20230815PAC to Staff 12 Attachment.pdf

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2023
or
☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to _______
Exact name of registrant as specified in its charter
State or other jurisdiction of incorporation or organization
Commission Address of principal executive offices IRS Employer
File Number Registrant's telephone number, including area code Identification No.
001-14881 BERKSHIRE HATHAWAY ENERGY COMPANY 94-2213782
(An Iowa Corporation)
666 Grand Avenue
Des Moines, Iowa 50309-2580
515-242-4300
001-05152 PACIFICORP 93-0246090
(An Oregon Corporation)
825 N.E. Multnomah Street, Suite 1900
Portland, Oregon 97232
888-221-7070
333-90553 MIDAMERICAN FUNDING, LLC 47-0819200
(An Iowa Limited Liability Company)
666 Grand Avenue
Des Moines, Iowa 50309-2580
515-242-4300
333-15387 MIDAMERICAN ENERGY COMPANY 42-1425214
(An Iowa Corporation)
666 Grand Avenue
Des Moines, Iowa 50309-2580
515-242-4300
000-52378 NEVADA POWER COMPANY 88-0420104
(A Nevada Corporation)
6226 West Sahara Avenue
Las Vegas, Nevada 89146
702-402-5000
000-00508 SIERRA PACIFIC POWER COMPANY 88-0044418
(A Nevada Corporation)
6100 Neil Road
Reno, Nevada 89511
775-834-4011
001-37591 EASTERN ENERGY GAS HOLDINGS, LLC 46-3639580
(A Virginia Limited Liability Company)
6603 West Broad Street
Richmond, Virginia 23230
804-613-5100
333-266049 EASTERN GAS TRANSMISSION AND STORAGE, INC.55-0629203
(A Delaware Corporation)
6603 West Broad Street
Richmond, Virginia 23230
804-613-5100
N/A
(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 Yes No
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). Yes 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
Non-accelerated filer
Smaller reporting company
Emerging growth company
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.☐☐☒☐☐
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 ☐ No x
All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of
investors. As of August 3, 2023, 75,627,913 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
August 3, 2023, 357,060,915 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 August 3, 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 August 3, 2023, 70,980,203 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 August 3, 2023, 1,000 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 August 3, 2023, 1,000 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 August 3, 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 August 3, 2023, 60,101 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.
TABLE OF CONTENTS

PART I

Item 1.Financial Statements 1
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations 2
Item 3.Quantitative and Qualitative Disclosures About Market Risk 194
Item 4.Controls and Procedures 194

PART II

Item 1.Legal Proceedings 195
Item 1A.Risk Factors 199
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds 199
Item 3.Defaults Upon Senior Securities 199
Item 4.Mine Safety Disclosures 199
Item 5.Other Information 200
Item 6.Exhibits 200
Signatures 204
i
Definition of Abbreviations and Industry Terms
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
CCR Coal Combustion Residuals
CPUC California Public Utilities Commission
CSAPR Cross-State Air Pollution Rule
D.C. Circuit United States Court of Appeals for the District of Columbia Circuit
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; the damage caused by such wildfires; the extent of the respective Registrant's liability in
connection with such wildfires (including the risk that the respective Registrant may be found liable for damages
regardless of fault); investigations into such wildfires; the outcomes of any legal proceedings initiated against the
respective Registrant; the risk that the respective Registrant is not able to recover costs from insurance or through
rates; and the effect of such wildfires, investigations and legal proceedings on the respective Registrant's financial
condition and reputation;
•the outcomes of legal actions associated with the 2020 Wildfires, which could have a material adverse effect on
PacifiCorp's financial condition and could limit PacifiCorp's ability to access capital on terms commensurate with
historical transactions and could impact PacifiCorp's liquidity, cash flows and capital expenditure plans;
•the respective Registrant's ability to reduce wildfire threats and improve safety, including the ability to comply with
the targets and metrics set forth in its wildfire mitigation plans; to retain or contract for the workforce necessary to
execute its wildfire mitigation plans; the effectiveness of its system hardening; ability to achieve vegetation
management targets; and the cost of these programs and the timing and outcome of any proceeding to recover such
costs through rates;
•the ability to economically obtain insurance coverage, or any insurance coverage at all, sufficient to cover losses
arising from catastrophic events, such as wildfires;
•a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging
strategy and the cost of balancing its generation resources with its retail load obligations;
•changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel
transportation that could have a significant impact on generating capacity and energy costs;
iv
•the financial condition, creditworthiness and operational stability of the respective Registrant's significant customers
and suppliers;
•changes in business strategy or development plans;
•availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper,
debt securities and other sources of debt financing and volatility in interest rates and credit spreads;
•changes in the respective Registrant's credit ratings;
•risks relating to nuclear generation, including unique operational, closure and decommissioning risks;
•hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;
•the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased
collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value
of certain contracts;
•the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;
•fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;
•increases in employee healthcare costs;
•the impact of investment performance, certain participant elections such as lump sum distributions and changes in
interest rates, legislation, healthcare cost trends, mortality, morbidity on pension and other postretirement benefits
expense and funding requirements;
•changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect
brokerage, mortgage and franchising transactions;
•the ability to successfully integrate future acquired operations into a Registrant's business;
•the impact of supply chain disruptions and workforce availability on the respective Registrant's ongoing operations and
its ability to timely complete construction projects;
•unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund
capital projects and other factors that could affect future facilities and infrastructure additions;
•the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
•the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial
results of the respective Registrants; and
•other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the
SEC or in other publicly disseminated written documents.
Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the
SEC, including Part II, Item 1A and other discussions contained in this Form 10-Q. Each Registrant undertakes no obligation to
publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
The foregoing factors should not be construed as exclusive.
v
Item 1.Financial Statements
Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm 4
Consolidated Balance Sheets 5
Consolidated Statements of Operations 7
Consolidated Statements of Comprehensive Income 8
Consolidated Statements of Changes in Equity 9
Consolidated Statements of Cash Flows 10
Notes to Consolidated Financial Statements 11
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm 57
Consolidated Balance Sheets 58
Consolidated Statements of Operations 60
Consolidated Statements of Changes in Shareholders' Equity 61
Consolidated Statements of Cash Flows 62
Notes to Consolidated Financial Statements 63
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm 84
Balance Sheets 85
Statements of Operations 87
Statements of Changes in Shareholder's Equity 88
Statements of Cash Flows 89
Notes to Financial Statements 90
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm 98
Consolidated Balance Sheets 99
Consolidated Statements of Operations 101
Consolidated Statements of Changes in Member's Equity 102
Consolidated Statements of Cash Flows 103
Notes to Consolidated Financial Statements 104
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm 118
Consolidated Balance Sheets 119
Consolidated Statements of Operations 120
Consolidated Statements of Changes in Shareholder's Equity 121
Consolidated Statements of Cash Flows 122
Notes to Consolidated Financial Statements 123
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm 138
Consolidated Balance Sheets 139
Consolidated Statements of Operations 140
Consolidated Statements of Changes in Shareholder's Equity 141
Consolidated Statements of Cash Flows 142
Notes to Consolidated Financial Statements 143
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm 159
Consolidated Balance Sheets 160
Consolidated Statements of Operations 162
Consolidated Statements of Comprehensive Income 163
Consolidated Statements of Changes in Equity 164
Consolidated Statements of Cash Flows 165
Notes to Consolidated Financial Statements 166
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm 178
Consolidated Balance Sheets 179
Consolidated Statements of Operations 181
Consolidated Statements of Comprehensive Income 182
Consolidated Statements of Changes in Shareholder's Equity 183
Consolidated Statements of Cash Flows 184
Notes to Consolidated Financial Statements 185
1
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
Berkshire Hathaway Energy Company and its subsidiaries 31
PacifiCorp and its subsidiaries 74
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company 108
Nevada Power Company and its subsidiaries 130
Sierra Pacific Power Company and its subsidiaries 151
Eastern Energy Gas Holdings, LLC and its subsidiaries 173
Eastern Gas Transmission and Storage, Inc. and its subsidiaries 190
2
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 June 30, 2023, the related consolidated statements of operations, comprehensive income, and changes in
equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods
ended June 30, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on
our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial
information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2022, and the related consolidated
statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented
herein); and in our report dated February 24, 2023, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2022,
is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of the Company's management. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists
principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.
It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which
is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an
opinion.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
August 4, 2023
4
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
ASSETS
Current assets:
Cash and cash equivalents $ 2,229 $ 1,591
Investments and restricted cash and cash equivalents 3,484 2,141
Trade receivables, net 2,488 2,876
Inventories 1,429 1,256
Mortgage loans held for sale 834 474
Regulatory assets 1,392 1,319
Other current assets 770 1,345
Total current assets 12,626 11,002

Property, plant and equipment, net 95,541 93,043
Goodwill 11,546 11,489
Regulatory assets 4,060 3,743
Investments and restricted cash and cash equivalents and investments 10,562 11,273
Other assets 3,416 3,290

Total assets $ 137,751 $ 133,840
The accompanying notes are an integral part of these consolidated financial statements.
5
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 2,502 $ 2,679
Accrued interest 563 558
Accrued property, income and other taxes 1,287 746
Accrued employee expenses 418 333
Short-term debt 2,243 1,119
Current portion of long-term debt 3,199 3,201
Other current liabilities 1,648 1,677
Total current liabilities 11,860 10,313

BHE senior debt 13,099 13,096
BHE junior subordinated debentures 100 100
Subsidiary debt 35,224 35,238
Regulatory liabilities 6,423 7,070
Deferred income taxes 12,726 12,678
Other long-term liabilities 5,359 4,706
Total liabilities 84,791 83,201

Commitments and contingencies (Note 11)

Equity:
BHE shareholders' equity:
Preferred stock - 100 shares authorized, $0.01 par value, 1 shares issued and outstanding 850 850
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding — —
Additional paid-in capital 6,298 6,298
Retained earnings 43,880 41,833
Accumulated other comprehensive loss, net (1,845) (2,149)
Total BHE shareholders' equity 49,183 46,832
Noncontrolling interests 3,777 3,807
Total equity 52,960 50,639

Total liabilities and equity $ 137,751 $ 133,840
The accompanying notes are an integral part of these consolidated financial statements.
6
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue:
Energy $ 4,933 $ 4,940 $ 10,404 $ 9,763
Real estate 1,296 1,672 2,171 2,879
Total operating revenue 6,229 6,612 12,575 12,642

Operating expenses:
Energy:
Cost of sales 1,566 1,525 3,521 2,985
Operations and maintenance 1,200 1,081 2,742 2,024
Depreciation and amortization 970 1,045 2,020 2,052
Property and other taxes 197 199 409 404
Real estate 1,250 1,555 2,170 2,734
Total operating expenses 5,183 5,405 10,862 10,199

Operating income 1,046 1,207 1,713 2,443

Other income (expense):
Interest expense (599) (550) (1,185) (1,082)
Capitalized interest 33 18 57 35
Allowance for equity funds 61 42 110 80
Interest and dividend income 127 30 213 53
Gains on marketable securities, net 303 2,528 1,002 1,271
Other, net 78 (26) 118 (21)
Total other income (expense) 3 2,042 315 336

Income (loss) before income tax expense (benefit) and equity income (loss) 1,049 3,249 2,028 2,779
Income tax expense (benefit) (255) 149 (417) (358)
Equity income (loss) (99) (83) (137) (140)
Net income 1,205 3,017 2,308 2,997
Net income attributable to noncontrolling interests 130 120 244 229
Net income attributable to BHE shareholders 1,075 2,897 2,064 2,768
Preferred dividends 9 13 17 29
Earnings on common shares $ 1,066 $ 2,884 $ 2,047 $ 2,739
The accompanying notes are an integral part of these consolidated financial statements.

7
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022

Net income $ 1,205 $ 3,017 $ 2,308 $ 2,997

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(4), $9, $(7) and $12 (7) 25 (11) 40
Foreign currency translation adjustment 232 (481) 331 (591)
Unrealized gains (losses) on cash flow hedges, net of tax of $13, $8, $(7) and $36 39 26 (16) 103
Total other comprehensive income (loss), net of tax 264 (430) 304 (448)

Comprehensive income 1,469 2,587 2,612 2,549
Comprehensive income attributable to noncontrolling interests 130 120 244 229
Comprehensive income attributable to BHE shareholders $ 1,339 $ 2,467 $ 2,368 $ 2,320
The accompanying notes are an integral part of these consolidated financial statements.
8
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
BHE Shareholders' Equity
Long-term Accumulated
Additional Income Other
Preferred Common Paid-in Tax Retained Comprehensive Noncontrolling Total
Stock Stock Capital Receivable Earnings Loss, Net Interests Equity
Balance, March 31, 2022 $ 1,650 $ — $ 6,374 $ (744) $ 40,608 $ (1,358) $ 3,894 $ 50,424
Net income — — — — 2,897 — 120 3,017
Other comprehensive loss — — — — — (430) — (430)
Preferred stock redemptions (800) — — — — — — (800)
Preferred stock dividend — — — — (13) — — (13)
Common stock purchases — — (77) — (793) — — (870)
Distributions — — — — — — (129) (129)
Contributions — — — — — — 2 2
Other equity transactions — — 1 — (11) — — (10)
Balance, June 30, 2022 $ 850 $ — $ 6,298 $ (744) $ 42,688 $ (1,788) $ 3,887 $ 51,191

Balance, December 31, 2021 $ 1,650 $ — $ 6,374 $ (744) $ 40,754 $ (1,340) $ 3,895 $ 50,589
Net income — — — — 2,768 — 229 2,997
Other comprehensive loss — — — — — (448) — (448)
Preferred stock redemptions (800) — — — — — — (800)
Preferred stock dividend — — — — (29) — — (29)
Common stock purchases — — (77) — (793) — — (870)
Distributions — — — — — — (245) (245)
Contributions — — — — — — 2 2
Other equity transactions — — 1 — (12) — 6 (5)
Balance, June 30, 2022 $ 850 $ — $ 6,298 $ (744) $ 42,688 $ (1,788) $ 3,887 $ 51,191
Balance, March 31, 2023 $ 850 $ — $ 6,298 $ — $ 42,814 $ (2,109) $ 3,798 $ 51,651
Net income — — — — 1,075 — 130 1,205
Other comprehensive income — — — — — 264 — 264
Preferred stock dividend — — — — (9) — — (9)
Distributions — — — — — — (144) (144)
Contributions — — — — — — 1 1
Other equity transactions — — — — — — (8) (8)
Balance, June 30, 2023 $ 850 $ — $ 6,298 $ — $ 43,880 $ (1,845) $ 3,777 $ 52,960

Balance, December 31, 2022 $ 850 $ — $ 6,298 $ — $ 41,833 $ (2,149) $ 3,807 $ 50,639
Net income — — — — 2,064 — 244 2,308
Other comprehensive income — — — — — 304 — 304
Preferred stock dividend — — — — (17) — — (17)
Distributions — — — — — — (269) (269)
Contributions — — — — — — 3 3
Other equity transactions — — — — — — (8) (8)
Balance, June 30, 2023 $ 850 $ — $ 6,298 $ — $ 43,880 $ (1,845) $ 3,777 $ 52,960
The accompanying notes are an integral part of these consolidated financial statements.
9
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods
Ended June 30,
2023 2022
Cash flows from operating activities:
Net income $ 2,308 $ 2,997
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net (1,002) (1,271)
Depreciation and amortization 2,045 2,081
Allowance for equity funds (110) (80)
Equity (income) loss, net of distributions 188 202
Net power cost deferrals (446) (288)
Amortization of net power cost deferrals 279 119
Other changes in regulatory assets and liabilities (66) (57)
Deferred income taxes and investment tax credits, net (117) 385
Other, net (93) 37
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets (60) (156)
Derivative collateral, net (224) 189
Pension and other postretirement benefit plans (10) (21)
Accrued property, income and other taxes, net 530 489
Accounts payable and other liabilities 52 457
Wildfires insurance receivable (133) (161)
Wildfires liability 524 225
Net cash flows from operating activities 3,665 5,147
Cash flows from investing activities:
Capital expenditures (4,025) (3,382)
Purchases of marketable securities (155) (281)
Proceeds from sales of marketable securities 1,798 257
Purchases of U.S. Treasury Bills (3,294) —
Proceeds from sales of U.S. Treasury Bills 231 —
Proceeds from maturities of U.S. Treasury Bills 1,775 —
Equity method investments (20) (28)
Other, net 16 (18)
Net cash flows from investing activities (3,674) (3,452)
Cash flows from financing activities:
Preferred stock redemptions — (800)
Preferred dividends (17) (33)
Common stock purchases — (870)
Proceeds from BHE senior debt — 987
Repayments of BHE senior debt (400) —
Proceeds from subsidiary debt 1,188 1,201
Repayments of subsidiary debt (959) (542)
Net proceeds from (repayments of) short-term debt 1,118 (54)
Distributions to noncontrolling interests (269) (246)
Other, net (36) (248)
Net cash flows from financing activities 625 (605)
Effect of exchange rate changes 7 (33)
Net change in cash and cash equivalents and restricted cash and cash equivalents 623 1,057
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 1,817 1,244
Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 2,440 $ 2,301
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) General
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 eight 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 four utility companies in the U.S. serving customers in 11 states, two electricity distribution
companies in Great Britain, five interstate natural gas pipeline companies in the U.S., interests in a liquefied natural gas
("LNG") export, import and storage facility in the U.S., an electric transmission business in Canada, interests in electric
transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and
hydroelectric projects and one of the largest residential real estate brokerage firms and residential real estate brokerage
franchise networks in the U.S.
The 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 June 30, 2023, and for the three-
and six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended
June 30, 2023, are not necessarily indicative of the results to be expected for the full year.
The 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 six-month period ended June 30, 2023, other than the updates associated with the Company's estimates of loss contingencies
related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and the 2022 McKinney fire as discussed
in Note 11.
11
(2) New Accounting Pronouncements
In March 2023, the FASB issued ASU No. 2023-02, amending FASB ASC Topic 323-740, "Investments—Equity Method and
Joint Ventures—Income Taxes" which set forth the conditions needed to apply the proportional amortization method. The
amendments in this update permit reporting entities to elect to account for their tax equity investments, regardless of the tax
credit program from which the income tax credits are received, using the proportional amortization method if certain conditions
are met. This guidance is effective for interim and annual reporting periods beginning after December 15, 2023, with early
adoption permitted, and is required to be adopted either using a modified retrospective approach by means of a cumulative-
effect adjustment to retained earnings as of the beginning of the fiscal year of adoption or a retrospective approach by means of
a cumulative-effect adjustment to retained earnings as of the beginning of the earliest fiscal year presented. The Company is
currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included
within Notes to Consolidated Financial Statements.
(3) Business Acquisitions
On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of
BHE, entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc. ("DEI") and DECP
Holdings, Inc. (the "Seller"), an indirect wholly owned subsidiary of DEI, to purchase (the "Transaction") Seller's 50% limited
partner interests in Cove Point LNG, LP ("Cove Point") for a cash purchase price of $3.3 billion, plus the pro rata portion of
any quarterly distribution made by Cove Point for the fiscal quarter in which the Transaction closes. BHE expects to fund the
purchase price with cash on hand, including cash realized from the liquidation of certain investments. Upon the completion of
the Transaction, the Buyer will own an aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP
Holding Company, LLC, will continue to own 100% of the general partner interest, of Cove Point.
The consummation of the Transaction contemplated by the Purchase Agreement is subject to customary closing conditions,
including without limitation (i) the expiration or termination of any applicable waiting periods under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended, (ii) the filing of a notification with the U.S. Department of Energy and the
expiration of any applicable period; and (iii) the accuracy of the representations and warranties and compliance by the parties in
all material respects with their respective obligations under the Purchase Agreement. The Transaction is expected to close by
year-end 2023, subject to satisfaction of the foregoing conditions, among other things.
The Purchase Agreement provides that if the Seller or DEI terminates the Purchase agreement due to a breach of the Purchase
Agreement by the Buyer or Buyer's failure to consummate the Transaction within three business days after all of the conditions
to close have been satisfied or waived, BHE will pay to the Seller a termination fee of $150 million.
12
(4) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of
Depreciable June 30, December 31,
Life 2023 2022
Regulated assets:
Utility generation, transmission and distribution systems 5-80 years $ 94,351 $ 92,759
Interstate natural gas pipeline assets 3-80 years 18,605 18,328
112,956 111,087
Accumulated depreciation and amortization (36,088) (34,599)
Regulated assets, net 76,868 76,488

Nonregulated assets:
Independent power plants 2-50 years 8,476 8,545
Cove Point LNG facility 40 years 3,417 3,412
Other assets 2-30 years 2,787 2,693
14,680 14,650
Accumulated depreciation and amortization (3,617) (3,452)
Nonregulated assets, net 11,063 11,198

87,931 87,686
Construction work-in-progress 7,610 5,357
Property, plant and equipment, net $ 95,541 $ 93,043
Construction work-in-progress includes $7.1 billion as of June 30, 2023 and $4.9 billion as of December 31, 2022, related to the
construction of regulated assets.
13
(5) Investments and Restricted Cash and Cash Equivalents and Investments
Investments and restricted cash and cash equivalents and investments consists of the following (in millions):
As of
June 30,December 31,
2023 2022
Investments:
BYD Company Limited common stock $ 3,129 $ 3,763
U.S. Treasury Bills 3,281 1,931
Rabbi trusts 468 433
Other 330 335
Total investments 7,208 6,462

Equity method investments:
BHE Renewables tax equity investments 4,289 4,535
Electric Transmission Texas, LLC 657 623
Iroquois Gas Transmission System, L.P. 596 600
Other 359 304
Total equity method investments 5,901 6,062
Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds 726 664
Other restricted cash and cash equivalents 211 226
Total restricted cash and cash equivalents and investments 937 890

Total investments and restricted cash and cash equivalents and investments $ 14,046 $ 13,414
Reflected as:
Other current assets $ 3,484 $ 2,141
Noncurrent assets 10,562 11,273
Total investments and restricted cash and cash equivalents and investments $ 14,046 $ 13,414
Investments
Gains on marketable securities, net recognized during the period consists of the following (in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Unrealized gains recognized on marketable securities held at the reporting date $ 268 $ 2,527 $ 725 $ 1,270
Net gains recognized on marketable securities sold during the period 35 1 277 1
Gains on marketable securities, net $ 303 $ 2,528 $ 1,002 $ 1,271
14
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a
maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by
legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially
of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. A
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):
As of
June 30,December 31,
2023 2022
Cash and cash equivalents $ 2,229 $ 1,591
Investments and restricted cash and cash equivalents 158 173
Investments and restricted cash and cash equivalents and investments 53 53
Total cash and cash equivalents and restricted cash and cash equivalents $ 2,440 $ 1,817
(6) Recent Financing Transactions
Long-Term Debt
In May 2023, PacifiCorp issued $1.2 billion of its 5.50% First Mortgage Bonds due May 2054. PacifiCorp intends, within 24
months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or
existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing
Framework.
Credit Facilities
In June 2023, BHE amended its existing $3.5 billion unsecured credit facility expiring in June 2025. The amendment extended
the expiration date to June 2026.
In June 2023, PacifiCorp amended its existing $1.2 billion unsecured credit facility expiring in June 2025. The amendment
increased the lender commitment to $2.0 billion and extended the expiration date to June 2026. Additionally, in June 2023,
PacifiCorp terminated its existing $800 million 364-day unsecured credit facility expiring in January 2024.
In June 2023, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2025. The
amendment extended the expiration date to June 2026.
In June 2023, Nevada Power and Sierra Pacific each amended its existing $400 million and $250 million secured credit
facilities expiring in June 2025. The amendments increased the commitment of the lenders to $600 million and $400 million,
respectively, and extended the expiration date to June 2026.
In April 2023, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one
year revolving credit facility to April 2024, by exercising a one-year extension option.
15
(7) Income Taxes
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:
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022

Federal statutory income tax rate 21 % 21 % 21 % 21 %
Income tax credits (34) (13) (35) (28)
State income tax, net of federal income tax impacts — (1) (2) —
Income tax effect of foreign income (3) — 2 (1)
Effects of ratemaking (3) (1) (3) (2)
Equity income (2) (1) (1) (1)
Noncontrolling interest (3) (1) (3) (2)
Other, net — 1 — —
Effective income tax rate (24) % 5 % (21) % (13) %
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 10 years
from the date the qualifying generating facilities are placed in-service. PTCs recognized for the six-month periods ended
June 30, 2023 and 2022 totaled $700 million and $734 million, respectively.
Income tax effect on foreign income includes, among other items, a deferred income tax charge of $82 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 received net cash payments for federal income
taxes from Berkshire Hathaway for the six-month periods ended June 30, 2023 and 2022 totaling $864 million and
$1,249 million, respectively.
In July 2022, the Company amended its tax allocation agreement with Berkshire Hathaway, which changed how state tax
attributes will be settled with respect to state income tax returns that Berkshire Hathaway includes the Company. As a result,
the Company no longer expects to receive the cash benefits from the state of Iowa net operating loss carryforward previously
recorded as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity, and
recognized a noncash distribution of $744 million to retained earnings.
16
(8) Employee Benefit Plans
Domestic Operations
Net periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following
components (in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Pension:
Service cost $ 5 $ 6 $ 9 $ 13
Interest cost 27 19 55 38
Expected return on plan assets (31) (27) (62) (54)
Settlement — — (5) 2
Net amortization 3 5 7 9
Net periodic benefit cost $ 4 $ 3 $ 4 $ 8
Other postretirement:
Service cost $ 2 $ 4 $ 3 $ 6
Interest cost 7 5 14 10
Expected return on plan assets (10) (7) (18) (14)
Net amortization — (1) (1) (1)
Net periodic benefit (credit) cost $ (1) $ 1 $ (2) $ 1
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 $13 million and $7 million, respectively, during 2023. As of June 30, 2023, $7 million and $3 million of
contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
Foreign Operations
Net periodic benefit cost (credit) for the United Kingdom pension plan included the following components (in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022

Service cost $ 1 $ 3 $ 3 $ 7
Interest cost 14 9 28 19
Expected return on plan assets (21) (23) (40) (48)
Net amortization 7 6 13 12
Net periodic benefit cost (credit)$ 1 $ (5) $ 4 $ (10)
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 £11 million during
2023. As of June 30, 2023, £6 million, or $7 million, of contributions had been made to the United Kingdom pension plan.
17
(9) Asset 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 six-month period ended June 30, 2023, MidAmerican Energy recorded an increase of $88 million for
decommissioning its wind-generating facilities, which is a non-cash investing activity and is due to an updated
decommissioning estimate reflecting changes in the projected removal costs per turbine.
(10) Fair 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.
18
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):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Other(1)Total
As of June 30, 2023:
Assets:
Commodity derivatives $ 3 $ 195 $ 13 $ (58) $ 153
Interest rate derivatives 53 57 12 — 122
Mortgage loans held for sale — 834 — — 834
Money market mutual funds 1,539 — — — 1,539
Debt securities:
U.S. government obligations 3,902 — — — 3,902
International government obligations — 1 — — 1
Corporate obligations — 72 — — 72
Municipal obligations — 3 — — 3
Agency, asset and mortgage-backed obligations — 1 — — 1
Equity securities:
U.S. companies 405 — — — 405
International companies 3,138 — — — 3,138
Investment funds 287 — — — 287
$ 9,327 $ 1,163 $ 25 $ (58) $ 10,457
Liabilities:
Commodity derivatives $ (6) $ (98) $ (187) $ 62 $ (229)
Foreign currency exchange rate derivatives — (11) — — (11)
Interest rate derivatives — (1) (1) — (2)
$ (6) $ (110) $ (188) $ 62 $ (242)
19
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Other(1)Total
As of December 31, 2022:
Assets:
Commodity derivatives $ 6 $ 614 $ 51 $ (194) $ 477
Interest rate derivatives 50 54 8 — 112
Mortgage loans held for sale — 474 — — 474
Money market mutual funds 1,178 — — — 1,178
Debt securities:
U.S. government obligations 2,146 — — — 2,146
International government obligations — 1 — — 1
Corporate obligations — 70 — — 70
Municipal obligations — 3 — — 3
Agency, asset and mortgage-backed obligations — 1 — — 1
Equity securities:
U.S. companies 360 — — — 360
International companies 3,771 — — — 3,771
Investment funds 231 — — — 231
$ 7,742 $ 1,217 $ 59 $ (194) $ 8,824
Liabilities:
Commodity derivatives $ (8) $ (206) $ (110) $ 106 $ (218)
Foreign currency exchange rate derivatives — (21) — — (21)
Interest rate derivatives — (2) (2) 1 (3)
$ (8) $ (229) $ (112) $ 107 $ (242)
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $4 million as of June 30, 2023 and payable of
$87 million as of December 31, 2022.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated
fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP.
When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the
market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses
forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could
contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price
quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs.
Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and
actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term
of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market
quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length
of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively
traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major
trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of the
underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and
duration of contracts.
The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the
prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical
securitization activities, including servicing value, portfolio composition, market conditions and liquidity.
20
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.
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 Six-Month Periods
Ended June 30,Ended June 30,
Interest Interest
Commodity Rate Commodity Rate
Derivatives Derivatives Derivatives Derivatives
2023:
Beginning balance $ (150) $ 15 $ (59) $ 6
Changes included in earnings(1) 1 (4) 10 5
Changes in fair value recognized in OCI — — (3) —
Changes in fair value recognized in net regulatory assets (85) — (183) —
Settlements 60 — 61 —
Ending balance $ (174) $ 11 $ (174) $ 11
2022:
Beginning balance $ (239) $ 13 $ (151) $ 19
Changes included in earnings(1) (26) 8 (82) 2
Changes in fair value recognized in OCI 5 — 10 —
Changes in fair value recognized in net regulatory assets 1 — (59) —
Purchases 1 — 1 —
Settlements 11 — 34 —
Transfers out of Level 3 into Level 2 69 — 69 —
Ending balance $ (178) $ 21 $ (178) $ 21
(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. The following table presents the carrying value and estimated fair value of the Company's long-
term debt (in millions):
As of June 30, 2023 As of December 31, 2022
Carrying Fair Carrying Fair
Value Value Value Value

Long-term debt $ 51,622 $ 46,124 $ 51,635 $ 46,906
21
(11) Commitments and Contingencies
Commitments
The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheets.
Construction Commitments
During the six-month period ended June 30, 2023, PacifiCorp entered into build transfer agreements totaling $1.2 billion
through 2025 for the construction of certain wind-powered generating facilities in Wyoming.
During the six-month period ended June 30, 2023, MidAmerican Energy entered into firm construction commitments totaling
$183 million for the remainder of 2023 through 2024 related to the construction of wind-powered generating facilities in Iowa.
Fuel Contracts
During the six-month period ended June 30, 2023, PacifiCorp entered into certain coal supply agreements totaling $425 million
through 2025.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions
performance standards, water quality, coal ash disposal, hazardous and other environmental matters that have the potential to
impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws
and regulations.
Lower Klamath Hydroelectric Project
In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower
Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and
California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no
longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance
agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility began in June 2023, and
removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has
$450 million in funding available for dam removal and restoration; $200 million collected from PacifiCorp's Oregon and
California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share
cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to
equally fund an initial $45 million contingency fund and equally share any additional costs above that amount to ensure dam
removal and restoration is complete.
Legal Matters
The Company is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of
which assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may
seek to impose fines, penalties and other costs.
Wildfire Liability Overview
A provision for a loss contingency is recorded when it is probable 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.
22
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal
property damages from wildfires without the utility being found negligent and regardless of fault. California law also permits
inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has
equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring
it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not
apply, PacifiCorp could be found liable for all damages.
2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several
major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and
widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service
territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California;
Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County,
Oregon, burning over 500,000 acres in aggregate. Third-party reports for these wildfires indicate over 2,000 structures
destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.
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 on behalf of plaintiffs related to the 2020 Wildfires have been filed in Oregon
and California, including a class action complaint in Oregon for which the jury issued a verdict for the 17 named plaintiffs in
June 2023 as described below. The plaintiffs seek damages for economic losses, noneconomic losses, including mental
suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several
insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the
aforementioned lawsuits. Additionally, certain governmental agencies have informed PacifiCorp that they are contemplating
filing actions in connection with certain of the Oregon 2020 Wildfires. Amounts sought in the lawsuits, complaints and
demands filed in Oregon total over $7 billion, excluding any doubling or trebling of damages included in the complaints.
Generally, the complaints filed in California do not specify damages sought and are not included in this amount. Final
determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar
processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial
condition.
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et
al, in Multnomah County Circuit Court, Oregon (the "James case"). The complaint was filed by Oregon residents and
businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed
beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed
an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain
Complex, South Obenchain and Two Four Two wildfires. In May 2022, the Multnomah County Circuit Court granted issue
class certification and consolidated the James case with several other cases. While PacifiCorp requested an immediate appeal of
the issue class certification, the Oregon Court of Appeals denied the request. In April 2023, the jury trial for the James case
with respect to 17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding
PacifiCorp liable to the 17 individual plaintiffs and to the class with respect to the four wildfires. The jury awarded the 17
named plaintiffs $90 million of damages, including $4 million of economic and property damages, $68 million of noneconomic
damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages. No
judgment has been entered by the Multnomah County Circuit Court and no determination has been made as to the timing,
process and procedures that will be used to adjudicate individual class member damages. PacifiCorp intends to vigorously
appeal the jury's findings and damage awards, including whether the case can proceed as a class action. The appeals process and
further actions could take several years.
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of the verdict
in the James case with respect to the 17 named plaintiffs, other litigation and recent settlements, PacifiCorp has accrued
cumulative estimated probable losses associated with the 2020 Wildfires of $1,018 million through June 30, 2023. PacifiCorp's
cumulative accrual includes estimates of probable 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.
23
It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts accrued that could have a material
adverse effect on PacifiCorp's financial condition; however, PacifiCorp is currently unable to reasonably estimate the range of
possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the
class to the James case, the variation in those types of properties and lack of available details and the ultimate outcome of legal
actions.
The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires
(in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Beginning balance $ 824 $ 252 $ 424 $ 252
Accrued losses 141 225 541 225
Payments (17) — (17) —
Ending balance $ 948 $ 477 $ 948 $ 477
PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $379 million and
$246 million, respectively, as of June 30, 2023 and December 31, 2022. During the three- and six-month periods ended June 30,
2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of
$49 million and $408 million, respectively. During the three- and six-month periods ended June 30, 2022, PacifiCorp
recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $64 million and
$64 million, respectively. The net losses are included in operations and maintenance on the Consolidated Statements of
Operations. No additional insurance recoveries beyond those accrued to date are expected to be available for the
2020 Wildfires.
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 $31 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 $103 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 for economic losses, noneconomic losses, including mental suffering, emotional distress,
personal injury and loss of life, punitive damages, other damages and attorneys' fees, but the amount of damages sought is not
specified. 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 or transfer of certain assets.
These guarantees are not expected to have a material impact on the Company's consolidated financial results.
24
(12) Revenue from Contracts with Customers
Energy Products and Services
The following table summarizes the Company's energy products and services revenue from contracts with customers
("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business, including a
reconciliation to the Company's reportable segment information included in Note 14 (in millions):
For the Three-Month Period Ended June 30, 2023
PacifiCorp MidAmerican Funding NV Energy Northern Powergrid
BHE Pipeline Group BHE Transmission BHE Renewables BHE andOther(1)Total
Customer Revenue:
Regulated:
Retail electric $ 1,232 $ 569 $ 1,043 $ — $ — $ — $ — $ — $ 2,844
Retail gas — 90 43 — — — — — 133
Wholesale 26 52 9 — — — — 2 89
Transmission and distribution 34 13 19 244 — 166 — — 476
Interstate pipeline — — — — 542 — — (27) 515
Other 24 — — — (1) — — — 23
Total Regulated 1,316 724 1,114 244 541 166 — (25) 4,080
Nonregulated — 1 — 33 270 30 376 1 711
Total Customer Revenue 1,316 725 1,114 277 811 196 376 (24) 4,791
Other revenue 11 34 5 29 7 (4) 61 (1) 142
Total $ 1,327 $ 759 $ 1,119 $ 306 $ 818 $ 192 $ 437 $ (25) $ 4,933
For the Six-Month Period Ended June 30, 2023
PacifiCorp MidAmerican Funding NV Energy Northern Powergrid
BHE Pipeline Group BHE Transmission BHE Renewables BHE andOther(1)Total
Customer Revenue:
Regulated:
Retail electric $ 2,581 $ 1,060 $ 1,891 $ — $ — $ — $ — $ — $ 5,532
Retail gas — 386 139 — — — — — 525
Wholesale 87 152 40 — — — — 1 280
Transmission and distribution 72 27 37 525 — 331 — — 992
Interstate pipeline — — — — 1,420 — — (83) 1,337
Other 56 — — — 1 — — — 57
Total Regulated 2,796 1,625 2,107 525 1,421 331 — (82) 8,723
Nonregulated — 4 1 78 536 70 681 1 1,371
Total Customer Revenue 2,796 1,629 2,108 603 1,957 401 681 (81) 10,094
Other revenue 15 50 10 57 34 (4) 149 (1) 310
Total $ 2,811 $ 1,679 $ 2,118 $ 660 $ 1,991 $ 397 $ 830 $ (82) $ 10,404
25
For the Three-Month Period Ended June 30, 2022
PacifiCorp MidAmerican Funding NV Energy Northern Powergrid
BHE Pipeline Group BHE Transmission BHE Renewables BHE andOther(1)Total
Customer Revenue:
Regulated:
Retail electric $ 1,167 $ 594 $ 831 $ — $ — $ — $ — $ (1) $ 2,591
Retail gas — 136 28 — — — — — 164
Wholesale 55 119 15 — — — — (2) 187
Transmission and distribution 45 13 18 274 — 172 — — 522
Interstate pipeline — — — — 524 — — (27) 497
Other 28 — — — — — — — 28
Total Regulated 1,295 862 892 274 524 172 — (30) 3,989
Nonregulated — — 1 42 285 15 414 (1) 756
Total Customer Revenue 1,295 862 893 316 809 187 414 (31) 4,745
Other revenue 19 35 6 29 47 (4) 32 31 195
Total $ 1,314 $ 897 $ 899 $ 345 $ 856 $ 183 $ 446 $ — $ 4,940
For the Six-Month Period Ended June 30, 2022
PacifiCorp MidAmerican Funding NV Energy Northern Powergrid
BHE Pipeline Group BHE Transmission BHE Renewables BHE andOther(1)Total
Customer Revenue:
Regulated:
Retail electric $ 2,352 $ 1,066 $ 1,430 $ — $ — $ — $ — $ (1) $ 4,847
Retail gas — 473 79 — — — — — 552
Wholesale 110 280 35 — — — — (2) 423
Transmission and distribution 77 28 35 543 — 348 — — 1,031
Interstate pipeline — — — — 1,269 — — (68) 1,201
Other 48 — 1 — 1 — — — 50
Total Regulated 2,587 1,847 1,580 543 1,270 348 — (71) 8,104
Nonregulated — 2 1 57 563 22 716 (1) 1,360
Total Customer Revenue 2,587 1,849 1,581 600 1,833 370 716 (72) 9,464
Other revenue 24 53 11 60 58 (4) 98 (1) 299
Total $ 2,611 $ 1,902 $ 1,592 $ 660 $ 1,891 $ 366 $ 814 $ (73) $ 9,763
(1)The BHE and Other reportable segment represents amounts related principally to other corporate entities, corporate functions and intersegment
eliminations.
Real Estate Services
The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):
HomeServices
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Customer Revenue:
Brokerage $ 1,202 $ 1,544 $ 2,001 $ 2,636
Franchise 15 17 27 37
Total Customer Revenue 1,217 1,561 2,028 2,673
Mortgage and other revenue 79 111 143 206
Total $ 1,296 $ 1,672 $ 2,171 $ 2,879
26
Remaining Performance Obligations
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 June 30,
2023, by reportable segment (in millions):
Performance obligations expected to be satisfied:
Less than 12 months More than 12 months Total
BHE Pipeline Group $ 3,007 $ 20,764 $ 23,771
BHE Transmission 328 — 328
Total $ 3,335 $ 20,764 $ 24,099
(13) Components of Accumulated Other Comprehensive Loss, Net
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):
Unrecognized Foreign Unrealized AOCI
Amounts on Currency Gains Attributable
Retirement Translation on Cash Noncontrolling To BHE
Benefits Adjustment Flow Hedges Interests Shareholders, Net
Balance, December 31, 2021 $ (318) $ (1,086) $ 59 $ 5 $ (1,340)
Other comprehensive income (loss) 40 (591) 103 — (448)
Balance, June 30, 2022 $ (278) $ (1,677) $ 162 $ 5 $ (1,788)
Balance, December 31, 2022 $ (390) $ (1,896) $ 135 $ 2 $ (2,149)
Other comprehensive (loss) income (11) 331 (16) — 304
Balance, June 30, 2023 $ (401) $ (1,565) $ 119 $ 2 $ (1,845)
27
(14) Segment Information
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the
United Kingdom, and BHE Transmission, whose business includes operations in Canada. Intersegment eliminations and
adjustments, including the allocation of goodwill, have been made. Effective January 1, 2023, the Company's unregulated retail
energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously
reported in BHE and Other, have been changed to reflect this activity in BHE Renewables. Information related to the
Company's reportable segments is shown below (in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue:
PacifiCorp $ 1,327 $ 1,314 $ 2,811 $ 2,611
MidAmerican Funding 759 897 1,679 1,902
NV Energy 1,119 899 2,118 1,592
Northern Powergrid 307 345 661 660
BHE Pipeline Group 818 856 1,991 1,891
BHE Transmission 192 183 397 366
BHE Renewables 437 478 830 814
HomeServices 1,296 1,672 2,171 2,879
BHE and Other(1) (26) (32) (83) (73)
Total operating revenue $ 6,229 $ 6,612 $ 12,575 $ 12,642
Depreciation and amortization:
PacifiCorp $ 279 $ 279 $ 558 $ 559
MidAmerican Funding 226 277 460 527
NV Energy 153 139 305 279
Northern Powergrid 85 100 170 180
BHE Pipeline Group 95 125 267 256
BHE Transmission 65 60 126 118
BHE Renewables 67 65 133 131
HomeServices 12 14 25 29
BHE and Other(1) — — 1 2
Total depreciation and amortization $ 982 $ 1,059 $ 2,045 $ 2,081
28
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating income:
PacifiCorp $ 131 $ 158 $ (36) $ 374
MidAmerican Funding 118 90 206 190
NV Energy 117 140 174 202
Northern Powergrid 121 110 267 269
BHE Pipeline Group 368 352 952 890
BHE Transmission 76 84 164 167
BHE Renewables 89 155 20 209
HomeServices 46 117 1 145
BHE and Other(1) (20) 1 (35) (3)
Total operating income 1,046 1,207 1,713 2,443
Interest expense (599) (550) (1,185) (1,082)
Capitalized interest 33 18 57 35
Allowance for equity funds 61 42 110 80
Interest and dividend income 127 30 213 53
Gains on marketable securities, net 303 2,528 1,002 1,271
Other, net 78 (26) 118 (21)
Total income (loss) before income tax expense (benefit) and equity income (loss)$ 1,049 $ 3,249 $ 2,028 $ 2,779
Interest expense:
PacifiCorp $ 134 $ 107 $ 258 $ 213
MidAmerican Funding 85 83 169 165
NV Energy 64 52 127 103
Northern Powergrid 30 34 60 66
BHE Pipeline Group 39 36 78 73
BHE Transmission 38 38 75 76
BHE Renewables 43 45 88 87
HomeServices 4 2 8 3
BHE and Other(1) 162 153 322 296
Total interest expense $ 599 $ 550 $ 1,185 $ 1,082
Earnings on common shares:
PacifiCorp $ 107 $ 83 $ (13) $ 213
MidAmerican Funding 233 204 482 445
NV Energy 90 93 124 122
Northern Powergrid 96 71 107 182
BHE Pipeline Group 187 199 556 521
BHE Transmission 58 62 122 124
BHE Renewables 206 264 285 409
HomeServices 34 84 — 105
BHE and Other(1) 55 1,824 384 618
Total earnings on common shares $ 1,066 $ 2,884 $ 2,047 $ 2,739
29
As of
June 30,December 31,
2023 2022
Assets:
PacifiCorp $ 31,700 $ 30,559
MidAmerican Funding 26,241 26,077
NV Energy 17,495 16,676
Northern Powergrid 9,531 9,005
BHE Pipeline Group 20,937 21,005
BHE Transmission 9,599 9,334
BHE Renewables 11,295 12,632
HomeServices 3,795 3,436
BHE and Other(1) 7,158 5,116
Total assets $ 137,751 $ 133,840
(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.
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue by country:
U.S.$ 5,749 $ 6,087 $ 11,564 $ 11,621
United Kingdom 295 345 628 660
Canada 173 180 350 361
Australia 12 — 33 —
Total operating revenue by country $ 6,229 $ 6,612 $ 12,575 $ 12,642
Income (loss) before income tax expense (benefit) and equity income (loss) by country:
U.S.$ 914 $ 3,117 $ 1,733 $ 2,463
United Kingdom 93 87 206 226
Canada 44 46 87 92
Australia (3) 1 2 1
Other 1 (2) — (3)
Total income (loss) before income tax expense (benefit) and equity income (loss) by country $ 1,049 $ 3,249 $ 2,028 $ 2,779
The following table shows the change in the carrying amount of goodwill by reportable segment for the six-month period ended
June 30, 2023 (in millions):
BHE Pipeline GroupPacifiCorpMidAmerican Funding NV Energy Northern Powergrid BHE Transmission BHE Renewables HomeServices Total

