Total
throughput
77,254
84,983
(7,729)
(9)
%
Average
number of retail customers (in thousands)
793
785
8
1
%
Average
revenue per retail Dth sold
$
7.63
$
7.84
$
(0.21)
(3)
%
Heating
degree days
3,132
3,485
(353)
(10)
%
Average
cost of natural gas per retail Dth sold
$
5.58
$
5.80
$
(0.22)
(4)
%
Combined
retail and wholesale average cost of natural gas per Dth sold
Electric utility margin decreased $7 million, or (1)%, for the first quarter of 2023 compared to 2022, primarily due to:
•a $23 million decrease in wholesale utility margin due to lower volumes of 18.3% and lower margins per unit of $7 million, reflecting lower market prices; partially offset by
•a $17 million increase in retail utility margin primarily due to $14 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $7 million from
higher customer usage; partially offset by $5 million from the unfavorable impact of weather. Retail customer volumes increased 1.0%.
Natural gas utility margin decreased $8 million, or 8%, for the first quarter of 2023 compared to 2022 primarily due to:
•a $5 million decrease from lower recoveries through a capital tracker mechanism;
•a $5 million decrease due to the unfavorable impact of weather; partially offset by
•a $3 million increase due to price impacts from changes in sales mix.
Operations and maintenance increased $13 million, or 7%, for the
first quarter of 2023 compared to 2022 primarily due to higher technology and other administrative costs of $6 million, higher other power and steam power generation costs of $5 million, higher property insurance costs of $3 million and higher benefit costs of $2 million, partially offset by lower nuclear power generation costs of $4 million.
98
Depreciation and amortization decreased $16 million, or 6%, for the first quarter of 2023 compared to 2022 primarily due to $22 million from lower Iowa revenue sharing accruals, and $16 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $19 million from wind-powered generating facilities and other plant placed
in-service and $3 million from lower depreciation expense deferrals in 2023.
Property and other taxes increased $2 million, or 5%, for the first quarter of 2023 compared to 2022 primarily due to $1 million from higher wind turbine property taxes and $1 million from higher replacement taxes.
Interest expense increased $2 million, or 3%, for the first quarter of 2023 compared to 2022 due to higher interest rates on variable rate long-term debt.
Allowance for equity funds decreased $4 million, or 27%, for the first quarter of 2023 compared to 2022 due to lower construction work-in-progress balances related to wind- and solar-powered generation.
Other,
net increased $19 million, or 633%, for the first quarter 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 lower non-service costs of employee benefit plans.
Income tax benefit decreased $3 million, or 1%, for the first quarter of 2023 compared to 2022 primarily due to lower PTCs and state income tax impacts. PTCs for the first quarter of 2023 and 2022 totaled $202 million and $203 million, respectively.
MidAmerican Funding -
Income tax benefit decreased $6 million, or 3%, for the first quarter of 2023 compared to 2022 principally
due to higher pretax income from a one-time gain on the sale of an investment and the changes in MidAmerican Energy's income tax benefit discussed above.
Liquidity and Capital Resources
As of March 31, 2023, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
MidAmerican Energy:
Cash
and cash equivalents
$
57
Credit facilities, maturing 2023 and 2025
1,505
Less:
Tax-exempt bond support
(363)
Net credit
facilities
1,142
MidAmerican Energy total net liquidity
$
1,199
MidAmerican Funding:
MidAmerican Energy total net liquidity
$
1,199
Cash
and cash equivalents
1
MHC, Inc. credit facility, maturing 2023
4
MidAmerican Funding total net liquidity
$
1,204
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022,
were $288 million and $360 million, respectively. MidAmerican Funding's net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $272 million and $353 million, respectively. Cash flows from operating activities reflect higher payments to vendors, higher derivative collateral posted, higher property tax payments and lower utility margins for MidAmerican Energy's regulated electric and natural gas businesses.
99
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 three-month periods ended March 31, 2023 and 2022, were $(384) million and $(461) million, respectively. MidAmerican Funding's net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(371) million and $(461) 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 three-month periods ended March 31, 2023 and 2022 were $(108) million and $— million, respectively. MidAmerican Funding's net cash flows from financing activities for the three-month periods ended March 31, 2023 and 2022, were $(108) million and $7 million, respectively. In January 2023, MidAmerican Funding made a $100 million distribution to its sole member, BHE. MidAmerican Funding paid $— million and received $8 million in 2023 and 2022, respectively, through its note payable with BHE.
Debt
Authorizations and Related Matters
Short-term Debt
MidAmerican Energy has authority from the FERC to issue, through April 2, 2024, commercial paper and bank notes aggregating $1.5 billion. MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 2025. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
Long-term Debt and Preferred Stock
MidAmerican Energy currently has an effective shelf registration statement with the SEC to issue up to $3.25 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, 2023, long-term debt securities up to an aggregate of $2.0 billion and preferred stock up to an aggregate of $500 million. MidAmerican Energy has authorization from the ICC through May 25, 2025, to issue long-term debt securities up to an aggregate of $2.2 billion and preferred stock up to an aggregate of $500 million; through October
15, 2024, to issue $750 million of long-term debt securities for the purpose of refinancing $250 million of its 3.70% Senior notes due September 2023 and $500 million of its 2.40% Senior notes due October 2024; and through January 1, 2025, to issue $105 million of long-term debt securities for the purpose of refinancing three of its variable-rate tax-exempt bond series, including $57 million due in May 2023, $35 million due in October 2024 and $13 million due in January 2025.
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.
100
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):
Three-Month
Periods
Annual
Ended March 31,
Forecast
2022
2023
2023
Wind generation
$
133
$
88
$
1,222
Electric
distribution
54
73
296
Electric transmission
21
33
187
Solar generation
44
9
10
Other
207
179
609
Total
$
459
$
382
$
2,324
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 $75 million and $3 million for the three-month periods ended March 31, 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 $1,025 million for the remainder of 2023.
