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
~~Registrants~~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 ~~MidAmerican Funding, MidAmerican Energy, Nevada Power and Sierra Pacific~~
~~Subsidiary Registrants~~	~~PacifiCorp, MidAmerican Funding, MidAmerican Energy, Nevada Power and Sierra Pacific~~
~~Northern Powergrid~~	~~Northern Powergrid Holdings Company~~
~~Northern Natural Gas~~	~~Northern Natural Gas Company~~
~~Kern River~~	~~Kern River Gas Transmission Company~~
~~AltaLink~~	~~BHE Canada Holdings Corporation~~
~~ALP~~	~~AltaLink, L.P.~~
~~BHE U.S. Transmission~~	~~BHE U.S. Transmission, LLC~~
~~HomeServices~~	~~HomeServices of America, Inc.~~ and its subsidiaries,
~~BHE Pipeline Group or Pipeline Companies~~	~~Consists of Northern Natural Gas and Kern River~~
~~BHE Transmission~~	~~Consists of AltaLink and BHE U.S. Transmission~~
~~BHE Renewables~~	~~Consists of BHE Renewables,~~ MidAmerican Funding, LLC and ~~CalEnergy Philippines~~
~~Utilities~~	~~PacifiCorp,~~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
~~Berkshire Hathaway~~Northern Powergrid		~~Berkshire Hathaway Inc.~~Northern Powergrid Holdings Company and its subsidiaries
BHE Pipeline Group		BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
~~Certain Industry Terms~~BHE GT&S		BHE GT&S, LLC and its subsidiaries
~~AESO~~Northern Natural Gas		~~Alberta Electric System Operator~~Northern Natural Gas Company
~~AFUDC~~Kern River		~~Allowance for Funds Used During Construction~~Kern River Gas Transmission Company
~~AUC~~BHE Transmission		~~Alberta Utilities Commission~~BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
~~CPUC~~BHE Canada		~~California Public Utilities Commission~~BHE Canada Holdings Corporation and its subsidiaries
~~Dth~~AltaLink		~~Decatherms~~AltaLink, L.P.
~~EPA~~BHE U.S. Transmission		~~United States Environmental Protection Agency~~BHE U.S. Transmission, LLC and its subsidiaries
~~FERC~~BHE Renewables		~~Federal Energy Regulatory Commission~~BHE Renewables, LLC and its subsidiaries
~~GHG~~HomeServices		~~Greenhouse Gases~~HomeServices of America, Inc. and its subsidiaries
~~GWh~~Utilities		~~Gigawatt Hours~~PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
~~GTA~~		~~General Tariff Application~~
~~IPUC~~	~~Idaho Public Utilities Commission~~
~~IUB~~	~~Iowa Utilities Board~~
kV	~~Kilovolt~~
MW	~~Megawatts~~



~~MWh~~						~~Megawatt Hours~~
~~OPUC~~



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
~~PUCN~~PTC						Production Tax Credit
PUCN						Public Utilities Commission of Nevada
~~REC~~						~~Renewable Energy Credit~~
~~RPS~~
RFP						Request for Proposals
RPS						Renewable Portfolio Standards
~~SEC~~
SCR						Selective Catalytic Reduction
SEC						United States Securities and Exchange Commission
SIP						State Implementation Plan
~~UPSC~~ SO2						Sulfur Dioxide

UPSC						Utah Public Service Commission
~~WPSC~~						~~Wyoming 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 ~~accidents,~~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;

•the financial condition, creditworthiness and ~~creditworthiness~~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;~~rates and credit spreads;

•changes in the respective Registrant's credit ratings;

•risks relating to nuclear generation, including unique operational, closure and decommissioning risks;

~~iii~~

•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, ~~and~~ morbidity on pension and other postretirement benefits expense and funding requirements;

•changes in the residential real estate brokerage, mortgage and ~~mortgage~~franchising industries and regulations that could affect brokerage, mortgage and ~~mortgage~~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 ~~consolidated~~ financial results of the respective Registrants; and

~~the ability to successfully integrate future acquired operations into a Registrant's business; 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.

Item 1.Financial Statements


~~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						5457
Consolidated Balance Sheets						5558
Consolidated Statements of Operations						5760
Consolidated Statements of Changes in Shareholders' Equity						5861
Consolidated Statements of Cash Flows						5962
Notes to Consolidated Financial Statements						6063
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm						7684
Balance Sheets						7785
Statements of Operations						7987
Statements of Changes in Shareholder's Equity						8088
Statements of Cash Flows						8189
Notes to Financial Statements						8290
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						9198
Consolidated Balance Sheets						9299
Consolidated Statements of Operations						94101
Consolidated Statements of Changes in Member's Equity						95102
Consolidated Statements of Cash Flows						96103
Notes to Consolidated Financial Statements						97104
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~111~~118
Consolidated Balance Sheets						~~112~~119
Consolidated Statements of Operations						~~113~~120
Consolidated Statements of Changes in Shareholder's Equity						~~114~~121
Consolidated Statements of Cash Flows						~~115~~122
Notes to Consolidated Financial Statements						~~116~~123
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~132~~138
Consolidated Balance Sheets						~~133~~139
Consolidated Statements of Operations						~~134~~140
Consolidated Statements of Changes in Shareholder's Equity						~~135~~141
Consolidated Statements of Cash Flows						~~136~~142
Notes to Consolidated Financial Statements						~~137~~143

Eastern Energy Gas Holdings, LLC and its subsidiaries
~~Item 2.~~ Report of Independent Registered Public Accounting Firm	~~Management's Discussion and Analysis of Financial Condition and Results~~	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

Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations



Berkshire Hathaway Energy Company and its subsidiaries						3031
PacifiCorp and its subsidiaries						6874
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company						~~100~~108
Nevada Power Company and its subsidiaries						~~125~~130
Sierra Pacific Power Company and its subsidiaries						~~145~~151
Eastern Energy Gas Holdings, LLC and its subsidiaries						173
Eastern Gas Transmission and Storage, Inc. and its subsidiaries						190

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

PART I


~~Item 1.~~	~~Financial Statements~~

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

~~Des Moines, Iowa~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of ~~September~~June 30, ~~2017, and~~2023, the related consolidated statements of operations, ~~and~~ comprehensive income, and changes in equity for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, and of ~~changes in equity and~~ cash flows for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016. These~~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 ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~the Company's management.~~America.

We ~~conducted our reviews~~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 ~~Public Company Accounting Oversight Board (United States),~~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.

Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them 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), the consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries as of ~~December 31, 2016, 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, 2017, 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, 2016~~ ~~is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.~~

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 3, 2017~~

August 4, 2023

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

As of
September 30, December 31,
2017 2016
ASSETS
Current assets:
Cash and cash equivalents $ 1,142
$ 721
Trade receivables, net 1,994
1,751
Inventories 887
925
Mortgage loans held for sale 534
359
Other current assets 1,095
917
Total current assets 5,652
4,673

Property, plant and equipment, net 64,979
62,509
Goodwill 9,700
9,010
Regulatory assets 4,582
4,307
Investments and restricted cash and investments 4,987
3,945
Other assets 1,154
996

Total assets $ 91,054
$ 85,440

The accompanying notes are an integral part of these consolidated financial statements.

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

As of
September 30, December 31,
2017 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 1,303
$ 1,317
Accrued interest 523
454
Accrued property, income and other taxes 780
389
Accrued employee expenses 392
261
Short-term debt 2,493
1,869
Current portion of long-term debt 3,070
1,006
Other current liabilities 1,034
1,017
Total current liabilities 9,595
6,313

Regulatory liabilities 3,086
2,933
BHE senior debt 6,771
7,418
BHE junior subordinated debentures 100
944
Subsidiary debt 26,183
26,748
Deferred income taxes 14,832
13,879
Other long-term liabilities 2,883
2,742
Total liabilities 63,450
60,977

Commitments and contingencies (Note 11)

Equity:

BHE shareholders' equity:

Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding —
—
Additional paid-in capital 6,362
6,390
Retained earnings 21,534
19,448
Accumulated other comprehensive loss, net (423 ) (1,511 )
Total BHE shareholders' equity 27,473
24,327
Noncontrolling interests 131
136
Total equity 27,604
24,463

Total liabilities and equity $ 91,054
$ 85,440

The accompanying notes are an integral part of these consolidated financial statements.

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016
Operating revenue:
Energy $ 4,322
$ 4,272
$ 11,501
$ 11,102
Real estate 961
820
2,502
2,152
Total operating revenue 5,283
5,092
14,003
13,254

Operating costs and expenses:
Energy:
Cost of sales 1,212
1,187
3,380
3,252
Operating expense 930
948
2,763
2,739
Depreciation and amortization 635
639
1,905
1,898
Real estate 882
733
2,311
1,973
Total operating costs and expenses 3,659
3,507
10,359
9,862

Operating income 1,624
1,585
3,644
3,392

Other income (expense):
Interest expense (464 ) (460 ) (1,379 ) (1,401 )
Capitalized interest 14
14
34
128
Allowance for equity funds 24
17
59
147
Interest and dividend income 32
39
85
93
Other, net 2
15
24
26
Total other income (expense) (392 ) (375 ) (1,177 ) (1,007 )

Income before income tax expense and equity income 1,232
1,210
2,467
2,385
Income tax expense 184
199
319
394
Equity income 30
36
80
96
Net income 1,078
1,047
2,228
2,087
Net income attributable to noncontrolling interests 10
11
30
25
Net income attributable to BHE shareholders $ 1,068
$ 1,036
$ 2,198
$ 2,062

The accompanying notes are an integral part of these consolidated financial statements.

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Net income $ 1,078
$ 1,047
$ 2,228
$ 2,087

Other comprehensive income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $1, $7, $(3), and $26 15
18
16
80
Foreign currency translation adjustment 227
(134 ) 535
(339 )
Unrealized gains on available-for-sale securities, net of tax of $284, $53, $355 and $89 423
80
542
151
Unrealized gains (losses) on cash flow hedges, net of tax of $1, $(3), $(3) and $(1) 1
(3 ) (5 ) (2 )
Total other comprehensive income, net of tax 666
(39 ) 1,088
(110 )

Comprehensive income 1,744
1,008
3,316
1,977
Comprehensive income attributable to noncontrolling interests 10
11
30
25
Comprehensive income attributable to BHE shareholders $ 1,734
$ 997
$ 3,286
$ 1,952

The accompanying notes are an integral part of these consolidated financial statements.

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

BHE Shareholders' Equity
Accumulated
Additional Other
Common Paid-in Retained Comprehensive Noncontrolling Total
Shares Stock Capital Earnings Loss, Net Interests Equity

Balance, December 31, 2015 77
$ —
$ 6,403
$ 16,906
$ (908 ) $ 134
$ 22,535
Net income —
—
—
2,062
—
14
2,076
Other comprehensive loss —
—
—
—
(110 ) —
(110 )
Distributions —
—
—
—
—
(14 ) (14 )
Other equity transactions —
—
1
—
—
8
9
Balance, September 30, 2016 77
$ —
$ 6,404
$ 18,968
$ (1,018 ) $ 142
$ 24,496

Balance, December 31, 2016 77
$ —
$ 6,390
$ 19,448
$ (1,511 ) $ 136
$ 24,463
Net income —
—
—
2,198
—
14
2,212
Other comprehensive income —
—
—
—
1,088
—
1,088
Distributions —
—
—
—
—
(16 ) (16 )
Common stock purchases —
—
(1 ) (18 ) —
—
(19 )
Common stock exchange —
—
(6 ) (94 ) —
—
(100 )
Other equity transactions —
—
(21 ) —
—
(3 ) (24 )
Balance, September 30, 2017 77
$ —
$ 6,362
$ 21,534
$ (423 ) $ 131
$ 27,604

The accompanying notes are an integral part of these consolidated financial statements.

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

Nine-Month Periods
Ended September 30,
2017 2016
Cash flows from operating activities:
Net income $ 2,228
$ 2,087
Adjustments to reconcile net income to net cash flows from operating activities:

Depreciation and amortization 1,943
1,922
Allowance for equity funds (59 ) (147 )
Equity income, net of distributions (14 ) (62 )
Changes in regulatory assets and liabilities 17
41
Deferred income taxes and amortization of investment tax credits 573
546
Other, net 13
(60 )
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets (98 ) (348 )
Derivative collateral, net (16 ) 22
Pension and other postretirement benefit plans (29 ) (73 )
Accrued property, income and other taxes 390
713
Accounts payable and other liabilities 170
183
Net cash flows from operating activities 5,118
4,824

Cash flows from investing activities:

Capital expenditures (3,179 ) (3,521 )
Acquisitions, net of cash acquired (1,102 ) (66 )
Increase in restricted cash and investments (45 ) (48 )
Purchases of available-for-sale securities (167 ) (98 )
Proceeds from sales of available-for-sale securities 186
125
Equity method investments (54 ) (462 )
Other, net (12 ) (47 )
Net cash flows from investing activities (4,373 ) (4,117 )

Cash flows from financing activities:

Repayments of BHE senior debt and junior subordinated debentures (1,344 ) (1,500 )
Common stock purchases (19 ) —
Proceeds from subsidiary debt 1,562
1,484
Repayments of subsidiary debt (834 ) (1,613 )
Net proceeds from short-term debt 365
887
Other, net (60 ) (50 )
Net cash flows from financing activities (330 ) (792 )

Effect of exchange rate changes 6
(5 )

Net change in cash and cash equivalents 421
(90 )
Cash and cash equivalents at beginning of period 721
1,108
Cash and cash equivalents at end of period $ 1,142
$ 1,018

The accompanying notes are an integral part of these consolidated financial statements.

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	~~General~~

(1) General

Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of ~~locally-managed~~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 is~~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) ~~Limited~~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 ("~~AltaLink"~~BHE Canada") (which primarily consists of AltaLink, L.P. ("~~ALP"~~AltaLink")) and BHE U.S. Transmission, ~~LLC)~~LLC and its subsidiaries), ~~BHE Renewables (which primarily consists of~~ BHE Renewables, LLC and ~~CalEnergy Philippines)~~its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. ~~(collectively with~~and its subsidiaries ~~"HomeServices"~~("HomeServices"). The Company, through these locally managed and operated businesses, owns four utility companies in the ~~United States~~U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, ~~two~~five interstate natural gas pipeline companies in the ~~United States,~~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 ~~United States,~~U.S., a renewable energy business primarily ~~selling power generated from~~investing in wind, solar, ~~wind,~~ geothermal and hydroelectric ~~sources under long-term contracts, the second largest residential real estate brokerage firm in the United States~~projects and one of the largest residential real estate brokerage firms and residential real estate brokerage franchise networks in the ~~United States.~~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 ~~September~~June 30, ~~2017~~2023, and for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~.2022. The results of operations for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~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, ~~2016~~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 ~~and policies~~ during the ~~nine-month~~six-month period ended~~September~~ June 30, ~~2017~~.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.

(2)

(2) New Accounting Pronouncements

In ~~August 2017,~~March 2023, the ~~Financial Accounting Standards Board ("FASB")~~FASB issued ~~Accounting Standards Update ("ASU")~~ASU No. ~~2017-12,~~2023-02, amending FASB ASC Topic 323-740, "Investments—Equity Method and Joint Ventures—Income Taxes" which ~~amends FASB Accounting Standards Codification ("ASC") Topic 815, "Derivatives and Hedging."~~set forth the conditions needed to apply the proportional amortization method. The amendments in this ~~guidance~~ update ~~the hedge accounting model to enable~~permit reporting entities to ~~better portray~~elect to account for their tax equity investments, regardless of the ~~economics of their risk management activities in~~tax credit program from which the ~~financial statements, expands an entity’s ability to hedge non-financial and financial risk components and reduces complexity in fair value hedges of interest rate risk. In addition, it eliminates~~income tax credits are received, using the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be presented in the same income statement line as the hedged item and also easesproportional amortization method if certain ~~documentation and assessment requirements.~~conditions are met. This guidance is effective for interim and annual reporting periods beginning after December 15, ~~2018,~~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.~~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

~~In March 2017,~~

On July 9, 2023, BHE and Eastern MLP Holding Company II, LLC ("the ~~FASB issued ASU No. 2017-07,~~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 ~~amends FASB ASC Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate~~ the ~~service cost component~~Transaction closes. BHE expects to fund the purchase price with cash on hand, including cash realized from the ~~other components~~liquidation of ~~net benefit cost~~certain investments. Upon the completion of the Transaction, the Buyer will own an aggregate of 75% of the limited partner interests, and ~~report~~its affiliate, Cove Point GP Holding Company, LLC, will continue to own 100% of the ~~service cost component in~~general partner interest, of Cove Point.

The consummation of the ~~same line item as other compensation costs arising from services rendered~~Transaction contemplated by the ~~pertinent employees during~~Purchase Agreement is subject to customary closing conditions, including without limitation (i) the ~~period. The other components~~expiration or termination of ~~net benefit cost are required to be presented in~~any applicable waiting periods under the ~~statement~~Hart-Scott-Rodino Antitrust Improvements Act of ~~operations separately from~~1976, as amended, (ii) the ~~service cost component~~filing of a notification with the U.S. Department of Energy and ~~outside~~ the ~~subtotal~~expiration of ~~operating income. Additionally,~~any applicable period; and (iii) the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentationaccuracy of the ~~service cost component~~representations and warranties and compliance by the ~~other components of net benefit cost~~parties in all material respects with their respective obligations under the ~~statement of operations and prospectively for the capitalization~~Purchase Agreement. The Transaction is expected to close by year-end 2023, subject to satisfaction of the ~~service cost component in~~foregoing conditions, among other things.

The Purchase Agreement provides that if the ~~balance sheet. The Company plans~~Seller or DEI terminates the Purchase agreement due to ~~adopt this guidance effective January 1, 2018. The Company does not believe this will have~~ a ~~material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.~~

In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. The Company plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will have a material impact on its Consolidated Financial Statements.

In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. The Company plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidationbreach of the ~~investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning~~Purchase Agreement by the Buyer or Buyer's failure to consummate the Transaction within three business days after ~~December 15, 2017, with early adoption not permitted, and is required~~all of the conditions to ~~be adopted prospectively by means of a cumulative-effect adjustment~~close have been satisfied or waived, BHE will pay to the ~~balance sheet as~~Seller a termination fee of ~~the beginning of the fiscal year of adoption. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements~~$150 million.

(4) Property, Plant and disclosures included within Notes to Consolidated Financial Statements. The material impacts currently identified include recording the unrealized gains and losses on available-for-sale securities in the Consolidated Statements of Operations as opposed to other comprehensive income ("OCI"). For the nine-month periods ended September 30, 2017 and 2016, these amounts, net of tax, were 542 million and 151 million, respectively.Equipment, Net

In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. The Company currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when the Company has the right to invoice as it corresponds directly with the value to the customer of the Company’s performance to date. The Company's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by regulated energy, nonregulated energy and real estate, with further disaggregation of regulated energy by jurisdiction and real estate by line of business.


~~(3)~~	~~Business Acquisitions~~

The Company completed various acquisitions totaling $1.1 billion, net of cash acquired, for the nine-month period ended September 30, 2017. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which primarily related to residential real estate brokerage businesses, development and construction costs for the 110-megawatt Alamo 6 solar project and the 50-megawatt Pearl solar project, and the remaining 25% interest in the Silverhawk natural gas-fueled generation facility at Nevada Power. As a result of the various acquisitions, the Company acquired assets of $1.1 billion, assumed liabilities of $476 million and recognized goodwill of $522 million.


~~(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

As of
Depreciable September 30, December 31,
Life 2017 2016
Regulated assets:
Utility generation, transmission and distribution systems 5-80 years $ 73,138
$ 71,536
Interstate natural gas pipeline assets 3-80 years 6,991
6,942
80,129
78,478
Accumulated depreciation and amortization (24,525 ) (23,603 )
Regulated assets, net 55,604
54,875

Nonregulated assets:

Independent power plants 5-30 years 5,911
5,594
Other assets 3-30 years 1,265
1,002
7,176
6,596
Accumulated depreciation and amortization (1,304 ) (1,060 )
Nonregulated assets, net 5,872
5,536

Net operating assets 61,476
60,411
Construction work-in-progress 3,503
2,098
Property, plant and equipment, net $ 64,979
$ 62,509

Construction work-in-progress includes ~~$3.1~~$7.1 billion as of ~~September~~June 30, ~~2017~~2023 and ~~$1.8~~$4.9 billion as of December 31, ~~2016~~,2022, related to the construction of regulated assets.

~~During the fourth quarter of 2016, MidAmerican Energy revised its electric~~

(5) Investments and gas depreciation rates based on the results of a new depreciation study, the most significant impact of which was longer estimated useful lives for certain wind-powered generating facilities. The effect of this change was to reduce depreciationRestricted Cash and ~~amortization expense by $34 million annually, or $9 million~~Cash Equivalents and ~~$26 million for the three- and nine-month periods ended September 30, 2017, based on depreciable plant balances at the time of the change.~~Investments


(5)	~~Investments and Restricted Cash 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

As of
September 30, December 31,
2017 2016
Investments:
BYD Company Limited common stock $ 2,087
$ 1,185
Rabbi trusts 431
403
Other 132
106
Total investments 2,650
1,694

Equity method investments:
BHE Renewables tax equity investments 804
741
Electric Transmission Texas, LLC 693
672
Bridger Coal Company 140
165
Other 158
142
Total equity method investments 1,795
1,720

Restricted cash and investments:

Quad Cities Station nuclear decommissioning trust funds 498
460
Other 317
282
Total restricted cash and investments 815
742

Total investments and restricted cash and investments $ 5,260
$ 4,156

Reflected as:
Other current assets $ 273
$ 211
Noncurrent assets 4,987
3,945
Total investments and restricted cash and investments $ 5,260
$ 4,156

Investments

~~BHE's investment~~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

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in ~~BYD Company Limited common stock~~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 ~~accounted~~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 ~~an available-for-sale security with changes~~presented on the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in ~~fair value recognized in accumulated other comprehensive income (loss) ("AOCI"). The fair value of BHE's investment in BYD Company Limited common stock reflects a pre-tax unrealized gain of~~ ~~$1,855 million~~ ~~and~~ ~~$953 million~~ ~~as of~~ ~~September 30, 2017~~ ~~and~~ ~~December 31, 2016, respectively.~~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~~

(6) Recent Financing Transactions

Long-Term Debt

~~In the first nine months of 2017, BHE repaid at par value a total of $944 million, plus accrued interest, of its junior subordinated debentures due December 2044.~~

In September 2017, HomeServices entered into a $250 million unsecured amortizing term loan due September 2022. The amortizing term loan has an underlying variable interest rate based on the London Interbank Offered Rate ("LIBOR") plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter. The net proceeds were used to fund the repayment or reimbursement of amounts provided by BHE for the costs related to acquisitions.

In July 2017, Northern Powergrid Metering Limited entered into a £200 million secured amortizing corporate facility with a stated maturity of June 2026. The amortizing facility has a variable interest rate based on the LIBOR plus a spread that varies based on an agreed-upon schedule. In July 2017, Northern Powergrid Metering Limited received proceeds of £120 million under the facility to repay amounts provided by Yorkshire Electricity Group plc which provides internal funds for the continuing smart meter deployment program of Northern Powergrid Metering Limited. Northern Powergrid Metering Limited has entered into interest rate swaps that fix the underlying interest rate on 85% of the outstanding debt.

In July 2017, Cordova Funding Corporation redeemed the remaining $89 million of its 8.48% to 9.07% Series A Senior Secured Bonds due December 2019, CE Generation, LLC redeemed the remaining $51 million of its 7.416% Senior Secured Bonds due December 2018, and Salton Sea Funding Corporation redeemed the remaining $20 million of its 7.475% Senior Secured Series F Bonds due November 2018, each at redemption prices determined in accordance with the terms of the respective indentures.

In June 2017, BHE issued $100 million of its 5.0% junior subordinated debentures due June 2057 in exchange for 181,819 shares of BHE no par value common stock held by a minority shareholder. The junior subordinated debentures are redeemable at BHE's option at any time from and after June 15, 2037, at par plus accrued and unpaid interest.

In May ~~2017, Alamo 6, LLC~~2023, PacifiCorp issued ~~$232 million~~$1.2 billion of its 4.17% Senior Secured Notes due March 2042. The principal of the notes amortizes beginning March 2018 with a final maturity in March 2042. The net proceeds were used to fund the repayment or reimbursement of amounts provided by BHE for the costs related to the development, construction and financing of a 110-megawatt solar project in Texas.

~~In April 2017, Kern River redeemed the remaining $175 million of its 4.893% Senior Notes due April 2018 at a redemption price determined in accordance with the terms of the indenture.~~

~~In February 2017, MidAmerican Energy issued $375 million of its 3.10%~~5.50% First Mortgage Bonds due May ~~2027 and $475 million~~2054. PacifiCorp intends, within 24 months of ~~its 3.95% First Mortgage Bonds due August 2047. An~~the issuance date, to allocate an amount equal to the net proceeds ~~was used~~ to finance ~~capital~~or refinance, in whole or in part, new or existing investments or expenditures ~~disbursed during the period from February 2, 2016 to February 1, 2017,~~made in one or more eligible projects in alignment with ~~respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds.~~BHE's Green Financing Framework.

~~In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.~~

Credit Facilities

In ~~September 2017, HomeServices terminated~~June 2023, BHE amended its ~~$350 million~~existing $3.5 billion unsecured credit facility expiring ~~July 2018 and entered into a $600 million~~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 ~~September 2022.~~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 which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the LIBOR or a base rate, at HomeServices' option, plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter.expiring in January 2024.

In June ~~2017, BHE~~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 ~~maturity~~expiration date ~~to June 2020~~ for its ~~$2.0 billion unsecured~~existing C$200 million one year revolving credit facility ~~and PacifiCorp extended, with lender consent, the maturity date~~ to ~~June 2020 for its $400 million unsecured credit facility, each~~April 2024, by exercising ~~the first of two available one-year extensions.~~

~~In June 2017, PacifiCorp terminated its $600 million unsecured credit facility expiring March 2018 and entered into~~ a ~~$600 million unsecured credit facility expiring June 2020 with two~~ one-year extension options subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. The credit facility requires PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.option.

In June 2017, MidAmerican Energy terminated its $600 million unsecured credit facility expiring March 2018 and entered into a $900 million unsecured credit facility expiring June 2020 with two one-year extension options subject to lender consent. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. The credit facility requires MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.

In June 2017, Nevada Power amended its $400 million secured credit facility, extending the maturity date to June 2020 with two one-year extension options subject to lender consent. The amended credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long-term debt securities. The amended credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not to exceed 0.65 to 1.0 as of the last day of each quarter.(7) Income Taxes

In June 2017, Sierra Pacific amended its $250 million secured credit facility, extending the maturity date to June 2020 with two one-year extension options subject to lender consent. The amended credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Sierra Pacific's option, plus a spread that varies based on Sierra Pacific's credit ratings for its senior secured long-term debt securities. The amended credit facility requires Sierra Pacific's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.

In May 2017, BHE entered into a $1.0 billion unsecured credit facility expiring May 2018. The credit facility, which is for general corporate purposes and also supports BHE's commercial paper program and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at BHE's option, plus a spread that varies based on BHE's credit ratings for its senior unsecured long-term debt securities. The credit facility requires BHE's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.70 to 1.0 as of the last day of each quarter.


(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)	%

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Federal statutory income tax rate 35 % 35 % 35 % 35 %
Income tax credits (19 ) (16 ) (18 ) (15 )
State income tax, net of federal income tax benefit —
—
(1 ) —
Income tax effect of foreign income (3 ) (3 ) (4 ) (4 )
Equity income 1
1
1
1
Other, net 1
(1 ) —

—
Effective income tax rate 15 % 16 % 13 % 17 %

Income tax credits relate primarily to production tax credits ("PTCs") from ~~wind-powered~~wind- and solar-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity ~~production tax credits~~PTCs are earned as energy from qualifying ~~wind-powered~~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-powered~~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.