December 31, 2022 $ 1,129 $ 2,102 $ 2,369 $ 917 $ 1,814 $ 1,461 $ 95 $ 1,602 $ 11,489
Acquisitions — — — — — — — 1 1
Foreign currency translation — — — 32 — 31 — — 63
Other — — — — — — — (7) (7)
June 30, 2023 $ 1,129 $ 2,102 $ 2,369 $ 949 $ 1,814 $ 1,492 $ 95 $ 1,596 $ 11,546
30
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated
financial condition and results of operations of the Company during the periods included herein. Explanations include
management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should
be read in conjunction with the Company's historical unaudited Consolidated Financial Statements and Notes to Consolidated
Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly
from the historical results.
BHE is a holding company that owns a highly diversified portfolio of locally managed and operated businesses principally
engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway that, as of August 3, 2023, owned 92%
of BHE's voting common stock. The balance of BHE's voting common stock is privately held by a limited group of investors.
Berkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which
primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific),
Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc),
BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE Transmission
(which consists of BHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and
HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the U.S. serving
customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in
the U.S., interests in an LNG export, import and storage facility in the U.S., an electric transmission business in Canada,
interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar,
geothermal and hydroelectric projects and one of the largest residential real estate brokerage firms and residential real estate
brokerage franchise networks in the U.S. The reportable segment financial information includes all necessary adjustments and
eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable
segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other corporate entities,
corporate functions and intersegment eliminations. Effective January 1, 2023, the Company's unregulated retail energy services
business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE
and Other, have been changed to reflect this activity in BHE Renewables.
31
Results of Operations for the Second Quarter and First Six Months of 2023 and 2022
Overview
Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows
(in millions):
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Operating revenue:
PacifiCorp $ 1,327 $ 1,314 $ 13 1 %$ 2,811 $ 2,611 $ 200 8 %
MidAmerican Funding 759 897 (138) (15) 1,679 1,902 (223) (12)
NV Energy 1,119 899 220 24 2,118 1,592 526 33
Northern Powergrid 307 345 (38) (11) 661 660 1 —
BHE Pipeline Group 818 856 (38) (4) 1,991 1,891 100 5
BHE Transmission 192 183 9 5 397 366 31 8
BHE Renewables 437 478 (41) (9) 830 814 16 2
HomeServices 1,296 1,672 (376) (22) 2,171 2,879 (708) (25)
BHE and Other (26) (32) 6 19 (83) (73) (10) (14)
Total operating revenue $ 6,229 $ 6,612 $ (383) (6) %$ 12,575 $ 12,642 $ (67) (1) %
Earnings on common shares:
PacifiCorp $ 107 $ 83 $ 24 29 %$ (13) $ 213 $ (226) *
MidAmerican Funding 233 204 29 14 482 445 37 8
NV Energy 90 93 (3) (3) 124 122 2 2
Northern Powergrid 96 71 25 35 107 182 (75) (41)
BHE Pipeline Group 187 199 (12) (6) 556 521 35 7
BHE Transmission 58 62 (4) (6) 122 124 (2) (2)
BHE Renewables(1) 206 264 (58) (22) 285 409 (124) (30)
HomeServices 34 84 (50) (60) — 105 (105) (100)
BHE and Other 55 1,824 (1,769) (97) 384 618 (234) (38)
Total earnings on common shares $ 1,066 $ 2,884 $ (1,818) (63) %$ 2,047 $ 2,739 $ (692) (25) %
(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
* Not meaningful
Earnings on common shares decreased $1,818 million for the second quarter of 2023 compared to 2022. Included in these
results was a pre-tax gain in the second quarter of 2023 of $293 million ($231 million after-tax) compared to a pre-tax gain in
the second quarter of 2022 of $2,557 million ($2,020 million after-tax) related to the Company's investment in BYD Company
Limited ("BYD"). Excluding the impact of this item, adjusted earnings on common shares for the second quarter of 2023 was
$835 million, a decrease of $29 million, or 3%, compared to adjusted earnings on common shares for the second quarter of
2022 of $864 million.
Earnings on common shares decreased $692 million for the first six months of 2023 compared to 2022. Included in these results
was a pre-tax gain in the first six months of 2023 of $984 million ($777 million after-tax) compared to a pre-tax gain in the first
six months of 2022 of $1,310 million ($1,035 million after-tax) related to the Company's investment in BYD. Excluding the
impact of this item, adjusted earnings on common shares for the first six months of 2023 was $1,270 million, a decrease of
$434 million, or 25%, compared to adjusted earnings on common shares for the first six months of 2022 of $1,704 million.
32
The decreases in earnings on common shares for the second quarter and for the first six months of 2023 compared to 2022 were
primarily due to the following:
•The Utilities' earnings increased $50 million for the second quarter and decreased $187 million for the first six months
of 2023 compared to 2022. The changes reflected higher operations and maintenance expense, largely due to an
increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfire for the first six
months, and increased interest expense. These items were offset by favorable interest and dividend income, higher
allowances for equity and borrowed funds used during construction, favorable changes in the cash surrender value of
corporate-owned life insurance policies, lower depreciation and amortization expense and higher electric utility margin
for the first six months. Electric retail customer volumes increased 0.1% for the first six months of 2023 compared to
2022;
•Northern Powergrid's earnings increased $25 million for the second quarter and decreased $75 million for the first six
months of 2023 compared to 2022. The changes were 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 offset by favorable
income tax expense from adjustments to the Energy Profits Levy income tax recognized in the second quarter of 2023.
Units distributed declined 4.6% for the first six months of 2023 compared to 2022 due to the unfavorable impact of
weather and lower customer usage;
•BHE Pipeline Group's earnings decreased $12 million for the second quarter and increased $35 million for the first six
months of 2023 compared to 2022, largely due to the impact of a general rate case, with interim rates effective January
2023, subject to refund, at Northern Natural Gas, offset by higher operations and maintenance expense and favorable
state unitary income tax adjustments recognized at BHE GT&S in the second quarter of 2022;
•BHE Renewables' earnings decreased $58 million for the second quarter and $124 million for the first six months of
2023 compared to 2022, primarily due to lower earnings from the retail energy services business, largely due to
unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves,
lower natural gas and geothermal earnings due to maintenance outages, lower solar earnings from lower generation
due to weather events in California and lower earnings from wind tax equity investments due to lower PTCs, partially
offset by higher earnings from owned wind projects primarily due to favorable derivative contract valuations and gains
on the extinguishment of debt;
•HomeServices' earnings decreased $50 million for the second quarter and $105 million for the first six months of 2023
compared to 2022, primarily due to lower earnings from brokerage, settlement and mortgage services, reflecting the
impact of rising interest rates and a corresponding decline in home sales; and
•BHE and Other's earnings decreased $1,769 million for the second quarter and $234 million for the first six months of
2023 compared to 2022, mainly due to $1,789 million and $258 million, respectively, of unfavorable comparative
changes in the Company's investment in BYD.
Reportable Segment Results
PacifiCorp
Operating revenue increased $13 million for the second quarter of 2023 compared to 2022, primarily due to higher retail
revenue of $59 million, partially offset by lower wholesale and other revenue of $45 million, primarily from lower wholesale
volumes and a decrease in wheeling revenue. Retail revenue increased primarily due to price impacts of $82 million from
higher average retail rates largely due to tariff changes and product mix, partially offset by $23 million from lower volumes.
Retail customer volumes decreased 2.2%, primarily due to lower customer usage, partially offset by an increase in the average
number of customers.
Earnings increased $24 million for the second quarter of 2023 compared to 2022, primarily due to higher allowances for equity
and borrowed funds used during construction of $27 million, a favorable income tax benefit from the effects of ratemaking of
$11 million and higher PTCs recognized of $8 million, increased interest and dividend income of $19 million, favorable
changes in the cash surrender value of corporate-owned life insurance policies of $6 million and higher utility margin of
$2 million, partially offset by higher operations and maintenance expense of $28 million and increased interest expense of
$27 million due to debt issuances in December 2022 and May 2023. Utility margin increased due to higher retail rates, lower
thermal generation costs and favorable deferred net power costs, partially offset by higher purchased power costs, lower retail
and wholesale volumes and lower wheeling revenue. Operations and maintenance expense was unfavorable largely due to
higher wildfire mitigation and vegetation management costs and higher legal expenses, partially offset by a decrease in loss
accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $15 million.
33
Operating revenue increased $200 million for the first six months of 2023 compared to 2022, primarily due to higher retail
revenue of $218 million, partially offset by lower wholesale and other revenue of $17 million, primarily from lower wholesale
volumes, partially offset by higher average wholesale market prices. Retail revenue increased primarily due to price impacts of
$189 million from higher average retail rates largely due to tariff changes and product mix and $29 million from higher
volumes. Retail customer volumes increased 0.6%, primarily due to favorable impacts of weather and an increase in the average
number of customers, partially offset by lower customer usage.
Earnings decreased $226 million for the first six months of 2023 compared to 2022, primarily due to higher operations and
maintenance expense of $456 million and increased interest expense of $45 million due to debt issuances in December 2022
and May 2023, partially offset by a favorable income tax benefit, higher allowances for equity and borrowed funds used during
construction of $50 million, higher utility margin of $40 million, increased interest and dividend income of $31 million and
favorable changes in the cash surrender value of corporate-owned life insurance policies of $9 million. 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 $344 million, higher wildfire mitigation and vegetation management costs, higher legal
expenses and higher general and plant maintenance costs. The favorable income tax benefit was driven by valuation allowance
changes on state net operating loss carryforwards, the effects of ratemaking of $12 million and higher PTCs recognized of
$11 million. Utility margin increased 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 $138 million for the second quarter of 2023 compared to 2022, primarily due to lower natural gas
operating revenue of $74 million from a lower average per-unit cost of natural gas sold resulting in lower purchased gas
adjustment recoveries (fully offset in cost of sales) and lower electric operating revenue of $64 million. Electric operating
revenue decreased due to lower wholesale and other revenue of $40 million and lower retail revenue of $24 million. Electric
wholesale and other revenue decreased mainly due to lower average wholesale per-unit prices of $33 million and lower
wholesale volumes of $6 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses
of $27 million (fully offset in expense, primarily cost of sales), partially offset by price impacts of $3 million from changes in
sales mix. Electric retail customer volumes increased 1.5%, primarily due to higher customer usage, partially offset by the
unfavorable impact of weather.
Earnings increased $29 million for the second quarter of 2023 compared to 2022, primarily due to lower depreciation and
amortization expense of $51 million and favorable changes in the cash surrender value of corporate-owned life insurance
policies of $21 million, partially offset by an unfavorable income tax benefit primarily from lower PTCs recognized of $12
million, higher operations and maintenance expense of $16 million and lower electric utility margin of $3 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 mainly due to higher general and plant maintenance
costs, increased administrative and other costs and unfavorable property insurance costs. Electric utility margin decreased
primarily due to the lower wholesale and retail revenues, partially offset by lower thermal generation and purchased power
costs.
Operating revenue decreased $223 million for the first six months of 2023 compared to 2022, primarily due to lower natural gas
operating revenue of $144 million and lower electric operating revenue of $81 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
$136 million (fully offset in cost of sales) and the unfavorable impact of weather of $9 million. Electric operating revenue
decreased due to lower wholesale and other revenue of $73 million and lower retail revenue of $8 million. Electric wholesale
and other revenue decreased mainly due to lower average wholesale per-unit prices of $46 million and lower wholesale
volumes of $28 million. Electric retail revenue decreased primarily due to lower recoveries through adjustment clauses of
$13 million (fully offset in expense, primarily cost of sales), partially offset by price impacts of $3 million from changes in
sales mix. Electric retail customer volumes increased 1.3%, primarily due to higher customer usage, partially offset by the
unfavorable impact of weather.
34
Earnings increased $37 million for the first six months of 2023 compared to 2022, primarily due to lower depreciation and
amortization expense of $67 million, favorable changes in the cash surrender value of corporate-owned life insurance policies
of $33 million and a one-time gain on the sale of an investment of $13 million, partially offset by higher operations and
maintenance expense of $29 million, an unfavorable income tax benefit primarily from lower PTCs recognized of $13 million,
lower electric utility margin of $10 million, lower natural gas utility margin of $8 million and lower allowances for equity and
borrowed funds used during construction of $6 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 mainly due to higher general and plant maintenance costs, increased administrative and other costs and
unfavorable property insurance costs. Electric utility margin decreased primarily due to lower wholesale and retail revenues,
partially offset by lower thermal generation and purchased power costs. Natural gas utility margin decreased primarily due to
the unfavorable impact of weather.
NV Energy
Operating revenue increased $220 million for the second quarter of 2023 compared to 2022, primarily due to higher electric
operating revenue of $205 million and higher natural gas operating revenue of $15 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 $206 million and increased base tariff general rates of $19 million at Sierra Pacific,
partially offset by lower customer volumes of $25 million. Electric retail customer volumes decreased 5.5%, primarily due to
the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of
customers.
Earnings decreased $3 million for the second quarter of 2023 compared to 2022, primarily due to unfavorable depreciation and
amortization expense of $13 million, increased interest expense of $12 million due to higher outstanding long-term debt
balances, higher operations and maintenance expense of $10 million and lower electric utility margin of $1 million, partially
offset by favorable interest and dividend income of $12 million, mainly from carrying charges on higher deferred energy
balances, higher allowances for equity and borrowed funds used during construction of $11 million and favorable changes in
the cash surrender value of corporate-owned life insurance policies of $7 million. Depreciation and amortization expense
increased primarily due to additional assets placed in-service. Operations and maintenance expense increased primarily due to
higher general and plant maintenance costs. Electric utility margin decreased primarily due to lower retail customer volumes
largely offset by higher base tariff general rates at Sierra Pacific.
Operating revenue increased $526 million for the first six months of 2023 compared to 2022, primarily due to higher electric
operating revenue of $466 million and higher natural gas operating revenue of $60 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 $435 million, increased base tariff general rates of $27 million at Sierra Pacific and
favorable transmission and wholesale revenue of $7 million, partially offset by lower customer volumes of $17 million. Electric
retail customer volumes decreased 1.7%, primarily due to the unfavorable impact of weather and lower customer usage,
partially offset by an increase in the average number of customers.
Earnings increased $2 million for the first six months of 2023 compared to 2022, primarily due to higher electric utility margin
of $30 million, favorable interest and dividend income of $28 million, mainly from carrying charges on higher deferred energy
balances, higher allowances for equity and borrowed funds used during construction of $14 million and favorable changes in
the cash surrender value of corporate-owned life insurance policies of $11 million, partially offset by higher operations and
maintenance expense of $34 million, unfavorable depreciation and amortization expense of $26 million and increased interest
expense of $24 million due to higher outstanding long-term debt balances. Electric utility margin increased primarily due to
higher base tariff general rates at Sierra Pacific and higher transmission and wholesale revenue, partially offset by lower retail
customer volumes. 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 decreased $38 million for the second quarter of 2023 compared to 2022, primarily due to lower distribution
revenue of $30 million and lower revenue at CE Gas of $16 million, partially offset by higher non-regulated contracting
revenue of $7 million. Distribution revenue decreased primarily due to lower recoveries of Supplier of Last Resort payments of
$29 million (fully offset in cost of sales). CE Gas revenue decreased due to lower gas production volumes and prices from a gas
project that commenced commercial operation in March 2022, partially offset by a solar project that commenced commercial
operation in July 2022.
35
Earnings increased $25 million for the second quarter of 2023 compared to 2022, primarily due to favorable income tax
expense from adjustments to the Energy Profits Levy income tax and lower distribution-related operating and depreciation
expenses of $12 million, partially offset by increased non-service benefit plan costs $9 million.
Operating revenue increased $1 million for the first six months of 2023 compared to 2022, primarily due to higher revenue at
CE Gas of $12 million, higher distribution revenue of $11 million and higher non-regulated contracting revenue of $11 million,
partially offset by $34 million from the stronger U.S. dollar. Distribution revenue increased primarily due to higher recoveries
of Supplier of Last Resort payments of $12 million (fully offset in cost of sales) and higher tariff rates of $10 million. Also
impacting distribution revenue was a 4.6% decline in units distributed, largely due to the unfavorable impact of weather and
lower customer usage in the first quarter of 2023, 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 $75 million for the first six months 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, increased
non-service benefit plan costs of $19 million and $5 million from the stronger U.S. dollar, partially offset by favorable income
tax expense from adjustments to the Energy Profits Levy income tax and 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 decreased $38 million for the second quarter of 2023 compared to 2022, primarily due to lower operating
revenue of $49 million at BHE GT&S, partially offset by higher operating revenue of $16 million at Northern Natural Gas. The
decrease in operating revenue at BHE GT&S was primarily due to lower non-regulated revenue of $75 million (largely offset in
cost of sales) due lower volumes and unfavorable commodity prices, partially offset by higher LNG revenue of $16 million at
Cove Point, an increase in variable revenue related to park and loan activity of $10 million at EGTS and an increase in
regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $8 million. The
increase in operating revenue at Northern Natural Gas was largely due to higher transportation revenue of $13 million from
higher rates, the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $9 million,
partially offset by lower gas sales of $12 million (partially offset in cost of sales) from system balancing activities.
Earnings decreased $12 million for the second quarter of 2023 compared to 2022, primarily due to lower earnings of
$39 million at BHE GT&S, partially offset by higher earnings of $30 million at Northern Natural Gas. The decrease at BHE
GT&S was due to favorable state unitary income tax adjustments recognized in the second quarter of 2022, increased cost of
gas from the unfavorable revaluation of volumes retained at EGTS due to lower natural gas prices and lower margin from non-
regulated activities, partially offset by the variable revenue increase related to park and loan activity at EGTS and increased
earnings at Cove Point. The increase at Northern Natural Gas was due to the impacts of the general rate case of $35 million and
the higher transportation revenue, partially offset by higher operations and maintenance expense of $13 million and unfavorable
margin on gas sales from system balancing activities of $10 million.
Operating revenue increased $100 million for the first six months of 2023 compared to 2022, primarily due to higher operating
revenue of $87 million at Northern Natural Gas and $5 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 $72 million and higher transportation revenue of $46 million from higher rates, partially offset by lower gas sales of $37
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 $50 million, higher LNG revenue of $32 million at Cove Point and an increase in variable revenue related to park
and loan activity of $20 million at EGTS, partially offset by lower non-regulated revenue of $97 million (largely offset in cost
of sales) from lower volumes and unfavorable commodity prices.
Earnings increased $35 million for the first six months of 2023 compared to 2022, primarily due to higher earnings of
$57 million at Northern Natural Gas, partially offset by lower earnings of $24 million at BHE GT&S. The increase at Northern
Natural Gas was due to the impacts of the general rate case of $51 million and the higher transportation revenue, partially offset
by higher operations and maintenance expense of $31 million and unfavorable margin on gas sales from system balancing
activities of $11 million. The decrease at BHE GT&S was due to higher operations and maintenance expense, increased cost of
gas from the unfavorable revaluation of volumes retained at EGTS due to lower natural gas prices, favorable state unitary
income tax adjustments recognized in the second quarter of 2022 and lower margin from non-regulated activities, partially
offset by the favorable rate case settlement at EGTS in 2022, the variable revenue increase related to park and loan activity at
EGTS, increased earnings at Cove Point and higher equity earnings at Iroquois Gas Transmission System.
36
BHE Transmission
Operating revenue increased $9 million for the second quarter of 2023 compared to 2022, primarily due to $16 million of
incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022, partially offset by
$9 million from the stronger U.S. dollar.
Earnings decreased $4 million for the second quarter of 2023 compared to 2022, primarily due to $2 million of losses from non-
regulated wind-powered generating facilities acquired in November 2022 and $2 million from the stronger U.S. dollar.
Operating revenue increased $31 million for the first six months of 2023 compared to 2022, primarily due to $42 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 $21 million from the stronger U.S. dollar.
Earnings decreased $2 million for the first six months of 2023 compared to 2022, primarily due to $5 million from the stronger
U.S. dollar, partially offset by $3 million of incremental earnings from non-regulated wind-powered generating facilities
acquired in November 2022.
BHE Renewables
Operating revenue decreased $41 million for the second quarter of 2023 compared to 2022, primarily due to lower natural gas
and electric retail energy services revenues of $22 million, mainly from unfavorable natural gas pricing, lower solar revenues of
$15 million, mainly from lower generation due to weather events in California, and lower natural gas and geothermal revenues
of $8 million, largely due to maintenance outages and unfavorable pricing. These items were partially offset by higher wind
revenues of $7 million, which increased primarily due to favorable changes in the valuations of certain derivatives contracts
offset by lower generation of $21 million.
Earnings decreased $58 million for the second quarter of 2023 compared to 2022, primarily due to lower earnings of
$19 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 $16 million, primarily
due to maintenance outages, lower wind earnings of $11 million and lower solar earnings of $10 million from the lower
generation. Wind earnings decreased due to lower earnings from tax equity investments of $46 million due to lower PTCs,
partially offset by higher earnings from owned projects of $35 million. Earnings from owned projects were higher primarily due
to the favorable derivative contract valuations and from gains on the extinguishment of debt, partially offset by a decrease in
operating revenue from lower generation.
Operating revenue increased $16 million for the first six months of 2023 compared to 2022, primarily due to higher wind
revenues of $67 million, partially offset by lower solar revenues of $35 million, mainly from lower generation due to weather
events in California, and lower natural gas and geothermal revenues of $8 million, mainly due to maintenance outages and
unfavorable pricing. Wind revenues increased primarily due to favorable changes in the valuations of certain derivatives
contracts offset by lower generation of $16 million.
Earnings decreased $124 million for the first six months of 2023 compared to 2022, primarily due to lower earnings of
$98 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 $56 million, primarily
due to maintenance outages, and lower solar earnings of $28 million from the lower generation. These items were partially
offset by higher wind earnings of $62 million due to increased earnings from owned projects of $80 million, partially offset by
lower earnings from tax equity investments of $18 million due to lower PTCs. Earnings from owned projects were higher
primarily due to the favorable derivative contract valuations and from gains on the extinguishment of debt, partially offset by a
decrease in operating revenue from lower generation.
HomeServices
Operating revenue decreased $376 million for the second quarter of 2023 compared to 2022, primarily due to lower brokerage
and settlement services revenue of $344 million and lower mortgage revenue of $31 million. The decrease in brokerage and
settlement services revenue resulted from a 24% 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 35% decrease in funded volume, primarily due
to rising interest rates.
37
Earnings decreased $50 million for the second quarter of 2023 compared to 2022, primarily due to lower earnings from
brokerage and settlement services of $40 million and mortgage services of $9 million. Earnings declined due to the decrease in
closed transaction and mortgage funded volumes, partially offset by favorable operating expenses primarily due to lower
compensation costs.
Operating revenue decreased $708 million for the first six months of 2023 compared to 2022, primarily due to lower brokerage
and settlement services revenue of $637 million and lower mortgage revenue of $65 million. The decrease in brokerage and
settlement services revenue resulted from a 26% 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 38% decrease in funded volume, primarily due
to rising interest rates.
Earnings decreased $105 million for the first six months of 2023 compared to 2022, primarily due to lower earnings from
brokerage and settlement services of $77 million and mortgage services of $21 million. Earnings declined due to the decrease in
closed transaction and mortgage funded volumes, partially offset by favorable operating expenses primarily due to lower
compensation costs.
BHE and Other
Operating revenue increased $6 million for the second quarter of 2023 and decreased $10 million for the first six months of
2023 compared to 2022, due to changes in intersegment eliminations.
Earnings decreased $1,769 million for the second quarter of 2023 compared to 2022, primarily due to the $1,789 million
unfavorable comparative change related to the Company's investment in BYD, $29 million of lower federal income tax credits
recognized on a consolidated basis and higher BHE corporate interest expense from an April 2022 debt issuance. These items
were partially offset by higher net interest and dividend income of $49 million related to the Company's investment in BYD,
favorable changes in the cash surrender value of corporate-owned life insurance policies of $24 million and $4 million of lower
dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway.
Earnings decreased $234 million for the first six months of 2023 compared to 2022, primarily due to the $258 million
unfavorable comparative change related to the Company's investment in BYD, $46 million of lower federal income tax credits
recognized on a consolidated basis and higher BHE corporate interest expense from an April 2022 debt issuance. These items
were partially offset by higher net interest and dividend income of $75 million related to the Company's investment in BYD,
favorable changes in the cash surrender value of corporate-owned life insurance policies of $38 million and $12 million of
lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway.
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.
38
As of June 30, 2023, the Company's total net liquidity was as follows (in millions):
BHE Pipeline
MidAmerican NV Northern BHE Group and
BHE PacifiCorp Funding Energy Powergrid Canada HomeServices Other Total
Cash and cash equivalents $ 112 $ 586 $ 454 $ 81 $ 26 $ 74 $ 271 $ 625 $ 2,229
Credit facilities(1) 3,500 2,000 1,509 1,000 341 812 2,230 — 11,392
Less:
Short-term debt (1,245) — — — (104) (111) (783) — (2,243)
Tax-exempt bond support and letters of credit — (249) (306) — — (1) — — (556)
Net credit facilities 2,255 1,751 1,203 1,000 237 700 1,447 — 8,593
Total net liquidity $ 2,367 $ 2,337 $ 1,657 $ 1,081 $ 263 $ 774 $ 1,718 $ 625 $ 10,822
Credit facilities:
Maturity dates 2026 2026 2024, 2026 2026 2025 2024, 2026, 2027 2023, 2024, 2026
(1)Includes $87 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.
Operating Activities
Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $3.7 billion and
$5.1 billion, respectively. The decrease was primarily due to unfavorable operating results, the timing of payments related to
fuel and energy costs, changes in working capital and a decrease in income tax receipts.
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 six-month periods ended June 30, 2023 and 2022, were $(3.7) billion and
$(3.5) billion, respectively. The change was primarily due to higher purchases, net of proceeds from sales and maturities, of
U.S. Treasury Bills totaling $1.3 billion and higher capital expenditures of $643 million, partially offset by higher proceeds
from sales, net of purchases, of marketable securities of $1.7 billion. Refer to "Future Uses of Cash" for a discussion of capital
expenditures.
Financing Activities
Net cash flows from financing activities for the six-month period ended June 30, 2023, was $625 million. Sources of cash
totaled $2.3 billion and consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and net proceeds from short-
term debt totaling $1.1 billion. Uses of cash totaled $1.7 billion and consisted mainly of repayments of subsidiary debt totaling
$959 million, repayments of BHE senior debt totaling $400 million and distributions to noncontrolling interests of
$269 million.
For a discussion of recent financing transactions, refer to Note 6 of Notes to Consolidated Financial Statements in Part I, Item 1
of this Form 10-Q.
Net cash flows from financing activities for the six-month period ended June 30, 2022, was $(605) million. Sources of cash
totaled $2.2 billion and consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and proceeds from BHE
senior debt issuances totaling $987 million. Uses of cash totaled $2.8 billion and consisted mainly of purchases of common
stock totaling $870 million, preferred stock redemptions of $800 million, repayments of subsidiary debt totaling $542 million,
distributions to noncontrolling interests of $246 million and net repayments of short-term debt totaling $54 million.
39
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.
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):
Six-Month Periods Annual
Ended June 30,Forecast
2022 2023 2023
Capital expenditures by business:
PacifiCorp $ 894 $ 1,529 $ 3,594
MidAmerican Funding 862 763 2,147
NV Energy 541 889 1,794
Northern Powergrid 450 249 556
BHE Pipeline Group 457 406 1,364
BHE Transmission 95 86 200
BHE Renewables 61 59 302
HomeServices 20 19 39
BHE and Other(1) 2 25 26
Total $ 3,382 $ 4,025 $ 10,022
Capital expenditures by type:
Wind generation $ 304 $ 615 $ 1,791
Electric distribution 805 1,045 2,221
Electric transmission 628 749 2,013
Natural gas transmission and storage 335 304 1,021
Solar generation 261 251 444
Electric battery and pumped hydro storage 3 45 257
Other 1,046 1,016 2,275
Total $ 3,382 $ 4,025 $ 10,022
(1)BHE and Other represents amounts related principally to other entities corporate functions and intersegment eliminations.
40
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 $200 million and
$5 million for the six-month periods ended June 30, 2023 and 2022, respectively. The timing and amount of
forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of
MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-
powered generating facilities totals $544 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $19 million and
$214 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for the
repowering of wind-powered generating facilities totals $46 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 $366 million and $11 million for the six-month
periods ended June 30, 2023 and 2022, respectively. Planned spending for the construction of additional
wind-powered generating facilities and those at acquired sites totals $444 million for the remainder of 2023
and is primarily for the Rock Creek I and Rock Creek II projects to be constructed in Wyoming totaling
590 MWs that are expected to be placed in-service in 2024 and 2025.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $45 million for the six-month
period ended June 30, 2022. Planned spending for the repower of wind-powered facilities totals $50 million
for the remainder of 2023.
•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 $313 million and $297 million for the six-month periods ended June 30, 2023 and 2022, respectively.
Planned spending for these Energy Gateway Transmission segments totals $667 million for the remainder of
2023.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have received
approval from the PUCN to build a 350-mile, 525-kV transmission line connecting the Ft. Churchill
substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line
connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV
transmission line from the new Ft. Churchill substation to the Mira Loma substation; and a 38-mile, 345-kV
transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Expenditures for
the expansion program and other growth projects totaled $113 million and $60 million for the six-month
periods ended June 30, 2023 and 2022, respectively. Planned spending for the expansion program estimated
to be placed in-service in 2026 through 2028 and other growth projects totals $94 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.
41
•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 six-month periods ended June 30, 2023 and 2022, solar generation spending totaled $10 million
and $77 million, respectively. Planned spending totals $14 million for the remainder of 2023.
◦Construction of a solar-powered generating facility at Nevada Power totaling $156 million and $23 million
for the six-month periods ended June 30, 2023 and 2022, respectively. Planned spending totals $50 million
for the remainder of 2023. Construction includes expenditures for a 150-MW solar photovoltaic facility with
an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada.
Commercial operation is expected by the end of 2023 or early 2024.
◦Construction of a solar-powered generating facility at BHE Renewables totaling $2 million for the six-month
period ended June 30, 2023. Planned spending totals $56 million for the remainder of 2023. Construction
includes expenditures for a 48-MW solar photovoltaic facility with an additional 48 MWs of co-located
battery storage that will be developed in Rosamond, California. Commercial operations is expected by the end
of 2024.
•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:
◦Construction at the Nevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW
solar photovoltaic facility that will be developed in Clark County, Nevada and a 220-MW grid-tied battery
energy storage system that will be developed on the site of the retired Reid Gardner generating station in
Clark County, Nevada, both with commercial operation expected by the end of 2023 or early 2024. Also, a
200-MW battery energy storage system that will be developed on the site of the Valmy generating station in
Humboldt County, Nevada with commercial operation expected by the end of 2025. Total spending for the
six-month period ended June 30, 2023, was $43 million with planned spending of $200 million for the
remainder of 2023.
•Other includes both growth and operating expenditures, including spending for routine expenditures for generation and
other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and
environmental spending relating to emissions control equipment and the management of coal combustion residuals.
Cove Point Acquisition
On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of
BHE, entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc. ("DEI") and DECP
Holdings, Inc. (the "Seller"), an indirect wholly owned subsidiary of DEI, to purchase (the "Transaction") Seller's 50% limited
partner interests in Cove Point LNG, LP ("Cove Point") for a cash purchase price of $3.3 billion, plus the pro rata portion of
any quarterly distribution made by Cove Point for the fiscal quarter in which the Transaction closes. BHE expects to fund the
purchase price with cash on hand, including cash realized from the liquidation of certain investments. Upon the completion of
the Transaction, the Buyer will own an aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP
Holding Company, LLC, will continue to own 100% of the general partner interest, of Cove Point. Subject to certain closing
conditions, the Transaction is expected to close by year-end 2023.
Material Cash Requirements
As of June 30, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of the
Company's Annual Report on Form 10-K for the year ended December 31, 2022, other than those disclosed in Note 11 of the
Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Regulatory Matters
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains
material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended
December 31, 2022, and new regulatory matters occurring in 2023.
42
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 July 2022, PacifiCorp filed an application requesting approval of an automatic adjustment clause with a balancing account to
recover costs associated with implementing PacifiCorp's wildfire protection plan in Oregon. Per formal rulemaking at the
OPUC, the wildfire protection plan was changed to be known as the wildfire mitigation plan, resulting in the requested
automatic adjustment clause being referred to as the Wildfire Mitigation Plan Automatic Adjustment Clause ("WMP AAC"). In
December 2022, a stipulation with certain parties was filed agreeing to the establishment of an automatic adjustment clause. In
May 2023, the OPUC approved the stipulation, which resulted in an overall annual increase of $20 million, or 1.6%, effective
May 24, 2023 for estimated 2022 incremental operation and maintenance costs in excess of those reflected in base rates as a
result of the last general rate case. In June 2023, PacifiCorp filed its WMP AAC to recover remaining 2022 deferred operations
and maintenance costs, projected incremental 2023 operations and maintenance costs and capital costs incremental to amounts
previously included in general rate case filings. The filing requested a rate increase of $27 million over the existing amount
approved in May 2023, to become effective November 5, 2023. When combined with the previously approved increase, the rate
schedule would be set to recover $47 million.
In 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.
In June 2023, PacifiCorp filed its power cost adjustment mechanism to recover deferred net power costs from 2022. The filing
requested recovery of over $71 million, which PacifiCorp proposed to recover over a two-year period with interest, resulting in
a rate increase of $37 million, or 9.5%, to become effective January 1, 2024.
Idaho
In October 2022, PacifiCorp filed an application for authority to implement the residential rate modernization plan. The plan
proposes a five-year transition to increase the monthly customer service charge from $8.00 to $29.25 per month with a
corresponding reduction to the energy rate, eliminates the tiered rates, and adjusts the on-peak off-peak period for time-of-day
customers. In response to concerns about the combined impact of the proposed changes, PacifiCorp proposed a modification to,
rather than elimination of, the tiered rates. In May 2023, the Idaho Public Utilities Commission issued an order approving
PacifiCorp's request to increase the customer service charge over five years, to adjust peak periods for time-of-day customers,
and to modify the tiered rate structure. The changes to the residential rates became effective June 1, 2023.
43
California
In May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become
effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to
establish a memorandum account to track the change in rates beginning January 1, 2023, until the new rates become effective
upon the issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in February 2023 with a slight adjustment of an
overall rate increase of $27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling requesting additional
information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum
accounts. In March 2023, the CPUC split the general rate case into two tracks. The first track addresses the general rate case
with an expected decision from the CPUC in late 2023, and the second track addresses the wildfire memorandum accounts with
a decision expected in the second quarter of 2024.
Deferral Accounting Treatment for Wildfire Liability
In June 2023, PacifiCorp filed deferral applications with its state commissions in all six states to track the costs associated with
third-party liability from litigation due to the 2020 Wildfires. The deferred accounting applications enable PacifiCorp to
preserve its ability to seek recovery in the future in the event the outcome could potentially impact its financial stability. The
applications state that PacifiCorp is not seeking recovery of these costs from customers at this time and does not expect to
determine if it will seek recovery until the appeals process has concluded.
MidAmerican Energy
Iowa Gas
In June 2023, MidAmerican Energy filed a request with the IUB for an increase in its Iowa retail natural gas rates, which would
increase revenue by $39 million annually. If approved, the requested rates would increase retail customer's bills by an average
of 6.1%. Interim rates of $31 million annually, or an average increase to customer's bills of 4.8%, were effective in June 2023.
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 included 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. On April 27, 2023, the IUB issued its final order regarding the application and found that
MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application, but
rejected the settlement and proposed its own principles for the project. MidAmerican Energy reviewed the order and filed a
motion for reconsideration or rehearing on May 17, 2023. On June 15, 2023, the IUB granted the motion for reconsideration
and rehearing. On July 14, 2023 the IUB issued a new procedural schedule with rehearing set to begin on October 10, 2023.
MidAmerican Energy expects the IUB to issue an order on the request for reconsideration and rehearing by the end of 2023.
44
Iowa Transmission Legislation
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and
maintain electric transmission lines that have been approved for construction in a federally registered planning authority's
transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First
Refusal, the law provides MidAmerican Energy, as an incumbent electric transmission owner, the legal right to construct, own
and maintain transmission lines in MidAmerican Energy's service territory that have been approved by the MISO (or another
federally registered planning authority) and are eligible to receive regional cost allocation. To exercise the legal right,
MidAmerican Energy must notify the IUB within 90 days of any such approval for the construction of eligible electric
transmission lines that it intends to construct, own and maintain. The law still requires an incumbent electric transmission
owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon
issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the
eligible electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to
construct the eligible electric transmission line. In October 2020, national transmission interests filed a lawsuit that challenged
the law on state constitutional grounds. The suit argues that the law was enacted in violation of the "single-subject" provision of
Iowa's state constitution because it was "log-rolled" into a late session appropriations bill and violates the equal protection
provision of the Iowa constitution. The State of Iowa defended the law, and MidAmerican Energy and ITC Midwest both
intervened and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of standing, and
the national transmission interests appealed. In June 2022, the Iowa Court of Appeals upheld the district court's decision, after
which the national transmission interests asked the Iowa Supreme Court to reconsider. In November 2022, the Iowa Supreme
Court granted the motion to reconsider. On March 24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower
courts, held the national transmission interests had standing, and remanded the case to the district court to consider the state
constitutional claims on their merits. The opinion also imposed a temporary injunction that stayed enforcement of the law
pending a decision on the merits. On April 7, 2023, the State of Iowa, acting individually, and MidAmerican Energy and ITC
Midwest, acting jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19, 2023, the national transmission
interests filed a reply that (1) expressed its opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to hold
that the injunction specifically applied to and precluded advancement of MidAmerican Energy's Long Range Transmission
Projects ("LRTP") Tranche 1 projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on the constitutional
claims on the merits without further briefing or argument. On April 26, 2023, the Iowa Supreme Court issued an order that
denied the petitions for rehearing without comment and made minor, non-substantive changes to the decision, with no changes
to the injunction. On May 30, 2023, the Iowa Supreme Court remanded the case to the district court for further proceedings on
the merits, where the national transmission interests have filed a motion for summary judgment. The State of Iowa,
MidAmerican Energy and ITC Midwest are collaborating on a resistance to the motion and the State of Iowa is preparing a
cross motion for summary judgment. A hearing on the motions for summary judgment is scheduled for September 29, 2023,
with defendants' resisting documents due on August 4, 2023, plaintiffs' documents due on September 8, 2023, and reply
documents due on September 18, 2023. To this point, MISO has taken no action to reverse or disrupt its approval of
MidAmerican Energy's LRTP Tranche 1 projects. This matter only potentially affects the manner in which MidAmerican
Energy would secure the right to construct transmission lines that are eligible for regional cost allocation and are otherwise
subject to competitive bidding under the MISO tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing
rights to construct any other transmission lines, including lines required to serve new or expanded retail load, connect new
generators or meet reliability criteria.
NV Energy (Nevada Power and Sierra Pacific)
Merger Application
In March 2022, the Nevada Utilities filed a joint application with the PUCN for authorization to merge Sierra Pacific with and
into Nevada Power, with Nevada Power being the surviving entity. If approved by the PUCN as filed, Nevada Power will have
two distinct electric service territories in northern and southern Nevada each with their own rates and one natural gas service
territory in the Reno and Sparks area. In October 2022, all parties to the proceedings relating to the joint application entered into
a Stipulation to delay the procedural schedule. The Nevada Utilities made a supplemental filing on December 30, 2022. In
March 2023, the proceedings relating to the joint application were postponed to May 2023. In April 2023, the Nevada Utilities
filed a notice with the PUCN requesting to withdraw the joint application to merge into a single corporate entity and vacate the
current procedural schedule, and executed a termination of the related merger agreement. In May 2023, the PUCN issued an
order vacating the procedural schedules and hearing.
45
Transportation Electrification Plan ("TEP")
In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of a Distributed Resource
Plan amendment to implement the state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs and schedules
to implement the TEP. The 2022 TEP outlines programs, investments and incentives to accelerate transportation electrification
across Nevada. The Nevada Utilities proposed a budget of $348 million, which represents the maximum cost over the
depreciable life of the TEP's programs and assets, to deploy the TEP in 2023 through 2024. In March 2023, the PUCN issued an
order approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on
the program management and contingency budget amounts. The unapproved programs have been deferred for approval in
future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs. In April 2023, interveners
filed a petition for reconsideration of the PUCN's March 2023 Order. In May 2023, the PUCN granted in part and denied in part
the petition for reconsideration and affirmed the March 2023 Order.
Deferred Energy Accounting Adjustment ("DEAA") Rate
In May 2023, the Nevada Utilities filed an application with the PUCN for approval to adjust the DEAA rates in excess of the
maximum allowable adjustment to provide a discounted rate to customers effective July 1, 2023. In June 2023, the Nevada
Utilities filed a stipulation signed by interveners that resolved all matters in the dockets opened for the application. In June
2023, the PUCN accepted the stipulation and granted the application as modified. The rate reduction for customers was
effective July 1, 2023.
Regulatory Rate Review
In June 2023, Nevada Power filed a regulatory rate review with the PUCN that requested an annual revenue increase of
$93 million, or 3.3%. In addition, a filing was made to revise depreciation rates based on a study, the results of which are
reflected in the proposed revenue requirements. An order is expected by the end of 2023 and, if approved, would be effective
January 1, 2024.
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 third 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.
46
Northern Natural Gas
In July 2022, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $1.3 billion. This
is an increase of $323 million above the cost of service filed in its 2019 rate case of $1.0 billion. Depreciation on increased rate
base and an increase in depreciation and negative salvage rates account for $115 million of the $323 million increase in the filed
cost of service. Northern Natural Gas has requested increases in various rates, including transportation and storage reservation
rates. In January 2023, the FERC approved Northern Natural Gas filing to implement its interim rates effective January 1, 2023,
subject to refund and the outcome of hearing procedures. In June 2023, a settlement agreement was filed with the FERC
resolving all pending issues in the rate case and providing for increased service rates and increased depreciation rates for
onshore transmission plant from 2.30% to 2.49%. Market Area transportation reservation rates increased 32.5% and storage
reservation rates increased 13.0% from the rates that were in effect in 2022. The settlement also provides for a Section 4 and
Section 5 rate action moratorium through June 30, 2024, subject to certain exceptions. The settlement rates were implemented
May 1, 2023, and the Company's provision for rate refunds for January 2023 through April 2023 totaled $88 million. FERC
approval of the settlement is expected before the end of 2023.
BHE Transmission
AltaLink
2024-2025 General Tariff Application
In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total transmission tariffs of C$902.3 million and C$908.6
million for 2024 and 2025, respectively, 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.
In July 2023, AltaLink requested the AUC to suspend the schedule for its 2024-2025 GTA until August 31, 2023. AltaLink
requires the schedule delay to amend its application. The amendment is in response to the unprecedented wildfire events that
AltaLink experienced in Alberta, Canada in May and June 2023. The AUC accepted AltaLink's request to refile its application
on August 31, 2023, and directed AltaLink to limit its application updates to its Wildfire Mitigation Plan and related wildfire
references. AltaLink plans to file an application with the AUC later this year to recover all costs incurred as a result of the
recent wildfire events.
Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the generic cost of capital proceeding. The proceeding will be conducted in two stages. The
first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based
approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with
respect to the first stage of the 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. 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 fourth quarter of 2023.
47
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.
Greenhouse Gas Standards
In May 2023, the EPA proposed rules addressing greenhouse gas emissions from new and reconstructed natural gas-fueled
combustion turbines (Clean Air Act Section 111(b) rule) and existing coal- and gas- or oil-fueled steam units and natural gas-
fueled combustion turbines (Clean Air Act Section 111(d) rule). The proposed requirements for existing units would take effect
January 1, 2030, through state implementation plans. Requirements for new combustion turbines are subcategorized based on
capacity factor, where low-load units would be required to meet an emissions limit, intermediate-load units would be required
to use a blend of low-emitting hydrogen and natural gas and base-load units would be required to utilize carbon capture and
sequestration technology or a high-percentage blend of low-emitting hydrogen. Requirements for existing gas- and oil-fueled
steam units are also subcategorized based on capacity factor, where low-load units would be subject to routine maintenance to
demonstrate no increase in emissions, intermediate-load units would be subject to an emission limit of 1,500 pounds of CO2 /
MWh-gross and base-load units would be subject to an emission limit of 1,300 pounds of CO2 / MWh-gross. Control
equipment requirements for existing combustion turbines only apply to large, high load turbines that are greater than 300MW in
capacity and operate at a greater than 50% capacity factor. These units would be required to begin utilizing carbon capture and
sequestration with a 90% capture rate by 2035 or use a blend of low-emitting hydrogen starting in 2032. Requirements for
existing coal-fueled units are subcategorized based on retirement date. Units with earlier retirement dates would be subject to
less stringent requirements while units that commit to later retirement dates would be subject to annual capacity factor limits or
natural gas co-firing requirements. Units that will continue operating after December 31, 2039, would be required to utilize
carbon capture and sequestration with a 90% carbon capture rate. Clean Air Act Section 111 establishes a cooperative approach
between the EPA and the states. The EPA establishes nationwide standards based on the best system of emissions reductions it
identifies for a source category. States are then expected to develop plans to implement those standards at affected units. States
may adopt the EPA's standards or develop state-specific standards that achieve the same air quality results. The EPA is
accepting comments on the proposal through August 8, 2023. The relevant Registrants operate facilities that may be affected by
these proposals. Until the EPA takes final action on the proposals, the states submit any required SIPs and litigation is
exhausted, the relevant Registrants cannot determine the impacts of the proposed rule.
Mercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other
hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS
became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission
standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply
with the new standards by April 16, 2015, with the potential for individual sources to obtain an extension of up to one
additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission
system reliability reasons. The relevant Registrants have completed emission reduction projects and unit retirements to comply
with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
48
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 accepted comments on the proposal through June 23, 2023. The relevant Registrants are not included
in the lignite subcategory. The relevant Registrants have identified that compliance can be achieved with existing controls. Until
the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon
monoxide, lead, NOx, particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that
achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those
that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment
area that are determined to contribute to the nonattainment are required to reduce emissions. Currently, with the exceptions
described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's
major emission sources are located are in attainment of the current NAAQS.
49
On June 4, 2018, the EPA published final ozone designations for much of the U.S. Relevant to the Registrants, these
designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern
Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These
areas were required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the
Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit
vacated several provisions of the 2018 implementing rules for the 2015 ozone standards for contravening the Clean Air Act.
The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or
disapprove the "good neighbor" provisions of interstate ozone plans of dozens of states. Relevant to the Registrants, the EPA
must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan,
Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On February 22, 2022, the EPA published a
series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the Registrants, these
states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also
proposed to approve Iowa's SIP after re-analyzing the state's data. In addition, the EPA must approve or disapprove the
interstate plans of Arizona, California, Nevada and Wyoming. On April 15, 2022 the EPA issued its final rule approving Iowa's
SIP as meeting the good neighbor provisions for the 2015 ozone standard. On May 24, 2022, the EPA proposed to disapprove
the Utah and Wyoming interstate ozone SIPs. On January 30, 2023, the EPA entered into a stipulated extension to the deadline
for action on the Wyoming SIP, setting a new deadline of December 15, 2023. The EPA explained that the extra time is needed
to fully consider updated air quality information and public comments. The EPA is also reevaluating SIPs for Tennessee and
Arizona. On February 13, 2023, the EPA published final disapproval of the 19 SIPs proposed in April 2022, setting the stage to
include those states in the federal implementation plan described under the Cross-State Air Pollution Rule. The EPA also
deferred action on the SIPs for Wyoming, Tennessee and Arizona in the final rule. Separately, on March 28, 2022, the EPA
proposed determinations as to whether certain areas have achieved levels of ground-level ozone pollution that meet the 2008
and 2015 ozone NAAQS. Relevant to Registrants, the Southern Wasatch Front in Utah and Yuma, Arizona are proposed to
have met the 2015 ozone standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch Front in Utah are
proposed to have not met the 2015 ozone standard and to be reclassified as Moderate Non-Attainment, and will have until
August 3, 2024 to meet the standard. Until the EPA takes final action on the proposal and the affected states submit any
required SIPs, the relevant Registrants cannot determine the impacts of the proposed rule.
50
Cross-State Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate
matter, from down-wind sources in the eastern U.S. to reduce emissions by implementing a plan based on a market-based cap-
and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate
transport of SO2 and NOx emissions in 27 Eastern and Midwestern states. In March 2022, the EPA released its Good Neighbor
Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015
ozone NAAQS. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key
industry regulated by the rule and will be subject to emissions allowance trading beginning in summer 2023. The final rule
shifted the maximum daily backstop rate for coal-fueled generating units, which drives the installation of new controls or
curtailment, to take effect in 2030 instead of 2027. PacifiCorp's Hunter Units 1-3 and Huntington Units 1-2, which do not have
SCR controls, are impacted by the rule. PacifiCorp's 2023 IRP selected the installation of SNCR on the Hunter and Huntington
Units by 2026 as part of the preferred portfolio. The level of NOx allowances for the Utah units remains similar to 2021 levels,
with significant reductions for the coal units beginning in 2026. The daily limit, which takes effect in 2030, will further restrict
operation of coal-fueled units without SCR. NV Energy's fossil-fueled units are also covered by the final rule. North Valmy
Units 1 and 2, which do not have SCR, will require additional controls or reduced operations during the ozone season if
operated beyond 2025. Nevada's regional haze SIP has an enforceable retirement date for North Valmy Units 1 and 2 of
December 31, 2028, and NV Energy's IRP identified a December 31, 2025, retirement date for the units. The EPA's updated
modeling suggests that Arizona, Iowa and Kansas may be significantly contributing to nonattainment in downwind states. The
EPA intends to undertake additional assessment of its modeling for these states and will determine if it is necessary to address
obligations for these states in future actions. The EPA also deferred final action for Wyoming, pending further review of
updated air quality and contribution modeling and analysis. Additional notice and comment rulemaking, such as a supplemental
rule, would be required to rescind Iowa's approved SIP and incorporate additional states into the program. The states of Nevada,
Utah and Wyoming challenged the EPA's denials and deferral, respectively, of their interstate ozone transport SIPs in the Ninth,
Tenth and D.C. Circuit Courts of Appeals. PacifiCorp also filed petitions with the court opposing the EPA's action in Utah and
Wyoming. At the time of filing, at least 11 other states have challenged the EPA's action to disapprove SIPs in different
regional federal courts of appeal. Stays have been granted by four circuit courts for SIP disapprovals in eight states. Relevant to
Registrants, the states of Nevada, Texas and Utah were granted stays. The final good neighbor rule was published June 5, 2023
and takes effect August 4, 2023. The EPA issued an interim final rule stating that the federal rule will not take effect in states in
which the SIP disapprovals have been deferred or stayed. In addition to litigation over SIP disapprovals, there are numerous
appeals of the final good neighbor rule pending in four different circuit courts, and at least four motions to stay the final rule
have been filed in three different circuit courts. Additional appeals may be filed prior to the rule's August 4, 2023, effective
date. Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants
cannot be determined.
For the first time, the EPA included additional sectors beyond the electric generation sector in the 2023 expanded CSAPR
program. Relevant to the Registrants, this includes the pipeline transportation of natural gas. Requirements for that sector focus
on emissions reductions from reciprocating internal combustion engines involved in the transport of natural gas and take effect
in 2026. There is no access to allowance trading for the non-electric generation sectors. The EPA excluded emergency engines
and engines that do not operate during the ozone season, included a facility-wide averaging plan and eased requirements for
monitoring in the final rule. Northern Natural Gas operates 18 affected units; BHE GT&S operates 157 affected units; and Kern
River is not affected by the final rule.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in
designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming,
Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the
Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit periodic SIPs that address
emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility
requirements in Class I areas by 2064.
51
In June 2019, the state of Utah incorporated a BART alternative into its SIP for regional haze planning period one. The BART
alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the
requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA approved the SIP
revision with the BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of
SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. On January 19, 2021, Heal Utah, National Parks
Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah
Regional Haze SIP Alternative in the Tenth Circuit. The EPA defended the SIP, and PacifiCorp and the state of Utah intervened
in the litigation in support of the EPA. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. A final decision from
the court is expected by fall 2023.
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 other parts of 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 was held
May 16, 2023. PacifiCorp argued that the Naughton claims are moot but that a court ruling on the Wyodak claims is necessary
because the EPA's federal plan complies with the Clean Air Act. A final decision from the court is expected by late fall 2023.
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.
The state of Colorado first planning period regional haze SIP requires SCR equipment at Craig Unit 2 and Hayden Units 1 and
2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are in-service. In addition, in
February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which
PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of
Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to
the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to
remove the unit from coal-fueled service by August 31, 2021, with an option to convert the unit to natural gas by August 31,
2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December
2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp
identified a December 31, 2025, retirement date for Craig Unit 1 in its 2023 IRP.
52
Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA and
received completeness determinations in August 2022. The EPA is required to make final determinations on the SIPs by August
2023. On August 25, 2022, the EPA promulgated a finding of failure to submit a SIP for the regional haze second planning
period for 15 states, including Iowa. The finding establishes a two-year deadline for the agency to promulgate FIPs to address
the requirements, unless prior to promulgating a FIP, the state submits, and the agency approves, a SIP meeting the
requirements. The finding says the agency intends to continue to work with states in developing approvable SIP submittals in a
timely manner. The Iowa Department of Natural Resources continues to work with the EPA on development of its SIP. On
February 13, 2023, Iowa issued a draft SIP and accepted comment on the draft plan through March 16, 2023. Iowa proposes to
require operational improvements to existing control equipment at MidAmerican Energy's Louisa Generation Station and
Walter Scott Jr. Energy Center - Unit 3. Iowa anticipates submitting a final plan to the EPA in fall 2023.
Water Quality Standards
In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating
sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion
residual leachate and non-chemical metal cleaning wastes. In November 2019, the EPA proposed updates to the 2015 rule,
specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule took effect in December
2020. The final rule changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport
water, revises the voluntary incentives program for flue gas desulfurization wastewater, and adds subcategories for high-flow
units, low utilization units, and those that will transition away from coal combustion by 2028. While most of the issues raised
by this rule are already being addressed through the CCR rule and are not expected to impose significant additional
requirements, the Dave Johnston generating facility is impacted by the rule's bottom ash handling requirements at Units 1 and 2.
The generating facility submitted notice to the Wyoming Department of Environmental Quality that it will either achieve a
cessation of coal combustion at Units 1 and 2 by December 31, 2028, or install bottom ash transport treatment technology by
December 31, 2025. On March 8, 2023, the EPA proposed additional changes to the effluent limitations guidelines to replace
the 2020 rule and provide stricter limits for bottom ash transport water, flue gas desulfurization wastewater and coal
combustion residual leachate. The relevant Registrants use a combination of zero discharge, enrollment in cessation-of-coal
subcategory and dry bottom ash handling to manage the affected wastestreams. As a result, significant impacts are not
anticipated. However, until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined. The
EPA accepted public comments through May 30, 2023, and intends to finalize a rule by spring 2024.
In March 2023, the latest changes to the definition of "waters of the U.S.," a rule that determines which waters are regulated
under the federal Clean Water Act, took effect. Under this rule, tributaries, many wetlands, intrastate lakes, intrastate ponds,
intrastate streams and some impoundments must meet either test from the 2006 Rapanos plurality decision to be considered a
water of the U.S. That is, a water must be relatively permanent and have a continuous surface connection to an included
waterbody (the "relatively permanent" test) or it must significantly affect the biological, physical or chemical integrity of a
traditional navigable water, territorial seas or interstate waters (the "significant nexus" test). The rule was challenged in multiple
courts. On May 23, 2023, the U.S. Supreme Court issued a decision in Sackett v. EPA, a case that challenged the Clean Water
Act's applicability to certain wetlands. In its decision, the Court significantly narrowed protections for wetlands and intermittent
streams under the federal Clean Water Act. The Court unanimously rejected the significant nexus test as unworkable. A divided
Court determined that jurisdiction applies to waters that are adjacent to traditional interstate navigable waters and that have a
continuous surface connection with that traditional interstate navigable waters. In light of the Sackett decision, the EPA secured
stays of litigation over its definitional rule in two of three pending challenges in order to conduct rulemaking to conform to the
Court's decision. The EPA sent a new final definition rule to the White House Office of Management and Budget on July 17,
2023, and has stated it intends to issue the new rule by September 1, 2023.
Coal Ash Disposal
In April 2015, the EPA released a final rule to regulate the management and disposal of coal combustion residuals (CCR) under
the RCRA. The rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes
minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for
coal combustion byproducts will need to be closed unless they can meet the more stringent regulatory requirements.
53
At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that
contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and
three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to
the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface
impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single
impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At
the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four
landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy
closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface
impoundments were closed on or before December 21, 2017, and the sixth is undergoing closure. At the time the rule was
published in April 2015, the Nevada Utilities operated 10 evaporative surface impoundments and two landfills that contained
coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the
surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two
surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.
Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit, resulting in settlement of some of the
issues and subsequent regulatory action by the EPA. The EPA finalized the first phase of the CCR rule amendments in July
2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater
performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of
unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location
restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or
remand this deadline extension, on March 13, 2019, the D.C. Circuit granted the EPA's request to remand the rule and left the
October 31, 2020, deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating
closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in
response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 rule
has not been finalized. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of
2016. The federal permit rule has not been finalized.
In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking
comment on and information related to issues relevant to development of regulations for legacy impoundments. On May 18,
2023, the EPA proposed the legacy surface impoundments rule and accepted comment on the proposal through July 17, 2023.
The proposal encompasses legacy surface impoundments, which are inactive surface impoundments at inactive facilities; and
CCR management units, which include CCR surface impoundments and landfills that closed prior to October 19, 2015, inactive
CCR landfills, and other areas where CCR has been or is managed directly on the land. CCR management units include all units
meeting that definition at active CCR facilities, as well as those at inactive facilities with one or more legacy surface
impoundment. EPA proposes the impose substantially the same regulatory obligations for both legacy surface impoundments
and CCR management units as are applicable to currently regulated units, including groundwater monitoring and corrective
action. All legacy surface impoundments and CCR management units would be required to initiate closure, including reclosure,
within one year after the rule is finalized. The EPA has indicated it intends to finalize the legacy surface impoundment rule by
spring 2024.
The EPA includes lists of potential legacy surface impoundments and CCR management units in the rulemaking docket and
those lists include several BHE facilities. The EPA also specifically identifies PacifiCorp's Huntington Power Plant and NV
Energy's Reid Gardner Generating Station as potential CCR management unit damage cases based on the EPA's review of
compliance information. BHE corrected the record in comments that: (1) The north and south ash ponds at MidAmerican's
Riverside Generating Station are incorrectly classified as legacy impoundments rather than CCR management units; (2)
historical impoundments, which were closed according to state requirements and no longer contain CCR or liquids, should be
removed from the list of CCR management units; (3) the EPA erroneously identified NV Energy's Reid Gardner Generating
Station and the Old Landfill at PacifiCorp's Huntington generating facility as potential damage cases; and (4) two
impoundments at PacifiCorp's former Carbon generating facility are incorrectly included on the list of legacy impoundments
because PacifiCorp never managed or disposed of CCR materials in wastewater ponds at the former Carbon generating facility.
Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.
54
In August 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule"). This proposal addressed the
D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule
established a new deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure. The Part A rule
also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure
by October 15, 2023; and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and complete
ash pond closure activities by October 17, 2028. PacifiCorp developed a demonstration for the development of alternative
capacity for the Jim Bridger facility's FGD Pond 2 and a demonstration for closure of the Naughton facility and ash pond and
submitted them to the EPA in November 2020. On January 11, 2022, the EPA deemed these submittals complete but has not
taken additional action on them. No other Registrants used the provisions of the Part A rule.
Notwithstanding the status of the final CCR rule, citizens' suits have been filed against regulated entities seeking judicial relief
for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been
successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately
released or connected to surface water. In addition, actions have been filed against regulated entities seeking to require that
surface impoundments containing CCR be subject to closure by removal rather than being allowed to effectuate closure in place
as provided under the final rule. The Registrants are not a party to these lawsuits and until they are resolved, the Registrants
cannot predict the impact on overall compliance obligations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be
settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates
involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will
likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the
accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets, pension and other
postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's
critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2022.
There have been no significant changes in the Company's assumptions regarding critical accounting estimates since
December 31, 2022.
55
PacifiCorp and its subsidiaries
Consolidated Financial Section
56
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
June 30, 2023, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and
six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022,
and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of
any material modifications that should be made to the accompanying interim financial information for it to be in conformity
with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2022, and the related consolidated
statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not
presented herein); and in our report dated February 24, 2023, we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of
December 31, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been
derived.
Basis for Review Results
This interim financial information is the responsibility of PacifiCorp's management. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists
principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.
It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which
is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an
opinion.
/s/ Deloitte & Touche LLP