◦Repowering
of wind-powered generating facilities totaling $5 million and $120 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $16 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 three-month periods ended March 31, 2023 and 2022 solar generation spend totaled $9 million and $44 million, respectively. Planned spending totals $1 million for the remainder of 2023.
•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 March 31, 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.
101
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.
102
Nevada Power Company and its subsidiaries
Consolidated Financial Section
103
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 March 31, 2023, the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 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 (loss) to net cash flows from operating activities:
Depreciation and amortization
i106
i103
Allowance
for equity funds
(i4)
(i3)
Changes
in regulatory assets and liabilities
(i9)
(i8)
Deferred
income taxes and amortization of investment tax credits
(i10)
i5
Deferred
energy
(i370)
(i51)
Amortization of deferred energy
i52
i13
Other,
net
i1
i4
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i74
i33
Inventories
(i13)
i3
Accrued
property, income and other taxes
i1
(i15)
Accounts
payable and other liabilities
(i44)
i3
Net
cash flows from operating activities
(i212)
i85
Cash
flows from investing activities:
Capital expenditures
(i333)
(i189)
Proceeds
from repayment of affiliate note receivable
i100
i—
Net
cash flows from investing activities
(i233)
(i189)
Cash
flows from financing activities:
Net (repayments of) proceeds from long-term debt
(i1)
i200
Net
(repayments of) proceeds from short-term debt
i33
(i76)
Contributions
from parent
i400
i—
Other,
net
(i5)
(i4)
Net
cash flows from financing activities
i427
i120
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i18)
i16
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
$
i42
$
i61
The
accompanying notes are an integral part of these consolidated financial statements.
108
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 March 31, 2023, and for the three-month periods ended March 31, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted
as net income equals comprehensive income for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 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 three-month period ended March 31, 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):
Non-regulated,
net of accumulated depreciation and amortization
i45 years
i1
i1
i6,946
i6,921
Construction
work-in-progress
i703
i485
Property,
plant and equipment, net
$
i7,649
$
i7,406
/
(4) iRecent
Financing Transactions
Long-Term Debt
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/%.
(5) iIncome
Taxes
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:
Effects
of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2021.
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for federal income tax has been computed on a separate return basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the three-month periods ended March 31, 2023 and 2022, Nevada Power made iino/
cash payments for federal income tax to BHE.
110
(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.
111
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 March 31, 2023 a regulatory asset of $i116 million was recorded related to the net derivative liability of $i116 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
March 31,
December
31,
Measure
2023
2022
Electricity purchases
Megawatt hours
i2
i2
Natural
gas purchases
Decatherms
i155
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.
112
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 March 31, 2023, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $i10
million and $i5 million as of March 31, 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.
113
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 March 31, 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.
114
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
(i65)
(i56)
Settlements
i1
i1
Ending
balance
$
(i116)
$
(i168)
/
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.
Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
115
(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 First Quarter of 2023 and 2022
Overview
Net income for the first quarter of 2023 was $4 million, an increase of $6 million, compared to 2022 primarily due to higher interest and dividend income, mainly from higher carrying charges on regulatory balances, higher utility margin and higher cash surrender value of corporate-owned life insurance policies, partially offset by higher interest expense, primarily due to higher long-term debt, higher operations and maintenance expenses, mainly due to higher customer service operations expenses and higher plant operations and maintenance expenses, and higher depreciation and amortization, mainly due to higher plant placed in-service. Utility margin increased primarily due to higher retail customer volumes, higher other retail revenue and higher
regulatory-related revenue deferrals. Retail customer volumes, including distribution only service customers, increased 3.3% primarily due to an increase in the average number of customers and the favorable impact of weather. Energy generated increased 37% for the first quarter of 2023 compared to 2022 due to higher natural gas-fueled generation. Wholesale electricity sales volumes decreased 50% and purchased electricity volumes decreased 35%.
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.
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):
First Quarter
2023
2022
Change
Utility
margin:
Operating revenue
$
599
$
415
$
184
44
%
Cost
of fuel and energy
384
212
172
81
Utility margin
215
203
12
6
Operations
and maintenance
73
65
8
12
Depreciation and amortization
106
103
3
3
Property
and other taxes
14
13
1
8
Operating income
$
22
$
22
$
—
—
%
117
Utility
Margin
A comparison of key operating results related to utility margin is as follows:
First
Quarter
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
599
$
415
$
184
44
%
Cost of fuel and energy
384
212
172
81
Utility
margin
$
215
$
203
$
12
6
%
Sales
(GWhs):
Residential
1,636
1,585
51
3
%
Commercial
997
998
(1)
—
Industrial
1,242
1,175
67
6
Other
43
46
(3)
(7)
Total
fully bundled(1)
3,918
3,804
114
3
Distribution only service
598
569
29
5
Total
retail
4,516
4,373
143
3
Wholesale
63
125
(62)
(50)
Total
GWhs sold
4,579
4,498
81
2
%
Average
number of retail customers (in thousands)
999
995
4
—
%
Average
revenue per MWh:
Retail - fully bundled(1)
$
146.17
$
102.11
$
44.06
43
%
Wholesale
$
98.31
$
42.91
$
55.40
*
Heating
degree days
1,310
954
356
37
%
Cooling degree days
3
49
(46)
(94)
%
Sources
of energy (GWhs)(2)(3):
Natural gas
3,263
2,378
885
37
%
Renewables
15
14
1
7
Total
energy generated
3,278
2,392
886
37
Energy purchased
1,137
1,761
(624)
(35)
Total
4,415
4,153
262
6
%
Average
cost of energy per MWh(4):
Energy generated
$
90.64
$
41.92
$
48.72
*
Energy
purchased
$
76.11
$
63.27
$
12.84
20
%
* Not meaningful
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The
average cost of energy per MWh and sources of energy excludes 283 GWhs and 424 GWhs of gas generated energy that is purchased at cost by related parties for the first quarter 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 increased
$12 million, or 6%, for the first quarter of 2023 compared to 2022 primarily due to:
•$3 million of higher electric retail utility margin due to higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 3.3% primarily due to an increase in the average number of customers and the favorable impact of weather;
•$3 million of higher energy efficiency program rates (offset in operations and maintenance expense);
•$3 million of higher other retail revenue; and
•$2 million of higher regulatory-related revenue deferrals.