~~Berkshire Hathaway~~Income tax effect on foreign income includes, ~~the Company in its United States federal~~among other items, a deferred income tax ~~return.~~ 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,~~basis. Berkshire Hathaway includes the Company in its consolidated U.S. federal and ~~substantially all~~Iowa state income tax returns and the majority of ~~its currently payable or receivable~~the Company's U.S. federal income ~~taxes are~~tax is remitted to or received from Berkshire Hathaway. ~~For the nine-month periods ended September 30,~~ ~~2017~~ ~~and 2016, the~~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 ~~$659~~$864 million and ~~$860~~$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.


(8)	~~Employee Benefit Plans~~

(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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016
Pension:
Service cost $ 6
$ 7
$ 18
$ 22
Interest cost 29
31
87
94
Expected return on plan assets (40 ) (39 ) (120 ) (120 )
Net amortization 7
12
22
36
Net periodic benefit cost $ 2
$ 11
$ 7
$ 32

Other postretirement:
Service cost $ 3
$ 2
$ 7
$ 7
Interest cost 7
7
21
23
Expected return on plan assets (9 ) (10 ) (30 ) (31 )
Net amortization (3 ) (2 ) (10 ) (9 )
Net periodic benefit credit $ (2 ) $ (3 ) $ (12 ) $ (10 )

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 ~~$15~~$13 million and $5$7 million, respectively, during ~~2017.~~2023. As of ~~September~~June 30, ~~2017, $9~~2023, $7 million and $5$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)

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Service cost $ 6
$ 5
$ 19
$ 16
Interest cost 15
17
44
55
Expected return on plan assets (25 ) (27 ) (74 ) (85 )
Settlement 18
—
18
—
Net amortization 17
11
50
34
Net periodic benefit cost $ 31
$ 6
$ 57
$ 20

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 ~~£45~~£11 million during ~~2017~~.2023. As of ~~September~~June 30, ~~2017~~, ~~£34~~2023, £6 million,, or ~~$43~~$7 million,, of contributions had been made to the United Kingdom pension plan.


(9)	~~Risk Management and Hedging Activities~~

The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of PacifiCorp,

(9) Asset Retirement Obligations

MidAmerican Energy ~~Nevada Power and Sierra Pacific (the "Utilities"~~estimates its asset retirement obligation ("ARO") as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt, future debt issuances and mortgage commitments. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain and Canada. The Company does not engage in a material amount of proprietary trading activities.

~~Each~~liabilities based upon detailed engineering calculations of the ~~Company's business platforms has established a risk management process that is designed to identify, assess, manage, monitor~~amount and ~~report each~~timing of the ~~various types~~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 risk involved in its business. To mitigate a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company 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 marketreasons including changes in interest rates. Additionally, the Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, forward sale commitments, or mortgage interest rate lock commitments, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price, interest ratelaws and ~~foreign currency exchange rate risks, thereby exposing the unhedged portion to changes in market prices.~~

~~There have been no significant~~regulations, plan revisions, inflation and changes in the ~~Company's accounting policies related to derivatives. Refer to Note 10~~amount and timing of expected work. During the six-month period ended June 30, 2023, MidAmerican Energy recorded an increase of $88 million for ~~additional information on derivative contracts.~~

~~The following table,~~decommissioning its wind-generating facilities, 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 the Company's derivative contracts, onis a ~~gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):~~

Other Other Other
Current Other Current Long-term
Assets Assets Liabilities Liabilities Total
As of September 30, 2017
Not designated as hedging contracts:
Commodity assets⁽¹⁾
$ 16
$ 93
$ 7
$ 3
$ 119
Commodity liabilities⁽¹⁾
(1 ) —
(60 ) (135 ) (196 )
Interest rate assets 22
—
—
—
22
Interest rate liabilities —
—
(3 ) (7 ) (10 )
Total 37
93
(56 ) (139 ) (65 )

Designated as hedging contracts:

Commodity assets —
—
2
6
8
Commodity liabilities —
—
(11 ) (17 ) (28 )
Interest rate assets —
6
—
—
6
Interest rate liabilities —
—
(1 ) —
(1 )
Total —
6
(10 ) (11 ) (15 )

Total derivatives 37
99
(66 ) (150 ) (80 )
Cash collateral receivable —
—
21
64
85
Total derivatives - net basis $ 37
$ 99
$ (45 ) $ (86 ) $ 5

Other Other Other
Current Other Current Long-term
Assets Assets Liabilities Liabilities Total
As of December 31, 2016
Not designated as hedging contracts:
Commodity assets⁽¹⁾
$ 42
$ 86
$ 5
$ 2
$ 135
Commodity liabilities⁽¹⁾
(10 ) —
(46 ) (150 ) (206 )
Interest rate assets 15
—
—
—
15
Interest rate liabilities —
—
(4 ) (6 ) (10 )
Total 47
86
(45 ) (154 ) (66 )

Designated as hedging contracts:
Commodity assets 1
—
2
3
6
Commodity liabilities —
—
(14 ) (8 ) (22 )
Interest rate assets —
8
—
—
8
Interest rate liabilities —
—
(3 ) —
(3 )
Total 1
8
(15 ) (5 ) (11 )

Total derivatives 48
94
(60 ) (159 ) (77 )
Cash collateral receivable —
—
13
61
74
Total derivatives - net basis $ 48
$ 94
$ (47 ) $ (98 ) $ (3 )

~~(1)~~

~~The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of~~ ~~September 30, 2017~~ ~~and~~ ~~December 31, 2016, a net regulatory asset of~~ ~~$162 million~~ ~~and~~ ~~$148 million, respectively, was recorded related to the net derivative liability of~~ ~~$77 million~~ ~~and~~ ~~$71 million, respectively. The difference between the net regulatory asset and the net derivative liability relates primarily to a power purchase agreement derivative at BHE Renewables.~~

~~Not Designated as Hedging Contracts~~

The following table reconciles the beginning and ending balances of the Company's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Beginning balance $ 162
$ 185
$ 148
$ 250
Changes in fair value recognized in net regulatory assets 10
18
43
5
Net (losses) gains reclassified to operating revenue (5 ) (3 ) 9
(6 )
Net losses reclassified to cost of sales (5 ) (5 ) (38 ) (54 )
Ending balance $ 162
$ 195
$ 162
$ 195

~~Designated as Hedging Contracts~~

The Company uses commodity derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions. Certain commodity derivative contracts have settled and the fair value at the date of settlement remains in AOCInon-cash investing activity and is recognized in earnings when the forecasted transactions impact earnings. The following table reconciles the beginning and ending balances of the Company's accumulated other comprehensive (income) loss (pre-tax) and summarizes pre-tax gains and losses on commodity derivative contracts designated and qualifying as cash flow hedges recognized in OCI, as well as amounts reclassified to earnings (in millions):

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Beginning balance $ 21
$ 26
$ 16
$ 46
Changes in fair value recognized in OCI 5
15
28
35
Net gains reclassified to operating revenue —
1
—
1
Net losses reclassified to cost of sales (7 ) (7 ) (25 ) (47 )
Ending balance $ 19
$ 35
$ 19
$ 35

Realized gains and losses on hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales, operating expense or interest expense depending upon the nature of the item being hedged. For the three- and nine-month periods ended ~~September 30, 2017~~ ~~and~~ ~~2016, hedge ineffectiveness was insignificant. As of~~ ~~September 30, 2017, the Company had cash flow hedges with expiration dates extending through~~ ~~June 2026~~ ~~and~~ ~~$10 million~~ ~~of pre-tax unrealized losses are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.~~

~~Derivative Contract Volumes~~

~~The following table summarizes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):~~

Unit of September 30, December 31,
Measure 2017 2016

Electricity purchases Megawatt hours 9
5
Natural gas purchases Decatherms 339
271
Fuel purchases Gallons 2
11
Interest rate swaps US$ 694
714
Interest rate swaps £ 102
—
Mortgage sale commitments, net US$ (442 ) (309 )

~~Credit Risk~~

The Utilities are exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent the Utilities' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Utilities analyze the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.

~~Collateral and Contingent Features~~

In accordance with industry practice, certain wholesale 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 three recognized credit rating agencies. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract,updated decommissioning estimate reflecting changes in the ~~event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of~~ ~~September 30, 2017, the applicable credit ratings from the three recognized credit rating agencies were investment grade.~~projected removal costs per turbine.

~~The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features totaled~~ ~~$190 million~~ ~~and~~ ~~$190 million~~ ~~as of~~ ~~September 30, 2017~~ ~~and~~ ~~December 31, 2016, respectively, for which the Company had posted collateral of $73 million and~~ ~~$69 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of~~ ~~September 30, 2017~~ ~~and~~ ~~December 31, 2016, the Company would have been required to post~~ ~~$105 million~~ ~~and~~ ~~$110 million~~, respectively, of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

(10) Fair Value Measurements


~~(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.

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)


																		Input Levels for Fair Value Measurements
	Input Levels for Fair Value Measurements																	Level 1			Level 2			Level 3			Other(1)			Total
	Level 1			Level 2			Level 3			Other⁽¹⁾			Total
As of September 30, 2017
As of December 31, 2022:																As of December 31, 2022:
Assets:																Assets:
Commodity derivatives	$	1		$	24		$	102		$	(19	)	$	108		Commodity derivatives		$	6		$	614		$	51		$	(194)		$	477

Interest rate derivatives	—			14			14			—			28			Interest rate derivatives		50			54			8			—			112
Mortgage loans held for sale	—			534			—			—			534			Mortgage loans held for sale		—			474			—			—			474
Money market mutual funds⁽²⁾	855			—			—			—			855				1,178			—			—			—			1,178
Debt securities:																Debt securities:
United States government obligations	168			—			—			—			168
U.S. government obligations																U.S. government obligations		2,146			—			—			—			2,146
International government obligations	—			5			—			—			5			International government obligations		—			1			—			—			1
Corporate obligations	—			37			—			—			37			Corporate obligations		—			70			—			—			70
Municipal obligations	—			2			—			—			2			Municipal obligations		—			3			—			—			3
Agency, asset and mortgage-backed obligations	—			1			—			—			1			Agency, asset and mortgage-backed obligations		—			1			—			—			1
Equity securities:																Equity securities:
United States companies	270			—			—			—			270
U.S. companies																U.S. companies		360			—			—			—			360
International companies	2,094			—			—			—			2,094			International companies		3,771			—			—			—			3,771
Investment funds	182			—			—			—			182			Investment funds		231			—			—			—			231
	$	3,570		$	617		$	116		$	(19	)	$	4,284				$	7,742		$	1,217		$	59		$	(194)		$	8,824
Liabilities:																Liabilities:
Commodity derivatives	$	(1	)	$	(207	)	$	(16	)	$	104		$	(120	)	Commodity derivatives		$	(8)		$	(206)		$	(110)		$	106		$	(218)
Foreign currency exchange rate derivatives																Foreign currency exchange rate derivatives		—			(21)			—			—			(21)
Interest rate derivatives	—			(10		)	(1		)	—			(11		)	Interest rate derivatives		—			(2)			(2)			1			(3)
	$	(1	)	$	(217	)	$	(17	)	$	104		$	(131	)			$	(8)		$	(229)		$	(112)		$	107		$	(242)

As of December 31, 2016
Assets:
Commodity derivatives $ 5
$ 49
$ 87
$ (22 ) $ 119
Interest rate derivatives —
16
7
—
23
Mortgage loans held for sale —
359
—
—
359
Money market mutual funds⁽²⁾
586
—
—
—
586
Debt securities:
United States government obligations 161
—
—
—
161
International government obligations —
3
—
—
3
Corporate obligations —
36
—
—
36
Municipal obligations —
2
—
—
2
Agency, asset and mortgage-backed obligations —
2
—
—
2
Equity securities:
United States companies 250
—
—
—
250
International companies 1,190
—
—
—
1,190
Investment funds 147
—
—
—
147
$ 2,339
$ 467
$ 94
$ (22 ) $ 2,878
Liabilities:
Commodity derivatives $ (2 ) $ (199 ) $ (27 ) $ 96
$ (132 )
Interest rate derivatives (1 ) (11 ) (1 ) —
(13 )
$ (3 ) $ (210 ) $ (28 ) $ 96
$ (145 )


~~(1)~~	~~Represents netting under master netting arrangements and a net cash collateral receivable of~~ ~~$85 million~~ ~~and~~ ~~$74 million~~ ~~as of~~ ~~September 30, 2017~~ ~~and~~ ~~December 31, 2016, respectively.~~


~~(2)~~	Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

(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. ~~Refer to Note 9 for further discussion regarding the Company's risk management and hedging activities.~~

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.

The Company's investments in money market mutual funds and debt and equity securities are stated at fair ~~value and are primarily accounted for as available-for-sale securities.~~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


	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
				Interest			Auction					Interest			Auction
	Commodity			Rate			Rate		Commodity			Rate			Rate
	Derivatives			Derivatives			Securities		Derivatives			Derivatives			Securities
2017:
2022:																	2022:
Beginning balance	$	81		$	8		$	—	$	60		$	6		$	—	Beginning balance	$	(239)	$	13	$	(151)	$	19
Changes included in earnings	7			34			—		19			100			—
Changes included in earnings(1)																	Changes included in earnings(1)	(26)		8		(82)		2
Changes in fair value recognized in OCI	(1		)	—			—		(3		)	—			—		Changes in fair value recognized in OCI	5		—		10		—
Changes in fair value recognized in net regulatory assets	(3		)	—			—		(5		)	—			—		Changes in fair value recognized in net regulatory assets	1		—		(59)		—
Purchases	—			8			—		1			6			—		Purchases	1		—		1		—

Settlements	2			(37		)	—		14			(99		)	—		Settlements	11		—		34		—
Transfers out of Level 3 into Level 2																	Transfers out of Level 3 into Level 2	69		—		69		—
Ending balance	$	86		$	13		$	—	$	86		$	13		$	—	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.

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
Interest Auction Interest Auction
Commodity Rate Rate Commodity Rate Rate
Derivatives Derivatives Securities Derivatives Derivatives Securities
2016:
Beginning balance $ 44
$ 14
$ 18
$ 47
$ 4
$ 44
Changes included in earnings 9
49
—
8
103
—
Changes in fair value recognized in OCI (2 ) —
—
(2 ) —
6
Changes in fair value recognized in net regulatory assets (1 ) —
—
(12 ) —
—
Purchases 1
—
—
1
—
—
Redemptions —
—
—
—
—
(32 )
Settlements 5
(52 ) —
14
(96 ) —
Ending balance $ 56
$ 11
$ 18
$ 56
$ 11
$ 18

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

As of September 30, 2017 As of December 31, 2016
Carrying Fair Carrying Fair
Value Value Value Value

Long-term debt $ 36,124
$ 41,197
$ 36,116
$ 40,718

(11) Commitments and Contingencies


(~~11)~~	~~Commitments and Contingencies~~

~~Fuel, Capacity and Transmission Contract~~ Commitments

~~During~~The Company has the nine-month period ended September 30, 2017, MidAmerican Energy amended certain of its natural gas supply and transportation contracts increasing minimum payments by $247 million through 2021 and $70 million for 2022 through 2037.following firm commitments that are not reflected on the Consolidated Balance Sheets.

Construction Commitments

During the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017,~~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 ~~contracts~~firm construction commitments totaling ~~$675~~$183 million for the remainder of 2023 through 2024 related to the construction of wind-powered generating facilities in ~~2017 through 2019, with remaining payments totaling $84 million for the fourth quarter of 2017, $340 million in 2018 and $8 million in 2019.~~Iowa.

~~Operating Leases and Easements~~Fuel Contracts

During the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017, MidAmerican Energy~~2023, PacifiCorp entered into ~~non-cancelable easements with minimum payments~~certain coal supply agreements totaling ~~$114~~$425 million through ~~2057 for land in Iowa on which some of its wind-powered generating facilities will be located.~~2025.

~~Legal Matters~~

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding air ~~and water~~ quality, ~~renewable portfolio standards,~~climate change, emissions performance standards, ~~climate change,~~water quality, coal ~~combustion byproduct~~ash disposal, hazardous ~~and solid waste disposal, protected species~~ and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.

~~Hydroelectric Relicensing~~

PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with the FERC. In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the state of California, the state of Oregon and various other governmental and non-governmental settlement parties signed theLower Klamath Hydroelectric ~~Settlement Agreement~~Project

In November 2022, the Federal Energy Regulatory Commission ("~~KHSA"~~FERC").

~~Congress failed to pass legislation needed to implement~~ issued a license surrender order for the original KHSA. On April 6, 2016, PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and Commerce and other stakeholders executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, on September 23, 2016, PacifiCorp andLower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") ~~jointly filed an application~~and the states of Oregon and California ("States") in December 2022, along with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilities from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with the FERC to surrender the license and decommission the facilities. The KRRC's license surrender application included a request for the FERC to refrain from acting on the surrender application until after the transfer of the ~~license~~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 ~~effective.~~

~~Under~~ready for removal. Removal of the ~~amended KHSA, PacifiCorp~~Copco No. 2 facility began in June 2023, and ~~its customers are protected from uncapped~~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 ~~costs~~ and ~~liabilities. The KRRC must indemnify PacifiCorp from liabilities associated with dam removal. The amended KHSA also limits PacifiCorp's contribution to facilities removal costs to no more than~~restoration; $200 million ~~of which up to $184 million would be~~ collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measure in November 2014 from which the state of California's contribution towards facilities removal costs are being drawn. In accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the California state budget in 2016, with the funding effective for at least five years. If facilities removal costs exceed the combined funding that will be available from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the ~~state~~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.

In California, ~~sufficient funds would need~~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.

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 ~~provided~~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 ~~KRRC or an entity other than~~U.S. Forest Service.

Due to the preliminary nature of the investigation, PacifiCorp ~~for removal to proceed.~~

~~If certain conditions in the amended KHSA are not satisfied and the license~~ does not ~~transfer~~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 ~~KRRC, PacifiCorp~~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 ~~resume relicensing with~~only be made following the ~~FERC.~~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.


~~(12~~)	~~Components of Other Comprehensive Income (Loss), Net~~

(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 and Other(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 and Other(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


	For the Three-Month Period Ended June 30, 2022
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(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 and Other(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

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 ~~AOCI attributable to BHE shareholders~~accumulated other comprehensive loss by each component of ~~OCI,~~other comprehensive income (loss), net of applicable income ~~taxes~~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)

Unrealized
Unrecognized Foreign Gains on Unrealized AOCI
Amounts on Currency Available- Gains (Losses) Attributable
Retirement Translation For-Sale on Cash To BHE
Benefits Adjustment Securities Flow Hedges Shareholders, Net

Balance, December 31, 2015 $ (438 ) $ (1,092 ) $ 615
$ 7
$ (908 )
Other comprehensive income (loss) 80
(339 ) 151
(2 ) (110 )
Balance, September 30, 2016 $ (358 ) $ (1,431 ) $ 766
$ 5
$ (1,018 )

Balance, December 31, 2016 $ (447 ) $ (1,675 ) $ 585
$ 26
$ (1,511 )
Other comprehensive income (loss) 16
535
542
(5 ) 1,088
Balance, September 30, 2017 $ (431 ) $ (1,140 ) $ 1,127
$ 21
$ (423 )

(14) Segment Information

~~Reclassifications from AOCI to net income for the periods ended~~ ~~September 30, 2017~~ ~~and~~ ~~2016~~ ~~were insignificant. For information regarding cash flow hedge reclassifications from AOCI to net income in their entirety, refer to Note 9. Additionally, refer to the "Foreign Operations" discussion in Note 8 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.~~


~~(13~~)	~~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, and BHE Renewables, whose business includes operations in the Philippines.~~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


											Three-Month Periods				Six-Month Periods
	Three-Month Periods				Nine-Month Periods						Ended June 30,				Ended June 30,
	Ended September 30,				Ended September 30,						2023		2022		2023		2022
	2017		2016		2017			2016
Operating revenue:
Operating income:										Operating income:
PacifiCorp	$	1,430	$	1,434	$	3,956		$	3,919	PacifiCorp	$	131	$	158	$	(36)	$	374
MidAmerican Funding	815		797		2,170			2,008		MidAmerican Funding	118		90		206		190
NV Energy	1,047		987		2,384			2,309		NV Energy	117		140		174		202
Northern Powergrid	221		220		685			748		Northern Powergrid	121		110		267		269
BHE Pipeline Group	193		201		700			704		BHE Pipeline Group	368		352		952		890
BHE Transmission	182		169		506			309		BHE Transmission	76		84		164		167
BHE Renewables	283		273		647			582		BHE Renewables	89		155		20		209
HomeServices	961		820		2,502			2,152		HomeServices	46		117		1		145
BHE and Other⁽¹⁾	151		191		453			523		BHE and Other(1)	(20)		1		(35)		(3)
Total operating revenue	$	5,283	$	5,092	$	14,003		$	13,254

Depreciation and amortization:
PacifiCorp	$	200	$	193	$	598		$	589
MidAmerican Funding	112		118		370			338
NV Energy	105		106		315			315
Northern Powergrid	55		49		156			149
BHE Pipeline Group	42		53		115			160
BHE Transmission	58		61		165			177
BHE Renewables	63		57		187			169
HomeServices	16		9		38			24
BHE and Other⁽¹⁾	—		2		(1		)	1
Total depreciation and amortization	$	651	$	648	$	1,943		$	1,922
Total operating income										Total operating income	1,046		1,207		1,713		2,443
Interest expense										Interest expense	(599)		(550)		(1,185)		(1,082)
Capitalized interest										Capitalized interest	33		18		57		35
Allowance for equity funds										Allowance for equity funds	61		42		110		80
Interest and dividend income										Interest and dividend income	127		30		213		53
Gains on marketable securities, net										Gains on marketable securities, net	303		2,528		1,002		1,271
Other, net										Other, net	78		(26)		118		(21)
Total income (loss) before income tax expense (benefit) and equity income (loss)										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


														As of
	Three-Month Periods						Nine-Month Periods							June 30,		December 31,
	Ended September 30,						Ended September 30,							2023		2022
	2017			2016			2017			2016
Operating income:
Assets:													Assets:
PacifiCorp	$	467		$	445		$	1,150		$	1,108		PacifiCorp	$	31,700	$	30,559
MidAmerican Funding	288			284			531			524			MidAmerican Funding	26,241		26,077
NV Energy	393			394			682			656			NV Energy	17,495		16,676
Northern Powergrid	81			90			308			373			Northern Powergrid	9,531		9,005
BHE Pipeline Group	65			68			328			320			BHE Pipeline Group	20,937		21,005
BHE Transmission	86			81			236			35			BHE Transmission	9,599		9,334
BHE Renewables	157			157			256			233			BHE Renewables	11,295		12,632
HomeServices	79			87			191			179			HomeServices	3,795		3,436
BHE and Other⁽¹⁾	8			(21		)	(38		)	(36		)	BHE and Other(1)	7,158		5,116
Total operating income	1,624			1,585			3,644			3,392
Interest expense	(464		)	(460		)	(1,379		)	(1,401		)
Capitalized interest	14			14			34			128
Allowance for equity funds	24			17			59			147
Interest and dividend income	32			39			85			93
Other, net	2			15			24			26
Total income before income tax expense and equity income	$	1,232		$	1,210		$	2,467		$	2,385
Total assets													Total assets	$	137,751	$	133,840

During the second quarter 2017, ALP responded to information requests from the AUC with respect to its 2017-2018 negotiated settlement agreement application filed in February 2017. In August 2017, the AUC issued a decision approving ALP's negotiated settlement agreement for the 2017-2018 GTA, as filed. Also, the AUC approved a C$31 million refund of accumulated depreciation surplus as opposed to the C$130 million refund proposed in the original application. In November 2017, ALP filed a compliance filing with the AUC to reflect the reduction of the accumulated depreciation surplus refund and related adjustments.

~~2018 Generic Cost of Capital Proceeding~~

In July 2017, the AUC denied the utilities’ request that the interim determinations of 8.5% return on equity and deemed capital structures for 2018 be made final, by stating that it is not prepared to finalize 2018 values in the absence of an evidentiary process and its intention to issue the generic cost of capital decision for 2018, 2019 and 2020 by the end of 2018 to reduce regulatory lag. The AUC also confirmed the process timelines with an oral hearing scheduled for March 2018.

~~Deferral Account Reconciliation Application~~

In April 2017, ALP filed its application with the AUC with respect to ALP’s 2014 projects and deferral accounts and specific 2015 projects. The application includes approximately C$2.0 billion in net capital additions. In June 2017, the AUC ruled that the scope of the deferral account proceeding would not be extended to consider the utilization of assets for which final cost approval is sought. However, the AUC will initiate a separate proceeding to address the issue of transmission asset utilization and how the corporate and property law principles applied in the Utility Asset Disposition ("UAD") decision may relate.

~~In June 2017, the AUC also suspended the process in order to address a conflict of interest issue related to the provision of confidential documents.~~

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air ~~and water~~ quality, ~~renewable portfolio standards,~~climate change, emissions performance standards, ~~climate change,~~water quality, coal ~~combustion byproduct~~ash disposal ~~hazardous and solid waste disposal, protected species~~ and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by ~~the EPA and~~ various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many ~~laws and regulations~~ are subject to interpretation that may ultimately be resolved by the courts. ~~Refer to "Liquidity and Capital Resources" of each respective Registrant in Part I, Item 2 of this Form 10-Q for discussion of each Registrant's forecast environmental-related capital expenditures.~~ 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, ~~2016~~,2022, and new environmental matters occurring in ~~2017.~~2023.

~~Clean~~ Air ~~Act~~Quality Regulations

The Clean Air Act, ~~is a federal law administered by the EPA that~~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. ~~The implementation of new standards is generally outlined in SIPs, which are a collection of~~These laws and regulations ~~programs and policies~~continue to be ~~followed. SIPs vary by~~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 ~~public hearings~~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 ~~EPA approval. Some states may adopt additional~~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 ~~more~~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 ~~than those implemented by the EPA. The major~~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 ~~programs most directly affecting~~Section 111 establishes a cooperative approach between the ~~Registrants'~~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.

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.

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.

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 ~~described below.~~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 ~~best available retrofit technology ("BART")~~BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

~~The~~In June 2019, the state of Utah ~~issued~~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 ~~requiring~~and removes the ~~installation of sulfur dioxide, nitrogen oxides and particulate matter controls~~requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. ~~In December 2012, the~~The EPA approved the ~~sulfur dioxide portion of the Utah regional haze~~ SIP and disapproved the nitrogen oxides and particulate matter portions. Certain groups appealed the EPA's approval of the sulfur dioxide portion and oral argument was heard before the United States Court of Appeals for the Tenth Circuit ("Tenth Circuit") in March 2014. In October 2014, the Tenth Circuit upheld the EPA's approval of the sulfur dioxide portion of the SIP. The state of Utah and PacifiCorp filed petitions for administrative and judicial review of the EPA's final rule onrevision with the BART ~~determinations for the nitrogen oxides and particulate matter portions~~alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of ~~Utah's regional haze SIP in March 2013. In May 2014, the Tenth Circuit dismissed the petition~~SCR equipment on ~~jurisdictional grounds. In addition, and separate from the EPA's approval process and related litigation, the Utah Division of Air Quality completed an alternative BART analysis for~~ 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 ~~alternative BART analysis~~EPA defended the SIP, and ~~revised~~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 SIP were submitted in June 2015 to the EPA for review and proposed action after a public comment period. The revised regional haze SIP included a state-enforceable requirement to cease operation of the Carbon Facility by August 15, 2015. PacifiCorp retired the Carbon Facility in December 2015. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to nitrogen oxides controls and requireSIPs requiring the installation of ~~selective catalytic reduction ("SCR")~~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 ~~Hunter~~Naughton Units 1 and 2, ~~and Huntington~~SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and ~~2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016.~~2022, and low-NOx burners at Dave Johnston Unit 4. The EPA ~~approved in part and~~ disapproved ~~in part~~a portion of the ~~Utah regional haze~~Wyoming SIP and issued a ~~federal implementation plan ("FIP") requiring~~FIP for Dave Johnston Unit 3, where it required the installation of SCR controls ~~at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years~~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 effective date of the rule. PacifiCorp and other parties have filed requests with the EPA to reconsider and stay that decision, and have also filed motions for stay and petitions for review with the Tenth Circuit asking the court to overturn the EPA’s actions. In June 2017, the state of Utah and PacifiCorp issued requests to the EPA to reconsider its decision in issuing the FIP. By letter dated July 14, 2017, from Administrator Scott Pruitt, the EPA indicated that based on existing and new evidence potentially relevant to the EPA’s evaluation of Utah’s 2015 SIP, the agency would reconsider its final rule and prepare a notice of proposed rulemaking and take public comment on its proposed action. On July 18, 2017, the EPA filed with the Tenth Circuit a motion to hold the pending appeals in abeyance pending agency reconsideration of the final rule. The Tenth Circuit initially requested that all parties file a response setting forth their opposition or nonopposition to the EPA’s motion to hold the cases in abeyance by July 28, 2017. However, on July 18, 2017, PacifiCorp asked the Tenth Circuit to take judicial notice of the EPA’s request to hold the appeals in abeyance and reaffirmed its request to stay the FIP. The Tenth Circuit ordered all parties to respond to both the EPA's motion for abeyance and the motions by PacifiCorp and others to take judicial notice of EPA's reconsideration by August 4, 2017. On September 11, 2017, the Tenth Circuit issued an order granting both the motion to hold the case in abeyance and the motions for stay. The stay tolls the compliance requirements of the federal implementation plan for the number of days the stay is in effect while the EPA reconsiders the basis for the issuance of the federal plan.