Portland, Oregon
August 4, 2023
57
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
ASSETS
Current assets:
Cash and cash equivalents $ 586 $ 641
Trade receivables, net 736 825
Other receivables, net 63 72
Inventories 533 474
Derivative contracts 51 184
Regulatory assets 374 275
Other current assets 112 213
Total current assets 2,455 2,684

Property, plant and equipment, net 25,488 24,430
Regulatory assets 1,745 1,605
Other assets 864 686

Total assets $ 30,552 $ 29,405
The accompanying notes are an integral part of these consolidated financial statements.
58
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 1,036 $ 1,049
Accrued interest 145 128
Accrued property, income and other taxes 161 67
Accrued employee expenses 101 86
Current portion of long-term debt 565 449
Regulatory liabilities 99 96
Other current liabilities 335 271
Total current liabilities 2,442 2,146

Long-term debt 9,984 9,217
Regulatory liabilities 2,587 2,843
Deferred income taxes 3,136 3,152
Other long-term liabilities 1,976 1,306
Total liabilities 20,125 18,664

Commitments and contingencies (Note 9)

Shareholders' equity:
Preferred stock 2 2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding — —
Additional paid-in capital 4,479 4,479
Retained earnings 5,955 6,269
Accumulated other comprehensive loss, net (9) (9)
Total shareholders' equity 10,427 10,741

Total liabilities and shareholders' equity $ 30,552 $ 29,405
The accompanying notes are an integral part of these consolidated financial statements.
59
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022

Operating revenue $ 1,327 $ 1,314 $ 2,811 $ 2,611

Operating expenses:
Cost of fuel and energy 462 451 1,076 916
Operations and maintenance 403 375 1,108 652
Depreciation and amortization 279 279 558 559
Property and other taxes 52 51 105 110
Total operating expenses 1,196 1,156 2,847 2,237

Operating income (loss) 131 158 (36) 374

Other income (expense):
Interest expense (134) (107) (258) (213)
Allowance for borrowed funds 16 6 29 12
Allowance for equity funds 34 15 61 28
Interest and dividend income 26 7 45 14
Other, net 3 (5) 5 (9)
Total other income (expense) (55) (84) (118) (168)

Income (loss) before income tax expense (benefit) 76 74 (154) 206
Income tax expense (benefit) (30) (8) (140) (6)
Net income (loss)$ 106 $ 82 $ (14) $ 212
The accompanying notes are an integral part of these consolidated financial statements.
60
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)
(Amounts in millions)
Accumulated
Additional Other Total
Preferred Common Paid-in Retained Comprehensive Shareholders'
Stock Stock Capital Earnings Loss, Net Equity

Balance, March 31, 2022 $ 2 $ — $ 4,479 $ 5,579 $ (16) $ 10,044
Net income — — — 82 — 82
Common stock dividends declared — — — (100) — (100)
Balance, June 30, 2022 $ 2 $ — $ 4,479 $ 5,561 $ (16) $ 10,026
Balance, December 31, 2021 $ 2 $ — $ 4,479 $ 5,449 $ (17) $ 9,913
Net income — — — 212 — 212
Other comprehensive income — — — — 1 1
Common stock dividends declared — — — (100) — (100)
Balance, June 30, 2022 $ 2 $ — $ 4,479 $ 5,561 $ (16) $ 10,026

Balance, March 31, 2023 $ 2 $ — $ 4,479 $ 5,849 $ (9) $ 10,321
Net income — — — 106 — 106
Balance, June 30, 2023 $ 2 $ — $ 4,479 $ 5,955 $ (9) $ 10,427
Balance, December 31, 2022 $ 2 $ — $ 4,479 $ 6,269 $ (9) $ 10,741
Net loss — — — (14) — (14)
Common stock dividends declared — — — (300) — (300)
Balance, June 30, 2023 $ 2 $ — $ 4,479 $ 5,955 $ (9) $ 10,427
The accompanying notes are an integral part of these consolidated financial statements.
61
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods
Ended June 30,
2023 2022
Cash flows from operating activities:
Net (loss) income $ (14) $ 212
Adjustments to reconcile net (loss) income to net cash flows from operating activities:
Depreciation and amortization 558 559
Allowance for equity funds (61) (28)
Net power cost deferrals (255) (62)
Amortization of net power cost deferrals 71 27
Other changes in regulatory assets and liabilities (54) (41)
Deferred income taxes and amortization of investment tax credits (68) 29
Other, net (2) 12
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets 113 17
Inventories (59) (16)
Derivative collateral, net (90) 69
Accrued property, income and other taxes, net 161 152
Accounts payable and other liabilities 216 219
Wildfires insurance receivable (133) (161)
Wildfires liability 524 225
Net cash flows from operating activities 907 1,213

Cash flows from investing activities:
Capital expenditures (1,529) (894)
Other, net — 6
Net cash flows from investing activities (1,529) (888)

Cash flows from financing activities:
Proceeds from long-term debt 1,189 —
Repayments of long-term debt (309) (9)
Dividends paid (300) (100)
Other, net (3) (2)
Net cash flows from financing activities 577 (111)

Net change in cash and cash equivalents and restricted cash and cash equivalents (45) 214
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 674 186
Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 629 $ 400

The accompanying notes are an integral part of these consolidated financial statements.
62
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
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").
The 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 June 30, 2023, and for the three-
and six-month periods ended June 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income (Loss) have
been omitted as net income (loss) materially equals comprehensive income (loss) for the three- and six-month periods ended
June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended June 30, 2023, are not necessarily
indicative of the results to be expected for the full year.
The 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
six-month period ended June 30, 2023, other than the updates associated with PacifiCorp's estimates of loss contingencies
related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and the 2022 McKinney fire as discussed
in Note 9.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a
maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by
legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially
of funds representing vendor retention, nuclear decommissioning and custodial funds. A 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):
As of
June 30,December 31,
2023 2022
Cash and cash equivalents $ 586 $ 641
Restricted cash and cash equivalents included in other current assets 9 7
Restricted cash included in other assets 34 26
Total cash and cash equivalents and restricted cash and cash equivalents $ 629 $ 674
63
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of
June 30,December 31,
Depreciable Life 2023 2022
Utility plant:
Generation 15 - 59 years $ 13,766 $ 13,726
Transmission 60 - 90 years 8,096 8,051
Distribution 20 - 75 years 8,689 8,477
Intangible plant(1) and other 5 - 75 years 2,783 2,755
Utility plant in-service 33,334 33,009
Accumulated depreciation and amortization (11,446) (11,093)
Utility plant in-service, net 21,888 21,916
Nonregulated, net of accumulated depreciation and amortization 14 - 95 years 18 18
21,906 21,934
Construction work-in-progress 3,582 2,496
Property, plant and equipment, net $ 25,488 $ 24,430
(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
(4) Recent Financing Transactions
Long-Term Debt
In May 2023, PacifiCorp issued $1.2 billion of its 5.50% First Mortgage Bonds due May 2054. PacifiCorp intends, within 24
months of the issuance date, to allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or
existing investments or expenditures made in one or more eligible projects in alignment with BHE's Green Financing
Framework.
Credit Facilities
In June 2023, PacifiCorp amended its existing $1.2 billion unsecured credit facility expiring in June 2025. The amendment
increased the lender commitment to $2.0 billion and extended the expiration date to June 2026. Additionally, in June 2023,
PacifiCorp terminated its existing $800 million 364-day unsecured credit facility expiring in January 2024.
Common Shareholders' Equity
In January 2023, PacifiCorp declared a common stock dividend of $300 million, paid in February 2023, to PPW Holdings LLC.
64
(5) Income Taxes
The effective income tax rate for the six-month period ended June 30, 2023 of 91% results from a $140 million income tax
benefit associated with a $154 million pre-tax loss primarily resulting from the $408 million pre-tax loss associated with the
2020 Wildfires described in Note 9. The $140 million income tax benefit is primarily comprised of a $32 million benefit (21%)
from the application of the federal statutory income tax rate to the pre-tax loss, a $55 million benefit (36%) from federal income
tax credits and a $34 million benefit (22%) from effects of ratemaking.
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:
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Federal statutory income tax rate 21 % 21 % 21 % 21 %
State income tax, net of federal income tax benefit 2 4 4 3
Federal income tax credits (34) (25) 36 (21)
Effects of ratemaking(1) (26) (13) 22 (11)
Valuation allowance — — 7 4
Other (2) 2 1 1
Effective income tax rate (39) % (11) % 91 % (3) %
(1)Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
Income tax credits relate primarily to production tax credits ("PTC") from PacifiCorp's wind-powered generating facilities.
Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and
sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating
facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs
recognized for the three-month periods ended June 30, 2023 and 2022, totaled $26 million and $18 million, respectively. PTCs
recognized for the six-month periods ended June 30, 2023 and 2022, totaled $55 million and $44 million, respectively.
For the six-month period ended June 30, 2023, PacifiCorp released an $11 million valuation allowance related to state net
operating loss carryforwards. For the six-month period ended June 30, 2022, PacifiCorp recorded an $8 million valuation
allowance related to state net operating loss carryforwards.
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established
regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and
substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the six-month
periods ended June 30, 2023 and 2022, PacifiCorp received net cash payments for federal and state income tax from BHE
totaling $205 million and $150 million, respectively. As of June 30, 2023, net income taxes payable to BHE were $55 million.
As of December 31, 2022, net income taxes receivable from BHE were $84 million.
65
(6)Employee Benefit Plans
Net periodic benefit cost (credit) for the pension and other postretirement benefit plans included the following components
(in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Pension:
Interest cost $ 9 $ 7 $ 19 $ 14
Expected return on plan assets (12) (11) (24) (21)
Net amortization 3 4 6 8
Net periodic benefit cost $ — $ — $ 1 $ 1
Other postretirement:
Service cost $ 1 $ 1 $ 1 $ 1
Interest cost 2 2 5 4
Expected return on plan assets (4) (3) (7) (5)
Net amortization — — (1) —
Net periodic benefit credit $ (1) $ — $ (2) $ —
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 $4 million and $— million, respectively, during 2023. As of June 30, 2023, $2 million of contributions had been
made to the pension plans.
(7)Risk Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally
exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in
its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions.
Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale
electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted
by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage,
and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances.
PacifiCorp does not engage in a material amount of proprietary trading activities.
PacifiCorp has established a risk management process that is designed to identify, assess, manage and report on each of the
various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity
derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future
supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to
variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest
rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or
locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods
presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion
to changes in market prices. Refer to Note 8 for additional information on derivative contracts.
66
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):
Derivative
Contracts -Other Other
Current Other Current Long-term
Assets Assets Liabilities Liabilities Total
As of June 30, 2023
Not designated as hedging contracts(1):
Commodity assets $ 57 $ — $ 6 $ 5 $ 68
Commodity liabilities (6) — (36) (17) (59)
Total 51 — (30) (12) 9