Operations and maintenance
increased $8 million, or 12%, for the first quarter of 2023 compared to 2022 primarily due to higher customer service operations expenses, higher energy efficiency program costs (offset in operating revenue) and higher plant operations and maintenance expenses.
Depreciation and amortization increased $3 million, or 3%, for the first quarter of 2023 compared to 2022 primarily due to higher plant placed in-service.
Interest expense increased $11 million, or 29%, for the first quarter of 2023 compared to 2022 primarily due to higher long-term debt.
Interest and dividend income increased $13 million for the first quarter of 2023 compared to 2022 primarily
due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $3 million for the first quarter of 2023 compared to 2022 primarily due to higher cash surrender value of corporate-owned life insurance policies.
Liquidity and Capital Resources
As of March 31, 2023, Nevada Power's total net liquidity was as follows (in millions):
Cash
and cash equivalents
$
23
Credit facility
400
Less -
Short-term debt
(33)
Net credit facility
367
Total
net liquidity
$
390
Credit facility:
Maturity date
2025
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $(212) million and $85 million, respectively. The change was primarily due to higher payments related to fuel and energy costs, partially offset by higher
collections from customers.
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 three-month periods ended March 31, 2023 and 2022, were $(233) million and $(189) 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.
119
Financing
Activities
Net cash flows from financing activities for the three-month periods ended March 31, 2023 and 2022, were $427 million and $120 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and higher proceeds from short-term debt, partially offset by lower proceeds from the issuance of long-term debt.
Long-Term Debt
In March 2023, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $40 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County, Arizona Pollution Control Corporation
Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County, Nevada Revenue Bonds, Series 2017, due 2036. The Coconino Series 2017A bond was offered at a fixed rate of 4.125% and the Coconino Series 2017B and Clark Series 2017 bonds were offered at a fixed rate of 3.750%
Debt Authorizations
Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $3.8 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective shelf registration statement with the SEC to issue up to $2.6 billion of general and refunding mortgage securities through November 2025.
Future
Uses of Cash
Nevada Power has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including regulatory approvals, Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital
expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customer rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates.
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):
Three-Month Periods
Annual
Ended March 31,
Forecast
2022
2023
2023
Electric
distribution
$
51
$
69
$
285
Electric transmission
21
34
130
Solar generation
7
30
205
Electric
battery storage
—
39
190
Other
110
161
528
Total
$
189
$
333
$
1,338
120
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, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma 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.
•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.
•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. 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.
Material Cash Requirements
As of March 31, 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.
121
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.
122
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
123
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 March 31, 2023, the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 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
i46
i36
Allowance
for equity funds
(i2)
(i2)
Changes
in regulatory assets and liabilities
i6
(i4)
Deferred
income taxes and amortization of investment tax credits
(i11)
(i3)
Deferred
energy
i2
(i7)
Amortization of
deferred energy
i42
i23
Changes
in other operating assets and liabilities:
Trade receivables and other assets
(i5)
i12
Inventories
(i4)
(i6)
Accrued
property, income and other taxes
i17
i7
Accounts
payable and other liabilities
(i31)
(i21)
Net
cash flows from operating activities
i87
i63
Cash
flows from investing activities:
Capital expenditures
(i104)
(i83)
Net
cash flows from investing activities
(i104)
(i83)
Cash
flows from financing activities:
Net (repayments of) proceeds from short-term debt
i50
(i102)
Contributions
from parent
i—
i130
Repayments
of affiliate note payable
(i70)
i—
Other,
net
(i2)
(i2)
Net
cash flows from financing activities
(i22)
i26
Net
change in cash and cash equivalents and restricted cash and cash equivalents
(i39)
i6
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
$
i17
$
i22
The
accompanying notes are an integral part of these consolidated financial statements.
128
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 March 31, 2023, and for the three-month periods ended March 31, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted
as net income equals comprehensive income for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 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 three-month period ended March 31, 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)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 the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2020.
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for federal income tax has been computed on a separate return basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the three-month periods ended March 31, 2023 and 2022, Sierra Pacific made iino/
cash payments for federal income tax to BHE.
130
(5) 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. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in
accumulated other comprehensive loss, net.
i
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost
of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.
Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Sierra
Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.
131
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 March 31, 2023 a net regulatory asset of $i33 million was recorded related to the net derivative liability of $i33
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
March 31,
December
31,
Measure
2023
2022
Electricity purchases
Megawatt hours
i1
i1
Natural
gas purchases
Decatherms
i67
i52
/
Credit
Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product
netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the
right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2023, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
132
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 March 31, 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.
(7) 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.
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 March 31, 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.
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
(i20)
(i19)
Ending
balance
$
(i33)
$
(i52)
/
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.
134
Legal Matters
Sierra
Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
(9) 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 10 (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.
135
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.