The state of Arizona issued a regional haze SIP requiring, among other things, the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the ArizonaWyoming SIP and issued a FIP for the ~~disapproved portions~~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 ~~controls~~ on ~~Cholla Unit 4. In January 2015, permit applications~~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 ~~studies were submitted to amend the Cholla Title V permit, and subsequently the Arizona SIP to convert Cholla Unit 4~~2 should have been subject to a ~~natural gas-fueled unit in 2025; after notice and comment,~~SCR requirement. Oral argument was held May 16, 2023. PacifiCorp argued that the ~~Arizona Department of Environmental Quality submitted~~Naughton claims are moot but that a court ruling on the ~~amended Arizona SIP to~~Wyodak claims is necessary because the ~~EPA, which approved~~EPA's federal plan complies with the ~~amendments to~~Clean Air Act. A final decision from the ~~Arizona regional haze SIP with an effective date of April 26, 2017.~~

~~The Navajo Generating Station, in which Nevada Power~~court is ~~a joint owner with an 11.3% ownership share, is also a source that is subject to~~expected by late fall 2023. Separately, on February 14, 2022, the ~~regional haze BART requirements. In January 2013, the EPA announced a proposed FIP addressing BART and an alternative~~First Judicial District Court for the ~~Navajo Generating Station that includes~~State of Wyoming entered a ~~flexible timeline for reducing nitrogen oxides emissions. Nevada Power, along with~~consent decree reached between the ~~other owners~~state of ~~the facility, have been reviewing the EPA's proposal to determine its impact on the viability~~Wyoming and PacifiCorp resolving claims of ~~the facility's future operations. The land lease for the Navajo Generating Station is subject to renewal in 2019. In the spring 2017, the owners~~threatened violations of the Navajo Generating Station voted to shut down and demolish the plant on or before December 23, 2019; however, the owners agreed to continue operating the plant through 2019 with demolition to follow if the tribe approved a new lease by July 1, 2017. Subsequently, the Navajo Council approved the requested lease extension June 26, 2017, and on July 1, 2017, the Navajo Nation signed the replacement lease with the utility owners of the Navajo Generating Station. Two remaining owners, the U.S. Bureau of Reclamation and the City of Los Angeles, must approve the lease by December 1, 2017, to enable continued operations through 2019. The Navajo Nation, along with the U.S. Bureau of Reclamation and Peabody Energy have further indicated a desire to keep the plant and coal mine operating through at least 2030, which would require a new ownership structure for the facility. The utility owners have specified that a new ownership proposal must be put forward by October 1, 2017, in order to complete the transition prior to December 23, 2019. Nevada Power filed the Emissions Reduction and Capacity Replacement Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019, which was approved by the PUCN. Bids to sell the facility were due to Salt River Project on October 1, 2017; however, none were tendered by that date. The owners were subsequently informed that several interested parties are preparing bids which are expected for submittal and review in late October. Any potential new owner, along with the Navajo Nation has until November 1, 2017, to reach an agreement in principle and one year from that date to reach a new ownership agreement and lease. In light of the tight time frames involved, it is expected that any bid received at this time will be highly conditioned.

~~Climate Change~~

In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce greenhouse gas emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global greenhouse gas emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. Under the terms of the Paris Agreement, ratifying countries are bound for a three-year period and must provide one-year's notice of their intent to withdraw. The Clean Power Plan, which was finalized by the EPA in 2015 and is currently under review, was the primary basis for the United States' commitment under the Paris Agreement. On June 1, 2017, President Trump announced the United States would begin the four-year process of withdrawing from the Paris Agreement.

~~GHG Performance Standards~~

~~Under~~ the Clean Air Act, the ~~EPA may establish emissions standards that reflect~~Wyoming Environmental Quality Act and the ~~degree of emissions reductions achievable through~~Wyoming Air Quality Standards and Regulations at the ~~best technology that has been demonstrated, taking into consideration~~Jim Bridger facility. No penalties were imposed under the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilitiesconsent decree. Consistent with the ~~"Best System~~terms and conditions of ~~Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture~~the consent decree, PacifiCorp must convert Jim Bridger Units 1 and ~~sequestration or integrated gasification combined-cycle units that are co-fired with~~2 to natural gas ~~or pre-combustion slipstream capture~~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 ~~carbon dioxide. The new source performance standards have been appealed~~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 ~~D.C. Circuit~~Wyoming Air Quality Division submitted the state-approved revised regional haze SIP requiring natural gas conversion of Jim Bridger Units 1 and oral argument was scheduled to be heard April 17, 2017; however, the court canceled the oral arguments March 30, 2017, and, on April 28, 2017, ordered that the cases be held in abeyance for 60 days, with supplemental briefs required to be filed May 15, 2017, regarding whether the cases should be remanded2 to the EPA ~~rather than held~~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 ~~abeyance.~~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.

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 ~~10, 2017, the court placed the case in abeyance pending further order of the court. Until such time as the court renders a final determination regarding the validity of the standards or~~25, 2022, the EPA ~~rescinds~~promulgated a finding of failure to submit a SIP for the ~~standards, any new fossil-fueled generating facilities constructed by~~regional haze second planning period for 15 states, including Iowa. The finding establishes a two-year deadline for the ~~relevant Registrants will be required~~agency to ~~meet~~promulgate FIPs to address the ~~GHG new source performance standards.~~

~~Clean Power Plan~~

~~In June 2014,~~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 ~~released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d)~~on development of ~~the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based~~its SIP. On February 13, 2023, Iowa issued a draft SIP and accepted comment on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization ofdraft plan through March 16, 2023. Iowa proposes to require operational improvements to existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The EPA also changed the compliance period to begin in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh and 1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. On February 9, 2016, the United States Supreme Court ordered that the EPA's emission guidelines for existing sources be stayed pending the disposition of the challenges to the rule in the D.C. Circuit and any action on a writ of certiorari before the U.S. Supreme Court. Oral argument was heard before the full D.C. Circuit (with the exception of Chief Judge Merrick Garland) on September 27, 2016, and the court has not yet issued its decision. The case has been held in abeyance pending underlying action by the EPA. On October 10, 2017, the EPA issued a proposal to repeal the Clean Power Plan and the public comment period closes on the proposal December 15, 2017. EPA has not determined whether it will issue a replacement rule. Until such time as the EPA takes final action on the repeal and determines whether there will be a replacement rule, the impact of EPA’s actions on the Registrants cannot be determined. PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

~~Water Quality Standards~~

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakescontrol equipment at existing facilities. The final rule was released in May 2014, and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the United States must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when organisms are drawn into the facility). PacifiCorp and MidAmerican Energy are assessing the options for compliance at their generating facilities impacted by the final rule and will complete impingement and entrainment studies. PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's ~~coal-fueled generating facilities, except~~ Louisa ~~Ottumwa~~Generation Station and Walter Scott Jr. Energy Center - Unit 4, which have water cooling towers, withdraw more than 125 million gallons per day of water from waters of the United States for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter and Huntington generating facilities currently utilize closed cycle cooling towers but are designed to withdraw more than two million gallons of water per day. The standards are required to be met as soon as possible after the effective date of the3. Iowa anticipates submitting a final rule, but no later than eight years thereafter. The costs of compliance with the cooling water intake structure rule cannot be fully determined until the prescribed studies are conducted. In the event that PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significantplan to the consolidated financial statements. Nevada Power and Sierra Pacific do not utilize once-through cooling water intake or discharge structures at any of their generating facilities. All of the Nevada Power and Sierra Pacific generating stations are designed to have either minimal or zero discharge; therefore, they are not impacted by the §316(b) final rule.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. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions has changed the effluent discharged from coal- and natural gas-fueled generating facilities. Under the guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal; the new limits were to have been met as soon as possible, beginningIn November 1, 2018 and implemented by December 31, 2023. On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with the EPA. The EPA granted the request for reconsideration on April 12, 2017, imposed an immediate administrative stay of compliance dates in the rule that had not passed judicial review, and requested that the court stay the pending litigation over the rule until September 12, 2017. On June 6, 2017,2019, the EPA proposed updates to ~~extend many of~~ the ~~compliance deadlines that would otherwise occur~~2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule took effect in ~~2018. On September 18, 2017, the EPA issued a~~December 2020. The final rule ~~extending certain compliance dates~~changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport water, ~~limits until November 1, 2020.~~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 ~~coal combustion residuals~~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 ~~facilities,~~proposal, the ~~impact~~full impacts of the rule cannot be ~~fully determined until~~determined. The EPA accepted public comments through May 30, 2023, and intends to finalize a rule by spring 2024.

In March 2023, the ~~reconsideration action is complete and any judicial review is concluded.~~

~~In April 2014,~~latest changes to the ~~EPA and the United States Army Corps~~definition of ~~Engineers issued a joint proposal to address~~ "waters of the ~~United States" to clarify protection~~U.S.," a rule that determines which waters are regulated under the federal Clean Water Act, ~~for~~took effect. Under this rule, tributaries, many wetlands, intrastate lakes, intrastate ponds, intrastate streams and ~~wetlands.~~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 proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was ~~released in May 2015 but is currently under appeal~~challenged in multiple ~~courts and a nationwide stay on the implementation of the rule was issued in October 2015.~~courts. On ~~January 13, 2017,~~May 23, 2023, the U.S. Supreme Court ~~granted~~issued a ~~petition~~decision in Sackett v. EPA, a case that challenged the Clean Water Act's applicability to ~~address jurisdictional~~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 ~~rule. On June 27, 2017, the EPA initiated the repeal of the "waters of the United States" rule.~~Court's decision. The EPA plans to undertake a two-step process, with the first step to repeal the 2015 rule and the second step to carry out a notice-and-comment rulemaking in which a substantive re-evaluation of the definition of the "waters of the United States" will be undertaken. The proposed repeal of the rule has not yet been published in the Federal Register. Depending on the outcome of the appeal(s) and intended rulemaking, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits would have been required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. On February 28, 2017, President Trump signed an Executive Order directing the EPA to review and rescind or revise the rule. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance ofsent a new ~~rule. Until~~final definition rule to the ~~outcome~~White House Office of Management and Budget on July 17, 2023, and has stated it intends to issue the pending actions and any litigation is known, the Registrants cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs or increased requirements for compensatory mitigation.new rule by September 1, 2023.

Coal ~~Combustion Byproduct~~Ash Disposal

In ~~May 2010,~~April 2015, the EPA released a ~~proposed~~final rule to regulate the management and disposal of coal combustion ~~byproducts, presenting two alternatives to regulation~~residuals (CCR) under the RCRA. The public comment period closed in November 2010. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and became effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of ~~coal combustion residuals.~~CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts ~~may~~will need to be closed unless they can meet the more stringent regulatory requirements. On August 10, 2017, the EPA issued proposed permitting guidance on how states’ coal combustion residuals permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. The public comment period on the permitting guidance closed on September 14, 2017. Also, on September 14, 2017, the EPA granted reconsideration on aspects of the final rule. On September 18, 2017, the EPA filed a motion to hold the pending litigation on the final rule in abeyance; however, the D.C. Circuit has not made a final ruling on the motion. The D.C. Circuit requested additional briefing on the abeyance motion and directed the EPA to identify, by November 15, 2017, which issues it intends to reconsider and the timeframe for completion of the reconsideration process. Oral argument on the motion for abeyance is scheduled for November 20, 2017.

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 ~~contained~~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. ~~These six~~Five of these surface impoundments ~~are subject to closure~~were closed on or before ~~April 2018.~~December 21, 2017, and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated ~~ten~~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 ~~and are subject to final closure on or before April 2018,~~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. Refer to Note 13 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2016 and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2016 for discussion of the impacts on asset retirement obligations as a result

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.

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.

~~New Accounting Pronouncements~~

~~For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.~~

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 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, ~~2016~~.2022. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, ~~2016~~.2022.

PacifiCorp and its subsidiaries

Consolidated Financial Section

PART I


~~Item 1.~~	~~Financial Statements~~

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

~~Portland, Oregon~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of ~~September~~June 30, ~~2017, and~~2023, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, and of ~~changes in shareholders' equity and~~ cash flowsfor the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016. These~~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 ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~PacifiCorp's management.~~America.

We ~~conducted our reviews~~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 have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 2016, 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, 2017, 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, 2016 ~~is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.~~

/s/ Deloitte & Touche LLP

Portland, Oregon

~~November 3, 2017~~August 4, 2023

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

As of
September 30, December 31,
2017 2016
ASSETS
Current assets:
Cash and cash equivalents $ 104
$ 17
Accounts receivable, net 722
728
Income taxes receivable —
17
Inventories:
Materials and supplies 237
228
Fuel 207
215
Regulatory assets 30
53
Other current assets 72
96
Total current assets 1,372
1,354

Property, plant and equipment, net 19,135
19,162
Regulatory assets 1,518
1,490
Other assets 388
388

Total assets $ 22,413
$ 22,394

The accompanying notes are an integral part of these consolidated financial statements.

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

As of
September 30, December 31,
2017 2016
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 398
$ 408
Income taxes payable 64
—
Accrued employee expenses 115
67
Accrued interest 106
115
Accrued property and other taxes 136
63
Short-term debt —
270
Current portion of long-term debt and capital lease obligations 591
58
Regulatory liabilities 67
54
Other current liabilities 164
164
Total current liabilities 1,641
1,199

Regulatory liabilities 1,032
978
Long-term debt and capital lease obligations 6,436
7,021
Deferred income taxes 4,884
4,880
Other long-term liabilities 913
926
Total liabilities 14,906
15,004

Commitments and contingencies (Note 8)

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 3,038
2,921
Accumulated other comprehensive loss, net (12 ) (12 )
Total shareholders' equity 7,507
7,390

Total liabilities and shareholders' equity $ 22,413
$ 22,394

The accompanying notes are an integral part of these consolidated financial statements.

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Operating revenue $ 1,430
$ 1,434
$ 3,956
$ 3,919

Operating costs and expenses:
Energy costs 465
478
1,305
1,295
Operations and maintenance 248
272
754
800
Depreciation and amortization 200
193
598
576
Taxes, other than income taxes 50
47
149
141
Total operating costs and expenses 963
990
2,806
2,812

Operating income 467
444
1,150
1,107

Other income (expense):
Interest expense (95 ) (95 ) (285 ) (285 )
Allowance for borrowed funds 4
4
12
12
Allowance for equity funds 7
7
21
21
Other, net 6
3
13
9
Total other income (expense) (78 ) (81 ) (239 ) (243 )

Income before income tax expense 389
363
911
864
Income tax expense 126
110
294
270
Net income $ 263
$ 253
$ 617
$ 594

The accompanying notes are an integral part of these consolidated financial statements.

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

Accumulated
Additional Other Total
Preferred Common Paid-in Retained Comprehensive Shareholders'
Stock Stock Capital Earnings Loss, Net Equity

Balance, December 31, 2015 $ 2
$ —
$ 4,479
$ 3,033
$ (11 ) $ 7,503
Net income —
—
—
594
—
594
Common stock dividends declared —
—
—
(550 ) —
(550 )
Balance, September 30, 2016 $ 2
$ —
$ 4,479
$ 3,077
$ (11 ) $ 7,547

Balance, December 31, 2016 $ 2
$ —
$ 4,479
$ 2,921
$ (12 ) $ 7,390
Net income —
—
—
617
—
617
Common stock dividends declared —
—
—
(500 ) —
(500 )
Balance, September 30, 2017 $ 2
$ —
$ 4,479
$ 3,038
$ (12 ) $ 7,507

The accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods							Six-Month Periods
	Ended September 30,							Ended June 30,
	2017			2016				2023		2022
Cash flows from operating activities:							Cash flows from operating activities:
Net income	$	617		$	594
Adjustments to reconcile net income to net cash flows from operating activities:
Net (loss) income							Net (loss) income	$	(14)	$	212
Adjustments to reconcile net (loss) income to net cash flows from operating activities:							Adjustments to reconcile net (loss) income to net cash flows from operating activities:
Depreciation and amortization	598			576			Depreciation and amortization	558		559
Allowance for equity funds	(21		)	(21		)	Allowance for equity funds	(61)		(28)
Net power cost deferrals							Net power cost deferrals	(255)		(62)
Amortization of net power cost deferrals							Amortization of net power cost deferrals	71		27
Other changes in regulatory assets and liabilities							Other changes in regulatory assets and liabilities	(54)		(41)
Deferred income taxes and amortization of investment tax credits	14			76			Deferred income taxes and amortization of investment tax credits	(68)		29
Changes in regulatory assets and liabilities	21			85
Other, net	1			6			Other, net	(2)		12
Changes in other operating assets and liabilities:							Changes in other operating assets and liabilities:
Accounts receivable and other assets	25			19
Trade receivables, other receivables and other assets							Trade receivables, other receivables and other assets	113		17
Inventories							Inventories	(59)		(16)
Derivative collateral, net	(4		)	2			Derivative collateral, net	(90)		69
Inventories	(1		)	(32		)
Income taxes	75			133

Accrued property, income and other taxes, net							Accrued property, income and other taxes, net	161		152
Accounts payable and other liabilities	110			(66		)	Accounts payable and other liabilities	216		219
Wildfires insurance receivable							Wildfires insurance receivable	(133)		(161)
Wildfires liability							Wildfires liability	524		225
Net cash flows from operating activities	1,435			1,372			Net cash flows from operating activities	907		1,213

Cash flows from investing activities:							Cash flows from investing activities:
Capital expenditures	(553		)	(586		)	Capital expenditures	(1,529)		(894)
Other, net	32			26			Other, net	—		6
Net cash flows from investing activities	(521		)	(560		)	Net cash flows from investing activities	(1,529)		(888)

Cash flows from financing activities:							Cash flows from financing activities:
Repayments of long-term debt and capital lease obligations	(54		)	(56		)
Net repayments of short-term debt	(270		)	(20		)
Common stock dividends	(500		)	(550		)
Proceeds from long-term debt							Proceeds from long-term debt	1,189		—
Repayments of long-term debt							Repayments of long-term debt	(309)		(9)

Dividends paid							Dividends paid	(300)		(100)
Other, net	(3		)	—			Other, net	(3)		(2)
Net cash flows from financing activities	(827		)	(626		)	Net cash flows from financing activities	577		(111)

Net change in cash and cash equivalents	87			186
Cash and cash equivalents at beginning of period	17			12
Cash and cash equivalents at end of period	$	104		$	198
Net change in cash and cash equivalents and restricted cash and cash equivalents							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							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							Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	629	$	400

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Beginning balance $ 95
$ 89
$ 73
$ 133
Changes in fair value recognized in net regulatory assets 6
15
36
(4 )
Net (losses) gains reclassified to operating revenue (5 ) (2 ) 8
8
Net gains (losses) reclassified to energy costs 1
—
(20 ) (35 )
Ending balance $ 97
$ 102
$ 97
$ 102

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 September 30, December 31,
Measure 2017 2016

Electricity sales Megawatt hours (3 ) (3 )
Natural gas purchases Decatherms 97
84
Fuel oil purchases Gallons 2
11


	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~~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 ~~three~~ recognized credit rating agencies. These ~~derivative contracts~~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. 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," or in some cases terminate the contract, in the event of~~assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of ~~September~~June 30, ~~2017,~~2023, PacifiCorp's issuer credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the ~~three~~ 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 ~~$102~~$58 million and ~~$97~~$48 million as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, respectively, for which PacifiCorp had posted collateral of ~~$73~~$— million, ~~and $69 million, respectively,~~ in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~2022, PacifiCorp would have been required to post ~~$26~~$35 million and ~~$22~~$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.

~~(7)~~(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 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)

Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3
Other⁽¹⁾
Total
As of September 30, 2017
Assets:
Commodity derivatives $ —
$ 7
$ —
$ (3 ) $ 4
Money market mutual funds⁽²⁾
100
—
—
—
100
Investment funds 20
—
—
—
20
$ 120
$ 7
$ —
$ (3 ) $ 124

Liabilities - Commodity derivatives $ —
$ (107 ) $ —
$ 76
$ (31 )

As of December 31, 2016
Assets:
Commodity derivatives $ —
$ 27
$ —
$ (7 ) $ 20
Money market mutual funds⁽²⁾
13
—
—
—
13
Investment funds 17
—
—
—
17
$ 30
$ 27
$ —
$ (7 ) $ 50

Liabilities - Commodity derivatives $ —
$ (104 ) $ —
$ 76
$ (28 )
(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.


~~(1)~~	~~Represents netting under master netting arrangements and a net cash collateral receivable of $73 million and $69 million as of September 30, 2017 and December 31, 2016, respectively.~~


~~(2)~~	~~Amounts are included in cash and cash equivalents, other current assets and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.~~

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 ~~six~~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 ~~six~~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 67 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 and are primarily accounted for as available-for-sale securities.~~value. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. 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

As of September 30, 2017 As of December 31, 2016
Carrying Fair Carrying Fair
Value Value Value Value

Long-term debt $ 7,005
$ 8,277
$ 7,052
$ 8,204

~~(8)~~(9) Commitments and Contingencies

~~Legal Matters~~Commitments

PacifiCorp ~~is party to a variety~~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 ~~legal actions arising out of~~certain wind-powered generating facilities in Wyoming.

Fuel Contracts

During the ~~normal course of business. Plaintiffs occasionally seek punitive or exemplary damages.~~six-month period ended June 30, 2023, PacifiCorp ~~does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.~~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 ~~and water~~ quality, ~~renewable portfolio standards,~~climate change, emissions performance standards, ~~climate change,~~water quality, coal ~~combustion byproduct~~ash disposal, ~~hazardous~~wildfire prevention and ~~solid waste disposal, protected species~~mitigation and other environmental matters that have the potential to impact ~~PacifiCorp's~~its current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

Lower Klamath Hydroelectric ~~Relicensing~~Project

~~PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with~~In November 2022, the Federal Energy Regulatory Commission ("FERC")~~. In February 2010, PacifiCorp,~~ issued a license surrender order for the United States Department of the Interior, the United States Department of Commerce, the state of California, the state of Oregon and various other governmental and non-governmental settlement parties signed theLower Klamath ~~Hydroelectric Settlement Agreement ("KHSA").~~

Congress failed to pass legislation needed to implement the original KHSA. On April 6, 2016, PacifiCorp, the states of California and Oregon, and the United States Departments of the Interior and Commerce and other stakeholders executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, on September 23, 2016, PacifiCorp andProject, which was accepted by the Klamath River Renewal Corporation ("KRRC") ~~jointly filed an application~~and the states of Oregon and California ("States") in December 2022, along with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilities from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with the FERC to surrender the license and decommission the facilities. The KRRC's license surrender application included a request for the FERC to refrain from acting on the surrender application until after the transfer of the ~~license~~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 ~~effective.~~

~~Under~~ready for removal. Removal of the ~~amended KHSA, PacifiCorp~~Copco No. 2 facility began in June 2023, and ~~its customers are protected from uncapped~~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 ~~costs~~ and ~~liabilities. The KRRC must indemnify PacifiCorp from liabilities associated with dam removal. The amended KHSA also limits PacifiCorp's contribution to facilities removal costs to no more than~~restoration; $200 million ~~of which up to $184 million would be~~ collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measure in November 2014 from which the state of California's contribution toward facilities removal costs are being drawn. In accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the California state budget in 2016, with the funding effective for at least five years. If facilities removal costs exceed the combined funding that will be available from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the ~~state~~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.

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.

2020 Wildfires

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

2022 McKinney Fire

Due to the preliminary nature of the investigation, PacifiCorp ~~for removal to proceed.~~

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.

~~(9) Related Party Transactions~~(10) Revenue from Contracts with Customers

~~Berkshire Hathaway includes BHE~~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

Item 2.Management's Discussion and ~~its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis,~~Analysis of Financial Condition and ~~substantially all~~Results of its currently payable or receivable income taxes are remitted to or received from BHE. For the nine-month periods ended September 30, 2017 and 2016, PacifiCorp made net cash payments for federal and state income taxes to BHE totaling $205 million and $61 million, respectively.Operations


~~Item 2.~~	~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.

Results of Operations for the ~~Third~~Second Quarter and First ~~Nine~~Six Months of ~~2017~~2023 and ~~2016~~2022

Overview

Net income for the ~~third~~second quarter of ~~2017~~2023 was ~~$263~~$106 million, an increase of ~~$10~~$24 million ~~or 4%,~~ compared to ~~2016. Net~~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 ~~gross margins of $30 million, excluding the impact of demand side management program revenue (offset in operations~~retail prices, lower coal-fueled generation volumes, higher net power costs deferrals and maintenance expense) of $21 million, partially offset by higher depreciation and amortization of $7 million, primarily from additional plant placed in-service. Gross margins increased due to higher retail customer volumes, lower coal costs, lower natural gas-fueled generation and higher wheeling revenue, partially offset by higher purchased electricity costs, lower average retail rates and lower wholesale revenue, primarily due to lower volumes. Retail customer volumes increased 2.1% due to impacts of weather on residential customers, primarily in Utah and Oregon, higher commercial usage primarily in Oregon and Utah, and an increase in the average number of residential and commercial customers in Utah, partially offset by lower irrigation usage in Idaho and Oregon, and lower industrial usage in Utah and Oregon. Energy generated decreased 2% for the third quarter of 2017 compared to 2016 primarily due to lower natural gas-fueled and wind-powered generation, partially offset by higher hydroelectric generation. Wholesale electricity sales volumes decreased 11% and purchased electricity volumes increased 19%.

Net income for the first nine months of 2017 was $617 million, an increase of $23 million, or 4%, compared to 2016. Net income increased primarily due to higher gross margins of $71 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense) of $44 million, partially offset by higher depreciation and amortization of $22 million from additional plant placed in-service and higher property taxes of $6 million. Gross margins increased due to higher retail customer volumes, lower natural gas-fueled generation, higher wholesale revenue from higher short-term market prices, ~~and volumes, and higher wheeling revenue,~~ 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 ~~rates.~~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 ~~2.4%~~0.6%, primarily due to favorable impacts of weather, ~~primarily on residential customers in Oregon, Washington and Utah,~~ 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.

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)	%

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.