Total derivatives 51 — (30) (12) 9
Cash collateral receivable (payable) — — — — —
Total derivatives - net basis $ 51 $ — $ (30) $ (12) $ 9
As of December 31, 2022
Not designated as hedging contracts(1):
Commodity assets $ 279 $ 27 $ 9 $ 3 $ 318
Commodity liabilities (22) (7) (14) (5) (48)
Total 257 20 (5) (2) 270

Total derivatives 257 20 (5) (2) 270
Cash collateral payable(2) (73) (5) — — (78)
Total derivatives - net basis $ 184 $ 15 $ (5) $ (2) $ 192
(1)PacifiCorp's commodity derivatives are generally included in rates. As of June 30, 2023, a regulatory liability of $9 million was recorded related to
the net derivative asset of $9 million. As of December 31, 2022, a regulatory liability of $270 million was recorded related to the net derivative asset
of $270 million.
(2)As of December 31, 2022, PacifiCorp had an additional $12 million cash collateral payable that was not required to be netted against total
derivatives.
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):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Beginning balance $ (109) $ (195) $ (270) $ (53)
Changes in fair value recognized in regulatory (liabilities) assets 102 (49) 92 (217)
Net losses reclassified to operating revenue (2) (8) (8) (11)
Net gains reclassified to energy costs — 29 177 58
Ending balance $ (9) $ (223) $ (9) $ (223)
67
Derivative Contract Volumes
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 June 30,December 31,
Measure 2023 2022
Electricity purchases, net Megawatt hours 2 2
Natural gas purchases Decatherms 145 127
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other
utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to
the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect
relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each
significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and
evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit
risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting
agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under
these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support
provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more
of the recognized credit rating agencies. These agreements may provide bilateral rights to demand cash or other security if
credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features").
These agreements and other agreements that do not refer to specified rating-dependent threshold levels may provide the right
for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These
rights can vary by contract and by counterparty. As of June 30, 2023, PacifiCorp's issuer credit ratings for its senior secured
debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent
features totaled $58 million and $48 million as of June 30, 2023 and December 31, 2022, respectively, for which PacifiCorp
had posted collateral of $— 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 June 30, 2023 and December 31, 2022, PacifiCorp would have been
required to post $35 million and $3 million, respectively, of additional collateral. PacifiCorp's collateral requirements could
fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other
factors.
(8) Fair 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).
68
•Level 3 — Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in
pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best
information available, including its own data.
The following table presents PacifiCorp's financial assets and liabilities recognized on the Consolidated Balance Sheets and
measured at fair value on a recurring basis (in millions):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Other(1) Total
As of June 30, 2023:
Assets:
Commodity derivatives $ — $ 68 $ — $ (17) $ 51
Money market mutual funds 598 — — — 598
Investment funds 29 — — — 29
$ 627 $ 68 $ — $ (17) $ 678
Liabilities - Commodity derivatives $ — $ (59) $ — $ 17 $ (42)
As of December 31, 2022:
Assets:
Commodity derivatives $ — $ 318 $ — $ (119) $ 199
Money market mutual funds 649 — — — 649
Investment funds 23 — — — 23
$ 672 $ 318 $ — $ (119) $ 871
Liabilities - Commodity derivatives $ — $ (48) $ — $ 41 $ (7)
(1)Represents netting under master netting arrangements and a net cash collateral of $— million and a net cash collateral payable of $78 million as of
June 30, 2023 and December 31, 2022, respectively. As of December 31, 2022, PacifiCorp had an additional $12 million cash collateral payable that
was not required to be netted against total derivatives.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated
fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. A
discounted cash flow valuation method was used to estimate fair value. When available, the fair value of derivative contracts is
estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted
prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent
PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates.
PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and
commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent
energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp.
Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first
three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes.
Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years.
Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp
uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are
based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward
commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer
to Note 7 for further discussion regarding PacifiCorp's risk management and hedging activities.
PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value. When available,
PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record
the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined
using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar
characteristics.
69
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):
As of June 30, 2023 As of December 31, 2022
Carrying Fair Carrying Fair
Value Value Value Value

Long-term debt $ 10,549 $ 9,406 $ 9,666 $ 9,045
(9) Commitments and Contingencies
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Consolidated Balance Sheets.
Construction Commitments
During the six-month period ended June 30, 2023, PacifiCorp entered into build transfer agreements totaling $1.2 billion
through 2025 for the construction of certain wind-powered generating facilities in Wyoming.
Fuel Contracts
During the six-month period ended June 30, 2023, PacifiCorp entered into certain coal supply agreements totaling $425 million
through 2025.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions
performance standards, water quality, coal ash disposal, wildfire prevention and mitigation and other environmental matters that
have the potential to impact its current and future operations. PacifiCorp believes it is in material compliance with all applicable
laws and regulations.
Lower Klamath Hydroelectric Project
In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower
Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and
California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no
longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance
agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility began in June 2023, and
removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has
$450 million in funding available for dam removal and restoration; $200 million collected from PacifiCorp's Oregon and
California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share
cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to
equally fund an initial $45 million contingency fund and equally share any additional costs above that amount to ensure dam
removal and restoration is complete.
Legal Matters
PacifiCorp is party to a variety of legal actions, including litigation, arising out of the normal course of business, some of which
assert claims for damages in substantial amounts and are described below. For certain legal actions, parties at times may seek to
impose fines, penalties and other costs.
70
Wildfires Overview
A provision for a loss contingency is recorded when it is probable 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.
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 500,000 acres in aggregate. Third-party reports for these wildfires indicate over 2,000 structures
destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities.
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 on behalf of plaintiffs related to the 2020 Wildfires have been filed in Oregon
and California, including a class action complaint in Oregon for which the jury issued a verdict for the 17 named plaintiffs in
June 2023 as described below. The plaintiffs seek damages for economic losses, noneconomic losses, including mental
suffering, emotional distress, personal injury and loss of life, punitive damages, other damages and attorneys' fees. Several
insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the
aforementioned lawsuits. Additionally, certain governmental agencies have informed PacifiCorp that they are contemplating
filing actions in connection with certain of the Oregon 2020 Wildfires. Amounts sought in the lawsuits, complaints and
demands filed in Oregon total over $7 billion, excluding any doubling or trebling of damages included in the complaints.
Generally, the complaints filed in California do not specify damages sought and are not included in this amount. Final
determinations of liability will only be made following the completion of comprehensive investigations, litigation or similar
processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial
condition.
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et
al, in Multnomah County Circuit Court, Oregon (the "James case"). The complaint was filed by Oregon residents and
businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed
beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed
an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain
Complex, South Obenchain and Two Four Two wildfires. In May 2022, the Multnomah County Circuit Court granted issue
class certification and consolidated the James case with several other cases. While PacifiCorp requested an immediate appeal of
the issue class certification, the Oregon Court of Appeals denied the request. In April 2023, the jury trial for the James case
with respect to 17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding
PacifiCorp liable to the 17 individual plaintiffs and to the class with respect to the four wildfires. The jury awarded the 17
named plaintiffs $90 million of damages, including $4 million of economic and property damages, $68 million of noneconomic
damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages. No
judgment has been entered by the Multnomah County Circuit Court and no determination has been made as to the timing,
process and procedures that will be used to adjudicate individual class member damages. PacifiCorp intends to vigorously
appeal the jury's findings and damage awards, including whether the case can proceed as a class action. The appeals process and
further actions could take several years.
71
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of the verdict
in the James case with respect to the 17 named plaintiffs, other litigation and recent settlements, PacifiCorp has accrued
cumulative estimated probable losses associated with the 2020 Wildfires of $1,018 million through June 30, 2023. PacifiCorp's
cumulative accrual includes estimates of probable 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 material additional losses beyond the amounts accrued that could have a material
adverse effect on PacifiCorp's financial condition; however, PacifiCorp is currently unable to reasonably estimate the range of
possible additional losses that could be incurred due to the number of properties and parties involved, including claimants in the
class to the James case, the variation in those types of properties and lack of available details and the ultimate outcome of legal
actions.
The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires
(in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Beginning balance $ 824 $ 252 $ 424 $ 252
Accrued losses 141 225 541 225
Payments (17) — (17) —
Ending balance $ 948 $ 477 $ 948 $ 477
PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $379 million and
$246 million, respectively, as of June 30, 2023 and December 31, 2022. During the three- and six-month periods ended June 30,
2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of
$49 million and $408 million, respectively. During the three- and six-month periods ended June 30, 2022, PacifiCorp
recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $64 million and
$64 million, respectively. The net losses are included in operations and maintenance on the Consolidated Statements of
Operations. No additional insurance recoveries beyond those accrued to date are expected to be available for the
2020 Wildfires.
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 $31 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 $103 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 for economic losses, noneconomic losses, including mental suffering, emotional distress,
personal injury and loss of life, punitive damages, other damages and attorneys' fees, but the amount of damages sought is not
specified. Final determinations of liability, however, will only be made following the completion of comprehensive
investigations and litigation processes.
72
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) Revenue from Contracts with Customers
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):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Customer Revenue:
Retail:
Residential $ 450 $ 417 $ 1,035 $ 922
Commercial 429 393 859 763
Industrial 270 277 560 550
Other retail 83 80 127 117
Total retail 1,232 1,167 2,581 2,352
Wholesale 26 55 87 110
Transmission 34 45 72 77
Other Customer Revenue 24 28 56 48
Total Customer Revenue 1,316 1,295 2,796 2,587
Other revenue 11 19 15 24
Total operating revenue $ 1,327 $ 1,314 $ 2,811 $ 2,611
73
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 Second Quarter and First Six Months of 2023 and 2022
Overview
Net income for the second quarter of 2023 was $106 million, an increase of $24 million compared to 2022 net income of
$82 million. The increase in net income was primarily due to lower other expense and higher income tax benefit, partially offset
by increased operations and maintenance expense primarily driven by higher wildfire mitigation costs and legal fees. Utility
margin was relatively flat at $2 million favorable primarily due to higher retail prices, lower coal-fueled generation volumes,
higher net power costs deferrals and lower natural gas-fueled generation prices, partially offset by higher purchased electricity
costs from higher volumes and prices, lower wholesale volumes, higher coal-fueled generation prices, lower retail volumes,
lower wheeling revenue and higher natural gas-fueled generation volumes. Retail customer volumes decreased 2.2%, primarily
due to lower customer usage, partially offset by an increase in the average number of customers. Energy generated decreased
22% for the second quarter of 2023 compared to 2022 primarily due to lower coal-fueled and wind-powered generation
volumes, partially offset by higher natural gas-fueled and hydroelectric generation volumes. Wholesale electricity sales
volumes decreased 52% and purchased electricity volumes increased 45%.
Net loss for the first six months of 2023 was $14 million, a decrease of $226 million compared to 2022 net income of
$212 million. The decrease in net income was primarily due to increased operations and maintenance expense largely due to an
increase to estimated losses associated with the 2020 Wildfires, net of expected insurance recoveries, partially offset by higher
income tax benefit, lower other expense and higher utility margin. Utility margin increased primarily due to higher retail prices
and volumes, higher net power cost deferrals, lower coal-fueled generation volumes and higher average wholesale market
prices, partially offset by higher purchased electricity costs from higher volumes and prices, higher natural gas-fueled
generation costs from higher prices and volumes, lower wholesale volumes and higher coal-fueled generation prices. Retail
customer volumes increased 0.6%, primarily due to favorable impacts of weather, higher commercial and residential customer
usage and an increase in the average number of customers, partially offset by lower industrial and irrigation customer usage.
Energy generated decreased 14% for the first six months of 2023 compared to 2022 primarily due to lower coal-fueled, wind-
powered and hydroelectric generation volumes, partially offset by higher natural gas-fueled volumes. Wholesale electricity
sales volumes decreased 49% and purchased electricity volumes increased 37%.
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.
74
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):
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Utility margin:
Operating revenue $ 1,327 $ 1,314 $ 13 1 %$ 2,811 $ 2,611 $ 200 8 %
Cost of fuel and energy 462 451 11 2 1,076 916 160 17
Utility margin 865 863 2 — 1,735 1,695 40 2
Operations and maintenance 403 375 28 7 1,108 652 456 70
Depreciation and amortization 279 279 — — 558 559 (1) —
Property and other taxes 52 51 1 2 105 110 (5) (5)
Operating income (loss)$ 131 $ 158 $ (27) (17) %$ (36) $ 374 $ (410) (110) %
75
Utility Margin
A comparison of key operating results related to utility margin is as follows:
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Utility margin (in millions):
Operating revenue $ 1,327 $ 1,314 $ 13 1 %$ 2,811 $ 2,611 $ 200 8 %
Cost of fuel and energy 462 451 11 2 1,076 916 160 17
Utility margin $ 865 $ 863 $ 2 — %$ 1,735 $ 1,695 $ 40 2 %
Sales (GWhs):
Residential 3,809 3,854 (45) (1) % 8,911 8,618 293 3 %
Commercial 4,794 4,633 161 3 9,777 9,183 594 6
Industrial, irrigation and other 4,444 4,849 (405) (8) 8,653 9,372 (719) (8)
Total retail 13,047 13,336 (289) (2) 27,341 27,173 168 1
Wholesale 601 1,245 (644) (52) 1,426 2,798 (1,372) (49)
Total sales 13,648 14,581 (933) (6) % 28,767 29,971 (1,204) (4) %
Average number of retail customers (in thousands) 2,065 2,033 32 2 % 2,061 2,029 32 2 %
Average revenue per MWh:
Retail $ 94.61 $ 88.14 $ 6.47 7 %$ 94.20 $ 86.77 $ 7.43 9 %
Wholesale $ 55.81 $ 51.53 $ 4.28 8 %$ 73.54 $ 44.64 $ 28.90 65 %
Heating degree days 1,314 1,736 (422) (24) % 6,519 6,481 38 1 %
Cooling degree days 456 406 50 12 % 456 411 45 11 %
Sources of energy (GWhs)(1):
Coal 3,594 6,260 (2,666) (43) % 9,149 13,171 (4,022) (31) %
Natural gas 3,108 2,747 361 13 7,063 5,862 1,201 20
Wind(2) 1,445 1,817 (372) (20) 3,528 4,209 (681) (16)
Hydroelectric and other(2) 1,111 1,033 78 8 1,923 2,017 (94) (5)
Total energy generated 9,258 11,857 (2,599) (22) 21,663 25,259 (3,596) (14)
Energy purchased 5,382 3,717 1,665 45 9,510 6,940 2,570 37
Total 14,640 15,574 (934) (6) % 31,173 32,199 (1,026) (3) %
Average cost of energy per MWh:
Energy generated(3)$ 21.20 $ 21.90 $ (0.70) (3) %$ 25.29 $ 20.27 $ 5.02 25 %
Energy purchased $ 57.49 $ 48.92 $ 8.57 18 %$ 66.27 $ 51.97 $ 14.30 28 %
(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.
76
Quarter Ended June 30, 2023 compared to Quarter Ended June 30, 2022
Utility margin increased $2 million for the second quarter of 2023 compared to 2022 primarily due to:
•$59 million increase in retail revenue due to higher average prices, partially offset by lower volumes. Retail customer
volumes decreased 2.2%, primarily due to unfavorable industrial customer usage across all states, except California,
unfavorable irrigation customer usage across all states, unfavorable Oregon residential customer usage and unfavorable Utah residential weather related impacts, partially offset by favorable Oregon, Utah and Wyoming
commercial customer usage, favorable increase in the average number of residential and commercial customers across
all states, except California, and favorable Oregon and Washington weather related impacts;
•$51 million of higher deferred net power costs net of amortization of previous deferrals in accordance with established
adjustment mechanisms;
•$35 million of lower natural gas-fueled generation costs primarily due to lower average market prices, partially offset
by higher volumes; and
•$31 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:
•$128 million of higher purchased electricity costs from higher volumes and higher average market prices;
•$31 million decrease in wholesale revenue primarily due to lower volumes, partially offset by higher average market
prices; and
•$14 million of lower other revenue primarily due to lower wheeling revenue and lower revenues associated with sales
of greenhouse gas allowances.
Operations and maintenance increased $28 million, or 7% for the second quarter of 2023 compared to 2022 primarily due to
$16 million of higher wildfire mitigation costs, including vegetation management and amortization of amounts previously
deferred in Oregon, $12 million of higher legal fees primarily related to wildfire matters, $7 million of higher demand-side
management amortization expense (offset in retail revenue), $6 million of increased bad debt expense and $4 million of higher
insurance costs related to wildfire coverage, partially offset by $15 million of lower current year accruals associated with the
2020 Wildfires, net of expected insurance recoveries, and lower plant operations and maintenance costs.
Interest expense increased $27 million, or 25%, for the second quarter of 2023 compared to 2022 primarily due to higher
average long-term debt balances.
Allowance for borrowed and equity funds increased $29 million for the second quarter of 2023 compared to 2022 primarily due
to higher qualified construction work-in-progress balances.
Interest and dividend income increased $19 million for the second quarter of 2023 compared to 2022 primarily due to the
recording of interest on higher deferred net power cost balances and higher investment income due to higher average interest
rates on temporary cash investment balances.
Other, net increased $8 million for the second 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 increased $22 million for the second quarter of 2023 compared to 2022 and the effective tax rate was (39)%
for 2023 and (11)% for 2022. The effective tax rate decreased primarily as a result of increased PTCs from PacifiCorp's wind-
powered generating facilities and a higher benefit from effects of ratemaking.
77
First Six Months of 2023 compared to First Six Months of 2022
Utility margin increased $40 million, or 2%, for the first six months of 2023 compared to 2022 primarily due to:
•$218 million increase in retail revenue due to higher average prices and volumes. Retail customer volumes increased
0.6%, primarily due to favorable Utah and Oregon commercial customer usage, favorable weather related impacts
across the western states, favorable changes in the average number of residential and commercial customers across the
service territory, mainly in Utah and Oregon, and favorable Utah residential customer usage, partially offset by
unfavorable industrial customer usage across all states, unfavorable irrigation customer usage across all states and
unfavorable Oregon residential customer usage;
•$149 million higher deferred net power costs net of amortization of previous deferrals in accordance with established
adjustment mechanisms; and
•$40 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices.
The increases above were partially offset by:
•$270 million of higher purchased electricity costs from higher volumes and higher average market prices;
•$74 million of higher natural gas-fueled generation costs due to higher average market prices and higher volumes; and
•$20 million decrease in wholesale revenue primarily due to lower volumes, partially offset by higher average market
prices.
Operations and maintenance increased $456 million, or 70%, for the first six months of 2023 compared to 2022 primarily due
to a $344 million increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires, $37 million
of higher wildfire mitigation costs, including vegetation management and amortization of amounts previously deferred in
Oregon, $16 million of higher legal fees primarily related to wildfire matters, $16 million of higher plant operations and
maintenance costs, $15 million of higher demand-side management amortization expense (offset in retail revenue), $10 million
of higher labor and benefit expenses, $6 million of increased bad debt expense and $6 million of higher insurance costs related
to wildfire coverage.
Property and other taxes decreased $5 million, or 5%, for the first six months of 2023 compared to 2022 primarily due to lower
property tax rates in Utah.
Interest expense increased $45 million, or 21%, for the first six months of 2023 compared to 2022 primarily due to higher
average long-term debt balances.
Allowance for borrowed and equity funds increased $50 million for the first six months of 2023 compared to 2022 primarily
due to higher qualified construction work-in-progress balances.
Interest and dividend income increased $31 million for the first six months of 2023 compared to 2022 primarily due to the
recording of interest on higher deferred net power cost balances and higher investment income due to higher average interest
rates on temporary cash investment balances.
Other, net increased $14 million for the first six months of 2023 compared to 2022 primarily due to higher cash surrender
values of Supplemental Executive Retirement Plan life insurance policies driven by market increases and a favorable change in
deferred compensation and long-term incentive plan primarily due to market movements (offset in operations and maintenance
expense).
Income tax benefit increased $134 million for the first six months of 2023 compared to 2022 and the effective tax rate was 91%
for 2023 and (3)% for 2022. The $134 million increase is primarily due to the increase in loss accruals, net of expected
insurance recoveries, associated with the 2020 Wildfires, higher PTCs from PacifiCorp's wind-powered generating facilities,
higher benefit from effects of ratemaking and the release of a valuation allowance on state net operating loss carryforwards in
2023 compared to the establishment of a state valuation allowance in 2022.
78
Liquidity and Capital Resources
As of June 30, 2023, PacifiCorp's total net liquidity was as follows (in millions):

Cash and cash equivalents $ 586

Credit facilities 2,000
Less:
Tax-exempt bond support and letters of credit (249)
Net credit facilities 1,751

Total net liquidity $ 2,337
Credit facilities:
Maturity dates 2026
Operating Activities
Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $907 million and
$1,213 million, respectively. The decrease is primarily due to higher wholesale and fuel purchases and collateral returned to
counterparties, partially offset by higher collections from retail customers.
The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal
income tax payment methods and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022, were $(1,529) million and
$(888) million, respectively. The change is primarily due to an increase in capital expenditures of $635 million. Refer to
"Future Uses of Cash" for discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the six-month period ended June 30, 2023, were $577 million. Sources of cash
consisted of net proceeds from the issuance of long-term debt of $1.2 billion. Uses of cash consisted primarily of $309 million
for the repayment of long-term debt and $300 million for common stock dividends paid to PPW Holdings LLC.
Net cash flows from financing activities for the six-month period ended June 30, 2022, were $(111) million. Uses of cash
consisted primarily of $100 million for common stock dividends paid to PPW Holdings LLC and $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 June 30, 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
$3.8 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp
currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds
through September 2023.
Common Shareholders' Equity
In January 2023, PacifiCorp declared a common stock dividend of $300 million, paid in February 2023, to PPW Holdings LLC.
79
Future Uses of Cash
PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash
flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured
revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for
current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which
PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors'
judgment of risk associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility
industry.
Capital Expenditures
PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and
may change significantly as a result of these reviews, which may consider, among other factors, impacts to customer rates;
changes in environmental and other rules and regulations; outcomes of regulatory proceedings, including regulatory filings for
Certificates of Public Convenience and Necessity; outcomes of legal actions associated with the 2020 Wildfires; 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):
Six-Month Periods Annual
Ended June 30,Forecast
2022 2023 2023
Wind generation $ 14 $ 373 $ 833
Electric distribution 296 421 889
Electric transmission 413 448 1,375
Solar generation — 1 21
Electric battery and pumped hydro storage 3 2 6
Other 168 284 470
Total $ 894 $ 1,529 $ 3,594
PacifiCorp has included estimates for new renewable and carbon free generation resources, conversion of certain coal-fueled
units to natural gas-fueled units, energy storage assets and associated transmission assets in its forecast capital expenditures
based on its IRP. These estimates are likely to change as a result of the associated RFP process. PacifiCorp's historical and
forecast capital expenditures include the following:
•Wind generation includes both growth projects and operating expenditures. Growth projects include construction of
new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired
from third parties totaling $366 million and $11 million for the six-month periods ended June 30, 2023 and 2022,
respectively. Planned spending for the construction of additional wind-powered generating facilities and those at
acquired sites totals $444 million for the remainder of 2023 and is primarily for the Rock Creek I and Rock Creek II
projects to be constructed in Wyoming totaling 590 MWs that are expected to be placed in-service in 2024 and 2025.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures include
spending on wildfire mitigation. Expenditures for wildfire mitigation totaled $96 million and $50 million for the six-
month periods ended June 30, 2023 and 2022, respectively. Planned spending for wildfire mitigation totals
$109 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 $313 million and $297 million for the six-month
periods ended June 30, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission
segments totals $667 million for the remainder of 2023.
80
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled
$89 million and $77 million for the six-month periods ended June 30, 2023 and 2022, respectively. Planned
information technology spending totals $119 million for the remainder of 2023. The remaining investments relate to
operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing
and expected demand.
Energy Supply Planning
As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp
can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing
and evolving environmental laws and regulations. PacifiCorp files its IRP biennially with the state commissions in each of the
six states where PacifiCorp operates. Five states indicate whether the IRP meets the state commission's IRP standards and
guidelines, a process referred to as "acknowledgment" in some states. Acknowledgment by a state commission does not address
cost recovery or prudency of resources ultimately selected.
In March 2023, PacifiCorp filed its 2023 IRP in Idaho, Oregon and Wyoming. The March 2023 filing was considered
informational in Utah. A 60-day post-filing extended comment period was added to the 2023 IRP to provide opportunity for
additional stakeholder feedback. Responsive to feedback from the extended comment period, PacifiCorp filed its 2023 IRP
(Amended Final) report on May 31, 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.
Requests for Proposals
PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands and
regulatory policy changes. The IRP and the RFPs provide for the identification and staged procurement of resources to meet
load or state-specific compliance obligations. Depending upon the specific RFP, applicable laws and regulations may require
PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may
be required depending on the nature of the RFPs.
PacifiCorp's most recent RFP, the 2022 All-Source 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 by the end of 2023 with resources contracted through the
first half of 2024. PacifiCorp may issue another or an expanded all-source RFP in connection with the 2023 IRP during the first
half of 2024.
Material Cash Requirements
As of June 30, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of
PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2022, other than those disclosed in Note 9 of the
Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Regulatory Matters
PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2
of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.
81
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions
performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact
PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and
regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive
relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. PacifiCorp
believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that
may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to
predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional
information regarding environmental laws and regulations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be
settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates
involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will
likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the
accounting for the effects of certain types of regulation, pension and other postretirement benefits, income taxes, revenue
recognition-unbilled revenue and wildfire loss contingencies. For additional discussion of PacifiCorp's critical accounting
estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2022. There have been no
significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2022. Refer to
Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for updates regarding the wildfire
loss contingency estimates.
82
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
83
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 June 30,
2023, the related statements of operations and changes in shareholder's equity for the three-month and six-month periods ended
June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30, 2023 and 2022, and the related notes
(collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material
modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting
principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2022, and the related statements of operations,
changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated
February 24, 2023, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth
in the accompanying balance sheet as of December 31, 2022, is fairly stated, in all material respects, in relation to the balance
sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of MidAmerican Energy's management. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to MidAmerican Energy in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists
principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.
It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which
is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an
opinion.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
August 4, 2023
84
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
ASSETS
Current assets:
Cash and cash equivalents $ 454 $ 258
Trade receivables, net 329 536
Income tax receivable 7 42
Inventories 320 277
Prepayments 107 91
Other current assets 30 66
Total current assets 1,247 1,270
Property, plant and equipment, net 21,145 21,091
Regulatory assets 603 550
Investments and restricted investments 980 902
Other assets 168 165
Total assets $ 24,143 $ 23,978
The accompanying notes are an integral part of these financial statements.
85
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable $ 384 $ 536
Accrued interest 83 85
Accrued property, income and other taxes 242 170
Current portion of long-term debt 253 317
Other current liabilities 133 93
Total current liabilities 1,095 1,201
Long-term debt 7,415 7,412
Regulatory liabilities 816 1,119
Deferred income taxes 3,503 3,433
Asset retirement obligations 782 683
Other long-term liabilities 508 485
Total liabilities 14,119 14,333
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding — —
Additional paid-in capital 561 561
Retained earnings 9,463 9,084
Total shareholder's equity 10,024 9,645
Total liabilities and shareholder's equity $ 24,143 $ 23,978
The accompanying notes are an integral part of these financial statements.
86
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue:
Regulated electric $ 661 $ 725 $ 1,252 $ 1,333
Regulated natural gas and other 98 172 427 569
Total operating revenue 759 897 1,679 1,902
Operating expenses:
Cost of fuel and energy 113 174 228 299
Cost of natural gas purchased for resale and other 46 120 282 418
Operations and maintenance 216 200 421 392
Depreciation and amortization 226 277 460 527
Property and other taxes 40 36 82 76
Total operating expenses 641 807 1,473 1,712
Operating income 118 90 206 190
Other income (expense):
Interest expense (81) (78) (161) (156)
Allowance for borrowed funds 4 5 8 9
Allowance for equity funds 13 14 24 29
Other, net 15 (12) 31 (15)
Total other income (expense) (49) (71) (98) (133)
Income before income tax expense (benefit) 69 19 108 57
Income tax expense (benefit) (167) (188) (370) (394)
Net income $ 236 $ 207 $ 478 $ 451
The accompanying notes are an integral part of these financial statements.
87
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions)
Common Stock
Additional Paid-in Capital RetainedEarnings
Total Shareholder'sEquity
Balance, March 31, 2022 $ — $ 561 $ 8,643 $ 9,204
Net income — — 207 207
Balance, June 30, 2022 $ — $ 561 $ 8,850 $ 9,411
Balance, December 31, 2021 $ — $ 561 $ 8,399 $ 8,960
Net income — — 451 451
Balance, June 30, 2022 $ — $ 561 $ 8,850 $ 9,411
Balance, March 31, 2023 $ — $ 561 $ 9,227 $ 9,788
Net income — — 236 236
Balance, June 30, 2023 $ — $ 561 $ 9,463 $ 10,024
Balance, December 31, 2022 $ — $ 561 $ 9,084 $ 9,645
Net income — — 478 478
Common stock dividend — — (100) (100)
Other equity transactions — — 1 1
Balance, June 30, 2023 $ — $ 561 $ 9,463 $ 10,024
The accompanying notes are an integral part of these financial statements.
88
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods
Ended June 30,
2023 2022
Cash flows from operating activities:
Net income $ 478 $ 451
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization 460 527
Amortization of utility plant to other operating expenses 16 19
Allowance for equity funds (24) (29)
Deferred income taxes and investment tax credits, net 46 58
Settlements of asset retirement obligations (15) (28)
Other, net 3 33
Changes in other operating assets and liabilities:
Trade receivables and other assets 203 2
Inventories (43) 8
Accrued property, income and other taxes, net 107 94
Accounts payable and other liabilities (106) (10)
Net cash flows from operating activities 1,125 1,125
Cash flows from investing activities:
Capital expenditures (763) (862)
Purchases of marketable securities (95) (214)
Proceeds from sales of marketable securities 81 210
Other, net 10 6
Net cash flows from investing activities (767) (860)
Cash flows from financing activities:
Common stock dividend (100) —
Repayments of long-term debt (65) —
Other, net (1) (1)
Net cash flows from financing activities (166) (1)
Net change in cash and cash equivalents and restricted cash and cash equivalents 192 264
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 268 239
Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 460 $ 503
The accompanying notes are an integral part of these financial statements.
89
MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
(1) General
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").
The 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 June 30, 2023, and for the three- and six-month periods ended June 30, 2023 and 2022.
The results of operations for the six-month period ended June 30, 2023, are not necessarily indicative of the results to be
expected for the full year.
The 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 six-month period ended June 30, 2023.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a
maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by
legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially
of funds restricted for wildlife preservation. A 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):
As of
June 30,December 31,
2023 2022
Cash and cash equivalents $ 454 $ 258
Restricted cash and cash equivalents in other current assets 6 10
Total cash and cash equivalents and restricted cash and cash equivalents $ 460 $ 268
90
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):