/
136
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 First Quarterof 2023 and 2022
Overview
Net
income for the first quarter of 2023 was $27 million, a decrease of $1 million, or 4%, compared to 2022 primarily due to higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher customer service operations expenses, higher depreciation and amortization, mainly due to higher plant placed in-service and higher regulatory amortizations, and higher interest expense, primarily due to higher interest rates and debt, partially offset by higher utility margin and higher interest and dividend income, primarily from carrying charges on regulatory balances. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, higher customer volumes and higher transmission and wholesale revenue. Electric retail customer volumes, including distribution only service customers, increased by 2.3% primarily due to the favorable impact of weather
and an increase in the average number of customers. Natural gas utility margin increased primarily due to higher customer volumes from the favorable impact of weather. Energy generated increased 11% for the first quarter of 2023 compared to 2022 primarily due to higher natural gas- and coal-fueled generation. Wholesale electricity sales volumes decreased 21% and purchased electricity volumes decreased 20%.
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.
137
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):
First
Quarter
2023
2022
Change
Electric utility margin:
Operating
revenue
$
304
$
227
$
77
34
%
Cost of fuel and energy
181
124
57
46
Electric
utility margin
123
103
20
19
%
Natural
gas utility margin:
Operating revenue
96
52
44
85
%
Natural
gas purchased for resale
75
34
41
*
Natural gas utility margin
21
18
3
17
%
Utility
margin
144
121
23
19
%
Operations
and maintenance
56
41
15
37
%
Depreciation and amortization
46
36
10
28
Property
and other taxes
7
6
1
17
Operating income
$
35
$
38
$
(3)
(8)
%
* Not
meaningful
138
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
First
Quarter
2023
2022
Change
Utility margin (in millions):
Operating
revenue
$
304
$
227
$
77
34
%
Cost of fuel and energy
181
124
57
46
Utility
margin
$
123
$
103
$
20
19
%
Sales
(GWhs):
Residential
732
663
69
10
%
Commercial
721
700
21
3
Industrial
646
755
(109)
(14)
Other
3
4
(1)
(25)
Total
fully bundled(1)
2,102
2,122
(20)
(1)
Distribution only service
668
585
83
14
Total
retail
2,770
2,707
63
2
Wholesale
229
291
(62)
(21)
Total
GWhs sold
2,999
2,998
1
—
%
Average
number of retail customers (in thousands)
372
369
3
1
%
Average
revenue per MWh:
Retail - fully bundled(1)
$
128.99
$
96.40
$
32.59
34
%
Wholesale
$
107.76
$
51.14
$
56.62
*
Heating
degree days
2,652
2,037
615
30
%
Sources
of energy (GWhs)(2):
Natural gas
1,066
990
76
8
%
Coal
201
153
48
31
Renewables
4
5
(1)
(20)
Total
energy generated
1,271
1,148
123
11
Energy purchased
823
1,033
(210)
(20)
Total
2,094
2,181
(87)
(4)
%
Average
cost of energy per MWh(3):
Energy generated
$
102.35
$
59.86
$
42.49
71
%
Energy
purchased
$
61.37
$
53.19
$
8.18
15
%
* Not meaningful
(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.
139
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
Electric utility margin increased$20 million, or 19%, for the first quarter of 2023 compared to 2022 primarily due to:
•$14 million of higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023 and higher customer volumes. Retail customer volumes, including distribution only service customers, increased by 2.3% primarily due to the favorable impact of
weather and an increase in the average number of customers; and
•$6 million of higher transmission and wholesale revenue.
Natural gas utility margin increased $3 million, or 17%, for the first quarter of 2023 compared to 2022 primarily due to higher customer volumes from the favorable impact of weather.
Operations and maintenance increased $15 million, or 37%, for the first quarter of 2023 compared to 2022 primarily due to higher plant operations and maintenance expenses, higher regulatory-approved cost recovery for the ON Line reallocation (offset in operating revenue) and higher customer service operations expenses.
Depreciation and amortization increased
$10 million, or 28%, for the first quarter of 2023 compared to 2022 primarily due to higher plant placed in-service and higher regulatory amortizations.
Interest expense increased $3 million, or 23%, for the first quarter of 2023 compared to 2022 primarily due to higher interest rates and debt.
Interest and dividend income increased $4 million, for the first quarter of 2023 compared to 2022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
140
Liquidity
and Capital Resources
As of March 31, 2023, Sierra Pacific's total net liquidity was as follows (in millions):
Cash and cash equivalents
$
8
Credit facility
250
Less:
Short-term
debt
(50)
Net credit facility
200
Total net liquidity
$
208
Credit facility:
Maturity date
2025
Operating
Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $87 million and $63 million, respectively. The change was primarily due to higher collections from customers, partially offset by higher payments related to fuel and energy costs.
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.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31,
2023 and 2022, were $(104) million and $(83) 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 three-month periods ended March 31, 2023 and 2022, were $(22) million and $26 million, respectively. The change was primarily due to lower contributions from NV Energy, Inc. and higher repayments of an affiliate note payable, partially offset by higher proceeds from 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 $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.
Future Uses of Cash
Sierra Pacific has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access
to external financing depends on a variety of factors, including regulatory approvals, Sierra Pacific's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
141
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):
Three-Month
Periods
Annual
Ended March 31,
Forecast
2022
2023
2023
Electric
distribution
$
20
$
32
$
164
Electric transmission
20
19
73
Solar generation
—
—
3
Electric
battery storage
—
—
8
Other
43
53
165
Total
$
83
$
104
$
413
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, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma 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.
Material Cash Requirements
As of March 31, 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.
142
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.
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.