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 anresidential 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 ~~primarily in Utah~~across all states, except California, and favorable Oregon and higher industrial usage in the eastern service territory, partially offset by lower residential usage across the service territory, lower industrial usage in Oregon and lower irrigation usage primarily in Oregon and Idaho. Energy generated decreased 2% for the first nine months of 2017 compared to 2016 primarily due to lower natural gas-fueled and wind-powered generation, partially offset by higher hydroelectric and coal generation. Wholesale electricity sales volumes decreased 3% and purchased electricity volumes increased 20%.Washington weather related impacts;

Operating revenue and energy costs are the key drivers of PacifiCorp's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. PacifiCorp believes that a discussion of gross margin, representing operating revenue less energy costs, is therefore meaningful.

~~A comparison of PacifiCorp's key operating results is as follows:~~

Third Quarter First Nine Months
2017 2016 Change 2017 2016 Change
Gross margin (in millions):
Operating revenue $ 1,430
$ 1,434
$ (4 ) — % $ 3,956
$ 3,919
$ 37
1 %
Energy costs 465
478
(13 ) (3 )% 1,305
1,295
10
1 %
Gross margin $ 965
$ 956
$ 9
1 % $ 2,651
$ 2,624
$ 27
1 %

Sales (GWh):
Residential 4,372
4,147
225
5 % 12,410
11,909
501
4 %
Commercial⁽¹⁾
4,783
4,544
239
5 % 13,303
12,863
440
3 %
Industrial, irrigation and other⁽¹⁾
5,683
5,839
(156 ) (3 )% 16,061
16,004
57
— %
Total retail 14,838
14,530
308
2 % 41,774
40,776
998
2 %
Wholesale 1,350
1,513
(163 ) (11 )% 4,362
4,493
(131 ) (3 )%
Total sales 16,188
16,043
145
1 % 46,136
45,269
867
2 %

Average number of retail customers
(in thousands) 1,868
1,842
26
1 % 1,863
1,837
26
1 %

Average revenue per MWh:
Retail $ 90.58
$ 93.10
$ (2.52 ) (3 )% $ 88.41
$ 90.44
$ (2.03 ) (2 )%
Wholesale $ 28.74
$ 28.32
$ 0.42
1 % $ 29.55
$ 25.41
$ 4.14
16 %

Heating degree days 304
236
68
29 % 6,472
5,726
746
13 %
Cooling degree days 1,804
1,494
310
21 % 2,342
2,051
291
14 %

Sources of energy (GWh)⁽²⁾:

Coal 10,764
10,775
(11 ) — % 27,120
26,637
483
2 %
Natural gas 2,486
2,743
(257 ) (9 )% 5,647
7,642
(1,995 ) (26 )%
Hydroelectric⁽³⁾
641
488
153
31 % 3,598
2,719
879
32 %
Wind and other⁽³⁾
460
647
(187 ) (29 )% 2,030
2,337
(307 ) (13 )%
Total energy generated 14,351
14,653
(302 ) (2 )% 38,395
39,335
(940 ) (2 )%
Energy purchased 3,023
2,542
481
19 % 10,845
9,031
1,814
20 %
Total 17,374
17,195
179
1 % 49,240
48,366
874
2 %

Average cost of energy per MWh:
Energy generated⁽⁴⁾
$ 19.89
$ 20.86
$ (0.97 ) (5 )% $ 19.21
$ 19.36
$ (0.15 ) (1 )%
Energy purchased $ 53.34
$ 49.68
$ 3.66
7 % $ 42.20
$ 43.02
$ (0.82 ) (2 )%


~~(1)~~	~~Prior period GWh amounts have been reclassified for consistency with the current period presentation.~~


~~(2)~~	~~GWh amounts are net of energy used by the related generating facilities.~~


~~(3)~~	All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.


~~(4)~~	~~The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.~~

~~Gross margin~~ ~~increased $9 million, or 1%, for the third quarter of 2017 compared to 2016 primarily due to:~~

•$3851 million of higher ~~retail revenues due to increased volumes of 2.1% due to impacts of weather and higher usage, primarily in Utah and Oregon;~~

~~$28 million of higher net deferrals of incurred~~deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms;

•$~~22 million of lower coal costs due to prior year charges related to damaged longwall mining equipment, and current quarter lower volumes; and~~

$735 million of lower natural ~~gas~~gas-fueled generation costs primarily due to lower ~~gas-fueled~~average market prices, partially offset by higher volumes; and

•$31 million of lower coal-fueled generation ~~as gas prices were~~costs primarily due to lower volumes, partially offset by higher ~~in 2017.~~

average prices.

The increases above were partially offset by:

•$35128 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 ~~prices~~average long-term debt balances.

Allowance for borrowed and ~~volumes;~~equity funds increased $29 million for the second quarter of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.

~~$22~~Interest and dividend income increased $19 million for the second quarter of ~~lower~~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 ~~retail rates;~~interest rates on temporary cash investment balances.

~~$21~~Other, net increased $8 million for the second quarter of ~~lower demand side management program revenue~~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)~~, primarily driven by the recently implemented Utah Sustainable Transportation and Energy Plan ("STEP") program; and~~.

$9Income tax benefit increased $22 million ~~of higher coal prices.~~

~~Operations and maintenance~~ ~~decreased $24 million, or 9%,~~ for the ~~third~~second quarter of ~~2017~~2023 compared to ~~2016 primarily due to a decrease in demand side management program expense (offset in operating revenue) driven by~~2022 and the ~~establishment of the Utah STEP program~~effective tax rate was (39)% for 2023 and ~~a decrease in pension expense primarily due to a current year plan change.~~

~~Depreciation and amortization~~ ~~increased $7 million, or 4%,~~(11)% for ~~the third quarter of 2017 compared to 2016 primarily due to higher plant-in-service.~~

~~Income tax expense~~ ~~increased $16 million, or 15%, for the third quarter of 2017 compared to 2016.~~2022. The effective tax rate ~~was 32% for 2017 and 30% for 2016. The effective tax rate~~decreased primarily as a result of increased ~~primarily due to lower production tax credits associated with~~PTCs from PacifiCorp's wind-powered generating facilities asand a ~~result~~higher benefit from effects of ~~the expiration~~ratemaking.

First Six Months of ~~the 10-year production tax credit period for certain wind-powered generating facilities.~~2023 compared to First Six Months of 2022

~~Gross~~Utility margin increased ~~$27~~$40 million, or 1%2%, for the first ~~nine~~six months of ~~2017~~2023 compared to ~~2016~~2022 primarily due to:

•$~~102~~218 million ~~of higher~~increase in retail ~~revenues~~revenue due to ~~increased~~higher average prices and volumes. Retail customer volumes ~~of 2.4%~~increased 0.6%, primarily due to favorable Utah and Oregon commercial customer usage, favorable weather related impacts ~~of weather, primarily on residential customers in Oregon, Washington and Utah, higher commercial usage primarily in Oregon, an increase~~across the western states, favorable changes in the average number of residential and commercial customers ~~primarily~~across the service territory, mainly in Utah and Oregon, and ~~higher industrial~~favorable Utah residential customer usage, ~~in the eastern service territory,~~ partially offset by ~~lower residential~~unfavorable industrial customer usage across ~~the service territory, lower industrial~~all states, unfavorable irrigation customer usage inacross all states and unfavorable Oregon ~~and lower irrigation usage primarily in Oregon and Idaho;~~residential customer usage;

•$36149 million of higher ~~net deferrals of incurred~~deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms; and

•$2840 million of lower ~~natural gas~~coal-fueled generation costs ~~primarily~~ due to lower ~~gas-fueled generation due to~~volumes, partially offset by higher ~~gas prices in 2017;~~

~~$20 million of lower coal costs due to prior year charges related to damaged longwall mining equipment;~~

~~$15 million of higher wholesale revenue due to higher short-term market prices and higher volumes; and~~

~~$13 million due to higher wheeling revenue, primarily due to higher volumes and short-term~~average prices.

The increases above were partially offset by:

•$69270 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 ~~prices;~~

~~$49~~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 ~~lower average retail rates;~~

~~$44~~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 ~~demand side management program revenue~~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)~~, primarily driven by the recently implemented Utah STEP program; and~~.

~~$24~~Income tax benefit increased $134 million ~~of higher coal costs due to higher prices and volumes.~~

~~Operations and maintenance~~ ~~decreased $46 million, or 6%,~~ for the first ~~nine~~six months of ~~2017~~2023 compared to 2016 primarily due to a decrease in demand side management program expense (offset in operating revenue) driven by the establishment of the Utah STEP program, and a decrease in pension expense primarily due to a current year plan change. These decreases were partially offset by higher injury and damage expenses, primarily due to a prior year accrual for insurance proceeds, and higher labor costs related to storm damage restoration.

~~Depreciation and amortization~~ ~~increased $22 million, or 4%, for the first nine months of 2017 compared to 2016 primarily due to higher plant-in-service.~~

~~Taxes, other than income taxes~~ ~~increased $8 million, or 6% for the first nine months of 2017 compared to 2016 due to higher assessed property values.~~

~~Income tax expense~~ ~~increased $24 million, or 9%, for the first nine months of 2017 compared to 2016~~2022 and the effective tax rate was ~~32%~~91% for 2023 and ~~31%~~(3)% for ~~2017 and 2016, respectively.~~2022. The ~~effective tax rate increased~~$134 million increase is primarily due to ~~lower production tax credits~~the increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires, higher PTCs from PacifiCorp's wind-powered generating facilities, ashigher benefit from effects of ratemaking and the release of a ~~result~~valuation allowance on state net operating loss carryforwards in 2023 compared to the establishment of ~~the expiration of the 10-year production tax credit period for certain wind-powered generating facilities.~~a state valuation allowance in 2022.

Liquidity and Capital Resources

As of ~~September~~June 30, ~~2017,~~2023, PacifiCorp's total net liquidity was as follows (in millions):

Cash and cash equivalents $ 104

Credit facilities 1,000
Less:
Short-term debt —
Tax-exempt bond support (130 )
Net credit facilities 870

Total net liquidity $ 974

Credit facilities:
Maturity dates 2020


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 ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, were ~~$1,435~~$907 million and ~~$1,372~~$1,213 million, respectively. The ~~change was~~decrease is primarily due to ~~the payment for USA Power final judgment and post-judgment interest in the prior year,~~ higher ~~receipts from~~ wholesale and ~~retail customers~~fuel purchases and ~~lower fuel payments,~~collateral returned to counterparties, partially offset by ~~current year~~ higher ~~cash payments for income taxes and purchased power.~~collections from retail customers.

The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions made for each payment date.

Investing Activities

Net cash flows from investing activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, were ~~$(521)~~$(1,529) million and ~~$(560)~~$(888) million, respectively. The change ~~mainly reflects a current year decrease~~is primarily due to an increase in capital expenditures of ~~$33~~$635 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017 was $(827)~~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 ~~substantially~~primarily of ~~$500~~$100 million for common stock dividends paid to PPW Holdings LLC ~~$270 million for the repayment of short-term debt~~ and ~~$50~~$9 million for the repayment of long-term debt.

Net cash flows from financing activities for the nine-month period ended September 30, 2016 was $(626) million. Uses of cash consisted substantially of $550 million for common stock dividends paid to PPW Holdings LLC, $54 million for the repayment of long-term debt and $20 million for the repayment of short-term debt.

Short-term Debt

Regulatory authorities limit PacifiCorp to ~~$1.5~~$2.0 billion of short-term debt. As of ~~September~~June 30, ~~2017,~~2023 and December 31, 2022, PacifiCorp had no short-term debt outstanding. ~~As of December 31, 2016, PacifiCorp had $270 million of short-term debt outstanding at a weighted average interest rate of 0.96%.~~

~~Long-term~~ Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the ~~IPUC~~Idaho Public Utilities Commission to issue an additional ~~$1.3~~$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.

AsCommon Shareholders' Equity

In January 2023, PacifiCorp declared a common stock dividend of ~~September 30, 2017, PacifiCorp had $216~~$300 million, of letters of credit providing credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling $213 million plus interest. These letters of credit were fully available as of September 30, 2017 and expire periodically through March 2019.paid in February 2023, to PPW Holdings LLC.

Future Uses of Cash

PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customer rates; changes in environmental and other rules and regulations; ~~impacts to customers' rates;~~ outcomes of regulatory ~~proceedings;~~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.

~~Historical~~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

Nine-Month Periods Annual
Ended September 30, Forecast
2016 2017 2017

Transmission system investment $ 68
$ 75
$ 118
Environmental 42
18
28
Wind investment —
8
8
Operating and other 476
452
644
Total $ 586
$ 553
$ 798

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:

~~Transmission system investment primarily reflects main grid reinforcement costs~~•Wind generation includes both growth projects and ~~initial costs~~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 ~~140-mile 500 kV Aeolus-Bridger/Anticline transmission line, a major segment~~six-month periods ended June 30, 2023 and 2022, respectively. Planned spending for the construction of ~~PacifiCorp’s Energy Gateway Transmission expansion program~~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 ~~2020.~~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 ~~Aeolus-Bridger/Anticline line totals $16 million in 2017.~~

~~Environmental includes the installation~~remainder of new or the replacement of existing emissions control equipment at certain generating facilities, including installation or upgrade of selective catalytic reduction control systems and low nitrogen oxide burners2023. The remaining investments primarily relate to ~~reduce nitrogen oxides, particulate matter control systems, sulfur dioxide emissions control systems and mercury emissions control systems, as well as~~ 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 ~~management~~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 ~~coal combustion residuals.~~2023.

~~Remaining~~•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 ~~transmission, distribution~~ and other infrastructure needed to serve existing and expected ~~demand, including upgrades to customer meters in Oregon, California and Idaho.~~demand.

~~Integrated Resource Plan~~Energy Supply Planning

In April 2017, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP") with its state commissions. The IRP includes investments in renewable energy resources, upgrades to the existing wind fleet, and energy efficiency measures to meet future customer needs. Implementation of wind upgrades, new transmission and new wind renewable resources will require an estimated $3 billion in capital investment from 2017 through 2020. PacifiCorp's forecast capital expenditures for 2018 through 2019 increased $723 million from the forecast included in PacifiCorp's 2016 Annual Report on Form 10-K as a result of its 2017 IRP.

~~Request for Proposals~~

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 ~~filed its~~to file draft ~~2017R Request for Proposals ("RFP")~~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 ~~June 2017~~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 ~~OPUC in August 2017. The UPSC and~~2023 IRP during the ~~OPUC approved PacifiCorp’s 2017R RFP in September 2017. The 2017R RFP was subsequently released to the market on September 27, 2017. The 2017R RFP is seeking up to 1,270 MW~~first half of new wind resources that can interconnect to PacifiCorp’s transmission system in Wyoming once a proposed high-voltage transmission line is constructed. The 2017R RFP is also seeking proposals for wind resources located outside of Wyoming capable of delivering all-in economic benefits for PacifiCorp's customers. The proposed high-voltage transmission line and new wind resources must be placed in service by December 31, 2020, to maximize potential federal production tax credit benefits for PacifiCorp's customers. Bids were due in October 2017.2024.

~~Contractual Obligations~~Material Cash Requirements

As of ~~September~~June 30, ~~2017,~~2023, there have been no material changes ~~outside the normal course of business~~ in ~~contractual obligations~~cash requirements from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2022, other than those disclosed in Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Regulatory Matters

PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state ~~local~~ and ~~foreign~~local laws and regulations regarding air ~~and water~~ quality, ~~RPS,~~climate change, emissions performance standards, ~~climate change,~~water quality, coal ~~combustion byproduct~~ash disposal ~~hazardous and solid waste disposal, protected species~~ and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by ~~the EPA~~various federal, state and ~~various state,~~ local ~~and international~~ 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 "Liquidity and Capital Resources" for discussion of PacifiCorp's forecast environmental-related capital expenditures.~~

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.~~laws and regulations.

~~New Accounting Pronouncements~~

~~For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of the Form 10-Q.~~

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,~~ pension and other postretirement benefits, income taxes, ~~and~~ revenue recognition-unbilled ~~revenue.~~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, ~~2016.~~2022. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, ~~2016.~~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.

MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

PART I


~~Item 1.~~	~~Financial Statements~~

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

~~Des Moines, Iowa~~

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of ~~September~~June 30, ~~2017, and~~2023, the related statements of operations and changes in shareholder's equity for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, and of ~~changes in equity and~~ cash flows for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016. These~~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 ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~MidAmerican Energy's management.~~America.

We ~~conducted our reviews~~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.

Based on our reviews, we are not aware of any material modifications that should be made to such interim financial statements for them 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), the balance sheet of MidAmerican Energy Company as of December 31, 2016, and the related 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, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 3, 2017~~August 4, 2023

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

As of
September 30, December 31,
2017 2016
ASSETS
Current assets:
Cash and cash equivalents $ 512
$ 14
Receivables, net 312
285
Income taxes receivable —
9
Inventories 235
264
Other current assets 21
35
Total current assets 1,080
607

Property, plant and equipment, net 13,587
12,821
Regulatory assets 1,335
1,161
Investments and restricted cash and investments 707
653
Other assets 193
217

Total assets $ 16,902
$ 15,459

The accompanying notes are an integral part of these financial statements.

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

As of
September 30, December 31,
2017 2016
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable $ 256
$ 303
Accrued interest 52
45
Accrued property, income and other taxes 228
137
Short-term debt —
99
Current portion of long-term debt 350
250
Other current liabilities 158
159
Total current liabilities 1,044
993

Long-term debt 4,544
4,051
Deferred income taxes 3,781
3,572
Regulatory liabilities 927
883
Asset retirement obligations 515
510
Other long-term liabilities 307
290
Total liabilities 11,118
10,299

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding —
—
Additional paid-in capital 561
561
Retained earnings 5,223
4,599
Total shareholder's equity 5,784
5,160

Total liabilities and shareholder's equity $ 16,902
$ 15,459

The accompanying notes are an integral part of these financial statements.

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016
Operating revenue:
Regulated electric $ 707
$ 692
$ 1,677
$ 1,572
Regulated gas and other 106
103
489
432
Total operating revenue 813
795
2,166
2,004

Operating costs and expenses:
Cost of fuel, energy and capacity 130
130
342
312
Cost of gas sold and other 54
55
288
237
Operations and maintenance 200
180
547
510
Depreciation and amortization 111
118
369
338
Property and other taxes 30
28
90
84
Total operating costs and expenses 525
511
1,636
1,481

Operating income 288
284
530
523

Other income (expense):
Interest expense (54 ) (50 ) (160 ) (147 )
Allowance for borrowed funds 4
3
9
6
Allowance for equity funds 11
6
25
14
Other, net 5
3
13
8
Total other income (expense) (34 ) (38 ) (113 ) (119 )

Income before income tax benefit 254
246
417
404
Income tax benefit (131 ) (74 ) (207 ) (123 )

Net income $ 385
$ 320
$ 624
$ 527

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions)


	Common Stock		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity

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

Common
Stock

Retained
Earnings

Accumulated
Other
Comprehensive
Loss, Net

Total
Equity

Balance, December 31, 2015 $ 561
$ 4,174
$ (30 ) $ 4,705
Net income —
527
—
527
Other comprehensive income —
—
2
2
Dividend —
(117 ) 27
(90 )
Other equity transactions —
(1 ) —
(1 )
Balance, September 30, 2016 $ 561
$ 4,583
$ (1 ) $ 5,143

Balance, December 31, 2016 $ 561
$ 4,599
$ —
$ 5,160
Net income —
624
—
624
Balance, September 30, 2017 $ 561
$ 5,223
$ —
$ 5,784

The accompanying notes are an integral part of these financial statements.

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

Nine-Month Periods
Ended September 30,
2017 2016
Cash flows from operating activities:
Net income $ 624
$ 527
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization 369
338
Deferred income taxes and amortization of investment tax credits 64
113
Changes in other assets and liabilities 28
34
Other, net (23 ) (42 )
Changes in other operating assets and liabilities:
Receivables, net (28 ) (67 )
Inventories 29
(26 )
Derivative collateral, net 3
4
Contributions to pension and other postretirement benefit plans, net (8 ) (5 )
Accounts payable (5 ) 14
Accrued property, income and other taxes, net 98
160
Other current assets and liabilities 20
30
Net cash flows from operating activities 1,171
1,080

Cash flows from investing activities:
Utility construction expenditures (1,162 ) (1,129 )
Purchases of available-for-sale securities (126 ) (96 )
Proceeds from sales of available-for-sale securities 127
92
Other, net —
5
Net cash flows from investing activities (1,161 ) (1,128 )

Cash flows from financing activities:
Proceeds from long-term debt 842
33
Repayments of long-term debt (255 ) (38 )
Net repayments of short-term debt (99 ) —
Net cash flows from financing activities 488
(5 )

Net change in cash and cash equivalents 498
(53 )
Cash and cash equivalents at beginning of period 14
103
Cash and cash equivalents at end of period $ 512
$ 50

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)


~~(1)~~	~~General~~

(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 and related corporate services.~~subsidiaries. MHC's nonregulated ~~subsidiaries include~~subsidiary is Midwest Capital Group, Inc. ~~and MEC Construction Services Co.~~ 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 ~~September~~June 30, ~~2017,~~2023, and for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~2022. The results of operations for the ~~three- and nine-month periods~~six-month period ended ~~September~~June 30, ~~2017,~~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, ~~2016,~~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 ~~and policies~~ during the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017.~~2023.


~~(2)~~	~~New Accounting Pronouncements~~

Cash equivalents consist of funds invested in ~~this guidance require that an employer disaggregate the service cost component from the~~money market mutual funds, U.S. Treasury Bills and other ~~components~~investments with a maturity of ~~net benefit cost~~three months or less when purchased. Cash and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. MidAmerican Energy plans to adopt this guidance effective January 1, 2018. MidAmerican Energy does not believe this will have a material impact on its Financial Statements and disclosures included within Notes to Financial Statements.

In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents ~~and~~exclude amounts ~~generally described as~~where availability is restricted ~~cash~~by legal requirements, loan agreements or ~~restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents must be included with~~other contractual provisions. Restricted cash and cash equivalents ~~when reconciling the beginning-of-period~~consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and ~~end-of-period total amounts shown~~cash equivalents and restricted cash and cash equivalents as presented on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy plans to adopt this guidance effective January 1, 2018, and does not believe the adoption of this guidance will have a material impact on its Financial Statements ~~and disclosures included within Notes to Financial Statements. In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement~~ of Cash ~~Flows." The amendments~~Flows is outlined below and disaggregated by the line items in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy plans to adopt this guidance effective January 1, 2018, and does not believe the adoption of this guidance will have a material impact on its Financial Statements.


	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

(3) Property, Plant and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. MidAmerican Energy plans to adopt this guidance effective January 1, 2019, and is currently evaluating the impact on its Financial Statements and disclosures included within Notes to Financial Statements.Equipment, Net

In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements. MidAmerican Energy does not believe this guidance will have a material impact on its Financial Statements and disclosures included within Notes to Financial Statements.

In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. MidAmerican Energy plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Financial Statements and disclosures included within Notes to Financial Statements. MidAmerican Energy currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when MidAmerican Energy has the right to invoice as it corresponds directly with the value to the customer of MidAmerican Energy’s performance to date. MidAmerican Energy's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by jurisdiction for each segment.


~~(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

As of
September 30, December 31,
Depreciable Life 2017 2016
Utility plant in service, net:
Generation 20-70 years $ 11,339
$ 11,282
Transmission 52-75 years 1,802
1,726
Electric distribution 20-75 years 3,297
3,197
Gas distribution 29-75 years 1,606
1,565
Utility plant in service 18,044
17,770
Accumulated depreciation and amortization (5,765 ) (5,448 )
Utility plant in service, net 12,279
12,322
Nonregulated property, net:
Nonregulated property gross 20-50 years 7
7
Accumulated depreciation and amortization (1 ) (1 )
Nonregulated property, net 6
6
12,285
12,328
Construction work-in-progress 1,302
493
Property, plant and equipment, net $ 13,587
$ 12,821

~~During the fourth quarter of 2016,~~Under a revenue sharing arrangement in Iowa, MidAmerican Energy ~~revised its electric and gas depreciation rates~~accrues throughout the year a regulatory liability based on the ~~results~~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 ~~a new depreciation study,~~ the ~~most significant impact of which was longer estimated useful lives for certain wind-powered generating facilities. The effect of this change was to reduce~~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 ~~by $34 million annually, or $9 million and $26 million for~~on the ~~three- and nine-month periods ended September 30, 2017, based on depreciable plant balances at the time~~Statement of ~~the change.~~Operations.

(4)Recent Financing Transactions

~~Long-Term Debt~~

In February 2017, MidAmerican Energy issued $375 million of its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95% First Mortgage Bonds due August 2047. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds.

~~In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.~~

Credit Facilities

In June ~~2017,~~2023, MidAmerican Energy ~~terminated~~amended its ~~$600 million~~existing $1.5 billion unsecured credit facility expiring ~~March 2018 and entered into a $900 million unsecured credit facility expiring~~in June ~~2020 with two one-year extension options subject~~2025. The amendment extended the expiration date to lender consent. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. The credit facility requires MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.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 ~~benefit~~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)	%

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Federal statutory income tax rate 35 % 35 % 35 % 35 %
Income tax credits (74 ) (58 ) (74 ) (58 )
State income tax, net of federal income tax benefit (10 ) (6 ) (7 ) (4 )
Effects of ratemaking (2 ) (1 ) (4 ) (3 )
Other, net (1 ) —
—
—
Effective income tax rate (52 )% (30 )% (50 )% (30 )%

Income tax credits relate primarily to production tax credits ("PTC") from MidAmerican Energy's ~~wind-powered~~wind- and solar-powered generating facilities. Federal renewable electricity ~~production tax credits~~PTCs are earned as energy from qualifying ~~wind-powered~~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-powered~~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 ~~United States~~U.S. federal and Iowa state income tax ~~return.~~returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income ~~taxes~~tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income ~~taxes are~~tax is remitted to or received from BHE. MidAmerican Energy received net cash payments for income ~~taxes~~tax from BHE totaling ~~$381~~$520 million and ~~$416~~$541 million for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, respectively.


~~(6)~~	~~Employee Benefit Plans~~

(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) ~~cost~~ 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)	$	—	$	—	$	—	$	—

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016
Pension:
Service cost $ 2
$ 3
$ 7
$ 8
Interest cost 8
8
23
25
Expected return on plan assets (11 ) (11 ) (33 ) (33 )
Net amortization —
—
1
1
Net periodic benefit (credit) cost $ (1 ) $ —
$ (2 ) $ 1

Other postretirement:
Service cost $ 2
$ 1
$ 4
$ 4
Interest cost 3
2
7
7
Expected return on plan assets (3 ) (3 ) (10 ) (10 )
Net amortization (1 ) (1 ) (3 ) (3 )
Net periodic benefit cost (credit) $ 1
$ (1 ) $ (2 ) $ (2 )

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 $8$7 million and $1$2 million, ~~respectively, during 2017.~~respectively. As of ~~September~~June 30, ~~2017, $5~~2023, $4 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.