As of
June 30,December 31,
Depreciable Life 2023 2022
Utility plant:
Generation 20-62 years $ 18,360 $ 18,582
Transmission 55-80 years 2,730 2,662
Electric distribution 15-80 years 5,072 4,931
Natural gas distribution 30-75 years 2,186 2,144
Utility plant in-service 28,348 28,319
Accumulated depreciation and amortization (8,351) (8,024)
Utility plant in-service, net 19,997 20,295
Nonregulated property, net of accumulated depreciation and amortization 20-50 years 6 6
20,003 20,301
Construction work-in-progress 1,142 790
Property, plant and equipment, net $ 21,145 $ 21,091
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 six-month periods ended June 30, 2023 and 2022, $16 million and $96 million, respectively, is reflected in
depreciation and amortization expense on the Statement of Operations.
(4)Recent Financing Transactions
Credit Facilities
In June 2023, MidAmerican Energy amended its existing $1.5 billion unsecured credit facility expiring in June 2025. The
amendment extended the expiration date to June 2026.
(5) Income Taxes
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:
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Federal statutory income tax rate 21 % 21 % 21 % 21 %
Income tax credits (251) (973) (347) (682)
State income tax, net of federal income tax impacts (6) (26) (10) (23)
Effects of ratemaking (4) (11) (6) (9)
Other, net (2) — (1) 2
Effective income tax rate (242) % (989) % (343) % (691) %
91
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 10 years from the date the qualifying generating
facilities are placed in-service. PTCs recognized for the six-month periods ended June 30, 2023 and 2022, totaled $375 million
and $388 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its U.S. federal and Iowa state income tax returns. Consistent with
established regulatory practice, MidAmerican Energy's provision for income tax has been computed on a stand-alone basis, and
substantially all of its currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Energy
received net cash payments for income tax from BHE totaling $520 million and $541 million for the six-month periods ended
June 30, 2023 and 2022, respectively.
(6) Employee 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.
Net periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following
components (in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Pension:
Service cost $ 3 $ 4 $ 6 $ 9
Interest cost 8 5 16 10
Expected return on plan assets (8) (7) (16) (14)
Settlement — — (5) 2
Net amortization — 1 — 1
Net periodic benefit cost (credit)$ 3 $ 3 $ 1 $ 8
Other postretirement:
Service cost $ 1 $ 2 $ 2 $ 4
Interest cost 3 2 6 4
Expected return on plan assets (4) (3) (8) (7)
Net amortization — (1) — (1)
Net periodic benefit cost (credit)$ — $ — $ — $ —
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 $7 million and $2 million, respectively. As of June 30, 2023, $4 million and $1 million of contributions had been
made to the pension and other postretirement benefit plans, respectively.
92
(7) Asset 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 six-month period ended June 30, 2023, MidAmerican Energy recorded an increase of $88 million for
decommissioning its wind-generating facilities, which is a non-cash investing activity and is due to an updated
decommissioning estimate reflecting changes in the projected removal costs per turbine.
(8) Fair 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.
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):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Other(1)Total
As of June 30, 2023:
Assets:
Commodity derivatives $ 2 $ 13 $ 2 $ (8) $ 9
Money market mutual funds 460 — — — 460
Debt securities:
U.S. government obligations 233 — — — 233
International government obligations — 1 — — 1
Corporate obligations — 72 — — 72
Municipal obligations — 3 — — 3
Agency, asset and mortgage-backed obligations — 1 — — 1
Equity securities:
U.S. companies 405 — — — 405
International companies 9 — — — 9
Investment funds 22 — — — 22
$ 1,131 $ 90 $ 2 $ (8) $ 1,215
Liabilities - commodity derivatives $ — $ (20) $ (16) $ 18 $ (18)
93
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Other(1)Total
As of December 31, 2022:
Assets:
Commodity derivatives $ 1 $ 37 $ 6 $ (10) $ 34
Money market mutual funds 225 — — — 225
Debt securities:
U.S. government obligations 215 — — — 215
International government obligations — 1 — — 1
Corporate obligations — 70 — — 70
Municipal obligations — 3 — — 3
Agency, asset and mortgage-backed obligations — 1 — — 1
Equity securities:
U.S. companies 360 — — — 360
International companies 8 — — — 8
Investment funds 16 — — — 16
$ 825 $ 112 $ 6 $ (10) $ 933
Liabilities - commodity derivatives $ — $ (12) $ (1) $ 10 $ (3)
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $10 million and $— million as of June 30, 2023 and
December 31, 2022, respectively.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with
debt securities accounted for as available-for-sale securities. When available, a readily observable quoted market price or net
asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or
net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable
market inputs and quoted market prices of securities with similar characteristics.
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):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Beginning balance $ (5) $ 4 $ 5 $ (5)
Changes in fair value recognized in net regulatory assets (14) 31 (27) 44
Settlements 5 (9) 8 (13)
Ending balance $ (14) $ 26 $ (14) $ 26
94
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. The following table presents the carrying value and estimated fair value of MidAmerican
Energy's long-term debt (in millions):
As of June 30, 2023 As of December 31, 2022
Carrying
Value FairValue
Carrying
Value FairValue
Long-term debt $ 7,668 $ 6,810 $ 7,729 $ 6,964
(9) Commitments and Contingencies
Commitments
MidAmerican Energy has the following firm commitments that are not reflected on the Balance Sheets.
Construction Commitments
During the six-month period ended June 30, 2023, MidAmerican Energy entered into firm construction commitments totaling
$183 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. 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.
95
(10) Revenue from Contracts with Customers
The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line
of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's
reportable segment information included in Note 12 (in millions):
For the Three-Month Period Ended June 30, 2023 For the Six-Month Period Ended June 30, 2023
Electric Natural Gas Other Total Electric Natural Gas Other Total
Customer Revenue:
Retail:
Residential $ 173 $ 58 $ — $ 231 $ 340 $ 257 $ — $ 597
Commercial 86 17 — 103 161 95 — 256
Industrial 272 4 — 276 486 11 — 497
Natural gas transportation services — 10 — 10 — 23 — 23
Other retail 38 1 — 39 73 — — 73
Total retail 569 90 — 659 1,060 386 — 1,446
Wholesale 45 7 — 52 116 36 — 152
Multi-value transmission projects 13 — — 13 27 — — 27
Other Customer Revenue — — 1 1 — — 4 4
Total Customer Revenue 627 97 1 725 1,203 422 4 1,629
Other revenue 34 — — 34 49 1 — 50
Total operating revenue $ 661 $ 97 $ 1 $ 759 $ 1,252 $ 423 $ 4 $ 1,679
For the Three-Month Period Ended June 30, 2022 For the Six-Month Period Ended June 30, 2022
Electric Natural Gas Other Total Electric Natural Gas Other Total
Customer Revenue:
Retail:
Residential $ 185 $ 87 $ — $ 272 $ 353 $ 312 $ — $ 665
Commercial 91 31 — 122 165 119 — 284
Industrial 277 9 — 286 475 18 — 493
Natural gas transportation services — 9 — 9 — 23 — 23
Other retail 41 — — 41 73 1 — 74
Total retail 594 136 — 730 1,066 473 — 1,539
Wholesale 84 34 — 118 188 92 — 280
Multi-value transmission projects 13 — — 13 28 — — 28
Other Customer Revenue — — 1 1 — — 2 2
Total Customer Revenue 691 170 1 862 1,282 565 2 1,849
Other revenue 34 1 — 35 51 2 — 53
Total operating revenue $ 725 $ 171 $ 1 $ 897 $ 1,333 $ 567 $ 2 $ 1,902
(11) Shareholder's Equity
In January 2023, MidAmerican Energy paid $100 million in cash dividends to its parent company, MHC.
96
(12) Segment Information
MidAmerican Energy has identified two 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.
The following tables provide information on a reportable segment basis (in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue:
Regulated electric $ 661 $ 725 $ 1,252 $ 1,333
Regulated natural gas 97 171 423 567
Other 1 1 4 2
Total operating revenue $ 759 $ 897 $ 1,679 $ 1,902
Operating income:
Regulated electric $ 120 $ 87 $ 170 $ 138
Regulated natural gas (2) 3 36 52
Total operating income 118 90 206 190
Interest expense (81) (78) (161) (156)
Allowance for borrowed funds 4 5 8 9
Allowance for equity funds 13 14 24 29
Other, net 15 (12) 31 (15)
Total income before income tax expense (benefit)$ 69 $ 19 $ 108 $ 57
As of
June 30,2023 December 31,2022
Assets:
Regulated electric $ 22,425 $ 22,092
Regulated natural gas 1,717 1,885
Other 1 1
Total assets $ 24,143 $ 23,978
97
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 June 30, 2023, the related consolidated statements of operations and changes in member's
equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods
ended June 30, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on
our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial
information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the
consolidated balance sheet of MidAmerican Funding as of December 31, 2022, and the related consolidated statements of
operations, changes in member's equity, and cash flows for the year then ended (not presented herein); and in our report dated
February 24, 2023, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the
information set forth in the accompanying consolidated balance sheet as of December 31, 2022, is fairly stated, in all material
respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting
firm registered with the PCAOB and are required to be independent with respect to MidAmerican Funding in accordance with
the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our reviews in accordance with standards of the PCAOB and with auditing standards generally accepted in the
United States of America applicable to reviews of interim financial information. A review of interim financial information
consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB and with
auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion
regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
August 4, 2023
98
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
ASSETS
Current assets:
Cash and cash equivalents $ 454 $ 261
Trade receivables, net 329 536
Income tax receivable 6 43
Inventories 320 277
Prepayments 107 91
Other current assets 40 66
Total current assets 1,256 1,274
Property, plant and equipment, net 21,146 21,092
Goodwill 1,270 1,270
Regulatory assets 603 550
Investments and restricted investments 982 904
Other assets 168 164
Total assets $ 25,425 $ 25,254
The accompanying notes are an integral part of these consolidated financial statements.
99
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable $ 384 $ 536
Accrued interest 89 90
Accrued property, income and other taxes 243 170
Current portion of long-term debt 253 317
Other current liabilities 133 93
Total current liabilities 1,102 1,206
Long-term debt 7,655 7,652
Regulatory liabilities 816 1,119
Deferred income taxes 3,501 3,431
Asset retirement obligations 782 683
Other long-term liabilities 508 484
Total liabilities 14,364 14,575
Commitments and contingencies (Note 9)
Member's equity:
Paid-in capital 1,679 1,679
Retained earnings 9,382 9,000
Total member's equity 11,061 10,679
Total liabilities and member's equity $ 25,425 $ 25,254
The accompanying notes are an integral part of these consolidated financial statements.
100
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue:
Regulated electric $ 661 $ 725 $ 1,252 $ 1,333
Regulated natural gas and other 98 172 427 569
Total operating revenue 759 897 1,679 1,902
Operating expenses:
Cost of fuel and energy 113 174 228 299
Cost of natural gas purchased for resale and other 46 120 282 418
Operations and maintenance 216 200 421 392
Depreciation and amortization 226 277 460 527
Property and other taxes 40 36 82 76
Total operating expenses 641 807 1,473 1,712
Operating income 118 90 206 190
Other income (expense):
Interest expense (85) (83) (169) (165)
Allowance for borrowed funds 4 5 8 9
Allowance for equity funds 13 14 24 29
Other, net 15 (10) 43 (14)
Total other income (expense) (53) (74) (94) (141)
Income before income tax expense (benefit) 65 16 112 49
Income tax expense (benefit) (168) (188) (370) (396)
Net income $ 233 $ 204 $ 482 $ 445
The accompanying notes are an integral part of these consolidated financial statements.
101
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)
(Amounts in millions)
Paid-inCapital RetainedEarnings
Total Member'sEquity
Balance, March 31, 2022 $ 1,679 $ 8,363 $ 10,042
Net income — 204 204
Balance, June 30, 2022 $ 1,679 $ 8,567 $ 10,246
Balance, December 31, 2021 $ 1,679 $ 8,122 $ 9,801
Net income — 445 445
Balance, June 30, 2022 $ 1,679 $ 8,567 $ 10,246
Balance, March 31, 2023 $ 1,679 $ 9,149 $ 10,828
Net income — 233 233
Balance, June 30, 2023 $ 1,679 $ 9,382 $ 11,061
Balance, December 31, 2022 $ 1,679 $ 9,000 $ 10,679
Net income — 482 482
Distribution to member — (100) (100)
Balance, June 30, 2023 $ 1,679 $ 9,382 $ 11,061
The accompanying notes are an integral part of these consolidated financial statements.
102
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods
Ended June 30,
2023 2022
Cash flows from operating activities:
Net income $ 482 $ 445
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization 460 527
Amortization of utility plant to other operating expenses 16 19
Allowance for equity funds (24) (29)
Deferred income taxes and investment tax credits, net 46 58
Settlements of asset retirement obligations (15) (28)
Other, net (10) 32
Changes in other operating assets and liabilities:
Trade receivables and other assets 194 1
Inventories (43) 8
Accrued property, income and other taxes, net 110 95
Accounts payable and other liabilities (106) (10)
Net cash flows from operating activities 1,110 1,118
Cash flows from investing activities:
Capital expenditures (763) (862)
Purchases of marketable securities (95) (214)
Proceeds from sales of marketable securities 81 210
Proceeds from sale of investment 12 —
Other, net 10 6
Net cash flows from investing activities (755) (860)
Cash flows from financing activities:
Distribution to member (100) —
Repayments of long-term debt (65) —
Net change in note payable to affiliate — 8
Other, net (1) (1)
Net cash flows from financing activities (166) 7
Net change in cash and cash equivalents and restricted cash and cash equivalents 189 265
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 271 240
Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 460 $ 505
The accompanying notes are an integral part of these consolidated financial statements.
103
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
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.
The 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 June 30, 2023, and for the three-
and six-month periods ended June 30, 2023 and 2022. The results of operations for the six-month period ended June 30, 2023,
are not necessarily indicative of the results to be expected for the full year.
The 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 six-month period ended June 30, 2023.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with a
maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by
legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially
of funds restricted for wildlife preservation. A 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):
As of
June 30,December 31,
2023 2022
Cash and cash equivalents $ 454 $ 261
Restricted cash and cash equivalents in other current assets 6 10
Total cash and cash equivalents and restricted cash and cash equivalents $ 460 $ 271
(3) Property, Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.
(4) Recent Financing Transactions
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
104
(5) Income Taxes
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:
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Federal statutory income tax rate 21 % 21 % 21 % 21 %
Income tax credits (266) (1,150) (335) (793)
State income tax, net of federal income tax impacts (8) (38) (10) (29)
Effects of ratemaking (5) (12) (5) (10)
Other, net — 4 (1) 3
Effective income tax rate (258) % (1,175) % (330) % (808) %
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 10 years from the date the qualifying generating
facilities are placed in-service. PTCs recognized for the six-month periods ended June 30, 2023 and 2022, totaled $375 million
and $388 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its U.S. federal and Iowa state income tax returns. Consistent with
established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been
computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or
received from BHE. MidAmerican Funding received net cash payments for income tax from BHE totaling $522 million and
$544 million for the six-month periods ended June 30, 2023 and 2022, respectively.
(6) Employee Benefit Plans
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.
(7) Asset Retirement Obligations
Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements.
(8) Fair Value Measurements
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at
cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value
measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash
flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican
Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market
rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt
(in millions):
As of June 30, 2023 As of December 31, 2022
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Long-term debt $ 7,908 $ 7,065 $ 7,969 $ 7,219
105
(9) Commitments and Contingencies
MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. MidAmerican Funding
does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.
(10) Revenue from Contracts with Customers
Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements.
(11) Member's Equity
In January 2023, MidAmerican Funding paid a $100 million cash distribution to its parent company, BHE.
(12) Segment Information
MidAmerican Funding has identified two 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.
The following tables provide information on a reportable segment basis (in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue:
Regulated electric $ 661 $ 725 $ 1,252 $ 1,333
Regulated natural gas 97 171 423 567
Other 1 1 4 2
Total operating revenue $ 759 $ 897 $ 1,679 $ 1,902
Operating income:
Regulated electric $ 120 $ 87 $ 170 $ 138
Regulated natural gas (2) 3 36 52
Total operating income 118 90 206 190
Interest expense (85) (83) (169) (165)
Allowance for borrowed funds 4 5 8 9
Allowance for equity funds 13 14 24 29
Other, net 15 (10) 43 (14)
Total income before income tax expense (benefit)$ 65 $ 16 $ 112 $ 49
106
As of
June 30,2023 December 31,2022
Assets(1):
Regulated electric $ 23,616 $ 23,283
Regulated natural gas 1,796 1,963
Other 13 8
Total assets $ 25,425 $ 25,254
(1)Assets by reportable segment reflect the assignment of goodwill to applicable reporting units.
107
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 Second Quarter and First Six Months of 2023 and 2022
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the second quarter of 2023 was $236 million, an increase of $29 million, or 14%,
compared to 2022, primarily due to lower depreciation and amortization expense and favorable other, net, partially offset by
lower income tax benefit, higher operations and maintenance expense, higher property and other taxes and higher interest
expense, lower electric utility margin and lower allowance for borrowed and equity funds. 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 1%, due to lower wind-powered generation partially offset by higher coal- and natural
gas-fueled generation; and energy purchased decreased 3%. Wholesale electricity sales volumes decreased 5% due to
unfavorable market conditions. Natural gas retail customer volumes decreased 16% due to the unfavorable impact of weather.
MidAmerican Energy's net income for the first six months of 2023 was $478 million, an increase of $27 million, or 6%,
compared to 2022, primarily due to lower depreciation and amortization expense, favorable other, net and higher nonregulated
utility margin, partially offset by higher operations and maintenance expense, lower income tax benefit, lower electric utility
margin, lower natural gas utility margin, lower allowance for borrowed and equity funds, higher property and other taxes and
higher interest 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 5%, due to lower wind-
powered generation partially offset by higher natural gas- and coal-fueled generation; and energy purchased increased 6%.
Wholesale electricity sales volumes decreased 12% due to unfavorable market conditions. Natural gas retail customer volumes
decreased 11% due to the unfavorable impact of weather.
MidAmerican Funding -
MidAmerican Funding's net income for the second quarter of 2023 was $233 million, an increase of $29 million, or 14%,
compared to 2022. MidAmerican Funding's net income for the first six months of 2023 was $482 million, an increase of
$37 million, or 8%, compared to 2022. The variance in net income was primarily due to the changes in MidAmerican Energy's
earnings discussed above and a one-time gain on the sale of an investment of $10 million.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP
financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric
utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on
the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated
cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased
for resale and other, respectively, on the Statements of Operations.
108
MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its
retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's expense included
in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility
margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue
and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin
provides meaningful and valuable insight into the information management considers important to running the business and a
measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be
viewed as a supplement to, and not a substitute for, operating income, which is the most comparable financial measure prepared
in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating
income (in millions):
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Electric utility margin:
Operating revenue $ 661 $ 725 $ (64) (9) %$ 1,252 $ 1,333 $ (81) (6) %
Cost of fuel and energy 113 174 (61) (35) 228 299 (71) (24)
Electric utility margin 548 551 (3) (1) % 1,024 1,034 (10) (1) %
Natural gas utility margin:
Operating revenue 97 171 (74) (43) % 423 567 (144) (25) %
Natural gas purchased for resale 46 120 (74) (62) 282 418 (136) (33)
Natural gas utility margin 51 51 — — % 141 149 (8) (5) %
Utility margin 599 602 (3) — % 1,165 1,183 (18) (2) %
Other operating revenue 1 1 — — % 4 2 2 100 %
Operations and maintenance 216 200 16 8 421 392 29 7
Depreciation and amortization 226 277 (51) (18) 460 527 (67) (13)
Property and other taxes 40 36 4 11 82 76 6 8
Operating income $ 118 $ 90 $ 28 31 %$ 206 $ 190 $ 16 8 %
109
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Utility margin (in millions):
Operating revenue $ 661 $ 725 $ (64) (9) %$ 1,252 $ 1,333 $ (81) (6) %
Cost of fuel and energy 113 174 (61) (35) 228 299 (71) (24)
Utility margin $ 548 $ 551 $ (3) (1) %$ 1,024 $ 1,034 $ (10) (1) %
Sales (GWhs):
Residential 1,479 1,552 (73) (5) % 3,272 3,405 (133) (4) %
Commercial 929 953 (24) (3) 1,947 1,966 (19) (1)
Industrial 4,365 4,149 216 5 8,467 8,128 339 4
Other 392 406 (14) (3) 801 809 (8) (1)
Total retail 7,165 7,060 105 1 14,487 14,308 179 1
Wholesale 3,942 4,146 (204) (5) 8,294 9,471 (1,177) (12)
Total sales 11,107 11,206 (99) (1) % 22,781 23,779 (998) (4) %
Average number of retail customers (in thousands)819 812 7 1 %818 811 7 1 %
Average revenue per MWh:
Retail $ 79.45 $ 84.18 $ (4.73) (6) %$ 73.17 $ 74.52 $ (1.35) (2) %
Wholesale $ 17.63 $ 25.23 $ (7.60) (30) %$ 17.59 $ 22.65 $ (5.06) (22) %
Heating degree days 462 677 (215) (32) % 3,454 3,992 (538) (13) %
Cooling degree days 393 421 (28) (7) % 393 421 (28) (7) %
Sources of energy (GWhs)(1):
Wind and other(2) 6,320 7,364 (1,044) (14) % 13,697 15,654 (1,957) (13) %
Coal 2,217 1,481 736 50 4,333 3,840 493 13
Nuclear 862 863 (1) — 1,789 1,783 6 —
Natural gas 569 397 172 43 913 631 282 45
Total energy generated 9,968 10,105 (137) (1) 20,732 21,908 (1,176) (5)
Energy purchased 1,282 1,315 (33) (3) 2,405 2,277 128 6
Total 11,250 11,420 (170) (1) % 23,137 24,185 (1,048) (4) %
Average cost of energy per MWh:
Energy generated(3)$ 6.20 $ 6.34 $ (0.14) (2) %$ 6.15 $ 5.92 $ 0.23 4 %
Energy purchased $ 39.75 $ 83.45 $ (43.70) (52) %$ 41.61 $ 74.41 $ (32.80) (44) %
(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.
110
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Utility margin (in millions):
Operating revenue $ 97 $ 171 $ (74) (43) %$ 423 $ 567 $ (144) (25) %
Natural gas purchased for resale 46 120 (74) (62) 282 418 (136) (33)
Utility margin $ 51 $ 51 $ — — %$ 141 $ 149 $ (8) (5) %
Throughput (000's Dths):
Residential 6,197 7,500 (1,303) (17) % 30,590 34,599 (4,009) (12) %
Commercial 3,023 3,599 (576) (16) 14,375 16,059 (1,684) (10)
Industrial 1,373 1,465 (92) (6) 2,856 3,309 (453) (14)
Other 13 16 (3) (19) 47 51 (4) (8)
Total retail sales 10,606 12,580 (1,974) (16) 47,868 54,018 (6,150) (11)
Wholesale sales 3,996 4,912 (916) (19) 14,403 17,144 (2,741) (16)
Total sales 14,602 17,492 (2,890) (17) 62,271 71,162 (8,891) (12)
Natural gas transportation service 23,830 22,491 1,339 6 53,415 53,804 (389) (1)
Total throughput 38,432 39,983 (1,551) (4) % 115,686 124,966 (9,280) (7) %
Average number of retail customers (in thousands) 792 781 11 1 % 792 784 8 1 %
Average revenue per retail Dth sold $ 7.53 $ 10.08 $ (2.55) (25) %$ 7.61 $ 8.36 $ (0.75) (9) %
Heating degree days 509 734 (225) (31) % 3,641 4,219 (578) (14) %
Average cost of natural gas per retail Dth sold $ 3.61 $ 6.78 $ (3.17) (47) %$ 5.14 $ 6.03 $ (0.89) (15) %
Combined retail and wholesale average cost of natural gas per Dth sold $ 3.15 $ 6.86 $ (3.71) (54) %$ 4.54 $ 5.87 $ (1.33) (23) %
Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022
MidAmerican Energy -
Electric utility margin decreased $3 million, or 1%, for the second quarter of 2023 compared to 2022, primarily due to:
•a $33 million decrease in wholesale utility margin due to lower margins per unit of $29 million from lower market
prices, and lower volumes of 4.9%; partially offset by
•a $29 million increase in retail utility margin primarily due to $26 million, net of energy costs, from higher recoveries
through bill riders (offset in operations and maintenance expense and income tax benefit); and $3 million due to price
impacts from changes in sales mix. Retail customer volumes increased 1.4%.
Natural gas utility margin for the second quarter of 2023 was equal to 2022, primarily due to:
•a $3 million increase from higher customer usage and other rate variances;
•a $1 million increase from lower refunds related to amortization of excess accumulated deferred income taxes arising
from 2017 tax reform (offset in income tax benefit); offset by
•a $4 million decrease due to the unfavorable impact of weather.
111
Operations and maintenance increased $16 million, or 8%, for the second quarter of 2023 compared to 2022 primarily due to
higher nuclear power generation costs of $6 million, higher benefit costs of $5 million, higher technology costs of $4 million,
and higher administrative and other costs of $4 million, partially offset by lower electric distribution and transmission costs of
$4 million.
Depreciation and amortization decreased $51 million, or 18%, for the second quarter of 2023 compared to 2022 primarily due
to $58 million from lower Iowa revenue sharing accruals, and $21 million from a regulatory mechanism that provides
customers the retail energy benefits of certain wind-powered generation projects, partially offset by $25 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 $4 million, or 11%, for the second quarter of 2023 compared to 2022 primarily due to
$2 million from higher wind turbine property taxes and $2 million from higher replacement taxes.
Interest expense increased $3 million, or 4%, for the second quarter of 2023 compared to 2022 due to higher interest rates on
variable rate long-term debt.
Allowance for borrowed and equity funds decreased $2 million, or 11%, for the second quarter of 2023 compared to 2022 due
to lower construction work-in-progress balances related to wind- and solar-powered generation.
Other, net increased $27 million, or 225%, for the second 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 higher
interest income from higher interest rates, partially offset by higher non-service costs of employee benefit plans.
Income tax benefit decreased $21 million, or 11%, for the second quarter of 2023 compared to 2022 primarily due to lower
PTCs and higher pretax income. PTCs for the second quarter of 2023 and 2022 totaled $173 million and $185 million,
respectively.
MidAmerican Funding -
Income tax benefit decreased $20 million, or 11%, for the second quarter of 2023 compared to 2022 principally due to the
changes in MidAmerican Energy's income tax benefit discussed above.
First Six Months of 2023 Compared to First Six Months of 2022
MidAmerican Energy -
Electric utility margin decreased $10 million, or 1%, for the first six months of 2023 compared to 2022, due to:
•a $55 million decrease in wholesale utility margin due to lower margins per unit of $36 million from lower market
prices, and lower volumes of 12.4%; partially offset by
•a $46 million increase in retail utility margin primarily due to $39 million, net of energy costs, from higher recoveries
through bill riders (offset in operations and maintenance expense and income tax benefit); $15 million from higher
customer usage; $3 million due to price impacts from changes in sales mix; and $2 million from higher wind-turbine
performance settlements; partially offset by $13 million from the unfavorable impact of weather. Retail customer
volumes increased 1.3%.
Natural gas utility margin decreased $8 million, or 5%, for the first six months of 2023 compared to 2022 primarily due to a
$9 million decrease from the unfavorable impact of weather.
Operations and maintenance increased $29 million, or 7%, for the first six months of 2023 compared to 2022 primarily due to
higher benefits costs of $8 million, higher technology costs of $7 million, higher administrative and other costs of $6 million,
higher other power generation costs of $5 million, higher property insurance costs of $3 million and higher nuclear power
generation costs of $2 million, partially offset by lower electric distribution and transmission costs of $4 million.
112
Depreciation and amortization decreased $67 million, or 13%, for the first six months of 2023 compared to 2022 primarily due
to $80 million from lower Iowa revenue sharing accruals, and $27 million from a regulatory mechanism that provides
customers the retail energy benefits of certain wind-powered generation projects, partially offset by $34 million from new
wind-powered generating facilities and other plant placed in-service and $6 million from lower depreciation expense deferrals
in 2023.
Property and other taxes increased $6 million, or 8%, for the first six months of 2023 compared to 2022 primarily due to
$3 million from higher wind turbine property taxes and $3 million from higher replacement taxes.
Interest expense increased $5 million, or 3%, for the first six months of 2023 compared to 2022 due to higher interest rates on
variable rate long-term debt.
Allowance for borrowed and equity funds decreased $6 million, or 16%, for the first six months of 2023 compared to 2022
primarily due to lower construction work-in-progress balances related to wind- and solar-powered generation.
Other, net increased $46 million, or 307%, for the first six months of 2023 compared to 2022 primarily due to favorable
investment earnings, largely attributable to higher cash surrender values of corporate-owned life insurance policies, higher
interest income from higher interest rates, and lower non-service costs of employee benefit plans.
Income tax benefit decreased $24 million, or 6%, for the first six months of 2023 compared to 2022 primarily due to lower
PTCs and higher pretax income. PTCs for the first six months of 2023 and 2022 totaled $375 million and $388 million,
respectively.
MidAmerican Funding -
Income tax benefit decreased $26 million, or 7%, for the first six months of 2023 compared to 2022 principally due to the
changes in MidAmerican Energy's income tax benefit discussed above and higher pretax income from a one-time gain on the
sale of an investment.
Liquidity and Capital Resources
As of June 30, 2023, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
MidAmerican Energy:
Cash and cash equivalents $ 454

Credit facilities, maturing 2024 and 2026 1,505
Less:
Tax-exempt bond support (306)
Net credit facilities 1,199

MidAmerican Energy total net liquidity $ 1,653

MidAmerican Funding:
MidAmerican Energy total net liquidity $ 1,653
MHC, Inc. credit facility, maturing 2024 4
MidAmerican Funding total net liquidity $ 1,657
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were
$1,125 million and $1,125 million, respectively. MidAmerican Funding's net cash flows from operating activities for the six-
month periods ended June 30, 2023 and 2022, were $1,110 million and $1,118 million, respectively. Cash flows from operating
activities reflect higher payments to vendors, lower income tax receipts and higher interest payments, offset by higher utility
margins for MidAmerican Energy's regulated electric and natural gas businesses.
113
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 six-month periods ended June 30, 2023 and 2022, were
$(767) million and $(860) million, respectively. MidAmerican Funding's net cash flows from investing activities for the six-
month periods ended June 30, 2023 and 2022, were $(755) million and $(860) 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 six-month periods ended June 30, 2023 and 2022 were
$(166) million and $(1) million, respectively. MidAmerican Funding's net cash flows from financing activities for the six-
month periods ended June 30, 2023 and 2022, were $(166) million and $7 million, respectively. In January 2023, MidAmerican
Funding made a $100 million distribution to its sole member BHE. In January 2023 and May 2023, MidAmerican Energy
repaid $7 million and $58 million of long-term debt, respectively. MidAmerican Funding received $— million and $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 2026. The credit
facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations
and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate,
plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities.
Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
Long-term Debt and Preferred Stock
MidAmerican Energy currently has an effective shelf registration statement with the SEC to issue 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, 2025, long-term debt securities up to an aggregate of $3.0 billion and preferred stock up to an aggregate
of $500 million. MidAmerican Energy has authorization from the Illinois Commerce Commission through May 25, 2025, to
issue long-term debt securities up to an aggregate of $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 $48 million of long-term debt securities for the purpose of refinancing two of its variable-rate tax-exempt bond
series, including $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.
114
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):
Six-Month Periods Annual
Ended June 30,Forecast
2022 2023 2023
Wind generation $ 244 $ 243 $ 906
Electric distribution 125 167 353
Electric transmission 46 76 163
Solar generation 77 10 24
Other 370 267 701
Total $ 862 $ 763 $ 2,147
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 $200 million and $5 million for the six-month
periods ended June 30, 2023 and 2022, respectively. The timing and amount of forecast wind generation
capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind
PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals
$544 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities totaling $19 million and $214 million for the six-month
periods ended June 30, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered
generating facilities totals $46 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 six-month
periods ended June 30, 2023 and 2022, solar generation spending totaled $10 million and $77 million, respectively.
Planned spending totals $14 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 June 30, 2023, there have been no material changes in MidAmerican Energy's and MidAmerican Funding's cash
requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31,
2022.
115
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.
116
Nevada Power Company and its subsidiaries
Consolidated Financial Section
117
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 June 30, 2023, the related consolidated statements of operations, and changes in shareholder's equity for the
three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30,
2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we
are not aware of any material modifications that should be made to the accompanying interim financial information for it to be
in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2022, and the related consolidated
statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in
our report dated February 24, 2023, we expressed an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2022, is fairly stated, in
all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to Nevada Power in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists
principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.
It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which
is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an
opinion.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
August 4, 2023
118
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
As of
June 30,December 31,
2023 2022
ASSETS
Current assets:
Cash and cash equivalents $ 47 $ 43
Trade receivables, net 460 388
Note receivable from affiliate — 100
Inventories 120 93
Regulatory assets 784 666
Other current assets 68 89
Total current assets 1,479 1,379
Property, plant and equipment, net 8,054 7,406
Regulatory assets 644 628
Other assets 388 388
Total assets $ 10,565 $ 9,801
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable $ 636 $ 422
Accrued interest 39 40
Accrued property, income and other taxes 35 32
Current portion of long-term debt 300 —
Regulatory liabilities 43 45
Customer deposits 54 51
Derivative contracts 104 51
Other current liabilities 63 49
Total current liabilities 1,274 690
Long-term debt 2,896 3,195
Finance lease obligations 286 295
Regulatory liabilities 1,035 1,093
Deferred income taxes 915 875
Other long-term liabilities 335 299
Total liabilities 6,741 6,447
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding — —
Additional paid-in capital 2,733 2,333
Retained earnings 1,092 1,022
Accumulated other comprehensive loss, net (1) (1)
Total shareholder's equity 3,824 3,354
Total liabilities and shareholder's equity $ 10,565 $ 9,801
The accompanying notes are an integral part of the consolidated financial statements.
119
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue $ 781 $ 639 $ 1,380 $ 1,054
Operating expenses:
Cost of fuel and energy 493 336 877 548
Operations and maintenance 78 75 151 140
Depreciation and amortization 108 103 214 206
Property and other taxes 14 12 28 25
Total operating expenses 693 526 1,270 919
Operating income 88 113 110 135
Other income (expense):
Interest expense (49) (39) (98) (77)
Capitalized interest 7 2 9 3
Allowance for equity funds 4 2 8 5
Interest and dividend income 19 9 41 18
Other, net 4 (1) 8 —
Total other income (expense) (15) (27) (32) (51)
Income before income tax expense (benefit) 73 86 78 84
Income tax expense (benefit) 7 10 8 10
Net income $ 66 $ 76 $ 70 $ 74
The accompanying notes are an integral part of these consolidated financial statements.
120
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
Accumulated
Additional Other Total
Common Stock Paid-in Retained Comprehensive Shareholder's
Shares Amount Capital Earnings Loss, Net Equity
Balance, March 31, 2022 1,000 $ — $ 2,308 $ 722 $ (2) $ 3,028
Net income — — — 76 — 76
Contributions — — 25 — — 25
Balance, June 30, 2022 1,000 $ — $ 2,333 $ 798 $ (2) $ 3,129
Balance, December 31, 2021 1,000 $ — $ 2,308 $ 724 $ (2) $ 3,030
Net income — — — 74 — 74
Contributions — — 25 — — 25
Balance, June 30, 2022 1,000 $ — $ 2,333 $ 798 $ (2) $ 3,129
Balance, March 31, 2023 1,000 $ — $ 2,733 $ 1,026 $ (1) $ 3,758
Net income — — — 66 — 66
Balance, June 30, 2023 1,000 $ — $ 2,733 $ 1,092 $ (1) $ 3,824
Balance, December 31, 2022 1,000 $ — $ 2,333 $ 1,022 $ (1) $ 3,354
Net income — — — 70 — 70
Contributions — — 400 — — 400
Balance, June 30, 2023 1,000 $ — $ 2,733 $ 1,092 $ (1) $ 3,824
The accompanying notes are an integral part of these consolidated financial statements.
121
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods
Ended June 30,
2023 2022
Cash flows from operating activities:
Net income $ 70 $ 74
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization 214 206
Allowance for equity funds (8) (5)
Changes in regulatory assets and liabilities (19) (14)
Deferred income taxes and amortization of investment tax credits 9 12
Deferred energy (252) (159)
Amortization of deferred energy 131 46
Other, net (1) 10
Changes in other operating assets and liabilities:
Trade receivables and other assets (83) (154)
Inventories (27) (4)
Accrued property, income and other taxes (4) 18
Accounts payable and other liabilities 202 194
Net cash flows from operating activities 232 224
Cash flows from investing activities:
Capital expenditures (719) (350)
Proceeds from repayment of affiliate note receivable 100 —
Net cash flows from investing activities (619) (350)
Cash flows from financing activities:
Net (repayments of) proceeds from long-term debt (1) 300
Net repayments of short-term debt — (180)
Contributions from parent 400 25
Other, net (10) (9)
Net cash flows from financing activities 389 136
Net change in cash and cash equivalents and restricted cash and cash equivalents 2 10
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 60 45
Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 62 $ 55
The accompanying notes are an integral part of these consolidated financial statements.
122
NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
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").
The 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 June 30, 2023, and for the three-
and six-month periods ended June 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been
omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2023 and 2022. The
results of operations for the three- and six-month periods ended June 30, 2023, are not necessarily indicative of the results to be
expected for the full year.
The 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 six-month period ended June 30, 2023.
(2)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 funds
restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A 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):
As of
June 30,December 31,
2023 2022
Cash and cash equivalents $ 47 $ 43
Restricted cash and cash equivalents included in other current assets 15 17
Total cash and cash equivalents and restricted cash and cash equivalents $ 62 $ 60
123
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of
Depreciable Life
June 30,December 31,
2023 2022
Utility plant:
Generation 30 - 55 years $ 4,100 $ 3,977
Transmission 45 - 70 years 1,581 1,562
Distribution 20 - 65 years 4,299 4,134
General and intangible plant 5 - 65 years 898 871
Utility plant 10,878 10,544
Accumulated depreciation and amortization (3,731) (3,624)
Utility plant, net 7,147 6,920
Non-regulated, net of accumulated depreciation and amortization 45 years 1 1
7,148 6,921
Construction work-in-progress 906 485
Property, plant and equipment, net $ 8,054 $ 7,406
(4) Recent 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: $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%.
Credit Facilities
In June 2023, Nevada Power amended its existing $400 million secured credit facility expiring in June 2025. The amendment
increased the commitment of the lenders to $600 million and extended the expiration date to June 2026.
(5) Income Taxes
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:
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022