143
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
144
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 March 31, 2023, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for the three-month periods ended March 31, 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:
Losses on other items, net
i1
i1
Depreciation
and amortization
i80
i85
Allowance
for equity funds
(i2)
(i2)
Equity
(income) loss, net of distributions
(i6)
(i8)
Changes
in regulatory assets and liabilities
(i92)
(i14)
Deferred
income taxes
i20
i27
Other,
net
i2
i2
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i40
i40
Gas
balancing activities
i19
i4
Derivative
collateral, net
i1
i2
Accrued
property, income and other taxes
i9
(i29)
Accounts
payable and other liabilities
i7
i28
Net
cash flows from operating activities
i319
i341
Cash
flows from investing activities:
Capital expenditures
(i59)
(i75)
Repayment
of notes by affiliates
i40
i3
Notes
to affiliates
(i134)
(i117)
Other,
net
(i3)
(i5)
Net
cash flows from investing activities
(i156)
(i194)
Cash
flows from financing activities:
Distributions
to noncontrolling interests
(i124)
(i114)
Net
cash flows from financing activities
(i124)
(i114)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i39
i33
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
$
i134
$
i72
The
accompanying notes are an integral part of these consolidated financial statements.
151
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. Eastern Energy Gas owns i100% of the general partner interest and i25%
of the limited partnership interest in Cove Point. In addition, Eastern Energy Gas owns a i50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a i416-mile
FERC-regulated interstate natural gas 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 March 31, 2023 and for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 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 three-month period ended March 31,
2023.
152
(2) iProperty, Plant and Equipment, Net
iProperty,
plant and equipment, net consists of the following (in millions):
As of
March 31,
December 31,
Depreciable Life
2023
2022
Utility
plant:
Interstate natural gas transmission and storage assets
i21 - i52
years
$
i9,053
$
i8,922
Intangible
plant
i5 - i18 years
i116
i113
Utility
plant in-service
i9,169
i9,035
Accumulated
depreciation and amortization
(i3,075)
(i3,039)
Utility
plant in-service, net
i6,094
i5,996
Nonutility
plant:
LNG facility
i40 years
i4,526
i4,522
Intangible
plant
i14 years
i25
i25
Nonutility
plant
i4,551
i4,547
Accumulated
depreciation and amortization
(i574)
(i542)
Nonutility
plant, net
i3,977
i4,005
i10,071
i10,001
Construction
work-in-progress
i210
i201
Property,
plant and equipment, net
$
i10,281
$
i10,202
/
Construction
work-in-progress includes $i192 million and $i181
million as of March 31, 2023 and December 31, 2022, respectively, related to the construction of utility plant.
(3) iRegulatory Matters
In September 2021, Eastern Gas
Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS 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.
153
(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
$
i316
$
i308
Reflected
as:
Current assets
$
i31
$
i30
Noncurrent
assets
i285
i278
Total
investments and restricted cash and cash equivalents
$
i316
$
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 March 31, 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 $i26 million and $i11
million for the three-month periods ended March 31, 2023 and 2022, respectively.
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
$
i134
$
i95
154
(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
i2
i5
Equity
interest
i3
i2
Effects
of ratemaking
i—
(i4)
Noncontrolling
interest
(i10)
(i11)
Other,
net
i—
i1
Effective
income tax rate
i16
%
i14
%
/
For
the period ended March 31, 2023, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by an absence of tax on income attributable to Cove Point's i75% noncontrolling interest.
(6) iEmployee
Benefit Plans
Eastern Energy Gas is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of Eastern Energy Gas. Eastern Energy Gas contributed $i2 million
and $i3 million to the MidAmerican Energy Company Retirement Plan for the three-month periods ended March 31, 2023 and 2022, respectively, and $ii1/ million
to the MidAmerican Energy Company Welfare Benefit Plan for the three-month periods ended March 31, 2023 and 2022. 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 March 31, 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.
(7) iFair Value Measurements
The carrying value of Eastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Eastern Energy Gas has various financial assets and liabilities
that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Eastern Energy Gas has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived
principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Eastern Energy Gas' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Eastern Energy Gas develops these inputs based on the best information available, including its own data.
155
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.
156
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. Plaintiffs occasionally seek punitive or exemplary damages. Eastern Energy Gas does not believe that
such normal and routine litigation will have a material impact on its consolidated financial results.
(9) iRevenue from Contracts with Customers
i
The
following table summarizes Eastern Energy Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):
(1)Other
revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" and includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts.
/
Eastern Energy Gas has recognized contract liabilities of $i70
million and $i80 million as of March 31, 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 three-month period ended March 31, 2023, Eastern Energy Gas recognized revenue of $i22
million from the beginning contract liability balance.
157
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 March 31, 2023 (in millions):
Performance obligations expected to be satisfied
Less than 12 months
More than 12 months
Total
Eastern
Energy Gas
$
i1,657
$
i15,340
$
i16,997
/
(10) iComponents
of Accumulated Other Comprehensive Loss, Net
i
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income tax (in millions):
Item
2.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.
Results
of Operations for the First Quarter of 2023 and 2022
Overview
Net income attributable to Eastern Energy Gas for the first quarter of 2023 was $122 million, an increase of $28 million compared to 2022. Net income increased primarily due to higher margin from EGTS' regulated gas transmission and storage operations of $32 million and higher earnings from Iroquois due to favorable fixed negotiated rate agreements and hedges, partially offset by higher operations and maintenance expenses.
Operating
revenue increased $71 million, or 15%, for the first quarter 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 $42 million, increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022 of $19 million, an increase in variable revenue related to park and loan activity of $10 million and derivative losses in 2022 of $7 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 $6 million.
Cost of (excess) gas was an expense of $20 million for the first quarter of 2023 compared to a credit of $1 million for the first
quarter of 2022. The change is primarily from the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker, due to lower natural gas prices.
Operations and maintenance increased $25 million, or 21%, for the first quarter of 2023 compared to 2022, primarily due to higher corporate charges of $10 million, an increase in salaries, wages and benefits of $6 million and an increase in Cove Point outside services of $4 million.
Depreciation and amortization decreased $5 million, or 6%, for the first quarter of 2023 compared to 2022, primarily due to the settlement of depreciation rates in EGTS' general rate case of $8 million, partially offset by higher plant placed in-service of $3 million.