~~(7)~~	~~Fair Value Measurements~~

(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 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)


																Input Levels for Fair Value Measurements
	Input Levels for Fair Value Measurements															Level 1		Level 2		Level 3		Other(1)		Total
	Level 1		Level 2			Level 3			Other⁽¹⁾			Total
As of September 30, 2017:
As of December 31, 2022:															As of December 31, 2022:
Assets:															Assets:
Commodity derivatives	$	—	$	2		$	2		$	(2	)	$	2		Commodity derivatives	$	1	$	37	$	6	$	(10)	$	34
Money market mutual funds⁽²⁾	520		—			—			—			520
Money market mutual funds															Money market mutual funds	225		—		—		—		225
Debt securities:															Debt securities:
United States government obligations	168		—			—			—			168
U.S. government obligations															U.S. government obligations	215		—		—		—		215
International government obligations	—		5			—			—			5			International government obligations	—		1		—		—		1
Corporate obligations	—		37			—			—			37			Corporate obligations	—		70		—		—		70
Municipal obligations	—		2			—			—			2			Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	—		1			—			—			1			Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:															Equity securities:
United States companies	270		—			—			—			270
U.S. companies															U.S. companies	360		—		—		—		360
International companies	7		—			—			—			7			International companies	8		—		—		—		8
Investment funds	15		—			—			—			15			Investment funds	16		—		—		—		16
	$	980	$	47		$	2		$	(2	)	$	1,027			$	825	$	112	$	6	$	(10)	$	933

Liabilities - commodity derivatives	$	—	$	(6	)	$	(4	)	$	2		$	(8	)	Liabilities - commodity derivatives	$	—	$	(12)	$	(1)	$	10	$	(3)

Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3
Other⁽¹⁾
Total
As of December 31, 2016:
Assets:
Commodity derivatives $ —
$ 9
$ 1
$ (2 ) $ 8
Money market mutual funds⁽²⁾
1
—
—
—
1
Debt securities:
United States government obligations 161
—
—
—
161
International government obligations —
3
—
—
3
Corporate obligations —
36
—
—
36
Municipal obligations —
2
—
—
2
Agency, asset and mortgage-backed obligations —
2
—
—
2
Equity securities:
United States companies 250
—
—
—
250
International companies 5
—
—
—
5
Investment funds 9
—
—
—
9
$ 426
$ 52
$ 1
$ (2 ) $ 477

Liabilities - commodity derivatives $ —
$ (3 ) $ (3 ) $ 3
$ (3 )


~~(1)~~	~~Represents netting under master netting arrangements and a net cash collateral receivable of $-~~(1)Represents netting under master netting arrangements and a net cash collateral receivable of $10 million and $— million ~~and $1 million as of September 30, 2017 and December 31, 2016, respectively.~~


~~(2)~~	~~Amounts are included in cash and cash equivalents and investments and restricted cash and investments on the Balance Sheets. The fair value of these money market mutual funds approximates cost.~~

~~Derivative contracts are recorded on the Balance Sheets~~ as ~~either assets or liabilities~~of June 30, 2023 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 MidAmerican Energy transacts. When quoted prices for identical contracts are not available, MidAmerican Energy uses forward price curves. Forward price curves represent MidAmerican Energy's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. MidAmerican Energy 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 MidAmerican Energy. Market price quotations are generally readily obtainable for the applicable term of MidAmerican Energy's outstanding derivative contracts; therefore, MidAmerican Energy'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, MidAmerican Energy 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, related volatility, counterparty creditworthiness and duration of contracts.

December 31, 2022, respectively.

MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, ~~and are primarily~~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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,

Commodity
Derivatives

Auction Rate
Securities

Commodity
Derivatives
Auction Rate Securities
2017:
Beginning balance $ (1 ) $ —
$ (2 ) $ —
Changes in fair value recognized in net regulatory assets (2 ) —
(2 ) —
Settlements 1
—
2
—
Ending balance $ (2 ) $ —
$ (2 ) $ —

2016:
Beginning balance $ (2 ) $ 18
$ (6 ) $ 26
Transfer to affiliate —
—
(4 ) —
Changes in fair value recognized in OCI —
—
—
3
Changes in fair value recognized in net regulatory assets (1 ) —
(5 ) —
Redemptions —
—
—
(11 )
Settlements 1
—
13
—
Ending balance $ (2 ) $ 18
$ (2 ) $ 18

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		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,668	$	6,810	$	7,729	$	6,964

As of September 30, 2017 As of December 31, 2016

Carrying
Value

Fair
Value

Carrying
Value

Fair
Value

Long-term debt $ 4,894
$ 5,446
$ 4,301
$ 4,735

~~(8)~~(9) Commitments and Contingencies

~~Natural Gas~~ Commitments

~~During the nine-month period ended September 30, 2017,~~ MidAmerican Energy ~~amended certain of its natural gas supply and transportation contracts increasing minimum payments by $247 million through 2021 and $70 million for 2022 through 2037.~~has the following firm commitments that are not reflected on the Balance Sheets.

Construction Commitments

During the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017,~~2023, MidAmerican Energy entered into ~~contracts~~firm construction commitments totaling ~~$675~~$183 million for the remainder of 2023 through 2024 related to the construction of wind-powered generating facilities in ~~2017 through 2019, with remaining payments totaling $84 million for the fourth quarter of 2017, $340 million in 2018 and $8 million in 2019.~~Iowa.

~~Easements~~

During the nine-month period ended September 30, 2017, MidAmerican Energy entered into non-cancelable easements with minimum payments totaling $114 million through 2057 for land in Iowa on which some of its wind-powered generating facilities will be located.

~~Legal Matters~~

MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.

Environmental 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 ~~FERC-approved~~ formula rates approved by the Federal Energy Regulatory Commission ("FERC") subject to true-up for actual cost of service. ~~Prior to September 2016, the rates in effect were based on a 12.38% return on equity ("ROE").~~ In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the ~~12.38% ROE~~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~~ROE. In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion vacating all orders related to ~~9.15%~~the complaints and ~~8.67%, respectively.~~remanding them back to the FERC. MidAmerican Energy ~~is authorized by~~cannot predict the ~~FERC to include a 0.50% adder beyond~~ultimate outcome of these matters or the ~~base ROE effective January 2015. In September 2016, the FERC issued an order for the first complaint, which reduces the base ROE to 10.32%~~amount of refunds, if any, and requires refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. It is uncertain when the FERC will rule on the second complaint, covering the period from February 2015 through May 2016. MidAmerican Energy believes it is probable that the FERC will order a base ROE lower than 12.38% in the second complaint and, as of September 30, 2017,accordingly, has reversed its previously accrued ~~a $9 million~~ liability for potential refunds ~~under the second complaint~~ of amounts collected under the higher ROE during the periods covered by the complaints.

(10) Revenue from ~~February 2015 through May 2016.~~Contracts with Customers


~~(9)~~	~~Components of Accumulated Other Comprehensive Income (Loss), Net~~

The following table ~~shows the change~~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 ~~accumulated other comprehensive income (loss), net by each component of other comprehensive income, net of applicable income taxes~~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.

Unrealized Unrealized Accumulated
Losses on Losses Other
Available-For-Sale on Cash Flow Comprehensive
Securities Hedges Loss, Net

Balance, December 31, 2015 $ (3 ) $ (27 ) $ (30 )
Other comprehensive income 2
—
2
Dividend —
27
27
Balance at September 30, 2016 $ (1 ) $ —
$ (1 )

(12) Segment Information


~~(10)~~	~~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 ~~regulated~~natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost.

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016
Operating revenue:
Regulated electric $ 707
$ 692
$ 1,677
$ 1,572
Regulated gas 103
102
485
430
Other 3
1
4
2
Total operating revenue $ 813
$ 795
$ 2,166
$ 2,004

Depreciation and amortization:
Regulated electric $ 101
$ 107
$ 338
$ 306
Regulated gas 10
11
31
32
Total depreciation and amortization $ 111
$ 118
$ 369
$ 338

Operating income:
Regulated electric $ 290
$ 289
$ 485
$ 481
Regulated gas (2 ) (5 ) 45
42
Total operating income $ 288
$ 284
$ 530
$ 523

As of
September 30,
2017 December 31,
2016
Assets:
Regulated electric $ 15,556
$ 14,113
Regulated gas 1,339
1,345
Other 7
1
Total assets $ 16,902
$ 15,459

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

~~Des Moines, Iowa~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of ~~September~~June 30, ~~2017, and~~2023, the related consolidated statements of operations and changes in member's equity for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, and of ~~changes in equity and~~ cash flows for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016. These~~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 ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~MidAmerican Funding's management.~~America.

We ~~conducted our reviews~~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 ~~Public Company Accounting Oversight Board (United States)~~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.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries as of December 31, 2016, 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, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 3, 2017~~August 4, 2023

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

As of
September 30, December 31,
2017 2016
ASSETS
Current assets:
Cash and cash equivalents $ 512
$ 15
Receivables, net 318
287
Income taxes receivable —
9
Inventories 235
264
Other current assets 21
35
Total current assets 1,086
610

Property, plant and equipment, net 13,602
12,835
Goodwill 1,270
1,270
Regulatory assets 1,335
1,161
Investments and restricted cash and investments 709
655
Other assets 194
216

Total assets $ 18,196
$ 16,747

The accompanying notes are an integral part of these consolidated financial statements.

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

As of
September 30, December 31,
2017 2016
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable $ 256
$ 302
Accrued interest 54
52
Accrued property, income and other taxes 227
138
Note payable to affiliate 52
31
Short-term debt —
99
Current portion of long-term debt 350
250
Other current liabilities 159
160
Total current liabilities 1,098
1,032

Long-term debt 4,870
4,377
Deferred income taxes 3,777
3,568
Regulatory liabilities 927
883
Asset retirement obligations 515
510
Other long-term liabilities 307
291
Total liabilities 11,494
10,661

Commitments and contingencies (Note 8)

Member's equity:
Paid-in capital 1,679
1,679
Retained earnings 5,023
4,407
Total member's equity 6,702
6,086

Total liabilities and member's equity $ 18,196
$ 16,747

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016
Operating revenue:
Regulated electric $ 707
$ 692
$ 1,677
$ 1,572
Regulated gas and other 108
105
493
436
Total operating revenue 815
797
2,170
2,008

Operating costs and expenses:
Cost of fuel, energy and capacity 130
130
342
312
Cost of gas sold and other 54
56
289
239
Operations and maintenance 202
181
549
511
Depreciation and amortization 111
118
369
338
Property and other taxes 30
28
90
84
Total operating costs and expenses 527
513
1,639
1,484

Operating income 288
284
531
524

Other income (expense):
Interest expense (59 ) (55 ) (177 ) (164 )
Allowance for borrowed funds 4
3
9
6
Allowance for equity funds 11
6
25
14
Other, net 6
3
14
9
Total other income (expense) (38 ) (43 ) (129 ) (135 )

Income before income tax benefit 250
241
402
389
Income tax benefit (133 ) (77 ) (214 ) (129 )

Net income $ 383
$ 318
$ 616
$ 518

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-in Capital		Retained Earnings		Total Member's Equity

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

Paid-in
Capital

Retained
Earnings

Accumulated
Other
Comprehensive
Loss, Net

Total
Equity

Balance, December 31, 2015 $ 1,679
$ 3,876
$ (30 ) $ 5,525
Net income —
518
—
518
Other comprehensive income —
—
2
2
Transfer to affiliate —
—
27
27
Other equity transactions —
(1 ) —
(1 )
Balance, September 30, 2016 $ 1,679
$ 4,393
$ (1 ) $ 6,071

Balance, December 31, 2016 $ 1,679
$ 4,407
$ —
$ 6,086
Net income —
616
—
616
Balance, September 30, 2017 $ 1,679
$ 5,023
$ —
$ 6,702

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

Nine-Month Periods
Ended September 30,
2017 2016
Cash flows from operating activities:
Net income $ 616
$ 518
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization 369
338
Deferred income taxes and amortization of investment tax credits 64
113
Changes in other assets and liabilities 28
34
Other, net (24 ) (42 )
Changes in other operating assets and liabilities:
Receivables, net (31 ) (67 )
Inventories 29
(26 )
Derivative collateral, net 3
4
Contributions to pension and other postretirement benefit plans, net (8 ) (5 )
Accounts payable (4 ) 14
Accrued property, income and other taxes, net 96
160
Other current assets and liabilities 14
24
Net cash flows from operating activities 1,152
1,065

Cash flows from investing activities:
Utility construction expenditures (1,162 ) (1,129 )
Purchases of available-for-sale securities (126 ) (96 )
Proceeds from sales of available-for-sale securities 127
92
Other, net (3 ) 5
Net cash flows from investing activities (1,164 ) (1,128 )

Cash flows from financing activities:
Proceeds from long-term debt 842
33
Repayments of long-term debt (255 ) (38 )
Net change in note payable to affiliate 21
16
Net repayments of short-term debt (99 ) —
Net cash flows from financing activities 509
11

Net change in cash and cash equivalents 497
(52 )
Cash and cash equivalents at beginning of period 15
103
Cash and cash equivalents at end of period $ 512
$ 51

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~~

(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 and related corporate services.~~subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas ~~operations. Direct,~~operations, and its direct wholly owned nonregulated ~~subsidiaries of MHC are~~subsidiary is Midwest Capital Group, Inc. ~~and MEC Construction Services Co.~~

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 ~~September~~June 30, ~~2017,~~2023, and for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~2022. The results of operations for the ~~three- and nine-month periods~~six-month period ended ~~September~~June 30, ~~2017,~~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, ~~2016,~~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 ~~and policies~~ during the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017.~~2023.


~~(2)~~	~~New Accounting Pronouncements~~

~~Refer to Note 2~~(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of ~~MidAmerican Energy's Notes to Financial Statements.~~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~~

(3) Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had as of September 30, 2017 and December 31, 2016, nonregulated property gross of $25 million and $22 million, respectively, related accumulated depreciation and amortization of $10 million and $9 million, respectively, and construction work-in-progress of $- million and $1 million, respectively, which consisted primarily of a corporate aircraft owned by MHC.

~~(4)~~ (4) Recent Financing Transactions

Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.

104

(5) Income Taxes


~~(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 ~~benefit~~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)	%

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Federal statutory income tax rate 35 % 35 % 35 % 35 %
Income tax credits (76 ) (60 ) (76 ) (61 )
State income tax, net of federal income tax benefit (10 ) (7 ) (8 ) (4 )
Effects of ratemaking (2 ) —
(4 ) (3 )
Effective income tax rate (53 )% (32 )% (53 )% (33 )%

Income tax credits relate primarily to production tax credits ("PTC") from MidAmerican Energy's ~~wind-powered~~wind- and solar-powered generating facilities. Federal renewable electricity ~~production tax credits~~PTCs are earned as energy from qualifying ~~wind-powered~~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-powered~~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 ~~United States~~U.S. federal and Iowa state income tax ~~return.~~returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income ~~taxes~~tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income ~~taxes are~~tax is remitted to or received from BHE. MidAmerican Funding received net cash payments for income ~~taxes~~tax from BHE totaling ~~$386~~$522 million and ~~$422~~$544 million for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, respectively.


~~(6)~~	~~Employee Benefit Plans~~

(6) Employee Benefit Plans

Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.


~~(7)~~	~~Fair Value Measurements~~

(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

As of September 30, 2017 As of December 31, 2016

Carrying
Value

Fair
Value

Carrying
Value

Fair
Value

Long-term debt $ 5,220
$ 5,873
$ 4,627
$ 5,164

~~(8)~~(9) Commitments and Contingencies

MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. ~~Plaintiffs occasionally seek punitive or exemplary damages.~~ MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

~~Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.~~

~~(9) Components of Accumulated Other Comprehensive Income (Loss), Net~~

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 ~~regulated~~natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the financial results and assets of nonregulated operations, MHC and MidAmerican Funding.

The following tables provide information on a reportable segment basis (in millions):


	Three-Month Periods						Nine-Month Periods					Three-Month Periods				Six-Month Periods
	Ended September 30,						Ended September 30,					Ended June 30,				Ended June 30,
	2017			2016			2017		2016			2023		2022		2023		2022
Operating revenue:											Operating revenue:
Regulated electric	$	707		$	692		$	1,677	$	1,572	Regulated electric	$	661	$	725	$	1,252	$	1,333
Regulated gas	103			102			485		430
Regulated natural gas											Regulated natural gas	97		171		423		567
Other	5			3			8		6		Other	1		1		4		2
Total operating revenue	$	815		$	797		$	2,170	$	2,008	Total operating revenue	$	759	$	897	$	1,679	$	1,902

Depreciation and amortization:
Regulated electric	$	101		$	107		$	338	$	306
Regulated gas	10			11			31		32
Total depreciation and amortization	$	111		$	118		$	369	$	338

Operating income:											Operating income:
Regulated electric	$	290		$	289		$	485	$	481	Regulated electric	$	120	$	87	$	170	$	138
Regulated gas	(2		)	(5		)	45		42
Other	—			—			1		1
Regulated natural gas											Regulated natural gas	(2)		3		36		52

Total operating income	$	288		$	284		$	531	$	524	Total operating income	118		90		206		190
Interest expense											Interest expense	(85)		(83)		(169)		(165)
Allowance for borrowed funds											Allowance for borrowed funds	4		5		8		9
Allowance for equity funds											Allowance for equity funds	13		14		24		29
Other, net											Other, net	15		(10)		43		(14)
Total income before income tax expense (benefit)											Total income before income tax expense (benefit)	$	65	$	16	$	112	$	49

As of
September 30,
2017 December 31,
2016
Assets⁽¹⁾:

Regulated electric $ 16,747
$ 15,304
Regulated gas 1,418
1,424
Other 31
19
Total assets $ 18,196
$ 16,747

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~~

~~MidAmerican Funding is an Iowa limited liability company whose sole member is BHE. MidAmerican Funding owns all~~Item 2.Management's Discussion and Analysis of ~~the outstanding common stock~~Financial Condition and Results of MHC Inc., which owns all of the common stock of MidAmerican Energy, Midwest Capital Group, Inc. and MEC Construction Services Co. MidAmerican Energy is a public utility company headquartered in Des Moines, Iowa. MHC Inc., MidAmerican Funding and BHE are also headquartered in Des Moines, Iowa.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 ~~as presented in this joint filing.~~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 ~~the~~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 ~~Energy's~~Funding's and MidAmerican ~~Funding's~~Energy's actual results in the future could differ significantly from the historical results.

Results of Operations for the ~~Third~~Second Quarter and First ~~Nine~~Six Months of ~~2017~~2023 and ~~2016~~2022

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the ~~third~~second quarter of ~~2017~~2023 was ~~$385~~$236 million, an increase of ~~$65~~$29 million, or ~~20%~~14%, compared to ~~2016~~2022, primarily due to ~~higher recognized production tax credits of $45 million, higher margins of $11 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense),~~ lower depreciation and amortization ~~of $7 million, substantially from changes in accruals for Iowa regulatory arrangements,~~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~~funds. Electric retail customer volumes increased 1%, primarily due to higher customer usage for certain industrial customers, partially offset by the unfavorable impact of ~~$6 million,~~weather. Energy generated decreased 1%, due to lower wind-powered generation partially offset by higher ~~operations~~coal- and maintenance expenses, primarily from higher generating facility maintenance, including additional wind turbines. The increase in electric margins of $7 million, excluding the impact of demand side management program revenue (offset in operationsnatural gas-fueled generation; and ~~maintenance expense), reflects higher recoveries through bill riders, higher transmission revenue and higher~~energy purchased decreased 3%. Wholesale electricity sales volumes decreased 5% due to unfavorable market conditions. Natural gas retail customer volumes ~~from industrial growth net of lower residential and commercial volumes~~decreased 16% due to ~~milder temperatures, partially offset by lower wholesale revenue from lower sales volumes and prices.~~the unfavorable impact of weather.

MidAmerican Energy's net income for the first ~~nine~~six months of ~~2017~~2023 was ~~$624~~$478 million, an increase of ~~$97~~$27 million, or ~~18%~~6%, compared to ~~2016~~2022, primarily due to ~~higher margins of $64 million, excluding the impact of demand side management program revenue (offset in operations~~lower depreciation and ~~maintenance expense), higher recognized production tax credits of $71 million~~amortization expense, favorable other, net and higher ~~allowance for borrowed and equity funds of $14 million,~~nonregulated utility margin, partially offset by higher operations and maintenance ~~expenses of $21 million, primarily from~~expense, lower income tax benefit, lower electric utility margin, lower natural gas utility margin, lower allowance for borrowed and equity funds, higher ~~maintenance from additional wind turbines,~~property and other taxes and higher depreciation and amortization of $31 million from accruals for Iowa regulatory arrangements and wind-powered generating facilities placed in-service in the second half of 2016, net of a reduction in depreciation rates in December 2016. The increase in electric margins of $60 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense), reflects higher recoveries through bill riders, higher wholesale revenue from higher sales volumes and prices, higher transmission revenue and higherinterest expense. Electric retail customer volumes ~~from industrial growth, net of lower residential and commercial volumes~~increased 1%, primarily due to ~~milder temperatures,~~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~~generation; and energy purchased ~~power costs.~~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 ~~third~~second quarter of ~~2017~~2023 was ~~$383~~$233 million, an increase of ~~$65~~$29 million, or ~~20%~~14%, compared to ~~2016.~~2022. MidAmerican Funding's net income for the first ~~nine~~six months of ~~2017~~2023 was ~~$616~~$482 million, an increase of ~~$98~~$37 million, or ~~19%~~8%, compared to ~~2016.The increases were~~2022. The variance in net income was primarily due to the changes in MidAmerican Energy's earnings discussed ~~above.~~above and a one-time gain on the sale of an investment of $10 million.

Non-GAAP Financial Measure

~~Regulated~~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 ~~Gross~~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 ~~regulated~~ electric ~~gross~~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

Third Quarter First Nine Months
2017 2016 Change 2017 2016 Change
Gross margin (in millions):
Operating revenue $ 707
$ 692
$ 15
2 % $ 1,677
$ 1,572
$ 105
7 %
Cost of fuel, energy and capacity 130
130
—
—
342
312
30
10
Gross margin $ 577
$ 562
$ 15
3
$ 1,335
$ 1,260
$ 75
6

Electricity Sales (GWh):
Residential 1,790
1,969
(179 ) (9 )% 4,753
5,018
(265 ) (5 )%
Commercial 987
1,023
(36 ) (4 ) 2,796
2,859
(63 ) (2 )
Industrial 3,366
3,106
260
8
9,621
8,999
622
7
Other 411
427
(16 ) (4 ) 1,185
1,213
(28 ) (2 )
Total retail 6,554
6,525
29
—
18,355
18,089
266
1
Wholesale 1,571
2,037
(466 ) (23 ) 7,162
5,620
1,542
27
Total sales 8,125
8,562
(437 ) (5 ) 25,517
23,709
1,808
8

Average number of retail customers (in thousands) 771
761
10
1 % 769
759
10
1 %

Average revenue per MWh:
Retail $ 98.15
$ 94.02
$ 4.13
4 % $ 78.62
$ 76.75
$ 1.87
2 %
Wholesale $ 25.57
$ 28.13
$ (2.56 ) (9 )% $ 23.90
$ 22.84
$ 1.06
5 %

Heating degree days 44
27
17
63 % 3,203
3,388
(185 ) (5 )%
Cooling degree days 752
855
(103 ) (12 )% 1,098
1,284
(186 ) (14 )%

Sources of energy (GWh)⁽¹⁾:

Coal 4,354
4,618
(264 ) (6 )% 11,019
9,907
1,112
11 %
Nuclear 961
1,003
(42 ) (4 ) 2,820
2,887
(67 ) (2 )
Natural gas 257
307
(50 ) (16 ) 274
515
(241 ) (47)
Wind and other⁽²⁾
1,929
1,950
(21 ) (1 ) 9,129
7,981
1,148
14
Total energy generated 7,501
7,878
(377 ) (5 ) 23,242
21,290
1,952
9
Energy purchased 812
916
(104 ) (11 ) 2,756
3,030
(274 ) (9 )
Total 8,313
8,794
(481 ) (5 ) 25,998
24,320
1,678
7
Natural Gas Utility Margin


~~(1)~~	~~GWh amounts are net of energy used by the related generating facilities.~~


~~(2)~~	All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.

~~Regulated electric gross margin~~ ~~increased $15 million for the third quarter of 2017 compared to 2016 primarily due to:~~


~~(1)~~	~~Higher retail gross margin of $16 million due to -~~

~~an increase of $38 million from higher recoveries through bill riders;~~

~~an increase of $3 million from non-weather-related usage factors, including higher industrial sales volumes;~~

~~a decrease of $12 million from the impact of milder temperatures; and~~

~~a decrease of $13 million from higher retail energy costs primarily due to higher coal-fueled generation and higher purchased power costs;~~


~~(2)~~	~~Higher Multi-Value Projects ("MVPs") transmission revenue of $6 million due to continued capital additions; and~~


~~(3)~~	~~Lower wholesale gross margin of $7 million due to lower margins per unit from lower market prices and lower sales volumes.~~

~~Regulated electric gross margin~~ ~~increased $75 million for the first nine months of 2017 compared to 2016 primarily due to:~~


~~(1)~~	~~Higher wholesale gross margin of $37 million primarily due to higher margins per unit from higher market prices and higher sales volumes enabled by greater availability of lower cost generation;~~


~~(2)~~	~~Higher retail gross margin of $25 million due to -~~

~~an increase of $47 million from higher recoveries through bill riders;~~

~~an increase of $28 million from non-weather-related usage factors, including higher industrial sales volumes;~~

~~a decrease of $25 million from higher retail energy costs primarily due to higher coal-fueled generation and higher purchased power costs; and~~

~~a decrease of $25 million from the impact of milder temperatures; and~~


~~(3)~~	~~Higher MVPs transmission revenue of $11 million due to continued capital additions.~~

~~Regulated Gas Gross Margin~~

A comparison of key operating results related to ~~regulated~~natural gas ~~gross~~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)	%

Third Quarter First Nine Months
2017 2016 Change 2017 2016 Change
Gross margin (in millions):
Operating revenue $ 103
$ 102
$ 1
1 % $ 485
$ 430
$ 55
13 %
Cost of gas sold 54
54
—
—
288
236
52
22
Gross margin $ 49
$ 48
$ 1
2
$ 197
$ 194
$ 3
2

Natural gas throughput (000's Dth):
Residential 2,773
2,820
(47 ) (2) % 29,442
31,121
(1,679 ) (5) %
Commercial 1,788
1,840
(52 ) (3 ) 14,797
15,729
(932 ) (6 )
Industrial 717
922
(205 ) (22 ) 3,070
3,574
(504 ) (14 )
Other 2
1
1
100
29
26
3
12
Total retail sales 5,280
5,583
(303 ) (5 ) 47,338
50,450
(3,112 ) (6 )
Wholesale sales 8,815
8,568
247
3
29,111
28,615
496
2
Total sales 14,095
14,151
(56 ) —
76,449
79,065
(2,616 ) (3 )
Gas transportation service 19,784
18,087
1,697
9
65,431
60,117
5,314
9
Total gas throughput 33,879
32,238
1,641
5
141,880
139,182
2,698
2

Average number of retail customers (in thousands) 746
738
8
1 % 747
738
9
1 %
Average revenue per retail Dth sold $ 13.33
$ 12.77
$ 0.56
4 % $ 7.93
$ 6.80
$ 1.13
17 %
Average cost of natural gas per retail Dth sold $ 5.56
$ 5.49
$ 0.07
1 % $ 4.33
$ 3.45
$ 0.88
26 %

Combined retail and wholesale average cost of natural gas per Dth sold $ 3.82
$ 3.82
$ —
— % $ 3.76
$ 2.99
$ 0.77
26 %

Heating degree days 45
27
18
67 % 3,406
3,572
(166 ) (5) %

Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022

~~Regulated gas revenue includes purchased gas adjustment clauses through which~~

MidAmerican Energy ~~is allowed to recover~~-

Electric utility margin decreased $3 million, or 1%, for the ~~cost~~second quarter of gas sold from its retail gas utility customers. Consequently, fluctuations in the cost of gas sold do not directly affect gross margin or net income because regulated gas revenue reflects comparable fluctuations through the purchased gas adjustment clauses. For the first nine months of 2017, MidAmerican Energy's combined retail and wholesale average per-unit cost of gas sold increased 26%, resulting in an increase of $59 million in gas revenue and cost of gas sold2023 compared to ~~2016,~~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 ~~lower gas sales volumes.~~

~~Regulated gas gross~~•a $29 million increase in retail utility margin ~~increased $1 million for the third quarter of 2017 compared to 2016~~ primarily due to $26 million, net of energy costs, from higher recoveries ~~of demand side management program revenue~~through bill riders (offset in operations and maintenance ~~expense).~~

~~Regulated gas gross margin~~ ~~increased~~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 marginfor the ~~first nine months~~second quarter of ~~2017 compared~~2023 was equal to ~~2016~~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 -


~~(1)~~	~~higher recoveries of demand side management program revenue (offset in operations and maintenance expense) of $2 million;~~


~~(2)~~	~~a higher average per-unit margin of $2 million;~~


~~(3)~~	~~higher gas transportation throughput of $1 million, and~~


~~(4)~~	~~lower retail sales volumes of $3 million from warmer winter temperatures.~~

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.