Federal statutory income tax rate 21 % 21 % 21 % 21 %
Effects of ratemaking (11) (10) (10) (10)
Other — 1 (1) 1
Effective income tax rate 10 % 12 % 10 % 12 %
Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to 2017 tax reform
pursuant to an order issued by the PUCN effective January 1, 2021.
124
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established
regulatory practice, Nevada Power's provision for federal income tax has been computed on a stand-alone basis, and
substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the six-month period
ended June 30, 2023, Nevada Power made no cash payments for federal income tax to BHE. For the six-month period ended
June 30, 2022, Nevada Power received net cash payments for federal income tax from BHE totaling $21 million.
(6) Employee 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.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following
(in millions):
As of
June 30,December 31,
2023 2022
Qualified Pension Plan:
Other non-current assets $ 26 $ 27
Non-Qualified Pension Plans:
Other current liabilities (1) (1)
Other long-term liabilities (6) (6)
Other Postretirement Plans:
Other non-current assets 7 7
(7)Risk Management and Hedging Activities
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is
principally exposed to electricity and natural gas market fluctuations primarily through Nevada Power's obligation to serve
retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial
underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to
generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as
supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility
availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased
power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt
issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the
various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity
derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future
supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to
variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest
rates. Additionally, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps
or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and
interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Note 8 for
additional information on derivative contracts.
125
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):
Derivative
Other Contracts -Other
Current Current Long-term
Assets Liabilities Liabilities Total
As of June, 30 2023
Not designated as hedging contracts(1) -
Total derivatives - commodity liabilities $ — $ (104) $ (22) $ (126)
As of December 31, 2022
Not designated as hedging contracts(1):
Commodity assets $ 23 $ — $ — $ 23
Commodity liabilities — (51) (24) (75)
Total derivatives - net basis $ 23 $ (51) $ (24) $ (52)
(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2023 a regulatory asset of
$126 million was recorded related to the net derivative liability of $126 million. As of December 31, 2022 a regulatory asset of $52 million was
recorded related to the net derivative liability of $52 million.
Derivative Contract Volumes
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 June 30,December 31,
Measure 2023 2022
Electricity purchases Megawatt hours 2 2
Natural gas purchases Decatherms 127 109
Credit Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with
other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated
to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and
indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial
condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to
each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate
wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining
and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada
Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support
provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more
of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or
other security if credit exposures on a net basis exceed specified rating-dependent threshold levels "credit-risk-related
contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse
change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2023,
Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the
recognized credit rating agencies were investment grade.
126
The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent
features totaled $9 million and $5 million as of June 30, 2023 and December 31, 2022, respectively, which represents the
amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had
been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in
credit ratings, changes in legislation or regulation or other factors.
(8) Fair 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.
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):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Total
As of June 30, 2023:
Assets:
Money market mutual funds $ 48 — — $ 48
Investment funds 3 — — 3
$ 51 $ — $ — $ 51
Liabilities - commodity derivatives $ — $ — $ (126) $ (126)
As of December 31, 2022:
Assets:
Commodity derivatives $ — $ — $ 23 $ 23
Money market mutual funds 34 — — 34
Investment funds 3 — — 3
$ 37 $ — $ 23 $ 60
Liabilities - commodity derivatives $ — $ — $ (75) $ (75)
127
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 June 30, 2023 and December 31, 2022, had an immaterial
impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using
Level 3 inputs.
Nevada Power's investments in money market mutual funds and investment funds are stated at fair value. When available, a
readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair
value.
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):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Beginning balance $ (116) $ (168) $ (52) $ (113)
Changes in fair value recognized in regulatory assets (54) (21) (119) (77)
Settlements 44 14 45 15
Ending balance $ (126) $ (175) $ (126) $ (175)
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. The following table presents the carrying value and estimated fair value of Nevada Power's
long-term debt (in millions):
As of June 30, 2023 As of December 31, 2022
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $ 3,196 $ 3,086 $ 3,195 $ 3,114
128
(9) Commitments and Contingencies
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio
standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid
waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and
future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business. Nevada Power does not believe
that such normal and routine litigation will have a material impact on its consolidated financial results.
(10) Revenue from Contracts with Customers
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):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Customer Revenue:
Retail:
Residential $ 404 $ 353 $ 697 $ 566
Commercial 177 131 313 226
Industrial 173 124 311 203
Other 4 3 10 4
Total fully bundled 758 611 1,331 999
Distribution only service 4 5 7 10
Total retail 762 616 1,338 1,009
Wholesale, transmission and other 15 18 33 34
Total Customer Revenue 777 634 1,371 1,043
Other revenue 4 5 9 11
Total operating revenue $ 781 $ 639 $ 1,380 $ 1,054
129
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 Second Quarter and First Six Months of 2023 and 2022
Overview
Net income for the second quarter of 2023 was $66 million, a decrease of $10 million, compared to 2022 primarily due to lower
utility margin, higher interest expense, primarily due to higher long-term debt, higher operations and maintenance expenses,
mainly due to increased plant operations and maintenance expenses, partially offset by lower earnings sharing, and higher
depreciation and amortization, mainly due to higher plant placed in-service. The decrease is offset by favorable interest and
dividend income, mainly from higher carrying charges on regulatory balances, higher capitalized interest mainly due to higher
construction work-in-progress and favorable cash surrender value of corporate-owned life insurance policies. Utility margin
decreased primarily due to lower retail customer volumes, partially offset by higher regulatory-related revenue deferrals. Retail
customer volumes, including distribution only service customers, decreased 4.5% primarily due to the unfavorable impact of
weather, offset by an increase in the average number of customers. Energy generated for the second quarter of 2023 was
comparable to 2022. Wholesale electricity sales volumes decreased 68% and purchased electricity volumes decreased 11%.
Net income for the first six months of 2023 was $70 million, a decrease of $4 million, compared to 2022 primarily due to
higher interest expense, mainly due to higher long-term debt, higher operations and maintenance expenses and higher
depreciation and amortization, mainly due to higher plant placed in-service. The decrease is partially offset by favorable interest
and dividend income, mainly from higher carrying charges on regulatory balances, higher capitalized interest mainly due to
higher construction work-in-progress and favorable cash surrender value of corporate-owned life insurance policies. Operations
and maintenance expenses increased primarily due to increased plant operations and maintenance expenses and higher customer
service operations expenses, partially offset by lower earnings sharing. Utility margin decreased primarily due to lower retail
customer volumes, partially offset by higher regulatory-related revenue deferrals and higher other retail revenue. Retail
customer volumes, including distribution only service customers, decreased 1.2% primarily due to the unfavorable impact of
weather, offset by an increase in the average number of customers. Energy generated increased 16% for the first six months of
2023 compared to 2022 primarily due to higher natural-gas fueled generation. Wholesale electricity sales volumes decreased
61% and purchased electricity volumes decreased 21%.
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.
130
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):
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Utility margin:
Operating revenue $ 781 $ 639 $ 142 22 %$ 1,380 $ 1,054 $ 326 31 %
Cost of fuel and energy 493 336 157 47 877 548 329 60
Utility margin 288 303 (15) (5) 503 506 (3) (1)
Operations and maintenance 78 75 3 4 151 140 11 8
Depreciation and amortization 108 103 5 5 214 206 8 4
Property and other taxes 14 12 2 17 28 25 3 12
Operating income $ 88 $ 113 $ (25) (22) %$ 110 $ 135 $ (25) (19) %
131
Utility Margin
A comparison of key operating results related to utility margin is as follows:
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Utility margin (in millions):
Operating revenue $ 781 $ 639 $ 142 22 %$ 1,380 $ 1,054 $ 326 31 %
Cost of fuel and energy 493 336 157 47 877 548 329 60
Utility margin $ 288 $ 303 $ (15) (5) %$ 503 $ 506 $ (3) (1) %
Sales (GWhs):
Residential 2,268 2,612 (344) (13) % 3,904 4,197 (293) (7) %
Commercial 1,251 1,272 (21) (2) 2,248 2,270 (22) (1)
Industrial 1,456 1,409 47 3 2,698 2,584 114 4
Other 44 46 (2) (4) 87 92 (5) (5)
Total fully bundled(1) 5,019 5,339 (320) (6) 8,937 9,143 (206) (2)
Distribution only service 708 661 47 7 1,306 1,230 76 6
Total retail 5,727 6,000 (273) (5) 10,243 10,373 (130) (1)
Wholesale 67 210 (143) (68) 130 335 (205) (61)
Total GWhs sold 5,794 6,210 (416) (7) % 10,373 10,708 (335) (3) %
Average number of retail customers (in thousands) 1,012 1,000 12 1 % 1,011 997 14 1 %
Average revenue per MWh:
Retail - fully bundled(1)$ 151.17 $ 114.36 $ 36.81 32 %$ 148.98 $ 109.26 $ 39.72 36 %
Wholesale $ 47.45 $ 34.36 $ 13.09 38 %$ 72.10 $ 37.55 $ 34.55 92 %
Heating degree days 73 31 42 * 1,383 985 398 40 %
Cooling degree days 1,121 1,322 (201) (15) % 1,124 1,371 (247) (18) %
Sources of energy (GWhs)(2)(3):
Natural gas 2,931 2,935 (4) — % 6,194 5,313 881 17 %
Renewables 19 20 (1) (5) 34 34 — —
Total energy generated 2,950 2,955 (5) — 6,228 5,347 881 16
Energy purchased 2,199 2,472 (273) (11) 3,336 4,233 (897) (21)
Total 5,149 5,427 (278) (5) % 9,564 9,580 (16) — %
Average cost of energy per MWh(4):
Energy generated $ 60.13 $ 49.65 $ 10.48 21 %$ 76.19 $ 46.19 $ 30.00 65 %
Energy purchased $ 143.80 $ 76.63 $ 67.17 88 %$ 120.73 $ 71.07 $ 49.66 70 %
* 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 179 GWhs and 360 GWhs of gas generated energy that is purchased at cost by
related parties for the second quarter of 2023 and 2022, respectively. The average cost of energy per MWh and sources of energy excludes 462
GWhs and 784 GWhs of gas generated energy that is purchased at cost by related parties for the first six months of 2023 and 2022, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
132
Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022
Utility margin decreased $15 million, or 5%, for the second quarter of 2023 compared to 2022 primarily due to:
•$21 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer
volumes, including distribution only service customers, decreased 4.5% primarily due to the unfavorable impact of
weather, offset by an increase in the average number of customers.
The decrease in utility margin was partially offset by:
•$3 million of higher energy efficiency program rates (offset in operations and maintenance expense) and
•$3 million of higher regulatory-related revenue deferrals.
Operations and maintenance increased $3 million, or 4%, for the second quarter of 2023 compared to 2022 primarily due to
increased plant operations and maintenance expenses, higher energy efficiency program costs (offset in operating revenue) and
higher customer service operations expenses, partially offset by lower earnings sharing.
Depreciation and amortization increased $5 million, or 5%, for the second quarter of 2023 compared to 2022 primarily due to
higher plant placed in-service.
Property and other taxes increased $2 million, or 17%, for the second quarter of 2023 compared to 2022 primarily due to a
decrease in the amount of abatements available and an increase in commerce and franchise tax from higher revenue.
Interest expense increased $10 million, or 26%, for the second quarter of 2023 compared to 2022 primarily due to higher long-
term debt.
Capitalized interest increased $5 million for the second quarter of 2023 compared to 2022 primarily due to higher construction
work-in-progress.
Allowance for equity funds increased $2 million for the second quarter of 2023 compared to 2022 primarily due to higher
construction work-in-progress.
Interest and dividend income increased $10 million for the second quarter of 2023 compared to 2022 primarily due to favorable
interest income, mainly from carrying charges on regulatory balances.
Other, net increased $5 million for the second quarter of 2023 compared to 2022 primarily due to favorable cash surrender
value of corporate-owned life insurance policies.
Income tax expense decreased $3 million, or 30%, for the second quarter of 2023 compared to 2022 primarily due to lower
pretax income. The effective tax rate was 10% in 2023 and 12% in 2022 and decreased primarily due to the effects of
ratemaking.
First Six Months of 2023 Compared to First Six Months of 2022
Utility margin decreased $3 million, or 5%, for the first six months of 2023 compared to 2022 primarily due to:
•$18 million of lower electric retail utility margin primarily due to lower retail customer volumes. Retail customer
volumes, including distribution only service customers, decreased 1.2% primarily due to the unfavorable impact of
weather, offset by an increase in the average number of customers.
The decrease in utility margin was offset by:
•$6 million of higher energy efficiency program rates (offset in operations and maintenance expense);
•$5 million of higher regulatory-related revenue deferrals; and
•$3 million of higher other retail revenue.
Operations and maintenance increased by $11 million, or 8%, for the first six months of 2023 compared to 2022 primarily due
to increased plant operations and maintenance expenses, higher energy efficiency program costs (offset in operating revenue)
and higher customer service operations expenses, partially offset by lower earnings sharing.
133
Depreciation and amortization increased $8 million, or 4%, for the first six months of 2023 compared to 2022 primarily due to
higher plant placed in-service.
Property and other taxes increased $3 million, or 12%, for the first six months of 2023 compared to 2022 primarily due to a
decrease in the amount of abatements available and an increase in commerce and franchise tax from higher revenue.
Interest expense increased $21 million, or 27%, for the first six months of 2023 compared to 2022 primarily due to higher long-
term debt.
Capitalized interest increased $6 million for the first six months of 2023 compared to 2022 primarily due to higher construction
work-in-progress.
Allowance for equity funds increased $3 million, or 60% for the first six months of 2023 compared to 2022 primarily due to
higher construction work-in-progress.
Interest and dividend income increased $23 million for the first six months of 2023 compared to 2022 primarily due to
favorable interest income, mainly from carrying charges on regulatory balances.
Other, net increased $8 million for the first six months of 2023 compared to 2022 primarily due to favorable cash surrender
value of corporate-owned life insurance policies.
Income tax expense decreased $2 million, or 20%, for the first six months of 2023 compared to 2022 primarily due to lower
pretax income. The effective tax rate was 10% in 2023 and 12% in 2022 and decreased primarily due to the effects of
ratemaking.
Liquidity and Capital Resources
As of June 30, 2023, Nevada Power's total net liquidity was as follows (in millions):
Cash and cash equivalents $ 47
Credit facility 600
Total net liquidity $ 647
Credit facility:
Maturity date 2026
Operating Activities
Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $232 million and
$224 million, respectively. The change was primarily due to higher collections from customers, the timing of payments for
operating costs and increased customer advance collections, partially offset by higher payments related to fuel and energy costs,
lower cash received for income tax and higher interest payments.
The timing of Nevada Power's income tax cash flows from period to period can be significantly affected by the estimated
federal income tax payment methods and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the six-month periods ended June 30, 2023 and 2022, were $(619) million and
$(350) million, respectively. The change was primarily due to increased capital expenditures, offset by the repayment of an
affiliate note receivable. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the six-month periods ended June 30, 2023 and 2022, were $389 million and
$136 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and lower repayments of
short-term debt, partially offset by lower proceeds from the issuance of long-term debt.
134
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 $600 million secured credit facility); and (2)
maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective shelf registration statement
with the SEC to issue 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):
Six-Month Periods Annual
Ended June 30,Forecast
2022 2023 2023
Electric distribution $ 108 $ 148 $ 315
Electric transmission 39 94 189
Solar generation 23 238 288
Electric battery storage — 41 241
Other 180 198 367
Total $ 350 $ 719 $ 1,400
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.
135
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the
Nevada Utilities' Greenlink Nevada transmission expansion program. Nevada Power has received approval from the
PUCN to build a 350-mile, 525-kV transmission line connecting the Ft. Churchill substation to the Northwest
substation to the Harry Allen substation; a 235-mile, 525-kV transmission line connecting the new Ft. Churchill
substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill
substation to the Mira Loma substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation
to the Robinson Summit substation. Operating expenditures consist of routine expenditures for transmission and other
infrastructure needed to serve existing and expected demand.
•Solar generation investment includes expenditures for a 150-MW solar photovoltaic facility with an additional 100
MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected
by the end of 2023 or early 2024.
•Electric battery storage includes two growth projects consisting of a 100-MW battery energy storage system co-located
with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada. Commercial operation is
expected by the end of 2023 or early 2024. The second project is a 220-MW grid-tied battery energy storage system
that will be developed on the site of the retired Reid Gardner generating facility in Clark County, Nevada. Commercial
operation is expected by the end of 2023.
•Other includes both growth projects and operating expenditures. Growth projects primarily consist of an additional 400
MW of peaking combustion turbines that will be developed at the Silverhawk generating facility in Clark County,
Nevada. Commercial operation is expected by the third quarter of 2024. Operating expenditures consist of turbine
upgrades at several generating facilities, routine expenditures for generation, other operating projects and other
infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of June 30, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of
Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2022, other than those disclosed in Note 4 of
the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Regulatory Matters
Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I,
Item 2 of this Form 10-Q for discussion regarding Nevada Power's current regulatory matters.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions
performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact
Nevada Power's current and future operations. In addition to imposing continuing compliance obligations, these laws and
regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive
relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Nevada
Power believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation
that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is
unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional
information regarding environmental laws and regulations.
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.
136
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
137
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 June 30, 2023, the related consolidated statements of operations, and changes in shareholder's equity for the
three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-month periods ended June 30,
2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we
are not aware of any material modifications that should be made to the accompanying interim financial information for it to be
in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheet of Sierra Pacific as of December 31, 2022, and the related consolidated
statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in
our report dated February 24, 2023, we expressed an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2022, is fairly stated, in
all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Sierra Pacific's management. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists
principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.
It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which
is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an
opinion.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
August 4, 2023
138
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
As of
June 30,December 31,
2023 2022
ASSETS
Current assets:
Cash and cash equivalents $ 37 $ 49
Trade receivables, net 165 175
Inventories 112 79
Regulatory assets 214 357
Other current assets 30 50
Total current assets 558 710
Property, plant and equipment, net 3,684 3,587
Regulatory assets 259 254
Other assets 183 181
Total assets $ 4,684 $ 4,732
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable $ 190 $ 224
Note payable to affiliate — 70
Accrued property, income and other taxes 51 15
Current portion of long-term debt 250 250
Derivative contracts 31 14
Other current liabilities 87 79
Total current liabilities 609 652
Long-term debt 899 898
Finance lease obligations 96 100
Regulatory liabilities 426 436
Deferred income taxes 416 445
Other long-term liabilities 143 153
Total liabilities 2,589 2,684
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding — —
Additional paid-in capital 1,576 1,576
Retained earnings 520 473
Accumulated other comprehensive loss, net (1) (1)
Total shareholder's equity 2,095 2,048
Total liabilities and shareholder's equity $ 4,684 $ 4,732
The accompanying notes are an integral part of the consolidated financial statements.
139
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue:
Regulated electric $ 293 $ 230 $ 597 $ 457
Regulated natural gas 44 28 140 80
Total operating revenue 337 258 737 537
Operating expenses:
Cost of fuel and energy 179 129 360 253
Cost of natural gas purchased for resale 31 16 106 50
Operations and maintenance 49 47 105 88
Depreciation and amortization 46 37 92 73
Property and other taxes 6 6 13 12
Total operating expenses 311 235 676 476
Operating income 26 23 61 61
Other income (expense):
Interest expense (15) (14) (31) (27)
Allowance for borrowed funds 3 — 5 1
Allowance for equity funds 3 2 5 4
Interest and dividend income 5 4 12 7
Other, net 1 — 2 2
Total other income (expense) (3) (8) (7) (13)
Income before income tax expense (benefit) 23 15 54 48
Income tax expense (benefit) 3 2 7 7
Net income $ 20 $ 13 $ 47 $ 41
The accompanying notes are an integral part of these consolidated financial statements.
140
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
Accumulated
Additional Other Total
Common Stock Paid-in Retained Comprehensive Shareholder's
Shares Amount Capital Earnings Loss, Net Equity
Balance, March 31, 2022 1,000 $ — $ 1,241 $ 453 $ (1) $ 1,693
Net income — — — 13 — 13
Dividends declared — — — (70) — (70)
Contributions — — 210 — — 210
Balance, June 30, 2022 1,000 $ — $ 1,451 $ 396 $ (1) $ 1,846
Balance, December 31, 2021 1,000 $ — $ 1,111 $ 425 $ (1) $ 1,535
Net income — — — 41 — 41
Dividends declared — — — (70) — (70)
Contributions — — 340 — — 340
Balance, June 30, 2022 1,000 $ — $ 1,451 $ 396 $ (1) $ 1,846
Balance, March 31, 2023 1,000 $ — $ 1,576 $ 500 $ (1) $ 2,075
Net income — — — 20 — 20
Balance, June 30, 2023 1,000 $ — $ 1,576 $ 520 $ (1) $ 2,095
Balance, December 31, 2022 1,000 $ — $ 1,576 $ 473 $ (1) $ 2,048
Net income — — — 47 — 47
Balance, June 30, 2023 1,000 $ — $ 1,576 $ 520 $ (1) $ 2,095
The accompanying notes are an integral part of these consolidated financial statements.
141
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods
Ended June 30,
2023 2022
Cash flows from operating activities:
Net income $ 47 $ 41
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization 92 73
Allowance for equity funds (5) (4)
Changes in regulatory assets and liabilities 8 (8)
Deferred income taxes and amortization of investment tax credits (38) 5
Deferred energy 61 (67)
Amortization of deferred energy 77 46
Other, net (1) 2
Changes in other operating assets and liabilities:
Trade receivables and other assets 9 (1)
Inventories (34) (10)
Accrued property, income and other taxes 49 3
Accounts payable and other liabilities (33) 28
Net cash flows from operating activities 232 108
Cash flows from investing activities:
Capital expenditures (170) (191)
Net cash flows from investing activities (170) (191)
Cash flows from financing activities:
Proceeds from long-term debt — 249
Long-term debt reacquired — (265)
Net repayments from short-term debt — (159)
Dividends paid — (70)
Contributions from parent — 340
Repayments of affiliate note payable (70) —
Other, net (4) (4)
Net cash flows from financing activities (74) 91
Net change in cash and cash equivalents and restricted cash and cash equivalents (12) 8
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 56 16
Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 44 $ 24
The accompanying notes are an integral part of these consolidated financial statements.
142
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
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").
The 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 June 30, 2023, and for the three-
and six-month periods ended June 30, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been
omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2023 and 2022. The
results of operations for the three- and six-month periods ended June 30, 2023, are not necessarily indicative of the results to be
expected for the full year.
The 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 six-month period ended June 30, 2023.
(2)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 funds
restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A 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):
As of
June 30,December 31,
2023 2022
Cash and cash equivalents $ 37 $ 49
Restricted cash and cash equivalents included in other current assets 7 7
Total cash and cash equivalents and restricted cash and cash equivalents $ 44 $ 56
143
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of
Depreciable Life
June 30,December 31,
2023 2022
Utility plant:
Electric generation 25 - 70 years $ 1,308 $ 1,298
Electric transmission 50 - 76 years 998 993
Electric distribution 20 - 76 years 2,015 1,983
Electric general and intangible plant 5 - 65 years 225 219
Natural gas distribution 35 - 70 years 465 455
Natural gas general and intangible plant 5 - 65 years 16 15
Common general 5 - 65 years 385 380
Utility plant 5,412 5,343
Accumulated depreciation and amortization (2,058) (1,992)
3,354 3,351
Construction work-in-progress 330 236
Property, plant and equipment, net $ 3,684 $ 3,587
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 $19 million annually based on depreciable plant balances at the time of the change.
(4) Recent Financing Transactions
Credit Facilities
In June 2023, Sierra Pacific amended its existing $250 million secured credit facility expiring in June 2025. The amendment
increased the commitment of the lenders to $400 million and extended the expiration date to June 2026.
(5)Income Taxes
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:
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Federal statutory income tax rate 21 % 21 % 21 % 21 %
Effects of ratemaking (9) (8) (9) (7)
Other 1 — 1 1
Effective income tax rate 13 % 13 % 13 % 15 %
Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to 2017 tax reform
pursuant to an order issued by the PUCN effective January 1, 2020.
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established
regulatory practice, Sierra Pacific's provision for federal income tax has been computed on a stand-alone basis, and
substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the six-month
periods ended June 30, 2023 and 2022, Sierra Pacific made no cash payments for federal income tax to BHE.
144
(6) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified
pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively,
"Non-Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare
Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other
Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific contributed $2 million to the Other Post Retirement Plans for
the six-month period ended June 30, 2023. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon
the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been
recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in
regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss,
net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following
(in millions):
As of
June 30,December 31,
2023 2022
Qualified Pension Plan:
Other non-current assets $ 44 $ 43
Non-Qualified Pension Plans:
Other current liabilities (1) (1)
Other long-term liabilities (5) (5)
Other Postretirement Plans:
Other long-term liabilities — (2)
(7)Risk Management and Hedging Activities
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally
exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail
customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying
commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate
electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply
and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability,
customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is
recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances.
Sierra Pacific does not engage in proprietary trading activities.
Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the
various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity
derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future
supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to
variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest
rates. Additionally, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps
or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and
interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Note 8 for
additional information on derivative contracts.
145
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):
Other Other
Current Current Long-term
Assets Liabilities Liabilities Total
As of June, 30 2023
Not designated as hedging contracts(1) -
Total derivatives - commodity liabilities $ — $ (31) $ (5) $ (36)
As of December 31, 2022
Not designated as hedging contracts(1):
Commodity assets $ 8 $ — $ — $ 8
Commodity liabilities — (14) (7) (21)
Total derivatives - net basis $ 8 $ (14) $ (7) $ (13)
(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2023 a net regulatory asset
of $36 million was recorded related to the net derivative liability of $36 million. As of December 31, 2022 a net regulatory asset of $13 million was
recorded related to the net derivative liability of $13 million.
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 June 30,December 31,
Measure 2023 2022
Electricity purchases Megawatt hours 1 1
Natural gas purchases Decatherms 56 52
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 June 30, 2023, Sierra
Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized
credit rating agencies were investment grade.
146
The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent
features totaled $1 million and $— million as of June 30, 2023 and December 31, 2022, respectively, which represents the
amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had
been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in
credit ratings, changes in legislation or regulation or other factors.
(8) Fair 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.
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):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Total
As of June 30, 2023:
Assets:
Money market mutual funds $ 36 — — $ 36
Investment funds 1 — — 1
$ 37 $ — $ — $ 37
Liabilities - commodity derivatives $ — $ — $ (36) $ (36)
As of December 31, 2022:
Assets:
Commodity derivatives $ — $ — $ 8 $ 8
Money market mutual funds 49 — — 49
Investment funds 1 — — 1
$ 50 $ — $ 8 $ 58
Liabilities - commodity derivatives $ — $ — $ (21) $ (21)
147
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 June 30, 2023 and December 31, 2022, had an immaterial
impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using
Level 3 inputs.
Sierra Pacific's investments in money market mutual funds and investment funds are stated at fair value. When available, a
readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair
value.
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):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Beginning balance $ (33) $ (52) $ (13) $ (33)
Changes in fair value recognized in regulatory assets (17) (7) (37) (26)
Settlements 14 5 14 5
Ending balance $ (36) $ (54) $ (36) $ (54)
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. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-
term debt (in millions):
As of June 30, 2023 As of December 31, 2022
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $ 1,149 $ 1,108 $ 1,148 $ 1,111
(9) Commitments and Contingencies
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards,
air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste
disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future
operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
148
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Sierra Pacific does not believe
that such normal and routine litigation will have a material impact on its consolidated financial results.
(10) Revenue from Contracts with Customers
The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of
business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable
segment information included in Note 11 (in millions):
Three-Month Periods
Ended June 30,
2023 2022
Electric Natural Gas Total Electric Natural Gas Total
Customer Revenue:
Retail:
Residential $ 95 $ 25 $ 120 $ 79 $ 19 $ 98
Commercial 102 12 114 82 6 88
Industrial 82 6 88 53 3 56
Other 1 — 1 1 — 1
Total fully bundled 280 43 323 215 28 243
Distribution only service 1 — 1 1 — 1
Total retail 281 43 324 216 28 244
Wholesale, transmission and other 12 — 12 14 — 14
Total Customer Revenue 293 43 336 230 28 258
Other revenue — 1 1 — — —
Total operating revenue $ 293 $ 44 $ 337 $ 230 $ 28 $ 258
Six-Month Periods
Ended June 30,
2023 2022
Electric Natural Gas Total Electric Natural Gas Total
Customer Revenue:
Retail:
Residential $ 210 $ 85 $ 295 $ 162 $ 51 $ 213
Commercial 193 39 232 151 21 172
Industrial 145 15 160 102 7 109
Other 3 — 3 3 — 3
Total fully bundled 551 139 690 418 79 497
Distribution only service 2 — 2 3 — 3
Total retail 553 139 692 421 79 500
Wholesale, transmission and other 44 — 44 35 — 35
Total Customer Revenue 597 139 736 456 79 535
Other revenue — 1 1 1 1 2
Total operating revenue $ 597 $ 140 $ 737 $ 457 $ 80 $ 537
149
(11)Segment Information
Sierra Pacific has identified two 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.
The following tables provide information on a reportable segment basis (in millions):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue:
Regulated electric $ 293 $ 230 $ 597 $ 457
Regulated natural gas 44 28 140 80
Total operating revenue $ 337 $ 258 $ 737 $ 537
Operating income:
Regulated electric $ 23 $ 19 $ 48 $ 49
Regulated natural gas 3 4 13 12
Total operating income 26 23 61 61
Interest expense (15) (14) (31) (27)
Allowance for borrowed funds 3 — 5 1
Allowance for equity funds 3 2 5 4
Interest and dividend income 5 4 12 7
Other, net 1 — 2 2
Total income before income tax expense (benefit)$ 23 $ 15 $ 54 $ 48
As of
June 30,December 31,
2023 2022
Assets:
Regulated electric $ 4,182 $ 4,224
Regulated natural gas 444 441
Other(1) 58 67
Total assets $ 4,684 $ 4,732
(1) Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.
150
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 Second Quarter and First Six Months of 2023 and 2022
Overview
Net income for the second quarter of 2023 was $20 million, an increase of $7 million, or 54%, compared to 2022 primarily due
to higher utility margin and higher allowance for borrowed funds, primarily due to increased construction work-in-progress,
partially offset by higher depreciation and amortization, mainly due to increased plant placed in-service and higher regulatory
amortizations. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with
new rates effective January 2023, partially offset by lower customer volumes and lower transmission and wholesale revenue.
Electric retail customer volumes, including distribution only service customers, decreased by 7.4% primarily due to the
unfavorable impact of weather, offset by an increase in the average number of customers. Energy generated decreased 1% for
the second quarter of 2023 compared to 2022 primarily due to lower coal-fueled generation offset by higher natural gas-fueled
generation. Wholesale electricity sales volumes increased 15% and purchased electricity volumes decreased 23%.
Net income for the first six months of 2023 was $47 million, an increase of $6 million, or 15%, compared to 2022 primarily due
to higher utility margin and higher interest and dividend income, primarily from carrying charges on regulatory balances,
partially offset by higher depreciation and amortization, mainly due to increased plant placed in-service and higher regulatory
amortizations, and increased operations and maintenance expenses, mainly due to higher plant operations and maintenance
expenses and increased customer service operations expenses. Electric utility margin increased primarily due to higher retail
rates due to the 2022 regulatory rate review with new rates effective January 2023 and higher transmission and wholesale
revenue, partially offset by lower customer volumes. Electric retail customer volumes, including distribution only service
customers, decreased by 2.6% primarily due to the unfavorable impact of weather, offset by an increase in the average number
of customers. Energy generated increased 5% for the first six months of 2023 compared to 2022 primarily due to higher natural
gas-fueled generation offset by lower coal-fueled generation. Wholesale electricity sales volumes decreased 11% and purchased
electricity volumes decreased 22%.
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.
151
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):
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Electric utility margin:
Operating revenue $ 293 $ 230 $ 63 27 %$ 597 $ 457 $ 140 31 %
Cost of fuel and energy 179 129 50 39 360 253 107 42
Electric utility margin 114 101 13 13 % 237 204 33 16 %
Natural gas utility margin:
Operating revenue 44 28 16 57 % 140 80 60 75 %
Natural gas purchased for resale 31 16 15 94 % 106 50 56 *
Natural gas utility margin 13 12 1 8 % 34 30 4 13 %
Utility margin 127 113 14 12 % 271 234 37 16 %
Operations and maintenance 49 47 2 4 % 105 88 17 19 %
Depreciation and amortization 46 37 9 24 92 73 19 26
Property and other taxes 6 6 — — 13 12 1 8
Operating income $ 26 $ 23 $ 3 13 %$ 61 $ 61 $ — — %
* Not meaningful
152
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Utility margin (in millions):
Operating revenue $ 293 $ 230 $ 63 27 %$ 597 $ 457 $ 140 31 %
Cost of fuel and energy 179 129 50 39 360 253 107 42
Utility margin $ 114 $ 101 $ 13 13 %$ 237 $ 204 $ 33 16 %
Sales (GWhs):
Residential 539 573 (34) (6) % 1,271 1,236 35 3 %
Commercial 735 778 (43) (6) 1,456 1,478 (22) (1)
Industrial 671 721 (50) (7) 1,317 1,476 (159) (11)
Other 3 3 — — 6 7 (1) (14)
Total fully bundled(1) 1,948 2,075 (127) (6) 4,050 4,197 (147) (4)
Distribution only service 670 752 (82) (11) 1,338 1,337 1 —
Total retail 2,618 2,827 (209) (7) 5,388 5,534 (146) (3)
Wholesale 131 114 17 15 360 405 (45) (11)
Total GWhs sold 2,749 2,941 (192) (7) % 5,748 5,939 (191) (3) %
Average number of retail customers (in thousands) 375 370 5 1 % 374 370 4 1 %
Average revenue per MWh:
Retail - fully bundled(1)$ 143.34 $ 103.25 $ 40.09 39 %$ 135.89 $ 99.79 $ 36.10 36 %
Wholesale $ 48.67 $ 65.84 $ (17.17) (26) %$ 86.26 $ 55.28 $ 30.98 56 %
Heating degree days 586 661 (75) (11) % 3,238 2,698 540 20 %
Cooling degree days 135 214 (79) (37) % 135 214 (79) (37) %
Sources of energy (GWhs)(2):
Natural gas 895 707 188 27 % 1,961 1,697 264 16 %
Coal 152 352 (200) (57) 353 505 (152) (30)
Renewables 9 8 1 13 13 13 — —
Total energy generated 1,056 1,067 (11) (1) 2,327 2,215 112 5
Energy purchased 1,227 1,590 (363) (23) 2,050 2,623 (573) (22)
Total 2,283 2,657 (374) (14) % 4,377 4,838 (461) (10) %
Average cost of energy per MWh(3):
Energy generated $ 62.36 $ 47.59 $ 14.77 31 %$ 84.21 $ 53.95 $ 30.26 56 %
Energy purchased $ 92.08 $ 49.73 $ 42.35 85 %$ 79.75 $ 51.09 $ 28.66 56 %
(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.
153
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
Second Quarter First Six Months
2023 2022 Change 2023 2022 Change
Utility margin (in millions):
Operating revenue $ 44 $ 28 $ 16 57 %$ 140 $ 80 $ 60 75 %
Natural gas purchased for resale 31 16 15 94 % 106 50 56 *
Utility margin $ 13 $ 12 $ 1 8 %$ 34 $ 30 $ 4 13 %
Sold (000's Dths):
Residential 1,843 1,797 46 3 % 7,709 6,349 1,360 21 %
Commercial 985 751 234 31 3,923 3,263 660 20
Industrial 581 402 179 45 1,647 1,055 592 56
Total retail 3,409 2,950 459 16 % 13,279 10,667 2,612 24 %
Average number of retail customers (in thousands) 182 179 3 2 % 182 179 3 2 %
Average revenue per retail Dth sold $ 12.79 $ 9.47 $ 3.32 35 %$ 10.52 $ 7.46 $ 3.06 42 %
Heating degree days 586 661 (75) (11) % 3,238 2,698 540 20 %
Average cost of natural gas per retail Dth sold $ 9.01 $ 5.48 $ 3.53 64 %$ 7.98 $ 4.67 $ 3.32 71 %
* Not meaningful
Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022
Electric utility margin increased $13 million, or 13%, for the second 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, offset
by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased
7.4% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers.
The increase in electric utility margin was offset by:
•$1 million of lower transmission and wholesale revenue.
Operations and maintenance increased $2 million, or 4%, for the second quarter of 2023 compared to 2022 primarily due to
higher plant operations and maintenance expenses and increased customer service operations expenses, partially offset by lower
regulatory-approved recovery for the ON Line reallocation (offset in operating revenue).
Depreciation and amortization increased $9 million, or 24%, for the second quarter of 2023 compared to 2022 primarily due to
increased plant placed in-service and higher regulatory amortizations.
Allowance for borrowed funds increased $3 million for the second quarter of 2023 compared to 2022 primarily due to higher
construction work-in-progress.
First Six Months of 2023 Compared to First Six Months of 2022
Electric utility margin increased $33 million, or 16%, for the first six months of 2023 compared to 2022 primarily due to:
•$28 million of higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, offset
by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased
2.6% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and
154
•$6 million of higher transmission and wholesale revenue.
Natural gas utility margin increased $4 million, or 13%, for the first six months of 2023 compared to 2022 primarily due to
higher customer volumes from the favorable impact of weather.
Operations and maintenance increased $17 million, or 19%, for the first six months of 2023 compared to 2022 primarily due to
higher plant operations and maintenance expenses, increased customer service operations expenses and higher regulatory-
approved amortization from the recovery for the ON Line reallocation (offset in operating revenue).
Depreciation and amortization increased $19 million, or 26%, for the first six months of 2023 compared to 2022 primarily due
to higher plant placed in-service and higher regulatory amortizations.
Interest expense increased $4 million, or 15%, for the first six months of 2023 compared to 2022 primarily due to higher
interest rates.
Allowance for borrowed funds increased $4 million for the first six months of 2023 compared to 2022 primarily due to higher
construction work-in-progress.
Interest and dividend income increased $5 million, or 71%, for the first six months of 2023 compared to 2022 primarily due to
higher interest income, mainly from carrying charges on regulatory balances.
Liquidity and Capital Resources
As of June 30, 2023, Sierra Pacific's total net liquidity was as follows (in millions):
Cash and cash equivalents $ 37
Credit facility 400
Total net liquidity $ 437
Credit facility:
Maturity date 2026
Operating Activities
Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022, were $232 million and
$108 million, respectively. The change was primarily due to higher collections from customers, partially offset by higher
payments related to fuel and energy costs and the timing of payments for operating 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 six-month periods ended June 30, 2023 and 2022, were $(170) million and
$(191) million, respectively. The change was primarily due to decreased capital expenditures. Refer to "Future Uses of Cash"
for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the six-month periods ended June 30, 2023 and 2022, were $(74) million and
$91 million, respectively. The change was primarily due to lower contributions from NV Energy, Inc., lower proceeds from the
issuance of long-term debt and higher repayments of an affiliate note payable, partially offset by lower long-term debt
reacquired, lower repayments of short-term debt and lower dividends paid to NV Energy, Inc.
155
Debt Authorizations
Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited
to a debt ceiling of $1.9 billion (excluding borrowings under Sierra Pacific's $400 million secured credit facility); and (2)
maintain a revolving credit facility of up to $600 million.
Future Uses of Cash
Sierra Pacific has available a variety of sources of liquidity and capital resources, both internal and external, including net cash
flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital
contributions and other sources. These sources are expected to provide funds required for current operations, capital
expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access
to external financing depends on a variety of factors, including regulatory approvals, Sierra Pacific's credit ratings, investors'
judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews,
which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customer rates;
outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system
reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and
availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies,
replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates.
Sierra Pacific's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and
other non-cash items are as follows (in millions):
Six-Month Periods Annual
Ended June 30,Forecast
2022 2023 2023
Electric distribution $ 46 $ 72 $ 166
Electric transmission 45 47 98
Solar generation — 1 1
Electric battery storage — 2 3
Other 100 48 126
Total $ 191 $ 170 $ 394
Sierra Pacific received PUCN approval through its previous IRP filings for an increase in solar generation and electric
transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2023. These
estimates may change as a result of the RFP process. Sierra Pacific's historical and forecast capital expenditures include the
following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for
distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the
Nevada Utilities' Greenlink Nevada transmission expansion program. Sierra Pacific has received approval from the
PUCN to build a 350-mile, 525-kV transmission line connecting the Ft. Churchill substation to the Northwest
substation to the Harry Allen substation; a 235-mile, 525-kV transmission line connecting the new Ft. Churchill
substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill
substation to the Mira Loma substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation
to the Robinson Summit substation. Operating expenditures consist of routine expenditures for transmission and other
infrastructure needed to serve existing and expected demand.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating
facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing
and expected demand.
156
Material Cash Requirements
As of June 30, 2023, there have been no material changes outside the normal course of business in material cash requirements
from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31,
2022.
Regulatory Matters
Sierra Pacific is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I,
Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's current regulatory matters.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions
performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact Sierra
Pacific's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations
provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other
sanctions. These laws and regulations are administered by various federal, state and local agencies. Sierra Pacific believes it is
in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately
be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the
impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional
information regarding environmental laws and regulations.
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.
157
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
158
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 June 30, 2023, the related consolidated statements of operations, comprehensive income, and
changes in equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the six-
month periods ended June 30, 2023 and 2022, and the related notes (collectively referred to as the "interim financial
information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying
interim financial information for it to be in conformity with accounting principles generally accepted in the United States of
America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheet of Eastern Energy Gas as of December 31, 2022, and the related consolidated
statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented
herein); and in our report dated February 24, 2023, we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2022,
is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Eastern Energy Gas' management. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to Eastern Energy Gas in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists
principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.
It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which
is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an
opinion.
/s/ Deloitte & Touche LLP
Richmond, Virginia
August 4, 2023
159
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
ASSETS
Current assets:
Cash and cash equivalents $ 82 $ 65
Trade receivables, net 153 202
Receivables from affiliates 21 30
Notes receivable from affiliates 449 536
Inventories 134 127
Prepayments and other deferred charges 31 78
Natural gas imbalances 28 193
Other current assets 70 72
Total current assets 968 1,303
Property, plant and equipment, net 10,309 10,202
Goodwill 1,286 1,286
Investments 278 278
Other assets 90 95
Total assets $ 12,931 $ 13,164
The accompanying notes are an integral part of these consolidated financial statements.
160
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of
June 30, 2023 December 31, 2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 40 $ 86
Accounts payable to affiliates 1 10
Accrued property, income and other taxes 65 77
Regulatory liabilities 37 126
Current portion of long-term debt 400 649
Other current liabilities 145 165
Total current liabilities 688 1,113
Long-term debt 3,248 3,243
Regulatory liabilities 597 596
Other long-term liabilities 354 324
Total liabilities 4,887 5,276
Commitments and contingencies (Note 9)
Equity:
Member's equity:
Membership interests 4,152 3,983
Accumulated other comprehensive loss, net (38) (42)
Total member's equity 4,114 3,941
Noncontrolling interests 3,930 3,947
Total equity 8,044 7,888
Total liabilities and equity $ 12,931 $ 13,164
The accompanying notes are an integral part of these consolidated financial statements.
161
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue $ 521 $ 504 $ 1,074 $ 986
Operating expenses:
Cost of (excess) gas 5 (21) 25 (22)
Operations and maintenance 134 124 277 242
Depreciation and amortization 80 80 160 165
Property and other taxes 26 37 63 66
Total operating expenses 245 220 525 451
Operating income 276 284 549 535
Other income (expense):
Interest expense (35) (36) (72) (72)
Allowance for equity funds 2 1 4 3
Interest and dividend income 11 — 20 —
Other, net 1 — 1 (1)
Total other income (expense) (21) (35) (47) (70)
Income before income tax expense (benefit) and equity income (loss) 255 249 502 465
Income tax expense (benefit) 31 37 70 67
Equity income (loss) 6 9 38 28
Net income 230 221 470 426
Net income attributable to noncontrolling interests 131 118 249 229
Net income attributable to Eastern Energy Gas $ 99 $ 103 $ 221 $ 197
The accompanying notes are an integral part of these consolidated financial statements.
162
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Net income $ 230 $ 221 $ 470 $ 426