Property
and other taxes increased $8 million, or 28%, for the first quarter of 2023 compared to 2022, primarily due to lower 2021 tax assessments that were finalized in 2022.
Interest and dividend income increased $9 million for the first quarter of 2023 compared to 2022, primarily due to higher outstanding borrowings and higher interest rates from BHE GT&S' intercompany revolving credit agreement with Eastern Energy Gas.
Income tax expense increased $9 million, or 30%, for the first quarter of 2023 compared to 2022, primarily due to higher pre-tax income. The effective tax rate was 16% for 2023 and 14% for 2022.
Equity income increased
$13 million, or 68%, for the first quarter of 2023 compared to 2022, primarily due to higher earnings from Iroquois due to favorable fixed negotiated rate agreements and hedges.
Net income attributable to noncontrolling interests increased $7 million, or 6%, for the first quarter of 2023 compared to 2022, primarily due to increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022, partially offset by an increase in Cove Point outside services.
159
Liquidity
and Capital Resources
As of March 31, 2023, Eastern Energy Gas' total net liquidity was as follows (in millions):
Cash and cash equivalents
$
103
Intercompany revolving credit agreement
400
Total
net liquidity
$
503
Intercompany revolving credit agreement:
Maturity date
2024
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022 were $319 million and $341
million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers, partially offset by the impacts from the rate increase in effect April 1, 2022 for the EGTS general rate case and 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 three-month periods ended March 31, 2023 and 2022
were $(156) million and $(194) million, respectively. The change is primarily due to an increase in repayments of loans by affiliates of $37 million and a decrease in capital expenditures of $16 million, partially offset by an increase in loans to its parent under an intercompany revolving credit agreement of $17 million.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2023 were $(124) million and consisted of distributions to noncontrolling interests from Cove Point.
Net cash flows from financing activities for the three-month period ended March 31, 2022 were $(114)
million and consisted 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.
160
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):
Three-Month Periods
Annual
Ended March 31,
Forecast
2022
2023
2023
Natural
gas transmission and storage
$
7
$
4
$
36
Other
68
55
390
Total
$
75
$
59
$
426
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 March 31, 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.
161
Eastern Gas Transmission and Storage, Inc. 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 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 March 31, 2023, the related consolidated statements of operations, comprehensive income, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 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 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:
Depreciation and amortization
i37
i43
Allowance
for equity funds
(i1)
(i1)
Changes
in regulatory assets and liabilities
(i85)
(i6)
Deferred
income taxes
i8
i13
Other,
net
i1
i3
Changes
in other operating assets and liabilities:
Trade receivables and other assets
i42
i37
Receivables
from affiliates
i—
(i9)
Gas
balancing activities
i17
(i1)
Accrued
property, income and other taxes
(i15)
(i18)
Accounts
payable and other liabilities
i21
i20
Accounts
payable to affiliates
i—
(i8)
Net
cash flows from operating activities
i93
i128
Cash
flows from investing activities:
Capital expenditures
(i37)
(i53)
Other,
net
(i3)
(i3)
Net
cash flows from investing activities
(i40)
(i56)
Cash
flows from financing activities:
Repayment of notes payable to affiliates, net
(i23)
(i68)
Net
cash flows from financing activities
(i23)
(i68)
Net
change in cash and cash equivalents and restricted cash and cash equivalents
i30
i4
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
$
i75
$
i30
The
accompanying notes are an integral part of these consolidated financial statements.
169
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 March 31, 2023 and for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31,
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 three-month period ended March 31, 2023.
(2) iProperty,
Plant and Equipment, Net
i
Property, plant and equipment, net consists of the following (in millions):
As
of
March 31,
December 31,
Depreciable Life
2023
2022
Interstate natural gas transmission and storage assets
i28
- i50 years
$
i6,842
$
i6,724
Intangible
plant
i12 - i20 years
i80
i79
Plant
in-service
i6,922
i6,803
Accumulated
depreciation and amortization
(i2,465)
(i2,440)
i4,457
i4,363
Construction
work-in-progress
i147
i141
Property,
plant and equipment, net
$
i4,604
$
i4,504
/
170
(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
$
i46
$
i43
Reflected
as:
Current assets
$
i29
$
i29
Noncurrent
assets
i17
i14
Total
investments and restricted cash and cash equivalents
$
i46
$
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
$
i75
$
i45
171
(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
i4
i5
Effective
income tax rate
i25
%
i26
%
/
(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 $i2
million and $i3 million to the MidAmerican Energy Company Retirement Plan for the three-month periods ended March 31, 2023 and 2022, respectively, and $ii1/ million
to the MidAmerican Energy Company Welfare Benefit Plan for the three-month period ended March 31, 2022. 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 March 31, 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.
172
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. Plaintiffs occasionally seek punitive or exemplary damages. EGTS does not believe that such normal and routine litigation will have a material
impact on its consolidated financial results.
(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 March 31, 2023 (in millions):
Performance obligations expected to be satisfied
Less
than 12 months
More than 12 months
Total
EGTS
$
i746
$
i3,390
$
i4,136
/
174
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 First Quarter of 2023 and 2022
Overview
Net income for the first quarter of 2023 was $68 million, an increase of $13 million, or 24%, compared to 2022. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $32 million and a decrease due to lower depreciation rates due to the settlement in EGTS' general rate case, partially offset by higher operations and maintenance expenses, lower 2021 tax assessments finalized in 2022 and an increase in income tax expense primarily due to higher pre-tax income.
Operating revenue increased $55 million, or 25%, for the first quarter 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 $42 million, an increase in variable revenue related to park and loan activity of $10 million and derivative losses in 2022 of $7 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 $6 million.