~~Operating Costs and Expenses~~

111

~~MidAmerican Energy -~~

Operations and maintenance increased ~~$20~~$16 million, or 8%, for the ~~third~~second quarter of ~~2017~~2023 compared to ~~2016~~2022 primarily due to higher ~~demand side management program expense (offset in operating revenue) of $8 million, higher wind-powered~~nuclear power generation ~~maintenance from additional wind turbines~~costs of $6 million, higher benefit costs of $5 million, higher technology costs of $4 million, and higher ~~coal-fueled~~administrative and ~~nuclear generation maintenance~~other costs of $4 million, partially offset by lower electric distribution and transmission costs of $4 million.

~~Operations~~Depreciation and ~~maintenance~~ ~~increased $37~~amortization decreased $51 million, or 18%, for the ~~first nine months~~second quarter of ~~2017~~2023 compared to ~~2016~~2022 primarily due to ~~higher demand side management program expense (offset in operating revenue)~~$58 million from lower Iowa revenue sharing accruals, and $21 million from a regulatory mechanism that provides customers the retail energy benefits of ~~$17 million, higher~~certain wind-powered generation ~~maintenance~~projects, partially offset by $25 million from ~~additional wind turbines of $13 million~~wind-powered generating facilities and ~~higher coal-fueled~~other plant placed in-service and ~~nuclear generation maintenance of $4 million.~~

~~Depreciation and amortization~~ ~~decreased $7 million for the third quarter of 2017 compared to 2016 due to lower accruals for Iowa regulatory arrangements of $9 million and $9~~$3 million from lower depreciation ~~rates implemented~~expense deferrals in ~~December 2016, partially offset by utility plant additions, including wind-powered generating facilities placed in-service in the second half of 2016.~~2023.

~~Depreciation and amortization~~ increased $31 million for the first nine months of 2017 compared to 2016 due to utility plant additions, including wind-powered generating facilities placed in-service in the second half of 2016, accruals for Iowa regulatory arrangements of $26 million, partially offset by $26 million from lower depreciation rates implemented in December 2016.

Property and other taxesincreased $2$4 million, ~~and $6 million~~or 11%, for the ~~third~~second quarter ~~and first nine months~~ of ~~2017~~2023 compared to ~~2016~~2022 primarily due to $2 million from higher ~~Iowa utility~~wind turbine property taxes and $2 million from higher replacement taxes.

~~Other Income (Expense)~~

~~MidAmerican Energy -~~

Interest expense increased $4$3 million, ~~and $13 million~~or 4%, for the ~~third~~second quarter ~~and first nine months~~ of ~~2017, respectively,~~2023 compared to ~~2016~~2022 due to higher interest ~~expense from the issuance of $850 million of first mortgage bonds in February 2017, partially offset by the redemption of a $250 million of 5.95% Senior Notes in February 2017.~~rates on variable rate long-term debt.

Allowance for borrowed and equity funds ~~increased $6~~decreased $2 million, ~~and $14 million~~or 11%, for the ~~third~~second quarter ~~and first nine months~~ of ~~2017, respectively,~~2023 compared to ~~2016 primarily~~2022 due to ~~higher~~lower construction work-in-progress balances related to ~~wind-powered~~wind- and solar-powered generation.

Other, net increased $2$27 million, ~~and $5 million~~or 225%, for the ~~third~~second quarter ~~and first nine months~~ of ~~2017, respectively,~~2023 compared to ~~2016~~2022 primarily due to favorable investment earnings, largely attributable to higher ~~returns on~~cash surrender values of corporate-owned life insurance ~~policies.~~policies, and higher interest income from higher interest rates, partially offset by higher non-service costs of employee benefit plans.

Income ~~Tax Benefit~~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 ~~Energy~~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 ~~increased $57~~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 ~~third quarter~~first six months of ~~2017~~2023 compared to ~~2016,~~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 ~~effective tax rate was (52)%~~unfavorable impact of weather. Retail customer volumes increased 1.3%.

Natural gas utility margin decreased $8 million, or 5%, for ~~2017 and (30)% for 2016. For~~ the first ~~nine~~six months of ~~2017~~2023 compared to ~~2016,~~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 ~~increased $84 million,~~discussed above and the effective tax rate was (50)% for 2017 and (30)% for 2016. The changes in the effective tax rates for 2017 compared to 2016 were substantially due to an increase in recognized production tax credits and the effects of ratemaking.

~~Production tax credits are recognized in earnings for interim periods based~~higher pretax income from a one-time gain on the ~~application~~sale of an estimated annual effective tax rate to pretax earnings. Federal renewable electricity production tax credits 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 were placed in service. Production tax credits recognized in the first nine months of 2017 were $306 million, or $71 million higher than the first nine months of 2016, while production tax credits earned in the first nine months of 2017 were $200 million, or $29 million higher than the first nine months of 2016 primarily due to wind-powered generation placed in-service in late 2016. The excess of production tax credits recognized over earned of $106 million as of September 30, 2017, will reduce earnings over the remainder of 2017.investment.

~~MidAmerican Funding -~~

MidAmerican Funding's income tax benefit increased $56 million for the third quarter of 2017 compared to 2016, and the effective tax rate was (53)% for 2017 and (32)% for 2016. MidAmerican Funding's income tax benefit increased $85 million for the first nine months of 2017 compared to 2016, and the effective tax rate was (53)% for 2017 and (33)% for 2016.The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.

Liquidity and Capital Resources

As of ~~September~~June 30, ~~2017, MidAmerican Energy's~~2023, the total net liquidity for MidAmerican Energy and MidAmerican Funding was $1,197 million consisting of $512 million of cash and cash equivalents and $905 million of credit facilities reduced by $220 million of the credit facilities reserved to support MidAmerican Energy's variable-rate tax-exempt bond obligations. As of September 30, 2017, MidAmerican Funding's total net liquidity was $1,201 million, including MHC Inc.'s $4 million credit facility.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 ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, were ~~$1,171~~$1,125 million and ~~$1,080~~$1,125 million, respectively. MidAmerican Funding's net cash flows from operating activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, were ~~$1,152~~$1,110 million and ~~$1,065~~$1,118 million, respectively. Cash flows from operating activities ~~increased primarily due~~reflect higher payments to vendors, lower income tax receipts and higher ~~cash gross~~interest payments, offset by higher utility margins for MidAmerican Energy's regulated electric business, including fuel inventory reductions, partially offset by the timing of MidAmerican Energy's income tax cash flows with BHE. MidAmerican Energy's income tax cash flows with BHE totaled net cash receipts from BHE of $381 million and ~~$416 million, respectively. Income tax cash flows for 2016 reflect the receipt of $106 million of income tax benefits generated in 2015.~~ 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.

In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Production tax credits were extended and phased-out for wind power and other forms of non-solar renewable energy projects that begin construction before the end of 2019. Production tax credits are maintained at the following levels for projects for which construction begins before the end of the respective year as follows: at full value for 2016, at 80% of value for 2017, at 60% of value for 2018, and 40% of value for 2019. As a result of PATH, MidAmerican Energy's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in service through 2019 and production tax credits earned on qualifying wind projects through 2029.

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, were ~~$(1,161)~~$(767) million and ~~$(1,128)~~$(860) million, respectively. MidAmerican Funding's net cash flows from investing activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, were ~~$(1,164)~~$(755) million and ~~$(1,128)~~$(860) million, respectively. Net cash flows from investing activities consist almost entirely of ~~utility construction expenditures, which increased due~~capital expenditures. Refer to ~~higher environmental and other operating construction~~"Future Uses of Cash" for further discussion of capital expenditures. Purchases and proceeds related to ~~available-for-sale~~marketable securities ~~primarily~~substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning ~~trust.~~trust and other trust investments.

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022 were ~~$488~~$(166) million and ~~$(5)~~$(1) million, respectively. MidAmerican Funding's net cash flows from financing activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, were ~~$509~~$(166) million and ~~$11~~$7 million, respectively. In ~~February 2017,~~January 2023, MidAmerican ~~Energy issued $375~~Funding made a $100 million ofdistribution to its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95% First Mortgage Bonds due August 2047. An amount equal to the net proceeds was used to finance capital expenditures disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds. In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.sole member BHE. In January ~~2016,~~2023 and May 2023, MidAmerican Energy repaid $4$7 million and $58 million of ~~variable-rate tax-exempt pollution control refunding revenue bonds due January 2016. Through its commercial paper program, MidAmerican Energy made payments totaling $99 million in 2017.~~long-term debt, respectively. MidAmerican Funding received ~~$21~~$— million and ~~$16~~$8 million in ~~2017~~2023 and ~~2016,~~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 ~~February 28, 2019,~~April 2, 2024, commercial paper and bank notes aggregating ~~$905 million at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of up to 400 basis points.~~$1.5 billion. MidAmerican Energy has a ~~$900 million~~$1.5 billion unsecured credit facility expiring in June ~~2020. MidAmerican Energy may request that the banks extend the credit facility up to two years.~~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 ~~Eurodollar rate or a base rate, at MidAmerican Energy's option,~~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 ~~United States Securities and Exchange Commission~~SEC to issue ~~an indeterminate amount~~up to $3.25 billion of long-term debt securities and preferred stock through ~~September 16, 2018.~~March 10, 2026. MidAmerican Energy has authorization from the FERC to issue, through ~~August 31, 2019,~~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 and long-term debt securities up to an aggregate of $2.4 billion at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points. Additionally,~~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 ~~through November 1, 2020 and additional~~of long-term debt securities upfor 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 ~~an aggregate~~issue $48 million of ~~$2.4 billion of additional~~ long-term debt securities for the purpose of ~~which $350~~refinancing two of its variable-rate tax-exempt bond series, including $35 million ~~expires March 15, 2018, $150~~due in October 2024 and $13 million ~~expires September 22, 2018, $500 million expires March 15, 2019 and $1.4 billion expires November 1, 2020.~~due in January 2025.

In conjunction with the March 1999 merger, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy's equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy. If MidAmerican Energy's common equity level were to drop below the required thresholds, MidAmerican Energy's ability to issue debt could be restricted. As of September 30, 2017, MidAmerican Energy's common equity ratio was 53% computed on a basis consistent with its commitment.

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.

~~Utility Construction~~

114

Capital Expenditures

MidAmerican ~~Energy's primary need for~~Energy has significant future capital ~~is utility construction expenditures.~~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; ~~impacts to customers' rates;~~ outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

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

Nine-Month Periods Annual
Ended September 30, Forecast
2016 2017 2017

Wind-powered generation $ 732
$ 455
$ 709
Wind-powered generation repowering —
272
496
Transmission Multi-Value Projects 73
18
25
Other 324
417
773
Total $ 1,129
$ 1,162
$ 2,003

MidAmerican Energy's ~~forecast utility~~capital expenditures provided above consist of the following:

•Wind generation includes the construction, ~~expenditures for 2017~~ ~~include the following:~~

~~The construction of 2,000 MW (nominal ratings)~~acquisition, repowering and operation of wind-powered generating facilities ~~expected to~~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 ~~placed in-service in 2017 through 2019. In August 2016,~~substantially impacted by the ~~IUB issued an order approving ratemaking principles related to~~ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction ~~of up to 2,000 MW (nominal ratings)~~ of additional wind-powered generating facilities ~~expected to be placed in service in 2017 through 2019. The ratemaking principles establish a cost cap~~totals $544 million for the remainder of ~~$3.6 billion, including AFUDC, and a fixed rate~~2023.

◦Repowering of return on equity of 11.0% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding. The cost cap ensures that as long as total costs are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. Additionally, the ratemaking principles modify the revenue sharing mechanism currently in effect. The revised sharing mechanism will be effective in 2018 and will be triggered each year by actual equity returns above the weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. Each of these projects is expected to qualify for 100% of production tax credits currently available.

~~The repowering of certain existing~~ wind-powered generating facilities ~~in Iowa. This project entails~~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 ~~significant components~~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 ~~oldest turbines~~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 ~~MidAmerican Energy’s fleet. The energy production from such repowered facilities is expected to qualify for 100% of~~2022. For the federal production tax credits available for ten years following completion. Under MidAmerican Energy's Iowa electric tariff, federal production tax credits related to facilities that were in-service prior to 2013 must be included in its Iowa energy adjustment clause. In August 2017, the IUB approved a tariff change that excludes from MidAmerican Energy's Iowa energy adjustment clause any future federal production tax credits related to these repowered facilities.

~~Transmission MVP investments. MidAmerican Energy has approval from the Midcontinent Independent System Operator, Inc.~~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 ~~construction~~remainder of ~~four MVPs located in Iowa and Illinois, which, when complete, will have added approximately 250 miles of 345 kV transmission line to MidAmerican Energy's transmission system since 2012.~~2023.

~~Remaining costs~~ •Other includes primarily ~~relate to~~ routine ~~expenditures~~projects for other generation, ~~transmission,~~natural gas distribution, technology, facilities and other ~~infrastructure needed~~operational needs to serve existing and expected demand.

~~Contractual Obligations~~Material Cash Requirements

As of ~~September~~June 30, ~~2017,~~2023, there have been no material changes ~~outside the normal course of business~~ in MidAmerican Energy's and MidAmerican Funding's ~~contractual obligations~~cash requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, ~~2016.~~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.

~~Quad Cities Generating Station Operating Status~~

Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018, as a result of Illinois not passing adequate legislation and Quad Cities Station not clearing the 2019-2020 PJM Interconnection, L.L.C. capacity auction. MidAmerican Energy expressed to Exelon Generation its desire for the continued operation of the facility through the end of its operating license in 2032 and worked with Exelon Generation on solutions to that end. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission credits will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. For the nuclear assets already in rate base, MidAmerican Energy's customers will not be charged for the subsidy, and MidAmerican Energy will not receive additional revenue from the subsidy.

On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of Illinois ("Northern District of Illinois") against the Illinois Power Agency alleging that the state’s zero emission credit program violates certain provisions of the U.S. Constitution. Both complaints argue that the Illinois zero emission credit program will distort the FERC’s energy and capacity market auction system of setting wholesale prices. As majority owner and operator of Quad Cities Station, Exelon Generation intervened in both suits and filed motions to dismiss in both matters. On July 14, 2017, the Northern District of Illinois granted the motions to dismiss. On July 17, 2017, the plaintiffs filed appeals with the United States Court of Appeals for the Seventh Circuit. The procedural schedule has been established for the appeals. MidAmerican Energy cannot predict the outcome of these lawsuits.

On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Price Offer Rule ("MOPR") provisions to apply to existing resources receiving zero emission credit compensation. If successful, an expanded MOPR could result in an increased risk of Quad Cities Station not clearing in future capacity auctions and Exelon Generation no longer receiving capacity revenues for the facility. As majority owner and operator of Quad Cities Station, Exelon Generation has filed protests at the FERC in response to each filing. The timing of the FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding air ~~and water~~ quality, climate change, emissions performance standards, ~~climate change,~~water quality, coal ~~combustion byproduct~~ash disposal ~~hazardous and solid waste disposal, protected species~~ and other environmental matters that have the potential to impact ~~its~~MidAmerican Energy's current and future operations. In addition to imposing continuing compliance obligations, ~~and capital expenditure requirements,~~ these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by ~~the EPA and~~ various federal, state and local agencies. ~~All such~~MidAmerican Energy believes it is in material compliance with all applicable laws and regulations, although many are subject to ~~a range of~~ interpretation ~~which~~that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and ~~consolidated~~ financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of MidAmerican Energy's forecast environmental-related capital expenditures.

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.

~~New Accounting Pronouncements~~

For a discussion of new accounting pronouncements affecting MidAmerican Energy and MidAmerican Funding, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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, ~~2016.~~2022. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, ~~2016.~~

2022.

116

Nevada Power Company and its subsidiaries

Consolidated Financial Section

117

PART I


~~Item 1.~~	~~Financial Statements~~

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

~~Las Vegas, Nevada~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of ~~September~~June 30, ~~2017, and~~2023, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, and of ~~changes in shareholder's equity and~~ cash flows for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016. These~~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 ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~Nevada Power's management.~~America.

We ~~conducted our reviews~~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 have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Nevada Power Company and subsidiaries as of December 31, 2016, 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, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

~~November 3, 2017~~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

As of
September 30, December 31,
2017 2016
ASSETS
Current assets:
Cash and cash equivalents $ 69
$ 279
Accounts receivable, net 362
243
Inventories 59
73
Regulatory assets 34
20
Other current assets 50
38
Total current assets 574
653

Property, plant and equipment, net 6,890
6,997
Regulatory assets 1,110
1,000
Other assets 39
39

Total assets $ 8,613
$ 8,689

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable $ 192
$ 187
Accrued interest 39
50
Accrued property, income and other taxes 109
93
Regulatory liabilities 35
37
Current portion of long-term debt and financial and capital lease obligations 842
17
Customer deposits 78
78
Other current liabilities 31
39
Total current liabilities 1,326
501

Long-term debt and financial and capital lease obligations 2,231
3,049
Regulatory liabilities 423
416
Deferred income taxes 1,529
1,474
Other long-term liabilities 281
277
Total liabilities 5,790
5,717

Commitments and contingencies (Note 9)

Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding —
—
Other paid-in capital 2,308
2,308
Retained earnings 518
667
Accumulated other comprehensive loss, net (3 ) (3 )
Total shareholder's equity 2,823
2,972

Total liabilities and shareholder's equity $ 8,613
$ 8,689

The accompanying notes are an integral part of the consolidated financial statements.

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Operating revenue $ 819
$ 766
$ 1,785
$ 1,690

Operating costs and expenses:
Cost of fuel, energy and capacity 318
251
721
618
Operating and maintenance 97
105
278
304
Depreciation and amortization 77
76
231
227
Property and other taxes 10
10
29
30
Total operating costs and expenses 502
442
1,259
1,179

Operating income 317
324
526
511

Other income (expense):
Interest expense (44 ) (45 ) (132 ) (140 )
Allowance for borrowed funds 1
—
1
2
Allowance for equity funds —
—
1
3
Other, net 5
7
18
17
Total other income (expense) (38 ) (38 ) (112 ) (118 )

Income before income tax expense 279
286
414
393
Income tax expense 103
98
151
136
Net income $ 176
$ 188
$ 263
$ 257

The accompanying notes are an integral part of these consolidated financial statements.

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

Accumulated
Other Other Total
Common Stock Paid-in Retained Comprehensive Shareholder's
Shares Amount Capital Earnings Loss, Net Equity

Balance, December 31, 2015 1,000
$ —
$ 2,308
$ 858
$ (3 ) $ 3,163
Net income —
—
—
257
—
257
Dividends declared —
—
—
(365 ) —
(365 )
Other equity transactions —
—
—
(1 ) —
(1 )
Balance, September 30, 2016 1,000
$ —
$ 2,308
$ 749
$ (3 ) $ 3,054

Balance, December 31, 2016 1,000
$ —
$ 2,308
$ 667
$ (3 ) $ 2,972
Net income —
—
—
263
—
263
Dividends declared —
—
—
(412 ) —
(412 )
Balance, September 30, 2017 1,000
$ —
$ 2,308
$ 518
$ (3 ) $ 2,823

The accompanying notes are an integral part of these consolidated financial statements.

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

Nine-Month Periods
Ended September 30,
2017 2016
Cash flows from operating activities:
Net income $ 263
$ 257
Adjustments to reconcile net income to net cash flows from operating activities:
Gain on nonrecurring items (1 ) —
Depreciation and amortization 231
227
Deferred income taxes and amortization of investment tax credits 61
52
Allowance for equity funds (1 ) (3 )
Changes in regulatory assets and liabilities 25
139
Deferred energy (22 ) (3 )
Amortization of deferred energy 13
(87 )
Other, net (1 ) 3
Changes in other operating assets and liabilities:
Accounts receivable and other assets (122 ) (96 )
Inventories 6
7
Accrued property, income and other taxes 11
98
Accounts payable and other liabilities 9
7
Net cash flows from operating activities 472
601

Cash flows from investing activities:
Capital expenditures (202 ) (249 )
Acquisitions (77 ) —
Other, net 4
—
Net cash flows from investing activities (275 ) (249 )

Cash flows from financing activities:
Proceeds from issuance of long-term debt 91
—
Repayments of long-term debt and financial and capital lease obligations (86 ) (221 )
Dividends paid (412 ) (365 )
Net cash flows from financing activities (407 ) (586 )

Net change in cash and cash equivalents (210 ) (234 )
Cash and cash equivalents at beginning of period 279
536
Cash and cash equivalents at end of period $ 69
$ 302

The accompanying notes are an integral part of these consolidated financial statements.

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) ~~Organization and Operations~~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 ~~United States~~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 ~~September~~June 30, ~~2017~~2023, and for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~2022. The results of operations for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~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, ~~2016~~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 ~~and policies~~ during the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017.~~2023.

(2) ~~New Accounting Pronouncements~~Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendmentsCash equivalents consist of funds invested in ~~this guidance require that an employer disaggregate the service cost component from the~~money market mutual funds, U.S. Treasury Bills and other ~~components~~investments with a maturity of ~~net benefit cost~~three months or less when purchased. Cash and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. Nevada Power plans to adopt this guidance effective January 1, 2018. Nevada Power does not believe this will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

~~In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement~~ of Cash ~~Flows." The amendments~~Flows is outlined below and disaggregated by the line items in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Nevada Power plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will have a material impact on its Consolidated Financial Statements.

~~In February 2016, the FASB issued ASU No. 2016-02,~~ which ~~creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities~~they appear on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. Nevada Power plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated ~~Financial Statements and disclosures included within Notes to Consolidated Financial Statements.~~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

In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. Nevada Power plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. Nevada Power currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power’s performance to date. Nevada Power's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by customer class.

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

As of
Depreciable Life September 30, December 31,
2017 2016
Utility plant:
Generation 30 - 55 years $ 3,725
$ 4,271
Distribution 20 - 65 years 3,294
3,231
Transmission 45 - 65 years 1,860
1,846
General and intangible plant 5 - 65 years 784
738
Utility plant 9,663
10,086
Accumulated depreciation and amortization (2,840 ) (3,205 )
Utility plant, net 6,823
6,881
Other non-regulated, net of accumulated depreciation and amortization 45 years 2
2
Plant, net 6,825
6,883
Construction work-in-progress 65
114
Property, plant and equipment, net $ 6,890
$ 6,997

~~Acquisitions~~

In April 2017, Nevada Power purchased the remaining 25% interest in the Silverhawk natural gas-fueled generating facility for $77 million. The Public Utilities Commission of Nevada ("PUCN") approved the purchase of the facility in Nevada Power’s triennial Integrated Resource Plan filing in December 2015. The purchase price was allocated to the assets acquired, consisting primarily of generation utility plant, and no significant liabilities were assumed.

(4) ~~Regulatory Matters~~Recent Financing Transactions

~~Deferred Energy~~Long-Term Debt

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

~~Chapter 704B Applications~~

Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one megawatt ("MW") or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs.

In May 2015, MGM Resorts International ("MGM") and Wynn Las Vegas, LLC ("Wynn"), filed applications with the PUCN to purchase energy from alternative providers of a new electric resource and become distribution only service customers of Nevada Power. In December 2015, the PUCN granted the applications subject to conditions, including paying an impact fee, on-going charges and receiving approval for specific alternative energy providers and terms. In December 2015, the applicants filed petitions for reconsideration. In January 2016, the PUCN granted reconsideration and updated some of the terms, including removing a limitation related to energy purchased indirectly from NV Energy. In September 2016, MGM and Wynn paid impact fees of $82 million and $15 million, respectively. In October 2016, MGM and Wynn became distribution only service customers and started procuring energy from another energy supplier. In April 2017, Wynn filed a motion with the PUCN seeking relief from the January 2016 order and requested the PUCN adopt an alternative impact fee and revise on-going charges associated with retirement of assets and high cost renewable contracts. In May 2017, a stipulation reached between MGM, Regulatory Operations Staff and the Bureau of Consumer Protection was filed requiring Nevada Power to credit $16 million as an offset against MGM's remaining impact fee obligation and, in June 2017, the PUCN approved the stipulation as filed.

In September 2016, Switch, Ltd. ("Switch"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power. In December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions, including paying an impact fee to Nevada Power. In May 2017, Switch paid impact fees of $27 million and, in June 2017, Switch became a distribution only service customer and started procuring energy from another energy supplier.

In November 2016, Caesars Enterprise Service ("Caesars"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers. In July 2017, Caesars made the required compliance filings and, in September 2017, the PUCN issued an order allowing Caesars to acquire electric energy and ancillary services from another energy supplier and become a distribution only service customer of Nevada Power.

~~Emissions Reduction and Capacity Replacement Plan ("ERCR Plan")~~

In March ~~2017,~~2023, Nevada Power retired Reid Gardner Unit 4, a 257-MW coal-fueled generating facility. The early retirement was approved by the PUCN in December 2016 as a part of Nevada Power's second amendment to the ERCR Plan. The remaining net book value of $151 million was moved from property, plantrepurchased and ~~equipment, net to noncurrent regulatory assets on the Consolidated Balance Sheet in March 2017, in compliance with the ERCR Plan. Refer to Note 9 for additional information on the ERCR Plan.~~

~~(5)~~ ~~Recent Financing Transactions~~

In January 2017, Nevada Power (1) issued a notice to the bondholders for the repurchase of the remaining outstanding amounts of its $38 million Pollution Control Revenue Bonds, Series 2006 and $38 million Pollution Control Revenue Bonds, Series 2006A and (2) redeemed the Pollution Control Revenue Bonds, Series 2006A, aggregate principal amount outstanding plus accrued interest with the use of cash on hand. In February 2017, Nevada Power redeemed the Pollution Control Revenue Bonds, Series 2006, aggregate principal amount outstanding plus accrued interest with the use of cash on hand.

~~In May 2017, Nevada Power~~ entered into a ~~Financing Agreement with Clark County, Nevada (the "Clark Issuer") whereby~~re-offering of the ~~Clark Issuer loaned to Nevada Power the proceeds from the issuance, on behalf~~following series of ~~Nevada Power, of $39.5~~fixed-rate tax-exempt bonds: $40 million of its 1.60% tax-exempt Pollution Control Refunding Revenue Bonds, Series 2017, due 2036 ("Series 2017 Bonds"). The Series 2017 Bonds are subject to mandatory purchase by Nevada Power in May 2020, and on and after the purchase date, the interest rate may be adjusted from time to time.

~~In May 2017, Nevada Power entered into a Financing Agreement with the~~ Coconino County, Arizona Pollution Control Corporation ~~(the "Coconino Issuer") whereby the Coconino Issuer loaned to Nevada Power the proceeds from the issuance, on behalf of Nevada Power, of $40 million of its 1.80% tax-exempt Pollution Control Refunding~~ Revenue Bonds, Series 2017A, due ~~2032 and~~2032; $13 million of its ~~1.60% tax-exempt~~Coconino County, Arizona Pollution Control ~~Refunding~~Corporation Revenue Bonds, Series 2017B, due ~~2039 (collectively, the "Series 2017AB Bonds"). The Series 2017AB Bonds are subject to mandatory purchase by Nevada Power in May 2020,~~2039; and ~~on and after the purchase date, the interest rate may be adjusted from time to time.~~

To provide collateral security for its obligations, Nevada Power issued its General and Refunding Mortgage Notes, Series AA, No. AA-1 in the amount of $39.5 million and No. AA-2 in the amount of $53 million (collectively, the "Series AA Notes").The obligation of Nevada Power to make any payment of the principal and interest on any Series AA Notes is discharged to the extent Nevada Power has made payment on the Series 2017 Bonds and the Series 2017AB Bonds.