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $—, $—, $— and $— — — (1) 1
Unrealized gains (losses) on cash flow hedges, net of tax of $4, $—, $3 and $1 7 (1) 5 3
Total other comprehensive income (loss), net of tax 7 (1) 4 4

Comprehensive income 237 220 474 430
Comprehensive income attributable to noncontrolling interests 131 118 249 229
Comprehensive income attributable to Eastern Energy Gas $ 106 $ 102 $ 225 $ 201
The accompanying notes are an integral part of these consolidated financial statements.
163
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
Accumulated
Other
Membership Comprehensive Noncontrolling Total
Interests Loss, Net Interests Equity
Balance, March 31, 2022 $ 3,595 $ (38) $ 4,033 $ 7,590
Net income 103 — 118 221
Other comprehensive loss — (1) — (1)
Distributions (33) — (128) (161)
Contributions 68 — — 68
Balance, June 30, 2022 $ 3,733 $ (39) $ 4,023 $ 7,717
Balance, December 31, 2021 $ 3,501 $ (43) $ 4,036 $ 7,494
Net income 197 — 229 426
Other comprehensive income — 4 — 4
Distributions (33) — (242) (275)
Contributions 68 — — 68
Balance, June 30, 2022 $ 3,733 $ (39) $ 4,023 $ 7,717
Balance, March 31, 2023 $ 4,109 $ (45) $ 3,941 $ 8,005
Net income 99 — 131 230
Other comprehensive income — 7 — 7
Distributions (79) — (142) (221)
Contributions 23 — — 23
Balance, June 30, 2023 $ 4,152 $ (38) $ 3,930 $ 8,044
Balance, December 31, 2022 $ 3,983 $ (42) $ 3,947 $ 7,888
Net income 221 — 249 470
Other comprehensive income — 4 — 4
Distributions (85) — (266) (351)
Contributions 33 — — 33
Balance, June 30, 2023 $ 4,152 $ (38) $ 3,930 $ 8,044
The accompanying notes are an integral part of these consolidated financial statements.
164
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods
Ended June 30,
2023 2022
Cash flows from operating activities:
Net income $ 470 $ 426
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on other items, net (7) 2
Depreciation and amortization 160 165
Allowance for equity funds (4) (3)
Equity loss (income), net of distributions 2 (5)
Changes in regulatory assets and liabilities (92) (2)
Deferred income taxes 47 52
Other, net — 5
Changes in other operating assets and liabilities:
Trade receivables and other assets 89 26
Receivables from affiliates 8 32
Gas balancing activities 17 (22)
Derivative collateral, net 2 (3)
Accrued property, income and other taxes 6 (3)
Accounts payable to affiliates (9) (32)
Accounts payable and other liabilities (45) 43
Net cash flows from operating activities 644 681
Cash flows from investing activities:
Capital expenditures (124) (151)
Proceeds from assignment of shale development rights 8 —
Repayment of notes by affiliates 252 15
Notes to affiliates (166) (204)
Other, net (3) (7)
Net cash flows from investing activities (33) (347)
Cash flows from financing activities:
Repayments of long-term debt (250) —
Distributions to noncontrolling interests (266) (242)
Distributions to parent (78) —
Net cash flows from financing activities (594) (242)
Net change in cash and cash equivalents and restricted cash and cash equivalents 17 92
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 95 39
Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 112 $ 131
The accompanying notes are an integral part of these consolidated financial statements.
165
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
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 100% of the general partner
interest and 25% of the limited partner interests in Cove Point. In addition, Eastern Energy Gas owns a 50% noncontrolling
interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 416-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.
The 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 June 30, 2023 and for the three- and
six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended
June 30, 2023 are not necessarily indicative of the results to be expected for the full year.
The 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 six-month period ended June 30, 2023.
(2) Business Acquisitions
On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of
Eastern Energy Gas, entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc.
("DEI") and DECP Holdings, Inc. (the "Seller"), an indirect wholly owned subsidiary of DEI, to purchase (the "Transaction")
Seller's 50% limited partner interests in Cove Point for a cash purchase price of $3.3 billion, plus the pro rata portion of any
quarterly distribution made by Cove Point for the fiscal quarter in which the Transaction closes. Eastern Energy Gas expects to
fund the purchase price with equity contributions from BHE. Upon the completion of the Transaction, the Buyer will own an
aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, will continue to own
100% of the general partner interest, of Cove Point.
The consummation of the Transaction contemplated by the Purchase Agreement is subject to customary closing conditions,
including without limitation (i) the expiration or termination of any applicable waiting periods under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended, (ii) the filing of a notification with the U.S. Department of Energy and the
expiration of any applicable period; and (iii) the accuracy of the representations and warranties and compliance by the parties in
all material respects with their respective obligations under the Purchase Agreement. The Transaction is expected to close by
year-end 2023, subject to satisfaction of the foregoing conditions, among other things.
The Purchase Agreement provides that if the Seller or DEI terminates the Purchase agreement due to a breach of the Purchase
Agreement by the Buyer or Buyer's failure to consummate the Transaction within three business days after all of the conditions
to close have been satisfied or waived, BHE will pay to the Seller a termination fee of $150 million.
166
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of
June 30,December 31,
Depreciable Life 2023 2022
Utility plant:
Interstate natural gas transmission and storage assets 21 - 51 years $ 9,132 $ 8,922
Intangible plant 5 - 17 years 116 113
Utility plant in-service 9,248 9,035
Accumulated depreciation and amortization (3,118) (3,039)
Utility plant in-service, net 6,130 5,996
Nonutility plant:
LNG facility 40 years 4,526 4,522
Intangible plant 14 years 25 25
Nonutility plant 4,551 4,547
Accumulated depreciation and amortization (605) (542)
Nonutility plant, net 3,946 4,005
10,076 10,001
Construction work-in-progress 233 201
Property, plant and equipment, net $ 10,309 $ 10,202
Construction work-in-progress includes $218 million and $181 million as of June 30, 2023 and December 31, 2022,
respectively, related to the construction of utility plant.
Assignment of Shale Development Rights
In June 2023, Eastern Gas Transmission and Storage, Inc. ("EGTS") conveyed development rights to a natural gas producer for
approximately 6,500 acres of Utica Shale and Point Pleasant Formation underneath one of its natural gas storage fields and
received proceeds of $8 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in
an $8 million ($6 million after-tax) gain, included in operations and maintenance expense in its Consolidated Statements of
Operations.
(4) Regulatory Matters
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective
November 1, 2021. EGTS proposed an annual cost-of-service of approximately $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.
167
(5) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following (in millions):
As of
June 30,December 31,
2023 2022
Investments:
Investment funds $ 18 $ 14
Equity method investments:
Iroquois 260 264
Total investments 278 278
Restricted cash and cash equivalents:
Customer deposits 30 30
Total restricted cash and cash equivalents 30 30
Total investments and restricted cash and cash equivalents $ 308 $ 308
Reflected as:
Current assets $ 30 $ 30
Noncurrent assets 278 278
Total investments and restricted cash and cash equivalents $ 308 $ 308
Equity Method Investments
Eastern Energy Gas, through subsidiaries, owns 50% of Iroquois, which owns and operates an interstate natural gas
transmission system located in the states of New York and Connecticut.
As of June 30, 2023 and December 31, 2022, the carrying amount of Eastern Energy Gas' investments exceeded its share of
underlying equity in net assets by $130 million. The difference reflects equity method goodwill and is not being amortized.
Eastern Energy Gas received distributions from its investments of $40 million and $23 million for the six-month periods ended
June 30, 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. A 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):
As of
June 30,December 31,
2023 2022
Cash and cash equivalents $ 82 $ 65
Restricted cash and cash equivalents included in other current assets 30 30
Total cash and cash equivalents and restricted cash and cash equivalents $ 112 $ 95
168
(6) Income Taxes
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:
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Federal statutory income tax rate 21 % 21 % 21 % 21 %
State income tax, net of federal income tax benefit 2 3 2 4
Equity interest 1 1 1 1
Effects of ratemaking — — — (2)
Noncontrolling interest (11) (10) (10) (10)
Other, net (1) — — —
Effective income tax rate 12 % 15 % 14 % 14 %
For the period ended June 30, 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 75% noncontrolling interest.
(7) Employee 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 $4 million and
$6 million to the MidAmerican Energy Company Retirement Plan for the six-month periods ended June 30, 2023 and 2022,
respectively, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the six-month periods ended
June 30, 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 June 30, 2023 and December 31, 2022, Eastern Energy Gas' amount due to
MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets
was $51 million.
(8) Fair 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.
169
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):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Total
As of June 30, 2023:
Assets:
Money market mutual funds $ 95 $ — $ — $ 95
Equity securities:
Investment funds 18 — — 18
$ 113 $ — $ — $ 113
Liabilities:
Commodity derivatives $ — $ (1) $ — $ (1)
Foreign currency exchange rate derivatives — (11) — (11)
$ — $ (12) $ — $ (12)
As of December 31, 2022:
Assets:
Commodity derivatives $ — $ 1 $ — $ 1
Money market mutual funds 42 — — 42
Equity securities:
Investment funds 14 — — 14
$ 56 $ 1 $ — $ 57
Liabilities:
Foreign currency exchange rate derivatives $ — $ (20) $ — $ (20)
$ — $ (20) $ — $ (20)
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.
170
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. The following table presents the carrying value and estimated fair
value of Eastern Energy Gas' long-term debt (in millions):
As of June 30, 2023 As of December 31, 2022
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $ 3,648 $ 3,295 $ 3,892 $ 3,510
(9) Commitments and Contingencies
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions
performance standards, water quality and other environmental matters that have the potential to impact its current and future
operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
Legal Matters
Eastern Energy Gas is party to a variety of legal actions arising out of the normal course of business. Eastern Energy Gas does
not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
(10) Revenue from Contracts with Customers
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):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Customer Revenue:
Regulated:
Gas transmission and storage $ 294 $ 286 $ 626 $ 571
Other (1) — 1 —
Total regulated 293 286 627 571
Nonregulated 226 216 443 419
Total Customer Revenue 519 502 1,070 990
Other revenue(1) 2 2 4 (4)
Total operating revenue $ 521 $ 504 $ 1,074 $ 986
(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 $35 million and $80 million as of June 30, 2023 and December 31,
2022, respectively, due to the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern
Energy Gas recognizes revenue as it fulfills its obligations to provide services to its customers. During the six-month period
ended June 30, 2023, Eastern Energy Gas recognized revenue of $49 million from the beginning contract liability balance.
171
Remaining Performance Obligations
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 June 30,
2023 (in millions):
Performance obligations expected to be satisfied
Less than 12 months More than 12 months Total
Eastern Energy Gas $ 1,662 $ 15,132 $ 16,794
(11) Components of Accumulated Other Comprehensive Loss, Net
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):
Unrecognized Accumulated
Amounts On Unrealized Other
Retirement Losses on Cash Noncontrolling Comprehensive
Benefits Flow Hedges Interests Loss, Net
Balance, December 31, 2021 $ (6) $ (42) $ 5 $ (43)
Other comprehensive income 1 3 — 4
Balance, June 30, 2022 $ (5) $ (39) $ 5 $ (39)
Balance, December 31, 2022 $ (1) $ (43) $ 2 $ (42)
Other comprehensive (loss) income (1) 5 — 4
Balance, June 30, 2023 $ (2) $ (38) $ 2 $ (38)
172
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 Second Quarter and First Six Months of 2023 and 2022
Overview
Net income attributable to Eastern Energy Gas for the second quarter of 2023 was $99 million, a decrease of $4 million, or 4%,
compared to 2022. Net income decreased primarily due to lower margin from EGTS' regulated gas transmission and storage
operations of $24 million, partially offset by lower than estimated 2022 tax assessments and a gain from an agreement to
convey development rights underneath one of its natural gas storage fields.
Net income attributable to Eastern Energy Gas for the first six months of 2023 was $221 million, an increase of $24 million, or
12%, compared to 2022. Net income increased primarily due to interest income from higher outstanding loans and higher
interest rates under BHE GT&S' intercompany revolving credit agreement with Eastern Energy Gas, higher earnings from
Iroquois due to favorable negotiated rate agreements and hedges, a gain from an agreement to convey development rights
underneath one of its natural gas storage fields, lower depreciation rates due to the settlement in EGTS' general rate case, higher
margin from EGTS' regulated gas transmission and storage operations of $8 million and additional LNG revenues from Cove
Point of $8 million, partially offset by higher technology and related charges and an increase in salaries, wages and benefits.
Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022
Operating revenue increased $17 million, or 3%, for the second 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 of $22 million,
an increase in variable revenue related to park and loan activity of $10 million and an increase in regulated gas transmission and
storage services revenues due to the settlement of EGTS' general rate case of $8 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 $11 million and a decrease in Cove Point LNG variable revenue of $5 million.
Cost of (excess) gas was an expense of $5 million for the second quarter of 2023 compared to a credit of $21 million for the
second quarter of 2022. The change is primarily from a decrease in other operational and system balancing fuel activities prior
to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $14 million and the unfavorable
revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of
$12 million.
Operations and maintenance increased $10 million, or 8%, for the second quarter of 2023 compared to 2022, primarily due to
higher technology and related charges of $9 million and an increase in salaries, wages and benefits of $9 million, partially offset
by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.
Property and other taxes decreased $11 million, or 30%, for the second quarter of 2023 compared to 2022, primarily due to
lower than estimated 2022 tax assessments.
Interest and dividend income increased $11 million for the second quarter of 2023 compared to 2022, primarily due to interest
income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement
with Eastern Energy Gas of $8 million and income from money market mutual fund investments of $2 million.
Income tax expense decreased $6 million, or 16%, for the second quarter of 2023 compared to 2022, primarily due to lower pre-
tax income and the effective tax rate was 12% for 2023 and 15% for 2022. The effective tax rate decreased primarily due to the
reduction in the Pennsylvania statutory rate.
Net income attributable to noncontrolling interests increased $13 million, or 11%, for the second 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.
173
First Six Months of 2023 Compared to First Six Months of 2022
Operating revenue increased $88 million, or 9%, for the first six months of 2023 compared to 2022, primarily due to an
increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of
$50 million, increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in
2022 of $41 million, an increase in variable revenue related to park and loan activity of $20 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 $17 million and a decrease in
Cove Point LNG variable revenue of $8 million.
Cost of (excess) gas was an expense of $25 million for the first six months of 2023 compared to a credit of $22 million for the
first six months 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 the settlement of EGTS' general rate case due to lower natural gas prices of $35 million and a
decrease from other operational and system balancing fuel activities prior to the effective date of the new fuel tracker of
$14 million.
Operations and maintenance increased $35 million, or 14%, for the first six months of 2023 compared to 2022, primarily due to
higher technology and related charges of $19 million, an increase in salaries, wages and benefits of $15 million and an increase
in Cove Point outside services of $3 million, partially offset by a gain from an agreement to convey development rights
underneath one of its natural gas storage fields of $8 million.
Depreciation and amortization decreased $5 million, or 3%, for the first six months 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 decreased $3 million, or 5%, for the first six months of 2023 compared to 2022, primarily due to
lower than estimated 2022 tax assessments.
Interest and dividend income increased $20 million for the first six months of 2023 compared to 2022, primarily due to interest
income from higher outstanding loans and higher interest rates under BHE GT&S' intercompany revolving credit agreement
with Eastern Energy Gas of $15 million and income from money market mutual fund investments of $4 million.
Income tax expense increased $3 million, or 4%, for the first six months of 2023 compared to 2022, primarily due to higher pre-
tax income. The effective tax rate was 14% for 2023 and 2022.
Equity income increased $10 million, or 36%, for the first six months of 2023 compared to 2022, primarily due to higher
earnings from Iroquois due to favorable negotiated rate agreements and hedges.
Net income attributable to noncontrolling interests increased $20 million, or 9%, for the first six months 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 a decrease in Cove Point LNG variable revenue and an increase in Cove Point outside
services.
Liquidity and Capital Resources
As of June 30, 2023, Eastern Energy Gas' total net liquidity was as follows (in millions):
Cash and cash equivalents $ 82
Intercompany revolving credit agreement 400
Total net liquidity $ 482
Intercompany revolving credit agreement:
Maturity date 2024
174
Operating Activities
Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022 were $644 million and
$681 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, higher collections from customers 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 six-month periods ended June 30, 2023 and 2022 were $(33) million and
$(347) million, respectively. The change is primarily due to an increase in repayments of loans by affiliates of $237 million, a
decrease in loans to its parent under an intercompany revolving credit agreement of $38 million, a decrease in capital
expenditures of $27 million and proceeds from the assignment of shale development rights of $8 million.
Financing Activities
Net cash flows from financing activities for the six-month period ended June 30, 2023 were $(594) million and consisted of
distributions to noncontrolling interests from Cove Point of $266 million, repayment of long-term debt of $250 million and
distributions to its indirect parent, BHE, of $78 million.
Net cash flows from financing activities for the six-month period ended June 30, 2022 were $(242) 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.
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):
Six-Month Periods Annual
Ended June 30,Forecast
2022 2023 2023
Natural gas transmission and storage $ 23 $ 11 $ 40
Other 128 113 375
Total $ 151 $ 124 $ 415
175
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.
Cove Point Acquisition
On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the Buyer"), an indirect wholly owned subsidiary of
Eastern Energy Gas, entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Dominion Energy, Inc.
("DEI") and DECP Holdings, Inc. (the "Seller"), an indirect wholly owned subsidiary of DEI, to purchase (the "Transaction")
Seller's 50% limited partner interests in Cove Point for a cash purchase price of $3.3 billion, plus the pro rata portion of any
quarterly distribution made by Cove Point for the fiscal quarter in which the Transaction closes. Eastern Energy Gas expects to
fund the purchase price with equity contributions from BHE. Upon the completion of the Transaction, the Buyer will own an
aggregate of 75% of the limited partner interests, and its affiliate, Cove Point GP Holding Company, LLC, will continue to own
100% of the general partner interest, of Cove Point. Subject to certain closing conditions, the Transaction is expected to close
by year-end 2023.
Material Cash Requirements
As of June 30, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of
Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2022.
Regulatory Matters
Eastern Energy Gas is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part
I, Item 2 of this Form 10-Q for discussion regarding Eastern Energy Gas' current regulatory matters.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions
performance standards, water quality and other environmental matters that have the potential to impact its current and future
operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the
authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and
regulations are administered by various federal, state and local agencies. Eastern Energy Gas believes it is in material
compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved
by the courts. Environmental laws and regulations continue to evolve, and Eastern Energy Gas is unable to predict the impact of
the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional
information regarding environmental laws and regulations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be
settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates
involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will
likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the
accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets and income taxes. For
additional discussion of Eastern Energy Gas' critical accounting estimates, see Item 7 of Eastern Energy Gas' Annual Report on
Form 10-K for the year ended December 31, 2022. There have been no significant changes in Eastern Energy Gas' assumptions
regarding critical accounting estimates since December 31, 2022.
176
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Consolidated Financial Section
177
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 June 30, 2023, the related consolidated statements of operations, comprehensive income, and
changes in shareholder's equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for
the six-month periods ended June 30, 2023 and 2022, and the related notes (collectively referred to as the "interim financial
information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying
interim financial information for it to be in conformity with accounting principles generally accepted in the United States of
America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (PCAOB), the consolidated balance sheet of EGTS as of December 31, 2022 and the related consolidated statements of
operations, comprehensive income (loss), changes in shareholder's equity, and cash flows for the year then ended (not presented
herein); and in our report dated February 24, 2023 we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2022,
is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of EGTS' management. We are a public accounting firm registered with
the PCAOB and are required to be independent with respect to EGTS in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists
principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.
It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which
is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an
opinion.
/s/ Deloitte & Touche LLP
Richmond, Virginia
August 4, 2023
178
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of
June 30,December 31,
2023 2022
ASSETS
Current assets:
Cash and cash equivalents $ 22 $ 16
Restricted cash and cash equivalents 28 29
Trade receivables, net 71 113
Receivables from affiliates 12 13
Inventories 53 50
Income taxes receivable 27 21
Prepayments and other deferred charges 26 36
Natural gas imbalances 26 193
Other current assets 6 9
Total current assets 271 480
Property, plant and equipment, net 4,655 4,504
Other assets 161 190
Total assets $ 5,087 $ 5,174
The accompanying notes are an integral part of these consolidated financial statements.
179
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions, except share data)
As of
June 30, 2023 December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable $ 31 $ 46
Accounts payable to affiliates 3 5
Accrued property, income and other taxes 56 71
Accrued employee expenses 27 13
Notes payable to affiliates 40 36
Regulatory liabilities 26 109
Customer and security deposits 28 29
Asset retirement obligations 16 25
Other current liabilities 36 39
Total current liabilities 263 373
Long-term debt 1,583 1,582
Regulatory liabilities 519 518
Other long-term liabilities 99 101
Total liabilities 2,464 2,574
Commitments and contingencies (Note 8)
Shareholder's equity:
Common stock - 75,000 shares authorized, $10,000 par value, 60,101 issued and outstanding 609 609
Additional paid-in capital 1,300 1,275
Retained earnings 743 746
Accumulated other comprehensive loss, net (29) (30)
Total shareholder's equity 2,623 2,600
Total liabilities and shareholder's equity $ 5,087 $ 5,174
The accompanying notes are an integral part of these consolidated financial statements.
180
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Operating revenue $ 236 $ 234 $ 514 $ 457
Operating expenses:
Cost of (excess) gas 5 (21) 25 (24)
Operations and maintenance 95 86 194 170
Depreciation and amortization 37 38 74 81
Property and other taxes 7 15 21 24
Total operating expenses 144 118 314 251
Operating income 92 116 200 206
Other income (expense):
Interest expense (17) (17) (35) (34)
Allowance for equity funds 2 1 3 2
Other, net 2 (1) 2 (1)
Total other income (expense) (13) (17) (30) (33)
Income before income tax expense (benefit) 79 99 170 173
Income tax expense (benefit) 20 28 43 47
Net income $ 59 $ 71 $ 127 $ 126
The accompanying notes are an integral part of these consolidated financial statements.
181
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Net income $ 59 $ 71 $ 127 $ 126
Other comprehensive income, net of tax:
Unrealized gains on cash flow hedges, net of tax of $—, $—, $— and $— — — 1 1
Total other comprehensive income, net of tax — — 1 1
Comprehensive income $ 59 $ 71 $ 128 $ 127
The accompanying notes are an integral part of these consolidated financial statements.
182
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
Accumulated
Additional Other Total
Common Stock Paid-in Retained Comprehensive Shareholder's
Shares Amount Capital Earnings Loss, Net Equity
Balance, March 31, 2022 60,101 $ 609 $ 1,241 $ 776 $ (30) $ 2,596
Net income — — — 71 — 71
Dividends declared — — — (97) — (97)
Contributions — — 13 — — 13
Balance, June 30, 2022 60,101 $ 609 $ 1,254 $ 750 $ (30) $ 2,583
Balance, December 31, 2021 60,101 $ 609 $ 1,241 $ 721 $ (31) $ 2,540
Net income — — — 126 — 126
Other comprehensive income — — — — 1 1
Dividends declared — — — (97) — (97)
Contributions — — 13 — — 13
Balance, June 30, 2022 60,101 $ 609 $ 1,254 $ 750 $ (30) $ 2,583
Balance, March 31, 2023 60,101 $ 609 $ 1,282 $ 805 $ (29) $ 2,667
Net income — — — 59 — 59
Dividends declared — — — (121) — (121)
Contributions — — 18 — — 18
Balance, June 30, 2023 60,101 $ 609 $ 1,300 $ 743 $ (29) $ 2,623
Balance, December 31, 2022 60,101 $ 609 $ 1,275 $ 746 $ (30) $ 2,600
Net income — — — 127 — 127
Other comprehensive income — — — — 1 1
Dividends declared — — — (130) — (130)
Contributions — — 25 — — 25
Balance, June 30, 2023 60,101 $ 609 $ 1,300 $ 743 $ (29) $ 2,623
The accompanying notes are an integral part of these consolidated financial statements.
183
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods
Ended June 30,
2023 2022
Cash flows from operating activities:
Net income $ 127 126
Adjustments to reconcile net income to net cash flows from operating activities:
(Gains) losses on other items, net (8) 1
Depreciation and amortization 74 81
Allowance for equity funds (3) (2)
Changes in regulatory assets and liabilities (80) (9)
Deferred income taxes 30 30
Other, net (1) 4
Changes in other operating assets and liabilities:
Trade receivables and other assets 53 28
Receivables from affiliates 1 1
Gas balancing activities 21 (22)
Accrued property, income and other taxes (15) (8)
Accounts payable and other liabilities 8 49
Accounts payable to affiliates (3) 2
Net cash flows from operating activities 204 281
Cash flows from investing activities:
Capital expenditures (86) (109)
Proceeds from assignment of shale development rights 8 —
Repayment of notes by affiliates — 10
Notes to affiliates — (8)
Other, net (3) (6)
Net cash flows from investing activities (81) (113)
Cash flows from financing activities:
Issuance (repayment) of notes payable to affiliates, net 4 (61)
Dividends paid (122) (80)
Net cash flows from financing activities (118) (141)
Net change in cash and cash equivalents and restricted cash and cash equivalents 5 27
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period 45 26
Cash and cash equivalents and restricted cash and cash equivalents at end of period $ 50 $ 53
The accompanying notes are an integral part of these consolidated financial statements.
184
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
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.
The 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 June 30, 2023 and for the three- and
six-month periods ended June 30, 2023 and 2022. The results of operations for the three- and six-month periods ended June 30,
2023 are not necessarily indicative of the results to be expected for the full year.
The 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 six-
month period ended June 30, 2023.
(2) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of
June 30,December 31,
Depreciable Life 2023 2022
Interstate natural gas transmission and storage assets 28 - 50 years $ 6,890 $ 6,724
Intangible plant 12 - 19 years 80 79
Plant in-service 6,970 6,803
Accumulated depreciation and amortization (2,498) (2,440)
4,472 4,363
Construction work-in-progress 183 141
Property, plant and equipment, net $ 4,655 $ 4,504
Assignment of Shale Development Rights
In June 2023, EGTS conveyed development rights to a natural gas producer for approximately 6,500 acres of Utica Shale and
Point Pleasant Formation underneath one of its natural gas storage fields and received proceeds of $8 million and an overriding
royalty interest in gas produced from the acreage. This transaction resulted in an $8 million ($6 million after-tax) gain, included
in operations and maintenance expense in its Consolidated Statements of Operations.
185
(3) Regulatory Matters
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective
November 1, 2021. EGTS proposed an annual cost-of-service of approximately $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.
(4) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following (in millions):
As of
June 30,December 31,
2023 2022
Investments:
Investment funds $ 18 $ 14
Restricted cash and cash equivalents:
Customer deposits 28 29
Total restricted cash and cash equivalents 28 29
Total investments and restricted cash and cash equivalents $ 46 $ 43
Reflected as:
Current assets $ 28 $ 29
Noncurrent assets 18 14
Total investments and restricted cash and cash equivalents $ 46 $ 43
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. A 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):
As of
June 30,December 31,
2023 2022
Cash and cash equivalents $ 22 $ 16
Restricted cash and cash equivalents 28 29
Total cash and cash equivalents and restricted cash and cash equivalents $ 50 $ 45
186
(5) Income Taxes
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:
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Federal statutory income tax rate 21 % 21 % 21 % 21 %
State income tax, net of federal income tax benefit 5 7 5 6
Allowance for funds used during construction-equity (1) — — —
Other, net — — (1) —
Effective income tax rate 25 % 28 % 25 % 27 %
(6) Employee 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 $4 million and $5 million to the MidAmerican
Energy Company Retirement Plan for the six-month periods ended June 30, 2023 and 2022, respectively, and $1 million to the
MidAmerican Energy Company Welfare Benefit Plan for the six-month periods ended June 30, 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 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 June 30,
2023 and December 31, 2022, EGTS' amount due to MidAmerican Energy associated with these plans and reflected in other
long-term liabilities on the Consolidated Balance Sheets was $47 million.
(7) Fair 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.
187
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):
Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Total
As of June 30, 2023:
Assets:
Money market mutual funds $ 29 $ — $ — $ 29
Equity securities:
Investment funds 18 — — 18
$ 47 $ — $ — $ 47
Liabilities:
Commodity derivatives $ — $ (1) $ — $ (1)
$ — $ (1) $ — $ (1)
As of December 31, 2022:
Assets:
Commodity derivatives $ — $ 1 $ — $ 1
Money market mutual funds 8 — — 8
Equity securities:
Investment funds 14 — — 14
$ 22 $ 1 $ — $ 23
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. The following
table presents the carrying value and estimated fair value of EGTS' long-term debt (in millions):
As of June 30, 2023 As of December 31, 2022
CarryingValue FairValue CarryingValue FairValue
Long-term debt $ 1,583 $ 1,354 $ 1,582 $ 1,337
188
(8) Commitments and Contingencies
Environmental Laws and Regulations
EGTS is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance
standards, water quality and other environmental matters that have the potential to impact its current and future operations.
EGTS believes it is in material compliance with all applicable laws and regulations.
Legal Matters
EGTS is party to a variety of legal actions arising out of the normal course of business. EGTS does not believe that such normal
and routine litigation will have a material impact on its consolidated financial results.
(9) Revenue from Contracts with Customers
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):
Three-Month Periods Six-Month Periods
Ended June 30,Ended June 30,
2023 2022 2023 2022
Customer Revenue:
Regulated:
Gas transmission $ 151 $ 145 $ 342 $ 310
Gas storage 70 69 137 116
Other (2) — — —
Total regulated 219 214 479 426
Management service and other revenues 15 19 32 37
Total Customer Revenue 234 233 511 463
Other revenue(1) 2 1 3 (6)
Total operating revenue $ 236 $ 234 $ 514 $ 457
(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
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 June 30, 2023 (in
millions):
Performance obligations expected to be satisfied
Less than 12 months More than 12 months Total
EGTS $ 757 $ 3,339 $ 4,096
189
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 Second Quarter and First Six Months of 2023 and 2022
Overview
Net income for the second quarter of 2023 was $59 million, a decrease of $12 million, or 17%, compared to 2022. Net income
decreased primarily due to lower margin from regulated gas transmission and storage operations of $24 million, an increase in
salaries, wages and benefits and higher technology and related charges, partially offset by a gain from an agreement to convey
development rights underneath one of its natural gas storage fields, lower than estimated 2022 tax assessments and lower
income tax expense primarily due to lower pre-tax income.
Net income for the first six months of 2023 was $127 million, an increase of $1 million, or 1%, compared to 2022. Net income
increased primarily due to higher margin from regulated gas transmission and storage operations of $8 million, a gain from an
agreement to convey development rights underneath one of its natural gas storage fields, lower depreciation rates due to the
settlement in EGTS' general rate case, lower income tax expense primarily due to lower pre-tax income and lower than
estimated 2022 tax assessments, partially offset by higher technology and related charges and an increase in salaries, wages and
benefits.
Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022
Operating revenue increased $2 million, or 1%, for the second quarter of 2023 compared to 2022, primarily due to an increase
in variable revenue related to park and loan activity of $10 million and an increase in regulated gas transmission and storage
services revenues due to the settlement of EGTS' general rate case of $8 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 $11 million.
Cost of (excess) gas was an expense of $5 million for the second quarter of 2023 compared to a credit of $21 million for the
second quarter of 2022. The change is primarily from a decrease in other operational and system balancing fuel activities prior
to the effective date of the new fuel tracker due to the settlement of EGTS' general rate case of $14 million and the unfavorable
revaluation of the volumes retained prior to the effective date of the new fuel tracker due to lower natural gas prices of
$12 million.
Operations and maintenance increased $9 million, or 10%, for the second quarter of 2023 compared to 2022, primarily due to
higher technology and related charges of $12 million and an increase in salaries, wages and benefits of $9 million, partially
offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.
Property and other taxes decreased $8 million, or 53%, for the second quarter of 2023 compared to 2022, primarily due to
lower than estimated 2022 tax assessments.
Other, net was income of $2 million for the second quarter of 2023 compared to expense of $1 million for the second quarter of
2022. The change is primarily from gains on marketable securities.
Income tax expense decreased $8 million, or 29%, for the second quarter of 2023 compared to 2022, primarily due to lower pre-
tax income and the effective tax rate was 25% for 2023 and 28% for 2022. The effective tax rate decreased primarily due to the
reduction in the Pennsylvania statutory rate.
First Six Months of 2023 Compared to First Six Months of 2022
Operating revenue increased $57 million, or 12%, for the first six months of 2023 compared to 2022, primarily due to an
increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of
$50 million, an increase in variable revenue related to park and loan activity of $20 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 $17 million.
190
Cost of (excess) gas was an expense of $25 million for the first six months of 2023 compared to a credit of $24 million for the
first six months 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 the settlement of EGTS' general rate case due to lower natural gas prices of $35 million and a
decrease from other operational and system balancing fuel activities prior to the effective date of the new fuel tracker of
$14 million.
Operations and maintenance increased $24 million, or 14%, for the first six months of 2023 compared to 2022, primarily due to
higher technology and related charges of $18 million and an increase in salaries, wages and benefits of $14 million, partially
offset by a gain from an agreement to convey development rights underneath one of its natural gas storage fields of $8 million.
Depreciation and amortization decreased $7 million, or 9%, for the first six months 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
$1 million.
Property and other taxes decreased $3 million, or 13%, for the first six months of 2023 compared to 2022, primarily due to
lower than estimated 2022 tax assessments.
Other, net was income of $2 million for the first six months of 2023 compared to expense of $1 million for the first six months
of 2022. The change is primarily from gains on marketable securities.
Income tax expense decreased $4 million, or 9%, for the first six months of 2023 compared to 2022, primarily due to lower pre-
tax income and the effective tax rate was 25% for 2023 and 27% for 2022. The effective tax rate decreased primarily due to the
reduction in the Pennsylvania statutory rate.
Liquidity and Capital Resources
As of June 30, 2023, EGTS' total net liquidity was as follows (in millions):
Cash and cash equivalents $ 22
Intercompany revolving credit agreement 400
Less:
Notes payable to affiliates 40
Net intercompany revolving credit agreement 360
Total net liquidity $ 382
Intercompany credit agreement:
Maturity date 2024
Operating Activities
Net cash flows from operating activities for the six-month periods ended June 30, 2023 and 2022 were $204 million and
$281 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 six-month periods ended June 30, 2023 and 2022 were $(81) million and
$(113) million, respectively. The change is primarily due to a decrease in capital expenditures of $23 million, proceeds from the
assignment of shale development rights of $8 million and a decrease in loans to affiliates of $8 million, partially offset by a
decrease in repayments of loans by affiliates of $10 million.
191
Financing Activities
Net cash flows from financing activities for the six-month period ended June 30, 2023 were $(118) million and consisted of
dividends paid to Eastern Energy Gas of $122 million, partially offset by net issuance of notes payable to Eastern Energy Gas
of $4 million.
Net cash flows from financing activities for the six-month period ended June 30, 2022 were $(141) million and consisted of
dividends paid to Eastern Energy Gas of $80 million and net repayment of notes payable to Eastern Energy Gas of $61 million.
Future Uses of Cash
EGTS has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows
from operating activities, public and private debt offerings, intercompany revolving credit agreements, capital contributions and
other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments,
debt retirements and other capital requirements. The availability and terms under which EGTS has access to external financing
depends on a variety of factors, including regulatory approvals, EGTS' credit ratings, investors' judgment of risk and conditions
in the overall capital markets, including the condition of the natural gas transmission and storage industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews,
which may consider, among other factors, new growth projects and the timing of growth projects; changes in environmental and
other rules and regulations; impacts to customer rates; outcomes of regulatory proceedings; changes in income tax laws; general
business conditions; system reliability standards; the cost and efficiency of construction labor, equipment and materials;
commodity prices; and the cost and availability of capital.
EGTS' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other
non-cash items, are as follows (in millions):
Six-Month Periods Annual
Ended June 30,Forecast
2022 2023 2023
Natural gas transmission and storage $ 21 $ 8 $ 28
Other 88 78 209
Total $ 109 $ 86 $ 237
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 June 30, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of
EGTS' Annual Report on Form 10-K for the year ended December 31, 2022.
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.
192
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.
193
Item 3.Quantitative and Qualitative Disclosures About Market Risk
For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual
Report on Form 10-K for the year ended December 31, 2022. Each Registrant's exposure to market risk and its management of
such risk has not changed materially since December 31, 2022. Refer to Note 7 of the Notes to Consolidated Financial
Statements of PacifiCorp, Note 7 of the Notes to Consolidated Financial Statements of Nevada Power and Note 7 of the Notes
to Consolidated Financial Statements of Sierra Pacific in Part I, Item 1 of this Form 10-Q for disclosure of the respective
Registrant's derivative positions as of June 30, 2023.
Item 4.Controls and Procedures
At the end of the period covered by this Quarterly Report on Form 10-Q, each of Berkshire Hathaway Energy Company,
PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power
Company, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. carried out separate evaluations,
under the supervision and with the participation of each such entity's management, including its Chief Executive Officer
(principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar
functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule
13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of
each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal
financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures
for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or
submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the
time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and
communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial
Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely
decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control
over financial reporting during the quarter ended June 30, 2023 that has materially affected, or is reasonably likely to materially
affect, its internal control over financial reporting except for Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission
and Storage, Inc. In April 2023, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. completed
implementation of a new enterprise resource planning system, which was designed to replace or enhance certain internal
financial and operating systems. In connection with the enterprise resource planning implementation, Eastern Energy Gas
Holdings, LLC and Eastern Gas Transmission and Storage, Inc. updated the processes and controls that constitute the internal
control over financial reporting, as necessary, to accommodate related changes to the accounting procedures and business
processes. There have been no other changes in internal control over financial reporting during the quarter ended June 30, 2023
that have materially affected, or are reasonably likely to materially affect, the Eastern Energy Gas Holdings, LLC and Eastern
Gas Transmission and Storage, Inc. internal control over financial reporting environments.
194
PART II
Item 1.Legal Proceedings
Berkshire Hathaway Energy and PacifiCorp
The following disclosures reflect material updates to legal proceedings and should be read in conjunction with Item 3 of
PacifiCorp's and Berkshire Hathaway Energy's Annual Reports on Form 10-K for the year ended December 31, 2022.
Multiple lawsuits, complaints and demands alleging similar claims have been filed in Oregon and California related to the
Labor Day 2020 Wildfires, certain of which have been described below. Amounts sought in the lawsuits, complaints and
demands filed in Oregon total over $7 billion, excluding any doubling or trebling of damages included in the complaints.
Generally, the complaints filed in California do not specify damages sought and are excluded from the total above. Multiple
complaints have also been filed in California for the 2022 McKinney fire. Investigations into the causes and origins of those
wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to
Note 11 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q,
and PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this
Form 10-Q.
Jeanyne James et al. v. PacifiCorp and Consolidated Cases
On September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et
al., Case No. 20CV33885, in Multnomah County Circuit Court, Oregon ("James"). The complaint was filed by Oregon
residents and businesses who sought to represent a class of all Oregon citizens and entities whose real or personal property was
harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the
plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain
Complex, South Obenchain, Two Four Two and Santiam Canyon fires, as well as to add claims for noneconomic damages. The
amended complaint alleged that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7,
2020, and that PacifiCorp acted with gross negligence, among other things. The amended complaint sought the following
damages for the plaintiffs and the class: (i) noneconomic damages, including mental suffering, emotional distress,
inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal
property and other economic losses of not less than $600 million; (iii) double the amount of property and economic damages;
(iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (v) double the damages for the costs of
litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness
fees. The plaintiffs demanded a trial by jury and reserved their right to further amend the complaint to allege claims for punitive
damages. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated this case with
others as described below. Plaintiffs' motion to bifurcate issues for trial between class-wide liability and individual damages
was also granted. PacifiCorp requested an immediate appeal of the issue class certification before the Oregon Court of Appeals.
In January 2023, the Oregon Court of Appeals denied PacifiCorp's request for immediate 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 sought punitive
damages at a five times multiplier to the amount of compensatory damages awarded. On April 24, 2023, the jury trial began in
Multnomah County Circuit Court for the 17 named plaintiffs. In June 2023, the jury issued its verdict finding PacifiCorp liable
to the 17 individual plaintiffs and to the class with respect to the four wildfires. The jury awarded the 17 named plaintiffs
$90 million of damages, including $4 million of economic and property damages, $68 million of noneconomic damages and
$18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages. Under ORS 477.089,
the economic and property damages awarded may be subject to doubling. No judgment has been entered by the Multnomah
County Circuit Court. The number of claimants in the class and the amounts of their claims, if any, have not been determined,
and no determination has been made by the court as to the timing, process and procedures that will be used to adjudicate
individual class member damages. PacifiCorp intends to vigorously appeal the jury's findings and damage awards, including
whether the case can proceed as a class action. The appeals process and further actions could take several years.
195
On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case
No. 21CV33595, ("Salter"), in Multnomah County Circuit Court, Oregon, in which two complaints, Case No. 21CV09339 and
Case No. 21CV09520, previously filed in Marion County Circuit Court, Oregon, were combined. The plaintiffs voluntarily
dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and
businesses who allege that they were injured by the Beachie Creek fire, which the plaintiffs allege began on or around
September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that
PacifiCorp's assets contributed to the Beachie Creek fire and that PacifiCorp acted with gross negligence, among other things.
The complaint seeks the following damages: (i) damages related to real and personal property in an amount determined by the
jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the
jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury
to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under
specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other
costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the
complaint to add a claim for punitive damages. In May 2022, the Salter case was consolidated with the James case (described
above).
In October 2020, the case Amy Allen, et al. v. PacifiCorp, Case No. 20CV37430 ("Allen") was filed in Multnomah County
Circuit Court, Oregon. The Allen case was filed by five individuals as amended in September 2021 claiming in excess of
$32 million in economic and noneconomic damages related to the Beachie Creek fire, as well as claims for statutory doubling
or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest. In May 2022, the Allen case was
consolidated with the James case (described above).
On August 26, 2022, a putative class action complaint seeking declaratory and equitable relief against PacifiCorp was filed,
captioned Margaret Dietrich et al. v. PacifiCorp, Case No. 22CV29187 ("Dietrich"), in Multnomah County Circuit Court,
Oregon. The complaint was filed by two Oregon residents individually and on behalf of a class initially defined to include
residents of, business owners in, real or personal property owners in and any other individuals physically present in specified
Oregon counties as of September 7, 2020 who experienced any harm, damage or loss as a result of the Santiam Canyon,
Beachie Creek, Lionshead, Echo Mountain Complex, Two Four Two or South Obenchain fires. The complaint was amended on
September 6, 2022, to add a claim for damages of over $900 million. The amended complaint adds four more individual
plaintiffs and modifies the class definition to cover only the Santiam Canyon, Echo Mountain Complex, Two Four Two, and
South Obenchain fires. The amended complaint alleges: (i) negligence due to alleged failure to comply with certain Oregon
statutes and administrative rules; (ii) gross negligence due to alleged conscious indifference to or reckless disregard for the
probable consequences of defendant's actions or inactions; (iii) private nuisance; (iv) public nuisance; (v) trespass; (vi) inverse
condemnation; (vii) accounting/injunction; and (viii) negligent infliction of emotional distress. The amended complaint seeks
the following: (i) an order certifying the matter as a class action; (ii) economic damages not less than $400 million; (iii) double
the amount of economic and property damages to the extent applicable under Oregon statute; (iv) reasonable costs of
reforestation activities; (v) doubling and trebling of certain other damages to the extent applicable under certain Oregon
statutes; (vi) noneconomic damages not less than $500 million; (vii) prejudgment interest; (viii) an order requiring an
accounting with respect to the amount of damages; (ix) an order enjoining PacifiCorp from leaving power lines energized in
areas of Oregon experiencing extremely critical fire conditions; (x) an award of reasonable attorney fees, costs, investigation
costs, disbursements and expert witness fees; and (xi) other relief the court finds appropriate. The plaintiffs and proposed class
demand a trial by jury. On December 19, 2022, the Dietrich case was consolidated into James (described above) and is
currently stayed.
On April 26, 2022, a complaint against PacifiCorp was filed, captioned Cady et al. v. PacifiCorp, Case No. 22CV13946
("Cady"), in Multnomah County Circuit Court, Oregon. The Cady case was filed by 21 individuals as amended in April 2022
claiming $10 million in economic and noneconomic damages in connection with the Echo Mountain Complex fire, as well as
claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest. On September 2,
2022, a complaint against PacifiCorp was filed, captioned Logan et al. v. PacifiCorp, Case No. 22CV29859 ("Logan"), in
Multnomah County Circuit Court, Oregon. The Logan case was filed by five individuals claiming $10 million in economic and
noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-
and post-judgment interest. The Logan and Cady complaints each allege injuries and damages resulting from the September
2020 Echo Mountain Complex fires and assert claims for: (i) negligence; (ii) trespass; (iii) nuisance; and (iv) inverse
condemnation. The Cady and Logan cases have been consolidated with James (described above).
196
On October 14, 2022, the Multnomah County Circuit Court consolidated 21st Century Centennial Insurance Company, et al. v.
PacifiCorp, Case No. 22CV26326 ("21st Century") and Allstate Vehicle and Property Insurance Company, et al. v. PacifiCorp,
Case No. 22CV29976 ("Allstate") into James (described above). The 21st Century and Allstate complaints were each filed in
Multnomah County Circuit Court, Oregon by subrogated insurance carriers alleging claims of (i) negligence, (ii) gross
negligence, and (iii) inverse condemnation resulting from the September 2020 Santiam Canyon, Echo Mountain Complex, 242
and South Obenchain fires. The 21st Century case was filed in August 2022 by 177 insurance carriers seeking $20 million in
damages. The Allstate case was filed in September 2022 by 11 insurance carriers seeking $40 million in damages. In May 2023,
PacifiCorp and the subrogated insurance carriers entered into a settlement agreement.
On October 17, 2022, the Multnomah County Circuit Court consolidated Michael Bell, et al. v. PacifiCorp, Case
No. 22CV30450 ("Bell") into James (described above). The Bell case was filed in Multnomah County Circuit Court, Oregon on
September 7, 2022, by 59 plaintiffs seeking $35 million in damages for claims of (i) negligence, (ii) trespass, (iii) nuisance, and
(iv) inverse condemnation.
On October 19, 2022, the Multnomah County Circuit Court consolidated Freres Timber, Inc. v. PacifiCorp, Case
No. 22CV29694 ("Freres") into James (described above). The Freres case was filed in Multnomah County Circuit Court,
Oregon on September 1, 2022, by one plaintiff and seeks $40 million for claims of (i) negligence, (ii) gross negligence, and (iii)
inverse condemnation.
On December 6, 2022, CW Specialty Lumber, Inc., et al. v. PacifiCorp, Case No. 22CV41640 ("CW Specialty") was filed in
Multnomah County Circuit Court, Oregon by two plaintiffs seeking $29 million in damages for claims of (i) negligence, (ii)
gross negligence, (iii) trespass, and (iv) inverse condemnation. The CW Specialty case has been consolidated with James
(described above).
Roseburg Resources Co et al. v. PacifiCorp and Consolidated Cases
On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case
No. 22CV09346 ("Roseburg") in Douglas County Circuit Court, Oregon. The complaint was filed by nine businesses and
public pension plans that own or operate timberlands or possess property in Douglas County who allege damages, losses and
injuries associated with their timberlands as a result of the French Creek, Archie Creek, Susan Creek and Smith Springs Road
fires in Douglas County in September 2020. The complaint alleges (i) PacifiCorp's conduct constituted not only common law
negligence but also gross negligence and that such conduct contributed to or caused the ignition and spread of the
aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence,
inverse condemnation. The complaint seeks the following damages as amended: (i) economic and property damages in excess
of $195 million under a determination of negligence or inverse condemnation; (ii) doubling of those economic damages to in
excess of $390 million under a determination of gross negligence pursuant to Oregon statute; (iii) all costs of the lawsuit; (iv)
prejudgment interest of $43 million and post-judgment interest as allowed by law; and (v) attorneys' fees of $105 million and
other costs.
On November 1, 2022, three complaints were filed against PacifiCorp, captioned Moore et al. v. PacifiCorp, No. 22CV37302;
Blodgett et al. v. PacifiCorp, No. 22CV37306; and Ellis et al. v. PacifiCorp, No. 22CV37304. Three additional cases were filed
December 5, 2022, captioned Tague et al. v. PacifiCorp, No. 22CV41242; Long, et al. v. PacifiCorp, No. 22CV41283; and
Moyers et al. v. PacifiCorp, No. 22CV41293. On January 6, 2023, an additional complaint was filed against PacifiCorp
captioned Meyer et al. v. PacifiCorp, No. 23CV00748. On January 17, 2023, seven additional cases were filed, captioned
Foster et al. v. PacifiCorp, No. 23CV02142; Hall et al. v. PacifiCorp, No. 23CV02184; Jones et al. v. PacifiCorp,
No. 23CV02110; Price et al. v. PacifiCorp, No. 23CV02175; Minott et al. v. PacifiCorp, No. 23CV02203; Webb et al. v.
PacifiCorp, No. 23CV02202; and Keith et al. v. PacifiCorp, No. 23CV02200. On January 24, 2023, three additional cases were
filed captioned Kidd et al. v. PacifiCorp, No. 23CV03318; Parker et al. v. PacifiCorp, No. 23CV03317; and Diaz et al. v.
PacifiCorp, No. 23CV03313.
These complaints were filed in Douglas County Circuit Court, Oregon with substantially similar allegations as those of
Roseburg with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral
ruling, the Douglas County Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues,
along with the above-mentioned Roseburg; the precise scope of the trial will be determined in a later order. Collectively, these
eighteen cases seek in excess of $1,300 million in damages, inclusive of the $573 million Roseburg case. On
February 14, 2023, the Douglas County Circuit Court ordered that all plaintiffs' claims for inverse condemnation be dismissed;
a written order is forthcoming.
197
Ashley Andersen et al. v. PacifiCorp and Consolidated Cases
On September 1, 2022, multiple complaints against PacifiCorp were filed in Multnomah County Circuit Court, Oregon,
captioned Martin Klinger et al. v. PacifiCorp, Case No. 22CV29674 ("Klinger"), Jeremiah E. Bowen et al. v. PacifiCorp, Case
No. 22CV29681 ("Bowen") and James Weathers et al. v. PacifiCorp, Case No. 22CV29683 ("Weathers"). The complaints were
filed by Oregon residents and Oregon property owners who allege damages resulting from the September 2020 Echo Mountain
Complex fires. The allegations made and damages sought are described below.
On September 6, 2022, a complaint against PacifiCorp was filed, captioned Blair Barnholdt et al. v. PacifiCorp, Case
No. 22CV30097, in Multnomah County Circuit Court, Oregon ("Barnholdt"). The complaint was filed by Oregon residents or
Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The
allegations made and damages sought are described below.
On September 7, 2022, multiple complaints against PacifiCorp were filed in Multnomah County Circuit Court, Oregon,
captioned Estate of Nancy Darlene Hunter, et al. v. PacifiCorp, Case No. 22CV30214 ("Hunter"), Willard K. Pratt et al. v.
PacifiCorp, Case No. 22CV30217 ("Pratt") and April Thompson et al. v. PacifiCorp, Case No. 22CV30451 ("Thompson"). The
complaints were filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages
resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described
below.
The above-described Klinger, Bowen, Weathers, Barnholdt, Hunter, Pratt and Thompson cases were consolidated with Sparks
et al. v. PacifiCorp, Case No. 21CV48022 ("Sparks") and Russie et al. v. PacifiCorp, Case No. 22CV15840 ("Russie") into
Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen"). The Klinger, Bowen, Weathers, Barnholdt, Pratt and
Thompson complaints each allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and
administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and
reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; and (v) inverse condemnation. The Klinger, Bowen,
Weathers, Barnholdt, Pratt and Thompson complaints each seek the following damages: (i) economic and property related
damages of $83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for
doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not
less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of
earnings capacity, evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and
(vii) pre-judgment interest. The plaintiffs for each Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson request a trial by
jury and have reserved their right to amend the complaint to add a claim for punitive damages. The Hunter complaint seeks
$50 million in damages and alleges claims for: (i) negligence, (ii) trespass, (iii), nuisance, (iv) inverse condemnation, and (v)
wrongful death. The Andersen case was filed by 50 individuals as amended in August 2022 seeking $250 million in economic
and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and
pre-judgment interest. The Sparks case was filed by 17 individuals in December 2021 claiming $125 million in economic and
noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-
judgment interest. The Russie case was filed by 45 individuals as amended in September 2022 seeking $250 million in
economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other
costs and pre-judgment interest.
Judith O'Keefe v. PacifiCorp and Consolidated Cases
On September 1, 2022, a complaint against PacifiCorp was filed, captioned Aaron Macy-Wyngarden et al. v. PacifiCorp, Case
No. 22CV29684, in Multnomah County Circuit Court, Oregon ("Macy-Wyngarden"). The complaint was filed by Oregon
residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Beachie Creek,
Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.
On September 22, 2022, a complaint against PacifiCorp was filed, captioned Zachary Bogle et al. v. PacifiCorp, Case
No. 22CV29717, in Multnomah County Circuit Court, Oregon ("Bogle"). The complaint was filed by Oregon residents who
allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires.
The allegations made and damages sought are described below.
198
The Macy-Wyngarden and Bogle complaints each allege: (i) negligence due in part to alleged failure to comply with certain
Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of
willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; and (v) inverse condemnation.
The Macy-Wyngarden and Bogle complaints each seek the following damages: (i) economic and property related damages of
$83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of
damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not less than
$83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of earnings
capacity, evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and (vii) pre-
judgment interest. The plaintiffs for each Macy-Wyngarden and Bogle request a trial by jury and have reserved their right to
amend the complaint to add a claim for punitive damages.
The Macy-Wyngarden and Bogle cases were consolidated with Ruthie Dodge et al. v. PacifiCorp, Case No. 22CV30222
("Dodge") into Judith O'Keefe v. PacifiCorp, Case No. 21CV15857 ("O'Keefe"). The Dodge case was filed in Multnomah
County Circuit Court, Oregon on September 8, 2022, by two plaintiffs seeking $9 million in damages for claims of negligence,
trespass, nuisance, and inverse condemnation. The O'Keefe lawsuit was filed in Multnomah County Circuit Court, Oregon on
April 23, 2021, by one individual seeking $2 million in damages for claims for negligence, nuisance, and trespass.
United States and Oregon Departments of Justice – Loss and Damages to Federal and State Lands
PacifiCorp recently received correspondence from the U.S. Department of Justice ("USDOJ"), representing the U.S.
Department of the Interior, Bureau of Land Management, Bureau of Indian Affairs, Department of Agriculture and Forest
Service, regarding the potential recovery of certain costs and damages alleged to have occurred to federal lands from the
September 2020 Archie Creek and Susan Creek fires. The USDOJ estimates the costs and damages relating to reforestation,
damaged timber and improvements, coordination with hydropower license, suppression costs and other assessment, cleanup and
rehabilitation costs and damages at approximately $640 million. The amounts alleged for natural resource damage from these
fires do not include environmental damages that the United States could potentially seek to recover if this matter was fully
litigated, nor do they include multipliers which the agencies are allegedly entitled to collect under pertinent federal regulations,
under which, for example, minimum damages for trespass to timber managed by the U.S. Department of Interior are twice the
fair market value of the resource at the time of the trespass, or three times if the violation was willful.
PacifiCorp also received correspondence from the Oregon Department of Justice ("ODOJ"), representing the State of Oregon,
regarding the potential recovery of losses and damages to state lands from the Archie Creek and Susan Creek fires. The ODOJ
estimates losses and damages relating to the sheltering of, and assistance to, affected Oregonians, fire control and
extinguishment costs, 39 acres of Oregon forestland, losses and damages at the Rock Creek Fish Hatchery, road and highway
damages, and other costs, at approximately $95 million.
PacifiCorp is actively cooperating with both the USDOJ and ODOJ on resolving these alleged claims, including through the
pursuit of alternative dispute resolution means.
Item 1A.Risk Factors
There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual
Report on Form 10-K for the year ended December 31, 2022.
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
Not applicable.
Item 3.Defaults Upon Senior Securities
Not applicable.
Item 4.Mine Safety Disclosures
Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in
accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95
to this Form 10-Q.
199
Item 5.Other Information
Not applicable.
Item 6.Exhibits
The following is a list of exhibits filed as part of this Quarterly Report.
200
Exhibit No.Description
BERKSHIRE HATHAWAY ENERGY
10.1 First Amendment to the $3,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2023, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Bank, Ltd. as Administrative Agent and the LC Issuing Banks.
10.2 First Amending Agreement to the Credit Agreement, dated April 27, 2021, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
10.3 Second Amending Agreement to the Credit Agreement, dated April 27, 2022, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
10.4 Third Amending Agreement to the Credit Agreement, dated April 27, 2023, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
15.1 Awareness Letter of Independent Registered Public Accounting Firm.
31.1 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
PACIFICORP
15.2 Awareness Letter of Independent Registered Public Accounting Firm.
31.3 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4 Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.3 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.4 Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
4.1 Thirty-Fourth Supplemental Indenture, dated as of May 1, 2023, to the Mortgage and Deed of Trust dated as of January 9, 1989 between PacifiCorp and the Bank of New York Mellon Trust Company, N.A., as successor Trustee (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated May 17, 2023).
10.5 First Amendment to the $2,000,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2023, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JP Morgan Chase Bank, N.A. as Administrative Agent and the LC Issuing Banks.
95 Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.
201
Exhibit No.Description
MIDAMERICAN ENERGY
15.3 Awareness Letter of Independent Registered Public Accounting Firm.
31.5 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.6 Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.5 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.6 Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
MIDAMERICAN FUNDING
31.7 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.8 Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.7 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.8 Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN ENERGY AND MIDAMERICAN FUNDING
10.6 First Amendment to the $1,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2023, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Mizuho Bank, Ltd., as Administrative Agent and the LC Issuing Banks.
NEVADA POWER
15.4 Awareness Letter of Independent Registered Public Accounting Firm.
31.9 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.10 Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.9 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.10 Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
10.7 First Amendment to the $600,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 2023, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.
SIERRA PACIFIC
31.11 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.12 Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.11 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.12 Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
202
Exhibit No.Description
BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
10.8 First Amendment to the $400,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 2023, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.
EASTERN ENERGY GAS
10.9 Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1, 2023, by and between BHE GT&S, LLC and Eastern Energy Gas Holdings, LLC (incorporated by reference to Exhibit 10.4 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
31.13 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.14 Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.13 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.14 Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
EASTERN GAS TRANSMISSION AND STORAGE
10.10 Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1, 2023, by and between Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. (incorporated by reference to Exhibit 10.5 to the Eastern Gas Transmission and Storage, Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
10.11 Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1, 2023, by and between Eastern Gas Transmission and Storage, Inc. and Eastern Energy Gas Holdings, LLC (incorporated by reference to Exhibit 10.6 to the Eastern Gas Transmission and Storage Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2023).
31.15 Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.16 Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.15 Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.16 Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
ALL REGISTRANTS
101 The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.
104 Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.
203
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.
BERKSHIRE HATHAWAY ENERGY COMPANY
Date: August 4, 2023 /s/ Calvin D. Haack
Calvin D. Haack
Senior Vice President and Chief Financial Officer
(principal financial and accounting officer)
PACIFICORP
Date: August 4, 2023 /s/ Nikki L. Kobliha
Nikki L. Kobliha
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
MIDAMERICAN FUNDING, LLC
MIDAMERICAN ENERGY COMPANY
Date: August 4, 2023 /s/ Blake M. Groen
Blake M. Groen
Vice President and Controller
of MidAmerican Funding, LLC and
Vice President and Chief Financial Officer
of MidAmerican Energy Company
(principal financial and accounting officer)
NEVADA POWER COMPANY
Date: August 4, 2023 /s/ Michael J. Behrens
Michael J. Behrens
Vice President and Chief Financial Officer
(principal financial and accounting officer)
SIERRA PACIFIC POWER COMPANY
Date: August 4, 2023 /s/ Michael J. Behrens
Michael J. Behrens
Vice President and Chief Financial Officer
(principal financial and accounting officer)
EASTERN ENERGY GAS HOLDINGS, LLC
Date: August 4, 2023 /s/ Scott C. Miller
Scott C. Miller
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
EASTERN GAS TRANSMISSION AND STORAGE, INC.
Date: August 4, 2023 /s/ Scott C. Miller
Scott C. Miller
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
204
EXHIBIT 15.1
August 4, 2023
To the Board of Directors and Shareholders of
Berkshire Hathaway Energy Company
666 Grand Avenue
Des Moines, Iowa 50309
We are aware that our report dated August 4, 2023, on our review of the interim financial information of Berkshire Hathaway
Energy Company appearing in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, is incorporated by
reference in Registration Statement No. 333-228511 on Form S-8.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
EXHIBIT 15.2
August 4, 2023
The Board of Directors and Shareholders of
PacifiCorp
825 N.E. Multnomah Street, Suite 1900
Portland, Oregon 97232
We are aware that our report dated August 4, 2023, on our review of the interim financial information of PacifiCorp appearing
in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, is incorporated by reference in Registration
Statement No. 333-249044 on Form S-3.
/s/ Deloitte & Touche LLP
Portland, Oregon
EXHIBIT 15.3
August 4, 2023
To the Board of Directors and Shareholder of
MidAmerican Energy Company
666 Grand Avenue
Des Moines, Iowa 50309
We are aware that our report dated August 4, 2023, on our review of the interim financial information of MidAmerican Energy
Company appearing in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, is incorporated by reference in
Registration Statement No. 333-257069 on Form S-3.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
EXHIBIT 15.4
August 4, 2023
To the Board of Directors and Shareholder of
Nevada Power Company
6226 W Sahara Ave.
Las Vegas, Nevada 89146
We are aware that our report dated August 4, 2023 on our review of the interim financial information of Nevada Power
Company and subsidiaries appearing in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, is
incorporated by reference in Registration Statement No. 333-267865 on Form S-3.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Scott W. Thon, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Berkshire Hathaway Energy Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Scott W. Thon
Scott W. Thon
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 31.2
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Calvin D. Haack, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Berkshire Hathaway Energy Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Calvin D. Haack
Calvin D. Haack
Senior Vice President and Chief Financial Officer
(principal financial officer)
EXHIBIT 31.3
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Scott W. Thon, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of PacifiCorp;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Scott W. Thon
Scott W. Thon
Chair of the Board of Directors and Chief Executive Officer
(principal executive officer)
EXHIBIT 31.4
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Nikki L. Kobliha, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of PacifiCorp;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Nikki L. Kobliha
Nikki L. Kobliha
Vice President, Chief Financial Officer and Treasurer
(principal financial officer)
EXHIBIT 31.5
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Kelcey A. Brown, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of MidAmerican Energy Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Kelcey A. Brown
Kelcey A. Brown
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 31.6
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Blake M. Groen, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of MidAmerican Energy Company;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Blake M. Groen
Blake M. Groen
Vice President and Chief Financial Officer
(principal financial officer)
EXHIBIT 31.7
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Kelcey A. Brown, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of MidAmerican Funding, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Kelcey A. Brown
Kelcey A. Brown
President
(principal executive officer)
EXHIBIT 31.8
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Blake M. Groen, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of MidAmerican Funding, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: August 4, 2023 /s/ Blake M. Groen
Blake M. Groen
Vice President and Controller
(principal financial officer)
EXHIBIT 31.9
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Douglas A. Cannon, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Nevada Power Company (dba NV Energy);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Douglas A. Cannon
Douglas A. Cannon
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 31.10
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Michael J. Behrens, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Nevada Power Company (dba NV Energy);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Michael J. Behrens
Michael J. Behrens
Vice President and Chief Financial Officer
(principal financial officer)