Cost of (excess) gas was an expense of $20 million for the first quarter of 2023 compared to a credit of $3 million for the first quarter of 2022. The change is primarily from
the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker, due to lower natural gas prices.
Operations and maintenance increased $15 million, or 18%, for the first quarter of 2023 compared to 2022, primarily due to higher corporate charges of $6 million and an increase in salaries, wages and benefits of $5 million.
Depreciation and amortization decreased $6 million, or 14%, for the first quarter of 2023 compared to 2022, primarily due to the settlement of deprecation rates in EGTS' general rate case of $8 million, partially offset by higher plant placed in-service of $2 million.
Property and other taxes increased
$5 million, or 56%, for the first quarter of 2023 compared to 2022, primarily due to lower 2021 tax assessments that were finalized in 2022.
Income tax expense increased $4 million, or 21%, for the first quarter of 2023 compared to 2022, primarily due to higher pre-tax income. The effective tax rate was 25% for 2023 and 26% for 2022.
175
Liquidity and Capital Resources
As of March 31,
2023, EGTS' total net liquidity was as follows (in millions):
Cash and cash equivalents
$
46
Intercompany revolving credit agreement
400
Less:
Notes
payable to affiliates
13
Net intercompany revolving credit agreement
387
Total net liquidity
$
433
Intercompany credit agreement:
Maturity
date
2024
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022 were $93 million and $128 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers, partially offset by the impacts from the rate increase in effect April 1, 2022 for the EGTS general rate case 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.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022 were $(40) million and $(56) million, respectively. The change is primarily due to a decrease in capital expenditures of $16 million.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2023 were $(23) million and consisted of net
repayment of notes payable to Eastern Energy Gas.
Net cash flows from financing activities for the three-month period ended March 31, 2022 were $(68) million and consisted of net repayment of notes payable to Eastern Energy Gas.
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.
176
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):
Three-Month Periods
Annual
Ended
March 31,
Forecast
2022
2023
2023
Natural gas transmission and storage
$
6
$
3
$
27
Other
47
34
225
Total
$
53
$
37
$
252
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 March 31, 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.
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.
177
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 6 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 March 31, 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 March 31, 2023 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
178
PART II
Item 1.Legal Proceedings
Berkshire Hathaway Energy and PacifiCorp
Multiple
lawsuits, complaints and demands alleging similar claims totaling approximately $8.0 billion have been filed in Oregon and California related to the 2020 Wildfires. Multiple complaints have also been filed in California for the 2022 McKinney fire. Generally, the complaints filed in California do not specify damages sought. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 9 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.
On September 30, 2020, a putative class action complaint against PacifiCorp was filed,
captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885, Circuit Court, Multnomah County, Oregon. The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain Complex, South Obenchain, Two Four Two and Santiam Canyon fires, as well as to add claims for noneconomic damages. The amended complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp
acted with gross negligence, among other things. The amended complaint seeks the following damages for the plaintiffs and the putative class: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal property and other economic losses of not less than $600 million; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (v) double the damages for the costs of litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The plaintiffs demand a trial by jury and have reserved their right to further amend the complaint to allege claims for punitive damages. In May 2022, the Multnomah Circuit Court granted issue class certification and consolidated this case with others
as described below. PacifiCorp requested an immediate appeal of the issue class certification before the Oregon Court of Appeals. In January 2023, the Oregon Court of Appeals denied PacifiCorp's request for appeal. 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 Circuit Court. Plaintiffs seek 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.
On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter
et al. v. PacifiCorp, Case No. 21CV33595, Multnomah County, Oregon, in which two complaints, Case No. 21CV09339 and Case No. 21CV09520, previously filed in Circuit Court, Marion County, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following
damages: (i) damages related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint with an intent to add a claim for punitive damages. In May 2022, this case was consolidated with others as described below.
179
On
March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22CV09346, Circuit Court, Douglas County, Oregon. The complaint was filed by nine businesses and public pension plans that own and/or operate timberlands or possess property in Douglas County who allege damages, losses and injuries associated with their timberlands as a result of the French Creek, Archie Creek, Susan Creek and Smith Springs Road fires in Douglas County in September 2020. The complaint alleges (i) PacifiCorp's conduct constituted not only common law negligence but also gross negligence and that such conduct contributed to or caused the ignition and spread of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence, inverse condemnation. The complaint seeks the following
damages as amended: (i) economic and property damages in excess of $195 million under a determination of negligence or inverse condemnation; (ii) doubling of those economic damages to in excess of $390 million under a determination of gross negligence pursuant to Oregon statutes; (iii) all costs of the lawsuit; (iv) prejudgment interest of $43 million and post-judgment interest as allowed by law; and (v) attorneys' fees of $105 million and other costs.
In May 2022, the Multnomah County Circuit Court granted plaintiffs' motion to consolidate Shylo Salter et al. v. PacifiCorp, Case No. 21CV33595 (described above) and Amy Allen, et al. v. PacifiCorp, Case No. 20CV37430 ("Allen") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885
(described above). Plaintiffs' motion to bifurcate issues for trial between class-wide liability and individual damages was also granted. The Allen case was filed by five individuals as amended in September 2021 claiming in excess of $32 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest.