~~The collective proceeds from the tax-exempt bond issuances were used to refund at par value, plus accrued interest, the Clark Issuer's $39.5~~$40 million of ~~Pollution Control Refunding~~its Clark County, Nevada Revenue Bonds, Series ~~2006~~2017, due 2036. The Coconino Series 2017A bond was offered at a fixed rate of 4.125% and the Coconino ~~Issuer's $40 million~~Series 2017B and Clark Series 2017 bonds were offered at a fixed rate of ~~Pollution Control Refunding Revenue Bonds, Series 2006A and $13 million of Pollution Control Refunding Revenue Bonds, Series 2006B, each previously issued on behalf of Nevada Power.~~3.750%.

Credit Facilities

In June ~~2017,~~2023, Nevada Power amended its existing $400 million secured credit facility ~~extending~~expiring in June 2025. The amendment increased the ~~maturity~~commitment of the lenders to $600 million and extended the expiration date to June ~~2020~~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 two one-year extension options subject to lender consent. The amended credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, atestablished regulatory practice, Nevada Power's ~~option, plus~~provision for federal income tax has been computed on a ~~spread that varies based on~~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's credit ratings~~Power made no cash payments for ~~its senior secured long-term debt securities. The amended credit facility requires~~federal income tax to BHE. For the six-month period ended June 30, 2022, Nevada ~~Power's ratio of consolidated debt, including current maturities, to total capitalization not to exceed 0.65 to 1.0 as of the last day of each quarter.~~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. ~~Nevada Power contributed $1 million to the Non-Qualified Pension Plans for the nine-month period ended September 30, 2017.~~ 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 ~~payable to~~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

As of
September 30, December 31,
2017 2016
Qualified Pension Plan -
Other long-term liabilities $ (27 ) $ (24 )

Non-Qualified Pension Plans:
Other current liabilities (1 ) (1 )
Other long-term liabilities (9 ) (9 )

Other Postretirement Plans -
Other long-term liabilities (4 ) (4 )

(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 ~~and coal~~ market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.

Nevada Power has established a risk management process that is designed to identify, assess, manage ~~monitor~~ 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 orand normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power'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
	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)

Other Other
Current Long-term
Liabilities Liabilities Total
As of September 30, 2017
Commodity liabilities⁽¹⁾
$ (3 ) $ (1 ) $ (4 )

As of December 31, 2016
Commodity liabilities⁽¹⁾
$ (7 ) $ (7 ) $ (14 )

(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.


~~(1)~~	Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates and as of September 30, 2017 and December 31, 2016, a regulatory asset of $4 million and $14 million, respectively, was recorded related to the derivative liability of $4 million and $14 million, respectively.

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with ~~indexed and~~ 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

As of
Unit of September 30, December 31,
Measure 2017 2016

Electricity sales Megawatt hours —
(2 )
Natural gas purchases Decatherms 149
114

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, ~~establish~~establishes limits on the amount of unsecured credit to be extended to each counterparty and ~~evaluate~~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 ~~three~~ recognized credit rating agencies. These ~~derivative contracts~~agreements may either specifically provide bilateral rights to demand cash or other security ~~in the event of~~if credit exposures on a ~~credit rating downgrade ("credit-risk-related~~net basis exceed specified rating-dependent threshold levels "credit-risk-related contingent features") or provide the right for counterparties to demand "adequate ~~assurance," in the event of~~assurance" if there is a material adverse change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of ~~September~~June 30, ~~2017,~~2023, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the ~~three~~ 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 ~~was $2~~totaled $9 million and $5 million as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~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~~

(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 ~~Balance Sheets~~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 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

Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Total
As of September 30, 2017
Assets - investment funds $ 2
$ —
$ —
$ 2

Liabilities - commodity derivatives $ —
$ —
$ (4 ) $ (4 )

As of December 31, 2016
Assets:
Money market mutual funds⁽¹⁾
$ 220
$ —
$ —
$ 220
Investment funds 6
—
—
6
$ 226
$ —
$ —
$ 226

Liabilities - commodity derivatives $ —
$ —
$ (14 ) $ (14 )


~~(1)~~	~~Amounts are included in cash and cash equivalents on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.~~

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of ~~September~~June 30, ~~2017~~2023 and December 31, ~~2016,~~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. ~~Refer to Note 7 for further discussion regarding Nevada Power's risk management and hedging activities.~~

Nevada Power's investments in money market mutual funds and ~~equity securities are accounted for as available-for-sale securities 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)

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016

Beginning balance $ (4 ) $ (22 ) $ (14 ) $ (22 )
Changes in fair value recognized in regulatory assets (1 ) (1 ) (3 ) (6 )
Settlements 1
4
13
9
Ending balance $ (4 ) $ (19 ) $ (4 ) $ (19 )

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

As of September 30, 2017 As of December 31, 2016
Carrying Fair Carrying Fair
Value Value Value Value

Long-term debt $ 2,599
$ 3,055
$ 2,581
$ 3,040

(9) Commitments and Contingencies


~~(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, ~~renewable portfolio standards,~~ emissions performance standards, ~~climate change,~~ coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.

~~Senate Bill 123~~

In June 2013, the Nevada State Legislature passed Senate Bill No. 123 ("SB 123"), which included the retirement of coal plants and replacing the capacity with renewable facilities and other generating facilities. In May 2014, Nevada Power filed its ERCR Plan in compliance with SB 123. In July 2015, Nevada Power filed an amendment to its ERCR Plan with the PUCN which was approved in September 2015. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123.

Consistent with the ERCR Plan, Nevada Power acquired a 272-MW natural gas co-generating facility in 2014, acquired a 210-MW natural gas peaking facility in 2014, constructed a 15-MW solar photovoltaic facility in 2015, contracted two renewable power purchase agreements with 100-MW solar photovoltaic generating facilities in 2015, contracted a renewable power purchase agreement with 100-MW solar photovoltaic generating facility in 2016 and acquired the remaining 130 MW, 25%, of the Silverhawk natural gas-fueled generating facility in April 2017, of which 54 MW were approved as part of the ERCR Plan. Nevada Power has the option to acquire 35 MW of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval. Nevada Power retired Reid Gardner Units 1, 2, and 3, 300 MW of coal-fueled generation, in 2014 and Reid Gardner Unit 4, 257 MW of coal-fueled generation, in March 2017. These transactions are related to Nevada Power's compliance with SB 123, resulting in the retirement of 812 MW of coal-fueled generation by 2019.

Legal Matters

Nevada Power is party to a variety of legal actions arising out of the normal course of business. ~~Plaintiffs occasionally seek punitive or exemplary damages.~~ Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

(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

~~General~~

Nevada Power's revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. Nevada Power is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short- and long-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of Nevada Power. Additionally, the timely recovery of purchased power, fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of Nevada Power.

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Nevada Power's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.

Results of Operations for the ~~Third~~Second Quarter and First ~~Nine~~Six Months of ~~2017~~2023 and ~~2016~~2022

Overview

Net income for the ~~third~~second quarter of ~~2017~~2023 was ~~$176~~$66 million, a decrease of ~~$12~~$10 million, ~~or 6%,~~ compared to ~~2016~~2022 primarily due to lower ~~commercial~~utility margin, higher interest expense, primarily due to higher long-term debt, higher operations and ~~industrial~~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 ~~from customers purchasing energy from alternative providers and becoming~~deferrals. Retail customer volumes, including distribution only service customers, ~~refinement~~decreased 4.5% primarily due to the unfavorable impact of ~~the unbilled revenue estimate and increased other operating costs. The decrease in net income was partially~~weather, offset by ~~higher other retail revenue primarily from impact fees~~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 ~~revenue relating to customers becoming distribution only service customers, customer usage patterns, higher transmission revenue and customer growth.~~purchased electricity volumes decreased 11%.

Net income for the first ~~nine~~six months of ~~2017~~2023 was ~~$263~~$70 million, ~~an increase~~a decrease of $6$4 million, ~~or 2%,~~ compared to ~~2016~~2022 primarily due to higher ~~other retail revenue primarily from impact fees and revenue relating~~interest expense, mainly due to ~~customers becoming distribution only service customers, lower interest on deferred charges and~~higher long-term debt, ~~customer growth,~~ higher ~~transmission revenue, customer usage patterns~~operations and ~~lower planned maintenance. The increase in net income was partially offset by lower commercial~~maintenance expenses and ~~industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers,~~ higher depreciation and amortization, ~~primarily~~mainly due to higher plant placed ~~in-service~~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 ~~operating costs.~~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%.

~~Operating revenue and cost of fuel, energy and capacity~~Non-GAAP Financial Measure

Management utilizes various key financial measures that are ~~key drivers of Nevada Power's~~prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of ~~operations~~operations. Utility margin is calculated as ~~they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. Nevada Power believes that a discussion of gross margin, representing~~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 ~~capacity,~~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 ~~therefore meaningful.~~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 ~~Nevada Power's~~ 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

Third Quarter First Nine Months
2017 2016 Change 2017 2016 Change
Gross margin (in millions):
Operating revenue $ 819
$ 766
$ 53
7
% $ 1,785
$ 1,690
$ 95
6
%
Cost of fuel, energy and capacity 318
251
67
27
721
618
103
17

Gross margin $ 501
$ 515
$ (14 ) (3 ) $ 1,064
$ 1,072
$ (8 ) (1 )

GWh sold:
Residential 3,899
3,814
85
2
% 7,899
7,802
97
1
%
Commercial 1,517
1,440
77
5
3,669
3,600
69
2

Industrial 1,783
2,149
(366 ) (17 ) 4,870
5,772
(902 ) (16 )
Other 60
59
1
2
154
155
(1 ) (1 )
Total fully bundled⁽¹⁾
7,259
7,462
(203 ) (3 ) 16,592
17,329
(737 ) (4 )
Distribution only service 617
119
498
*
1,367
305
1,062
*

Total retail 7,876
7,581
295
4
17,959
17,634
325
2

Wholesale 59
76
(17 ) (22 ) 214
177
37
21

Total GWh sold 7,935
7,657
278
4
18,173
17,811
362
2

Average number of retail customers (in thousands):
Residential 813
799
14
2
% 809
795
14
2
%
Commercial 106
105
1
1
106
105
1
1

Industrial 2
2
—
—
2
2
—
—

Total 921
906
15
2
917
902
15
2

Average retail revenue per MWh:
Fully bundled⁽¹⁾
$ 109.85
$ 101.22
$ 8.63
9
% $ 104.06
$ 95.69
$ 8.37
9
%

Heating degree days —
—
—
—
% 791
829
(38 ) (5 ) %
Cooling degree days 2,319
2,295
24
1
% 3,808
3,674
134
4
%

Sources of energy (GWh)⁽²⁾:

Natural gas 4,592
4,657
(65 ) (1 ) % 10,338
11,569
(1,231 ) (11 ) %
Coal 367
599
(232 ) (39 ) 1,182
1,140
42
4

Renewables 19
26
(7 ) (27 ) 57
47
10
21

Total energy generated 4,978
5,282
(304 ) (6 ) 11,577
12,756
(1,179 ) (9 )
Energy purchased 2,500
2,471
29
1
5,665
5,410
255
5

Total 7,478
7,753
(275 ) (4 ) 17,242
18,166
(924 ) (5 )

Average total cost of energy per MWh⁽³⁾:
$ 42.46
$ 32.30
$ 10.16
31
% $ 41.80
$ 34.01
$ 7.79
23
%
Quarter Ended June 30, 2023 Compared to Quarter Ended June 30, 2022

* ~~Not meaningful~~


~~(1)~~	~~Fully bundled includes sales to customers for combined energy, transmission and distribution services.~~


~~(2)~~	~~GWh amounts are net of energy used by the related generating facilities.~~


~~(3)~~	~~The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.~~

~~Gross~~Utility margin decreased ~~$14~~$15 million, or 3%5%, for the ~~third~~second quarter of ~~2017~~2023 compared to ~~2016~~2022 primarily due to:

•$1521 million inof lower ~~commercial and industrial~~electric retail ~~revenue from customers purchasing energy from alternative providers and becoming~~utility margin primarily due to lower retail customer volumes. Retail customer volumes, including distribution only service ~~customers;~~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:

•$103 million ~~in lower~~of higher energy efficiency program ~~revenue~~rates (offset in ~~operating~~operations and maintenance expense) and

~~$9 million from a refinement of the unbilled revenue estimate.~~

~~The decrease in gross margin was offset by:~~

~~$8 million in higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers;~~

~~$5 million from customer usage patterns;~~

•$3 million inof higher ~~transmission~~regulatory-related revenue deferrals.

Operations and maintenance increased $3 million, or 4%, for the second quarter of 2023 compared to 2022 primarily due to ~~customers becoming distribution only service customers and~~

~~$2 million due to customer growth.~~

~~Operating~~increased plant operations and maintenance ~~decreased $8 million, or 8%, for the third quarter of 2017 compared to 2016 due to lower~~ expenses, higher energy efficiency program ~~expense~~costs (offset in operating revenue) ~~of $8 million.~~and higher customer service operations expenses, partially offset by lower earnings sharing.

~~Income tax expense~~Depreciation and amortization increased $5 million, or 5%, for the ~~third~~second quarter of ~~2017~~2023 compared to ~~2016. The effective tax rate was 37% in 2017 and 34% in 2016. The increase in the effective tax rate is primarily due to the qualified production activities deduction in 2016.~~

~~Gross margin~~ ~~decreased $8 million, or 1%, for the first nine months of 2017 compared to 2016 due to:~~

~~$24 million in lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers and~~

~~$22 million in lower energy efficiency program revenue (offset in operating and maintenance expense).~~

~~The decrease in gross margin was offset by:~~

~~$19 million in higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers;~~

~~$7 million due to customer growth;~~

~~$6 million in higher transmission revenue primarily due to customers becoming distribution only service customers and~~

~~$5 million from customer usage patterns.~~

~~Operating and maintenance~~ decreased $26 million, or 9%, for the first nine months of 2017 compared to 2016 due to lower energy efficiency program expense (offset in operating revenue); lower planned maintenance; and decreased expenses related to uncollectible accounts. These decreases are partially offset by higher other operating costs.

~~Depreciation and amortization~~ ~~increased$4 million, or 2%, for the first nine months of 2017 compared to 2016~~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, ~~income (expense)~~ isnet increased $5 million for the second quarter of 2023 compared to 2022 primarily due to favorable $6cash 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 ~~nine~~six months of ~~2017~~2023 compared to ~~2016~~2022 primarily due to:

•$18 million of lower electric retail utility margin primarily due to lower ~~interest expense on deferred charges~~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 ~~redemption~~first six months of ~~$210 million Series M, 5.950% General~~2023 compared to 2022 primarily due to increased plant operations and ~~Refunding Mortgage Notes~~maintenance expenses, higher energy efficiency program costs (offset in ~~2016,~~operating revenue) and higher customer service operations expenses, partially offset by lower ~~allowance for funds used during construction.~~earnings sharing.

~~Income tax expense~~

133

Depreciation and amortization increased ~~$15~~$8 million, or ~~11%~~4%, for the first ~~nine~~six months of ~~2017~~2023 compared to ~~2016.~~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 ~~36%~~10% in ~~2017~~2023 and ~~35%~~12% in ~~2016. The increase in the effective tax rate is~~2022 and decreased primarily due to the ~~qualified production activities deduction in 2016.~~effects of ratemaking.

Liquidity and Capital Resources

As of ~~September~~June 30, ~~2017,~~2023, Nevada Power's total net liquidity was ~~$469 million consisting of $69 million in cash and cash equivalents and $400 million of a credit facility.~~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 ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, were ~~$472~~$232 million and ~~$601~~$224 million, respectively. The change was primarily due to higher ~~impact fees received in 2016~~collections from customers, the timing of payments for operating costs and ~~higher intercompany tax payments,~~increased customer advance collections, partially offset by ~~a 2016 contribution~~higher payments related to ~~the pension plan.~~fuel and energy costs, lower cash received for income tax and higher interest payments.

In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). As a result of PATH, Nevada Power's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019 and investment tax credits (once the net operating loss is fully utilized) earned on qualifying projects through 2021.

The timing of Nevada Power's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions made for each payment date.

Investing Activities

Net cash flows from investing activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, were ~~$(275)~~$(619) million and ~~$(249)~~$(350) million, respectively. The change was primarily due to ~~the acquisition of the remaining 25% in the Silverhawk generating station, partially~~increased capital expenditures, offset by ~~decreased~~the repayment of an affiliate note receivable. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, were ~~$(407)~~$389 million and ~~$(586)~~$136 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and lower repayments of ~~long‑term debt and proceeds from issuance of long‑term~~short-term debt, partially offset by ~~higher dividends paid to NV Energy, Inc. in 2017.~~lower proceeds from the issuance of long-term debt.

134

~~Ability to Issue~~

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's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2017, Nevada~~ Power currently has financing authority from the PUCN consisting of the ability to: (1) ~~issue new long-term~~establish debt ~~securities~~issuances limited to a debt ceiling of ~~up to $1.3 billion;~~$3.8 billion (excluding borrowings under Nevada Power's $600 million secured credit facility); and (2) ~~refinance up to $1.2 billion of long-term debt securities; and (3)~~ maintain a revolving credit facility of up to $1.3 billion. Nevada ~~Power's revolving credit facility contains a financial maintenance covenant which Nevada~~ Power ~~was in compliance~~currently has an effective shelf registration statement with asthe SEC to issue up to $2.6 billion of ~~September 30, 2017.~~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

~~Nevada Power 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, changes in environmental and other rules and regulations; impacts to ~~customers'~~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. ~~Expenditures for certain assets may ultimately include acquisition of existing assets.~~

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

Nine-Month Periods Annual
Ended September 30, Forecast
2016 2017 2017

Generation development $ 1
$ —
$ —
Distribution 110
41
58
Transmission system investment 29
6
10
Other 109
155
180
Total $ 249
$ 202
$ 248

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 ~~approved~~historical and forecast capital expenditures include ~~investments related~~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 ~~that~~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 ~~distribution, generation~~ 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.

~~In April 2017, Nevada Power purchased~~•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 ~~remaining 25% interest~~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 ~~natural gas-fueled~~ 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 $77 million. The Public Utilities Commission of Nevada ("PUCN") approved the purchase of the facility in Nevada Power’s triennial Integrated Resource Plan filing in December 2015. The purchase price was allocatedgeneration, other operating projects and other infrastructure needed to ~~the assets acquired, consisting primarily of generation utility plant,~~serve existing and ~~no significant liabilities were assumed.~~expected demand.

~~Contractual Obligations~~Material Cash Requirements

As of ~~September~~June 30, ~~2017,~~2023, there have been no material changes ~~outside the normal course of business~~ in ~~contractual obligations~~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, ~~2016.~~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 ~~and water~~ quality, ~~RPS,~~climate change, emissions performance standards, ~~climate change,~~water quality, coal ~~combustion byproduct~~ash disposal ~~hazardous and solid waste disposal, protected species~~ and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations, ~~and capital expenditure requirements,~~ these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by ~~the EPA and~~ various federal, state and local agencies. ~~All such~~Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to ~~a range of~~ interpretation ~~which~~that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and ~~consolidated~~ financial results. Nevada Power believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of Nevada Power's forecasted environmental-related capital expenditures.

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.~~laws and regulations.

~~New Accounting Pronouncements~~

~~For a discussion of new accounting pronouncements affecting Nevada Power, refer to Note 2 of Notes to Consolidated Financial Statements in Nevada Power's Part I, Item 1 of this Form 10-Q.~~

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, ~~2016.~~2022. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, ~~2016.~~

2022.

136

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

137

PART I


~~Item 1.~~	~~Financial Statements~~

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

~~Las Vegas, Nevada~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of ~~September~~June 30, ~~2017, and~~2023, the related consolidated statements of operations, and changes in shareholder's equity for the three-month and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016,~~2022, and of ~~changes in shareholder's equity and~~ cash flows for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016. These~~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 ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~Sierra Pacific's management.~~America.

We ~~conducted our reviews~~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 have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Sierra Pacific Power Company and subsidiaries as of December 31, 2016, 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, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

~~November 3, 2017~~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

As of
September 30, December 31,
2017 2016
ASSETS
Current assets:
Cash and cash equivalents $ 30
$ 55
Accounts receivable, net 102
117
Inventories 47
45
Regulatory assets 38
25
Other current assets 20
13
Total current assets 237
255

Property, plant and equipment, net 2,862
2,822
Regulatory assets 400
410
Other assets 8
6

Total assets $ 3,507
$ 3,493

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable $ 75
$ 146
Accrued interest 11
14
Accrued property, income and other taxes 11
10
Regulatory liabilities 17
69
Current portion of long-term debt and financial and capital lease obligations 1
1
Customer deposits 15
16
Other current liabilities 18
12
Total current liabilities 148
268

Long-term debt and financial and capital lease obligations 1,151
1,152
Regulatory liabilities 223
221
Deferred income taxes 663
617
Other long-term liabilities 134
127
Total liabilities 2,319
2,385

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding —
—
Other paid-in capital 1,111
1,111
Retained earnings (deficit) 78
(2 )
Accumulated other comprehensive loss, net (1 ) (1 )
Total shareholder's equity 1,188
1,108

Total liabilities and shareholder's equity $ 3,507
$ 3,493

The accompanying notes are an integral part of the consolidated financial statements.

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016
Operating revenue:
Electric $ 215
$ 207
$ 534
$ 539
Natural gas 15
15
66
81
Total operating revenue 230
222
600
620

Operating costs and expenses:
Cost of fuel, energy and capacity 76
73
193
208
Natural gas purchased for resale 4
5
26
42
Operating and maintenance 40
40
121
126
Depreciation and amortization 29
30
85
88
Property and other taxes 6
5
18
18
Total operating costs and expenses 155
153
443
482

Operating income 75
69
157
138

Other income (expense):
Interest expense (11 ) (12 ) (33 ) (42 )
Allowance for borrowed funds 1
—
1
1
Allowance for equity funds 1
1
2
2
Other, net 2
2
4
3
Total other income (expense) (7 ) (9 ) (26 ) (36 )

Income before income tax expense 68
60
131
102
Income tax expense 24
22
46
37
Net income $ 44
$ 38
$ 85
$ 65

The accompanying notes are an integral part of these consolidated financial statements.

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

Accumulated
Other Retained Other Total
Common Stock Paid-in Earnings Comprehensive Shareholder's
Shares Amount Capital (Deficit) Loss, Net Equity

Balance, December 31, 2015 1,000
$ —
$ 1,111
$ (35 ) $ —
$ 1,076
Net income —
—
—
65
—
65
Dividends declared —
—
—
(45 ) —
(45 )
Other equity transactions —
—
—
—
(1 ) (1 )
Balance, September 30, 2016 1,000
$ —
$ 1,111
$ (15 ) $ (1 ) $ 1,095

Balance, December 31, 2016 1,000
$ —
$ 1,111
$ (2 ) $ (1 ) $ 1,108
Net income —
—
—
85
—
85
Dividends declared —
—
—
(5 ) —
(5 )
Balance, September 30, 2017 1,000
$ —
$ 1,111
$ 78
$ (1 ) $ 1,188

The accompanying notes are an integral part of these consolidated financial statements.

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

Nine-Month Periods
Ended September 30,
2017 2016
Cash flows from operating activities:
Net income $ 85
$ 65
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization 85
88
Allowance for equity funds (2 ) (2 )
Deferred income taxes and amortization of investment tax credits 46
37
Changes in regulatory assets and liabilities 9
(14 )
Deferred energy (23 ) 55
Amortization of deferred energy (43 ) (35 )
Other, net —
(1 )
Changes in other operating assets and liabilities:
Accounts receivable and other assets 13
12
Inventories (2 ) 1
Accrued property, income and other taxes (2 ) —
Accounts payable and other liabilities (54 ) (15 )
Net cash flows from operating activities 112
191

Cash flows from investing activities:
Capital expenditures (131 ) (137 )
Net cash flows from investing activities (131 ) (137 )

Cash flows from financing activities:
Proceeds from issuance of long-term debt, net of costs —
1,089
Repayments of long-term debt and financial and capital lease obligations (1 ) (1,137 )
Dividends paid (5 ) (45 )
Net cash flows from financing activities (6 ) (93 )

Net change in cash and cash equivalents (25 ) (39 )
Cash and cash equivalents at beginning of period 55
106
Cash and cash equivalents at end of period $ 30
$ 67

The accompanying notes are an integral part of these consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) ~~Organization and Operations~~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 ~~United States~~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 ~~September~~June 30, ~~2017~~2023, and for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~2022. The results of operations for the three- and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~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, ~~2016~~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 ~~and policies~~ during the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017.~~2023.

(2) ~~New Accounting Pronouncements~~Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendmentsCash equivalents consist of funds invested in ~~this guidance require that an employer disaggregate the service cost component from the~~money market mutual funds, U.S. Treasury Bills and other ~~components~~investments with a maturity of ~~net benefit cost~~three months or less when purchased. Cash and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. Sierra Pacific plans to adopt this guidance effective January 1, 2018. Sierra Pacific does not believe this will have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

~~In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement~~ of Cash ~~Flows." The amendments~~Flows is outlined below and disaggregated by the line items in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Sierra Pacific plans to adopt this guidance effective January 1, 2018 and does not believe the adoption of this guidance will have a material impact on its Consolidated Financial Statements.

~~In February 2016, the FASB issued ASU No. 2016-02,~~ which ~~creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities~~they appear on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. Sierra Pacific plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated ~~Financial Statements and disclosures included within Notes to Consolidated Financial Statements.~~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

In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. Sierra Pacific plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. Sierra Pacific currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific’s performance to date. Sierra Pacific's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by segment and customer class.

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

As of
Depreciable Life September 30, December 31,
2017 2016
Utility plant:
Electric generation 25 - 60 years $ 1,140
$ 1,137
Electric distribution 20 - 100 years 1,445
1,417
Electric transmission 50 - 100 years 782
771
Electric general and intangible plant 5 - 70 years 182
164
Natural gas distribution 35 - 70 years 388
381
Natural gas general and intangible plant 5 - 70 years 14
15
Common general 5 - 70 years 290
267
Utility plant 4,241
4,152
Accumulated depreciation and amortization (1,496 ) (1,442 )
Utility plant, net 2,745
2,710
Other non-regulated, net of accumulated depreciation and amortization 70 years 5
5
Plant, net 2,750
2,715
Construction work-in-progress 112
107
Property, plant and equipment, net $ 2,862
$ 2,822

During ~~2016,~~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 ~~estimated useful~~average service lives ~~at the Valmy Generating Station.~~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 $9$19 million annually based on depreciable plant balances at the time of the change. However, the Public Utilities Commission of Nevada ("PUCN") ordered the change relating to the Valmy Generating Station of $7 million annually be deferred for future recovery through a regulatory asset.

(4) ~~Regulatory Matters~~

~~Deferred Energy~~

~~Regulatory Rate Review~~

In June 2016, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing requested no incremental annual revenue relief. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving most, but not all, issues in the proceeding and reduced Sierra Pacific's electric revenue requirement by $3 million spread evenly to all rate classes. In December 2016, the PUCN approved the settlement agreement and established an additional six MW of net metering capacity under the grandfathered rates, which are those net metering rates that were in effect prior to January 2016; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. The new rates were effective January 1, 2017. In January 2017, Sierra Pacific filed a petition for reconsideration relating to the creation of the additional six megawatts ("MW") of net metering at the grandfathered rates. Sierra Pacific believes the effects of the PUCN decision result in additional cost shifting to non-net metering customers and reduces the stipulated rate reduction for other customer classes. In June 2017, the PUCN denied the petition for reconsideration.

In June 2016, Sierra Pacific filed a gas regulatory rate review with the PUCN. The filing requested a slight decrease in its incremental annual revenue requirement. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving all issues in the proceeding and reduced Sierra Pacific's gas revenue requirement by $2 million. In December 2016, the PUCN approved the settlement agreement. The new rates were effective January 1, 2017.