EXHIBIT 31.11
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Douglas A. Cannon, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Sierra Pacific Power Company (dba NV Energy);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Douglas A. Cannon
Douglas A. Cannon
President and Chief Executive Officer
(principal executive officer)

EXHIBIT 31.12
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Michael J. Behrens, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Sierra Pacific Power Company (dba NV Energy);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Michael J. Behrens
Michael J. Behrens
Vice President and Chief Financial Officer
(principal financial officer)

EXHIBIT 31.13
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Paul E. Ruppert, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Eastern Energy Gas Holdings, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Paul E. Ruppert
Paul E. Ruppert
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 31.14
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Scott C. Miller, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Eastern Energy Gas Holdings, LLC;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Scott C. Miller
Scott C. Miller
Vice President, Chief Financial Officer and Treasurer
(principal financial officer)
EXHIBIT 31.15
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Paul E. Ruppert, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Eastern Gas Transmission and Storage, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Paul E. Ruppert
Paul E. Ruppert
President and Chair of the Board of Directors
(principal executive officer)
EXHIBIT 31.16
CERTIFICATION PURSUANT TO
SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, Scott C. Miller, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q of Eastern Gas Transmission and Storage, Inc.;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that
occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant's ability to record,
process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant's internal control over financial reporting.
Date: August 4, 2023 /s/ Scott C. Miller
Scott C. Miller
Vice President, Chief Financial Officer and Treasurer
(principal financial officer and accounting officer)
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Scott W. Thon, President and Chief Executive Officer of Berkshire Hathaway Energy Company (the "Company"), certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of the Company for the quarterly period ended June 30, 2023 (the "Report") fully
complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or
78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of the Company.
Date: August 4, 2023 /s/ Scott W. Thon
Scott W. Thon
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 32.2
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Calvin D. Haack, Senior Vice President and Chief Financial Officer of Berkshire Hathaway Energy Company (the
"Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my
knowledge:
(1)the Quarterly Report on Form 10-Q of the Company for the quarterly period ended June 30, 2023 (the "Report") fully
complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or
78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of the Company.
Date: August 4, 2023 /s/ Calvin D. Haack
Calvin D. Haack
Senior Vice President and Chief Financial Officer
(principal financial officer)
EXHIBIT 32.3
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Scott W. Thon, Chair of the Board of Directors and Chief Executive Officer of PacifiCorp, certify, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of PacifiCorp for the quarterly period ended June 30, 2023 (the "Report") fully
complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or
78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of PacifiCorp.
Date: August 4, 2023 /s/ Scott W. Thon
Scott W. Thon
Chair of the Board of Directors and Chief Executive Officer
(principal executive officer)
EXHIBIT 32.4
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Nikki L. Kobliha, Vice President, Chief Financial Officer and Treasurer of PacifiCorp, certify, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of PacifiCorp for the quarterly period ended June 30, 2023 (the "Report") fully
complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or
78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of PacifiCorp.
Date: August 4, 2023 /s/ Nikki L. Kobliha
Nikki L. Kobliha
Vice President, Chief Financial Officer and Treasurer
(principal financial officer)
EXHIBIT 32.5
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Kelcey A. Brown, President and Chief Executive Officer of MidAmerican Energy Company, certify, pursuant to Section 906
of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of MidAmerican Energy Company for the quarterly period ended June 30, 2023
(the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of MidAmerican Energy Company.
Date: August 4, 2023 /s/ Kelcey A. Brown
Kelcey A. Brown
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 32.6
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Blake M. Groen, Vice President and Chief Financial Officer of MidAmerican Energy Company, certify, pursuant to Section
906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of MidAmerican Energy Company for the quarterly period ended June 30, 2023
(the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of MidAmerican Energy Company.
Date: August 4, 2023 /s/ Blake M. Groen
Blake M. Groen
Vice President and Chief Financial Officer
(principal financial officer)
EXHIBIT 32.7
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Kelcey A. Brown, President of MidAmerican Funding, LLC, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of
2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of MidAmerican Funding, LLC for the quarterly period ended June 30, 2023 (the
"Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15
U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of MidAmerican Funding, LLC.
Date: August 4, 2023 /s/ Kelcey A. Brown
Kelcey A. Brown
President
(principal executive officer)
EXHIBIT 32.8
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Blake M. Groen, Vice President and Controller of MidAmerican Funding, LLC, certify, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of MidAmerican Funding, LLC for the quarterly period ended June 30, 2023 (the
"Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15
U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of MidAmerican Funding, LLC.
Date: August 4, 2023 /s/ Blake M. Groen
Blake M. Groen
Vice President and Controller
(principal financial officer)
EXHIBIT 32.9
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Douglas A. Cannon, President and Chief Executive Officer of Nevada Power Company (dba NV Energy), certify, pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of Nevada Power Company for the quarterly period ended June 30, 2023 (the
"Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15
U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of Nevada Power Company.
Date: August 4, 2023 /s/ Douglas A. Cannon
Douglas A. Cannon
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 32.10
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Michael J. Behrens, Vice President and Chief Financial Officer of Nevada Power Company (dba NV Energy), certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of Nevada Power Company for the quarterly period ended June 30, 2023 (the
"Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15
U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of Nevada Power Company.
Date: August 4, 2023 /s/ Michael J. Behrens
Michael J. Behrens
Vice President and Chief Financial Officer
(principal financial officer)
EXHIBIT 32.11
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Douglas A. Cannon, President and Chief Executive Officer of Sierra Pacific Power Company (dba NV Energy), certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of Sierra Pacific Power Company for the quarterly period ended June 30, 2023
(the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of Sierra Pacific Power Company.
Date: August 4, 2023 /s/ Douglas A. Cannon
Douglas A. Cannon
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 32.12
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Michael J. Behrens, Vice President and Chief Financial Officer of Sierra Pacific Power Company (dba NV Energy), certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of Sierra Pacific Power Company for the quarterly period ended June 30, 2023
(the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of Sierra Pacific Power Company.
Date: August 4, 2023 /s/ Michael J. Behrens
Michael J. Behrens
Vice President and Chief Financial Officer
(principal financial officer)
EXHIBIT 32.13
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Paul E. Ruppert, President and Chief Executive Officer of Eastern Energy Gas Holdings, LLC, certify, pursuant to Section
906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of Eastern Energy Gas Holdings, LLC for the quarterly period ended June 30,
2023 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of
1934 (15 U.S.C. 78m(a) or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of Eastern Energy Gas Holdings, LLC.
Date: August 4, 2023 /s/ Paul E. Ruppert
Paul E. Ruppert
President and Chief Executive Officer
(principal executive officer)
EXHIBIT 32.14
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Scott C. Miller, Vice President, Chief Financial Officer and Treasurer of Eastern Energy Gas Holdings, LLC, certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of Eastern Energy Gas Holdings, LLC for the quarterly period ended June 30,
2023 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of
1934 (15 U.S.C. 78m(a) or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of Eastern Energy Gas Holdings, LLC.
Date: August 4, 2023 /s/ Scott C. Miller
Scott C. Miller
Vice President, Chief Financial Officer and Treasurer
(principal financial officer)
EXHIBIT 32.15
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Paul E. Ruppert, President and Chair of the Board of Directors of Eastern Gas Transmission and Storage, Inc., certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of Eastern Gas Transmission and Storage, Inc. for the quarterly period ended
June 30, 2023 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange
Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of Eastern Gas Transmission and Storage, Inc.
Date: August 4, 2023 /s/ Paul E. Ruppert
Paul E. Ruppert
President and Chair of the Board of Directors
(principal executive officer)
EXHIBIT 32.16
CERTIFICATION PURSUANT TO
SECTION 906 OF THE
SARBANES-OXLEY ACT OF 2002
I, Scott C. Miller, Vice President, Chief Financial Officer and Treasurer of Eastern Gas Transmission and Storage, Inc., certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge:
(1)the Quarterly Report on Form 10-Q of Eastern Gas Transmission and Storage, Inc. for the quarterly period ended
June 30, 2023 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange
Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2)the information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of Eastern Gas Transmission and Storage, Inc.
Date: August 4, 2023 /s/ Scott C. Miller
Scott C. Miller
Vice President, Chief Financial Officer and Treasurer
(principal financial and accounting officer)
EXHIBIT 95
MINE SAFETY VIOLATIONS AND OTHER LEGAL MATTER DISCLOSURES
PURSUANT TO SECTION 1503(a) OF THE DODD-FRANK WALL STREET
REFORM AND CONSUMER PROTECTION ACT
PacifiCorp and its subsidiaries operate certain coal mines and coal processing facilities (collectively, the "mining facilities")
that are regulated by the Federal Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health
Act of 1977 (the "Mine Safety Act"). MSHA inspects PacifiCorp's mining facilities on a regular basis. The total number of
reportable Mine Safety Act citations, orders, assessments and legal actions for the three-month period ended June 30, 2023 are
summarized in the table below and are subject to contest and appeal. The severity and assessment of penalties may be reduced
or, in some cases, dismissed through the contest and appeal process. Amounts are reported regardless of whether PacifiCorp has
challenged or appealed the matter. Mines that are closed or idled are not included in the information below. There were no
mining-related fatalities during the three-month period ended June 30, 2023. PacifiCorp has not received any notice of a
pattern, or notice of the potential to have a pattern, of violations of mandatory health or safety standards that are of such nature
as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards
under Section 104(e) of the Mine Safety Act during the three-month period ended June 30, 2023.
Mine Safety Act Legal Actions
Total
Section 104 Section Value of
Significant Section 107(a)Proposed Pending
and Section 104(d)Section Imminent MSHA as of Last Instituted Resolved
Substantial 104(b)Citations/110(b)(2)Danger Assessments Day of During During
Mining Facilities Citations(1)Orders(2)Orders(3)Violations(4)Orders(5)(in thousands)Period(6)Period Period
Bridger (surface) — — — — — $ — — — —
Wyodak Coal Crushing Facility — — — — — — — — —
(1)Citations for alleged violations of mandatory health and safety standards that could significantly or substantially contribute to the cause and effect of
a safety or health hazard under Section 104 of the Mine Safety Act.
(2)For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation.
(3)For alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mandatory health or safety
standard.
(4)For alleged flagrant violations (i.e., reckless or repeated failure to make reasonable efforts to eliminate a known violation of a mandatory health or
safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury).
(5)For the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm
before such condition or practice can be abated.
(6)For the existence of any proposed penalties under Subparts B-H of the Federal Mine Safety and Health Review Commission's procedural rules. The
pending legal actions are not exclusive to citations, notices, orders and penalties assessed by the MSHA during the reporting period.