On August 26, 2022, a putative class action complaint seeking declaratory and equitable relief against PacifiCorp was filed, captioned Margaret Dietrich et al. v. PacifiCorp, Case No. 22CV29187, Circuit Court, Multnomah County, Oregon. The complaint was filed by two Oregon residents individually and on behalf of a class initially defined to include residents of, business owners
in, real or personal property owners in and any other individuals physically present in specified Oregon counties as of September 7, 2020 who experienced any harm, damage or loss as a result of the Santiam, Beachie Creek, Lionshead, Echo Mountain Complex, Two Four Two or South Obenchain fires in September 2020. The complaint was amended on September 6, 2022, to seek damages of over $900 million that were originally demanded on August 4, 2022, pursuant to Oregon Rule of Civil Procedure 32 H. The amended complaint alleges: (i) negligence due to alleged failure to comply with certain Oregon statutes and administrative rules; (ii) gross negligence due to alleged conscious indifference to or reckless disregard for the probable consequences of defendant's actions or inactions; (iii) private nuisance; (iv) public nuisance; (v)
trespass; (vi) inverse condemnation; (vii) accounting/injunction; (viii) negligent infliction of emotional distress. The amended complaint seeks the following: (i) an order certifying the matter as a class action; (ii) economic damages not less than $400 million; (iii) double the amount of economic and property damages to the extent applicable under Oregon statute; (iv) reasonable costs of reforestation activities; (v) doubling and trebling of certain other damages to the extent applicable under certain Oregon statutes; (vi) noneconomic damages not less than $500 million; (vii) prejudgment interest; (viii) an order requiring an accounting with respect to the amount of damages; (ix) an order enjoining PacifiCorp from leaving power lines energized in areas of Oregon experiencing extremely critical fire conditions; (x) an award of reasonable attorney fees, costs, investigation costs, disbursements and expert witness fees; and (xi) other relief the court finds appropriate.
The plaintiffs and proposed class demand a trial by jury. On December 19, 2022, the Dietrich case was consolidated into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above) and is currently stayed.
On September 1, 2022, a complaint against PacifiCorp was filed, captioned Martin Klinger et al. v. PacifiCorp, Case No. 22CV29674, Multnomah County, Oregon ("Klinger"). The complaint was filed by Oregon residents or Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September
1, 2022, a complaint against PacifiCorp was filed, captioned Jeremiah E. Bowen et al. v. PacifiCorp, Case No. 22CV29681, Multnomah County, Oregon ("Bowen"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 1, 2022, a complaint against PacifiCorp was filed, captioned James Weathers et al. v. PacifiCorp, Case No. 22CV29683, Multnomah County, Oregon ("Weathers"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020
Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 6, 2022, a complaint against PacifiCorp was filed, captioned Blair Barnholdt et al. v. PacifiCorp, Case No. 22CV30097, Multnomah County, Oregon ("Barnholdt"). The complaint was filed by Oregon residents or Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
180
On September 7, 2022, a complaint
against PacifiCorp was filed, captioned Estate of Nancy Darlene Hunter, et al. v. PacifiCorp, Case No. 22CV30214, Multnomah County, Oregon ("Hunter"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 7, 2022, a complaint against PacifiCorp was filed, captioned Willard K. Pratt et al. v. PacifiCorp, Case No. 22CV30217, Multnomah County, Oregon ("Pratt"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain
Complex fires. The allegations made and damages sought are described below.
On September 7, 2022, a complaint against PacifiCorp was filed, captioned April Thompson et al. v. PacifiCorp, Case No. 22CV30451, Multnomah County, Oregon ("Thompson"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
The Klinger, Bowen, Weathers, Barnholdt, Hunter, Pratt and Thompson cases are in the process of being 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.
On September 1, 2022, a complaint against PacifiCorp was filed, captioned Aaron Macy-Wyngarden et al. v. PacifiCorp, Case No. 22CV29684, Multnomah County, Oregon ("Macy-Wyngarden").
The complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.
On September 22, 2022, a complaint against PacifiCorp was filed, captioned Zachary Bogle et al. v. PacifiCorp, Case No. 22CV29717, Multnomah County, Oregon ("Bogle"). The complaint was filed by Oregon residents who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.
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.
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On September 2, 2022, a complaint against PacifiCorp was filed, captioned Logan et al. v. PacifiCorp, Case No. 22CV29859, Multnomah County, Oregon ("Logan"). The Logan complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The Logan case is in the process of being consolidated with Cady et al. v. PacifiCorp, Case No. 22CV13946 ("Cady")
into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The Logan and Cady complaints each allege: (i) negligence; (ii) trespass; (iii) nuisance, and (iv) inverse condemnation. 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 Cady case was filed by 21 individuals as amended in April 2022 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-judgment interest.
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 into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The 21st Century and Allstate complaints were each filed 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.
On October
17, 2022, the Multnomah County Circuit Court consolidated Michael Bell, et al. v. PacifiCorp, Case No. 22CV30450 ("Bell") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The Bell case was filed in Oregon Circuit Court in Multnomah County, 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 Jeanyne James et al. v. PacifiCorp
et al., Case No. 20CV33885 (described above). The Freres case was filed in Oregon Circuit Court in Multnomah County, 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 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 Circuit Courts, Douglas County and Multnomah County, Oregon with substantially similar allegations as those of the Roseburg Resources Co case with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral ruling, the Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues, along with the above mentioned Roseburg Resources Co case; 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 Resources Co case. On February 14, 2023, the Circuit Court
ordered that all plaintiffs' claims for inverse condemnation be dismissed; a written order is forthcoming.
On December 6, 2022, CW Specialty Lumber, Inc., et al. v. PacifiCorp, Case No. 22CV41640 ("CW Specialty") was filed in Oregon Circuit Court in Multnomah County, Oregon by two plaintiffs seeking $28.6 million in damages for claims of (i) negligence, (ii) gross negligence, (iii) trespass, and (iv) inverse condemnation. The CW Specialty case is in the process of being consolidated into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above).
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.
182
Item
3.Defaults Upon Senior Securities
Not applicable.
Item 4.Mine Safety Disclosures
Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.
Item
5.Other Information
Not applicable.
Item 6.Exhibits
The following is a list of exhibits filed as part of this Quarterly Report.
The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2023, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated
Financial Statements, tagged in summary and detail.
104
Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