~~Chapter 704B Applications~~

In September 2016, Switch, Ltd. ("Switch"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific. In December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions. In June 2017, Switch became a distribution only service customer and started procuring energy from another energy supplier.

In November 2016, Caesars Enterprise Service ("Caesars"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers. In July 2017, Caesars made the required compliance filings and, in September 2017, the PUCN issued an order allowing Caesars to acquire electric energy and ancillary services from another energy supplier and become a distribution only service customer of Sierra Pacific.

In May 2017, Peppermill Resort Spa Casino ("Peppermill"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific. In August 2017, the PUCN approved a stipulation allowing Peppermill to purchase energy from alternative providers subject to conditions, including paying an impact fee. In September 2017, Peppermill provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.

~~(5)~~Recent Financing Transactions

Credit Facilities

In June ~~2017,~~2023, Sierra Pacific amended its existing $250 million secured credit facility ~~extending~~expiring in June 2025. The amendment increased the ~~maturity~~commitment of the lenders to $400 million and extended the expiration date to June ~~2020~~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 two one-year extension options subject to lender consent. The amended credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, atestablished regulatory practice, Sierra Pacific's ~~option, plus~~provision for federal income tax has been computed on a ~~spread that varies based on~~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's credit ratings~~Pacific made no cash payments for ~~its senior secured long-term debt securities. The amended credit facility requires Sierra Pacific's ratio of consolidated debt, including current maturities,~~federal income tax to ~~total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.~~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 $4$2 million to the Other ~~Postretirement~~Post Retirement Plans for the ~~nine-month~~six-month period ended ~~September~~June 30, ~~2017.~~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 ~~payable to~~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

As of
September 30, December 31,
2017 2016
Qualified Pension Plan -
Other long-term liabilities $ (13 ) $ (12 )

Non-Qualified Pension Plans:
Other current liabilities (1 ) (1 )
Other long-term liabilities (9 ) (9 )

Other Postretirement Plans -
Other long-term liabilities (25 ) (28 )
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)

~~(7)~~

(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 ~~Balance Sheets~~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 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

Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3 Total
As of September 30, 2017
Assets - investment funds $ —
$ —
$ —
$ —

As of December 31, 2016
Assets:
Money market mutual funds⁽¹⁾
$ 35
$ —
$ —
$ 35
Investment funds 1
—
—
1
$ 36
$ —
$ —
$ 36
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.


~~(1)~~	~~Amounts are included in cash and cash equivalents on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.~~

Sierra Pacific's investments in money market mutual funds and ~~equity securities are accounted for as available-for-sale securities 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

As of September 30, 2017 As of December 31, 2016
Carrying Fair Carrying Fair
Value Value Value Value

Long-term debt $ 1,120
$ 1,201
$ 1,119
$ 1,191


~~(8)~~	~~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, ~~renewable portfolio standards,~~ emissions performance standards, ~~climate change,~~ coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact 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. ~~Plaintiffs occasionally seek punitive or exemplary damages.~~ Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

~~(9)~~(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.

Sierra Pacific believes presenting gross margin allows the reader to assess the impact of Sierra Pacific's regulatory treatment and its overall regulatory environment on a consistent basis and is meaningful. Gross margin is calculated as operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale ("cost of sales").

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

Three-Month Periods Nine-Month Periods
Ended September 30, Ended September 30,
2017 2016 2017 2016
Operating revenue:
Regulated electric $ 215
$ 207
$ 534
$ 539
Regulated gas 15
15
66
81
Total operating revenue $ 230
$ 222
$ 600
$ 620

Cost of sales:
Regulated electric $ 76
$ 73
$ 193
$ 208
Regulated gas 4
5
26
42
Total cost of sales $ 80
$ 78
$ 219
$ 250

Gross margin:
Regulated electric $ 139
$ 134
$ 341
$ 331
Regulated gas 11
10
40
39
Total gross margin $ 150
$ 144
$ 381
$ 370

Operating and maintenance:
Regulated electric $ 36
$ 36
$ 108
$ 112
Regulated gas 4
4
13
14
Total operating and maintenance $ 40
$ 40
$ 121
$ 126

Depreciation and amortization:
Regulated electric $ 25
$ 26
$ 74
$ 76
Regulated gas 4
4
11
12
Total depreciation and amortization $ 29
$ 30
$ 85
$ 88

Operating income:
Regulated electric $ 72
$ 68
$ 142
$ 127
Regulated gas 3
1
15
11
Total operating income $ 75
$ 69
$ 157
$ 138

Interest expense:
Regulated electric $ 10
$ 11
$ 30
$ 38
Regulated gas 1
1
3
4
Total interest expense $ 11
$ 12
$ 33
$ 42

As of
September 30, December 31,
2017 2016
Assets:
Regulated electric $ 3,165
$ 3,119
Regulated gas 305
314
Regulated common assets⁽¹⁾
37
60
Total assets $ 3,507
$ 3,493


~~(1)~~	~~Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.~~

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

~~General~~

Sierra Pacific's revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. Sierra Pacific is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short- and long-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of Sierra Pacific. Additionally, the timely recovery of purchased power, fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of Sierra Pacific.

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.

Results of Operations for the ~~Third~~Second Quarter and First ~~Nine~~Six Monthsof ~~2017~~2023 and ~~2016~~2022

Overview

Net income for the ~~third~~second quarter of ~~2017~~2023 was ~~$44~~$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 ~~16%~~15%, compared to ~~2016~~2022 primarily due to ~~a decrease in~~higher utility margin and higher interest ~~expense from lower rates on outstanding debt balances~~ and ~~on deferred charges, higher electric margins~~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 ~~usage~~service operations expenses. Electric utility margin increased primarily due to higher retail rates due to the ~~impacts of weather~~2022 regulatory rate review with new rates effective January 2023 and ~~customer usage patterns~~higher transmission and ~~decreased other operating costs. The increase in net income was~~wholesale revenue, partially offset by lower ~~wholesale revenue.~~

~~Net income~~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 ~~nine~~six months of ~~2017 was $85 million, an increase of $20 million, or 31%,~~2023 compared to ~~2016~~2022 primarily due to ~~a decrease in interest expense from lower rates on outstanding debt balances and on deferred charges,~~ higher electric margins primarily from increased customer usage due to the impacts of weather and customer usage patterns, higher transmission revenue and lower other operating costs. The increase in net income was partiallynatural gas-fueled generation offset by lower ~~wholesale revenue.~~coal-fueled generation. Wholesale electricity sales volumes decreased 11% and purchased electricity volumes decreased 22%.

~~Operating~~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 ~~capacity and~~cost of natural gas purchased for resale are ~~key drivers of~~generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's ~~results of operations as they encompass retail and wholesale electricity~~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 ~~direct costs associated with providing electricity~~presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to ~~customers. Sierra Pacific believes that~~running the business and a ~~discussion~~measure of ~~gross~~comparability to others in the industry.

151

Electric utility margin ~~representing operating revenue less cost of fuel, energy and capacity~~ and natural gas ~~purchased~~utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, ~~resale,~~operating income which is ~~therefore meaningful.~~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 ~~Sierra Pacific's~~ 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	%

~~Electric Gross Margin~~

(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

Third Quarter First Nine Months
2017 2016 Change 2017 2016 Change
Gross margin (in millions):
Operating electric revenue $ 215
$ 207
$ 8
4
% $ 534
$ 539
$ (5 ) (1 ) %
Cost of fuel, energy and capacity 76
73
3
4
193
208
(15 ) (7 )
Gross margin $ 139
$ 134
$ 5
4
$ 341
$ 331
$ 10
3

GWh sold:
Residential 736
694
42
6
% 1,904
1,798
106
6
%
Commercial 850
854
(4 ) —
2,271
2,241
30
1

Industrial 797
747
50
7
2,346
2,235
111
5

Other 4
4
—
—
12
12
—
—

Total fully bundled⁽¹⁾
2,387
2,299
88
4
6,533

6,286

247
4

Distribution only service 348
346
2
1
1,041

1,019

22
2

Total retail 2,735
2,645
90
3
7,574
7,305
269
4

Wholesale 103
147
(44 ) (30 ) 392
481
(89 ) (19 )
Total GWh sold 2,838
2,792
46
2
7,966
7,786
180
2

Average number of retail customers (in thousands):
Residential 295
292
3
1
% 295
291
4
1
%
Commercial 47
47
—
—
47
47
—
—

Total 342
339
3
1
342
338
4
1

Average revenue per MWh:
Retail fully bundled⁽¹⁾
$ 85.07
$ 84.77
$ 0.30
—
% $ 75.89
$ 79.90
$ (4.01 ) (5 ) %
Wholesale $ 61.21
$ 52.33
$ 8.88
17
$ 52.92

$ 50.96

$ 1.96
4

Heating degree days 118
43
75
*
% 2,823
2,487
336
14
%
Cooling degree days 1,070
796
274
34
% 1,401
1,088
313
29
%

Sources of energy (GWh)⁽²⁾:

Natural gas 1,221
1,215
6
—
% 3,227

3,195

32
1
%
Coal 355
392
(37 ) (9 ) 457
691
(234 ) (34 )
Renewables 12
—
12
*
31

—

31
*

Total energy generated 1,588
1,607
(19 ) (1 ) 3,715
3,886
(171 ) (4 )
Energy purchased 1,074
878
196
22
3,698
3,111
587
19

Total 2,662
2,485
177
7
7,413
6,997
416
6

Average total cost of energy per MWh⁽³⁾:
$ 28.53
$ 29.67
$ (1.14 ) (4 ) % $ 26.07

$ 29.82

$ (3.75 ) (13 ) %

* ~~Not meaningful~~


~~(1)~~	~~Fully bundled includes sales to customers for combined energy, transmission and distribution services.~~


~~(2)~~	~~GWh amounts are net of energy used by the related generating facilities.~~


~~(3)~~	~~The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.~~

Natural Gas ~~Gross~~Utility Margin

Third Quarter First Nine Months
2017 2016 Change 2017 2016 Change
Gross margin (in millions):
Operating natural gas revenue $ 15
$ 15
$ —
—
% $ 66
$ 81
$ (15 ) (19 ) %
Natural gas purchased for resale 4
5
(1 ) (20 ) 26
42
(16 ) (38 )
Gross margin $ 11
$ 10
$ 1
10
$ 40
$ 39
$ 1
3

Dth sold:
Residential 835
727
108
15
% 6,866
5,958
908
15
%
Commercial 494
459
35
8
3,522
3,182
340
11

Industrial 244
216
28
13
1,255
1,080
175
16

Total retail 1,573
1,402
171
12
11,643
10,220
1,423
14

Average number of retail customers (in thousands) 164
162
2
1
% 164
161
3
2
%
Average revenue per retail Dth sold $ 8.59
$ 10.22
$ (1.63 ) (16 ) % $ 5.47
$ 7.68
$ (2.21 ) (29 ) %
Average cost of natural gas per retail Dth sold $ 2.53
$ 3.11
$ (0.58 ) (19 ) % $ 2.20
$ 4.09
$ (1.89 ) (46 ) %
Heating degree days 118
43
75
*
% 2,823
2,487
336
14
%
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 ~~gross~~utility marginincreased$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 $5$2 million, or 4%, for the ~~third~~second quarter of ~~2017~~2023 compared to ~~2016 due to:~~

~~$4 million higher customer usage primarily from the impacts of weather and~~

~~$3 million from customer usage patterns.~~

~~The increase in electric gross margin was partially offset by:~~

~~$2 million in decreased wholesale revenue due to lower volumes.~~

~~Other income (expense)~~ ~~is favorable $2 million, or 22%, for the third quarter of 2017 compared to 2016~~2022 primarily due to ~~lower interest on deferred charges.~~

~~Income tax expense~~ ~~increased $2 million, or 9%, for the third quarter of 2017 compared to 2016. The effective tax rate was 35% in 2017 and 37% in 2016.~~

~~Electric gross margin~~ ~~increased $10 million, or 3%, for the first nine months of 2017 compared to 2016 due to:~~

~~$8 million~~ higher ~~customer usage primarily from the impacts of weather;~~

~~$3 million from customer usage patterns and~~

~~$2 million in higher transmission revenue.~~

~~The increase in electric gross margin was partially offset by:~~

~~$4 million in decreased wholesale revenue due to lower volumes.~~

~~Operating~~plant operations and maintenance ~~decreased $5 million, or 4%, for the first nine months of 2017 compared to 2016 due to lower other operating costs,~~expenses and increased customer service operations expenses, partially offset by lower regulatory-approved recovery for the ON Line reallocation (offset in operating ~~and maintenance related regulatory credit amortizations.~~revenue).

Depreciation and amortization ~~decreased $3 million, or 3%, for the first nine months of 2017 compared to 2016 primarily due to regulatory amortizations.~~

~~Other income (expense)~~ is favorable $10 million, or 28%, for the first nine months of 2017 compared to 2016 due to a decrease in interest expense from lower rates on outstanding debt balances and lower interest on deferred charges.

~~Income tax expense~~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 ~~nine~~six months of ~~2017~~2023 compared to ~~2016. The~~2022 primarily due to:

•$28 million of higher retail rates due to the 2022 regulatory rate review with new rates effective ~~tax rate was 35%~~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 ~~2017~~the average number of customers and ~~36%~~

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 ~~2016.~~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 ~~September~~June 30, ~~2017,~~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

Cash and cash equivalents $ 30

Credit facility 250
Less:
Tax-exempt bond support (80 )
Net credit facility 170

Total net liquidity $ 200

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, were ~~$112~~$232 million and ~~$191~~$108 million, respectively. The change was primarily due to higher ~~payments for fuel costs,~~collections from customers, partially offset by ~~lower contributions~~higher payments related to fuel and energy costs and the ~~pension plan.~~timing of payments for operating costs.

In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). As a result of PATH, Sierra Pacific's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019 and investment tax credits (once the net operating loss is fully utilized) earned on qualifying projects through 2021.

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 ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, were ~~$(131)~~$(170) million and ~~$(137)~~$(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 ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022, were ~~$(6)~~$(74) million and ~~$(93)~~$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. ~~in 2017, partially offset by lower proceeds from issuance of long-term debt.~~

~~Ability to Issue Debt~~

155

Debt Authorizations

Sierra ~~Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2017, Sierra~~ Pacific currently has financing authority from the PUCN consisting of the ability to: (1) ~~issue additional long-term~~establish debt ~~securities~~issuances limited to a debt ceiling of ~~up to $350 million;~~$1.9 billion (excluding borrowings under Sierra Pacific's $400 million secured credit facility); and (2) ~~refinance up to $55 million of long-term debt securities; and (3)~~ maintain a revolving credit facility of up to $600 million. ~~Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of September 30, 2017.~~

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

~~Sierra Pacific 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, changes in environmental and other rules and regulations; impacts to ~~customers'~~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. ~~Expenditures for certain assets may ultimately include acquisition of existing assets.~~

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

Nine-Month Periods Annual
Ended September 30, Forecast
2016 2017 2017

Distribution $ 73
$ 61
$ 91
Transmission system investment 16
9
14
Other 48
61
80
Total $ 137
$ 131
$ 185

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 ~~investments that~~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 ~~operating projects that~~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 ~~distribution, generation~~ 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.

~~Contractual Obligations~~

156

Material Cash Requirements

As of ~~September~~June 30, ~~2017,~~2023, there have been no material changes outside the normal course of business in ~~contractual obligations~~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, ~~2016.~~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 ~~and water~~ quality, ~~RPS,~~climate change, emissions performance standards, ~~climate change,~~water quality, coal ~~combustion byproduct~~ash disposal ~~hazardous and solid waste disposal, protected species~~ and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations, ~~and capital expenditure requirements,~~ these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by ~~the EPA and~~ various federal, state and local agencies. ~~All such~~Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to ~~a range of~~ interpretation ~~which~~that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and ~~consolidated~~ financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of Sierra Pacific's forecasted environmental-related capital expenditures.

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.

~~New Accounting Pronouncements~~

~~For a discussion of new accounting pronouncements affecting Sierra Pacific, refer to Note 2 of Notes to Consolidated Financial Statements in Sierra Pacific's Part I, Item 1 of this Form 10-Q.~~

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, ~~2016.~~2022. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, ~~2016.~~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

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):


~~Item 3.~~Cash and cash equivalents	~~Quantitative and Qualitative Disclosures About Market Risk~~	$	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

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.

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(3) Regulatory Matters

(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

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(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 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.

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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
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	1,583	$	1,354	$	1,582	$	1,337

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(8) Commitments and Contingencies

Environmental 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

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

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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.

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 thefirst 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.

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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

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, ~~2016~~.2022. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, ~~2016~~.2022. Refer to Note ~~9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, Note 6~~7 of the Notes to Consolidated Financial Statements of PacifiCorp, ~~in Part I, Item 1~~Note 7 of ~~this Form 10-Q~~the Notes to Consolidated Financial Statements of Nevada Power and Note 7 of the Notes to Consolidated Financial Statements of ~~Nevada Power~~Sierra Pacific in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of ~~September~~June 30, ~~2017~~.2023.


~~Item 4.~~	~~Controls and Procedures~~

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, ~~and~~ Sierra Pacific Power Company, Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc. carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended ~~September~~June 30, ~~2017~~2023 that has materially affected, or is reasonably likely to materially affect, its internal control over financial ~~reporting.~~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~~

~~Not applicable.~~Item 1.Legal Proceedings


~~Item 1A.~~	~~Risk Factors~~

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.

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On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21CV33595, ("Salter"), in Multnomah County Circuit Court, Oregon, in which two complaints, Case No. 21CV09339 and Case No. 21CV09520, previously filed in Marion County Circuit Court, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages. In May 2022, the Salter case was consolidated with the James case (described above).

In October 2020, the case Amy Allen, et al. v. PacifiCorp, Case No. 20CV37430 ("Allen") was filed in Multnomah County Circuit Court, Oregon. The Allen case was filed by five individuals as amended in September 2021 claiming in excess of $32 million in economic and noneconomic damages related to the Beachie Creek fire, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest. In May 2022, the Allen case was consolidated with the James case (described above).

On August 26, 2022, a putative class action complaint seeking declaratory and equitable relief against PacifiCorp was filed, captioned Margaret Dietrich et al. v. PacifiCorp, Case No. 22CV29187 ("Dietrich"), in Multnomah County Circuit Court, Oregon. The complaint was filed by two Oregon residents individually and on behalf of a class initially defined to include residents of, business owners in, real or personal property owners in and any other individuals physically present in specified Oregon counties as of September 7, 2020 who experienced any harm, damage or loss as a result of the Santiam Canyon, Beachie Creek, Lionshead, Echo Mountain Complex, 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; Joneset al. v. PacifiCorp, No. 23CV02110; Price et al. v. PacifiCorp, No. 23CV02175; Minottet al. v. PacifiCorp, No. 23CV02203; Webbet al. v. PacifiCorp, No. 23CV02202; and Keithet al. v. PacifiCorp, No. 23CV02200. On January 24, 2023, three additional cases were filed captioned Kiddet al. v. PacifiCorp, No. 23CV03318; Parkeret al. v. PacifiCorp, No. 23CV03317; and Diazet al. v. PacifiCorp, No. 23CV03313.

These complaints were filed in Douglas County Circuit Court, Oregon with substantially similar allegations as those of Roseburg with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral ruling, the Douglas County Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues, along with the above-mentioned Roseburg; the precise scope of the trial will be determined in a later order. Collectively, these eighteen cases seek in excess of $1,300 million in damages, inclusive of the $573 million Roseburg case. On February 14, 2023, the Douglas County Circuit Court ordered that all plaintiffs' claims for inverse condemnation be dismissed; a written order is forthcoming.

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 Sparkset al. v. PacifiCorp, Case No. 21CV48022 ("Sparks")and Russieet al. v. PacifiCorp, Case No. 22CV15840 ("Russie") into Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen"). The Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson complaints each allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; and (v) inverse condemnation. The Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson complaints each seek the following damages: (i) economic and property related damages of $83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of earnings capacity, evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and (vii) pre-judgment interest. The plaintiffs for each Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages. The Hunter complaint seeks $50 million in damages and alleges claims for: (i) negligence, (ii) trespass, (iii), nuisance, (iv) inverse condemnation, and (v) wrongful death. The Andersen case was filed by 50 individuals as amended in August 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest. The Sparks case was filed by 17 individuals in December 2021 claiming $125 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- judgment interest. The Russie case was filed by 45 individuals as amended in September 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest.

Judith O'Keefe v. PacifiCorp and Consolidated Cases

On September 1, 2022, a complaint against PacifiCorp was filed, captioned Aaron Macy-Wyngarden et al. v. PacifiCorp, Case No. 22CV29684, in Multnomah County Circuit Court, Oregon ("Macy-Wyngarden"). The complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.

On September 22, 2022, a complaint against PacifiCorp was filed, captioned Zachary Bogle et al. v. PacifiCorp, Case No. 22CV29717, in Multnomah County Circuit Court, Oregon ("Bogle"). The complaint was filed by Oregon residents who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.

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, ~~2016~~.2022.


~~Item 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.


~~Item 3.~~	~~Defaults Upon Senior Securities~~

Item 3.Defaults Upon Senior Securities

Not applicable.


~~Item 4.~~	~~Mine Safety Disclosures~~

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~~

Item 5.Other Information

Not applicable.


~~Item 6.~~	~~Exhibits~~

Item 6.Exhibits

The following is a list of exhibits ~~listed on the accompanying Exhibit Index are~~ filed as part of this Quarterly Report.

~~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.~~

200



Exhibit No.		~~BERKSHIRE HATHAWAY ENERGY COMPANY~~

~~Date: November 3, 2017~~	~~/s/ Patrick J. Goodman~~
	~~Patrick J. Goodman~~
	~~Executive Vice President and Chief Financial Officer~~
	~~(principal financial and accounting officer)~~

	~~PACIFICORP~~

~~Date: November 3, 2017~~	~~/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: November 3, 2017~~	~~/s/ Thomas B. Specketer~~
	~~Thomas B. Specketer~~
	~~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: November 3, 2017~~	~~/s/ E. Kevin Bethel~~
	~~E. Kevin Bethel~~
	~~Senior Vice President and Chief Financial Officer~~
	~~(principal financial and accounting officer)~~

	~~SIERRA PACIFIC POWER COMPANY~~

~~Date: November 3, 2017~~	~~/s/ E. Kevin Bethel~~
	~~E. Kevin Bethel~~
	~~Senior Vice President and Chief Financial Officer~~
	~~(principal financial and accounting officer)~~Description

~~EXHIBIT INDEX~~


~~Exhibit No.~~	~~Description~~

BERKSHIRE HATHAWAY ENERGY


10.1			~~$1,000,000,000~~First Amendment to the $3,500,000,000 Third Amended and Restated Credit Agreement, dated as of ~~May 11, 2017,~~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~~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 ~~Tokyo-Mitsubishi UFJ, LTD.,~~Canada, as ~~Administrative Agent~~administrative agent, and Lenders (incorporated by reference to Exhibit 10.1 to t he Berkshire Hathawa y Energy Co mpany 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 ~~June 30, 2017)~~March 31, 2023).


~~15.1~~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~~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-Four th 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 1 7 , 2023).

~~10.2~~10.5			~~$600,000,000~~First Amendment to the $2,000,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, ~~2017,~~2023, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, ~~JPMorgan~~JP Morgan Chase Bank, N.A., as Administrative Agent and the LC Issuing ~~Banks (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).~~Banks.


95			Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

~~MIDAMERICAN ENERGY~~

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.

~~BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY~~

~~10.3~~

$900,000,000 Credit Agreement, dated as of June 30, 2017, 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 (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

~~Exhibit No.Description~~

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.

~~NEVADA POWER~~

BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN ENERGY AND MIDAMERICAN FUNDING


~~15.4~~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


~~4.1~~10.7			Financing Agreement dated May 1, 2017 between Clark County, Nevada and Nevada Power Company (relating to Clark County, Nevada's $39,500,000 Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2017) (incorporated by reference to Exhibit 4.1First Amendment to the ~~Nevada Power Company Current Report on Form 8-K dated May 25, 2017).~~$

~~4.2~~

Financing Agreement dated May 1, 2017 between the Coconino County, Arizona Pollution Control Corporation and Nevada Power Company (relating to the Coconino County, Arizona Pollution Control Corporation's $53,000,000 Pollution Control Refunding Revenue Bonds (Nevada Power Company Projects) Series 2017A and 2017B) (incorporated by reference to Exhibit 4.2 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).6


~~4.3~~	Officer’s Certificate establishing the terms of Nevada Power Company’s General and Refunding Mortgage Notes, Series AA (Nos. AA-1 and AA-2) (incorporated by reference to Exhibit 4.3 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).


~~10.4~~	~~$400,000,000 Second~~00,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, ~~2017,~~202 3 , 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 ~~(incorporated by reference to Exhibit 10.4 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017)~~.

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


~~10.5~~10.8			First Amendment to the $~~250,000,000 Second~~40 0,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, ~~2017,~~202 3 , 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 ~~(incorporated~~.

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, LL C (incorporated by reference to Exhibit ~~10.5~~10.4 to the ~~Berkshire Hathaway~~Eastern Energy ~~Company~~ Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended ~~June 30, 2017)~~March 31, 2023 ).

~~Exhibit No.Description~~

~~ALL REGISTRANTS~~


~~101~~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 ~~September~~June 30, ~~2017~~,2023, is formatted in ~~XBRL (eXtensible~~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.

~~156~~

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


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



Registrant	Yes	No
BERKSHIRE HATHAWAY ENERGY COMPANY	X☒
PACIFICORP	X☒
MIDAMERICAN FUNDING, LLC		X☒
MIDAMERICAN ENERGY COMPANY	X☒
NEVADA POWER COMPANY	X☒
SIERRA PACIFIC POWER COMPANY	X☒
EASTERN ENERGY GAS HOLDINGS, LLC	☒
EASTERN GAS TRANSMISSION AND STORAGE, INC.	☒



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	~~151~~194
Item 4.	Controls and Procedures	~~151~~194



Item 1.		Legal Proceedings	~~152~~195
Item 1A.		Risk Factors	~~152~~199
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds	~~152~~199
Item 3.		Defaults Upon Senior Securities	~~152~~199
Item 4.		Mine Safety Disclosures	~~152~~199
Item 5.		Other Information	~~152~~200
Item 6.		Exhibits	~~152~~200
Signatures			~~153~~204
~~Exhibit Index~~	~~154~~



	As of
	September 30,		December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	1,142	$	721
Trade receivables, net	1,994		1,751
Inventories	887		925
Mortgage loans held for sale	534		359
Other current assets	1,095		917
Total current assets	5,652		4,673

Property, plant and equipment, net	64,979		62,509
Goodwill	9,700		9,010
Regulatory assets	4,582		4,307
Investments and restricted cash and investments	4,987		3,945
Other assets	1,154		996

Total assets	$	91,054	$	85,440



As of December 31, 2016
Assets:
Commodity derivatives	$	5		$	49		$	87		$	(22	)	$	119
Interest rate derivatives	—			16			7			—			23
Mortgage loans held for sale	—			359			—			—			359
Money market mutual funds⁽²⁾	586			—			—			—			586
Debt securities:
United States government obligations	161			—			—			—			161
International government obligations	—			3			—			—			3
Corporate obligations	—			36			—			—			36
Municipal obligations	—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			2			—			—			2
Equity securities:
United States companies	250			—			—			—			250
International companies	1,190			—			—			—			1,190
Investment funds	147			—			—			—			147
	$	2,339		$	467		$	94		$	(22	)	$	2,878
Liabilities:
Commodity derivatives	$	(2	)	$	(199	)	$	(27	)	$	96		$	(132	)
Interest rate derivatives	(1		)	(11		)	(1		)	—			(13		)
	$	(3	)	$	(210	)	$	(28	)	$	96		$	(145	)


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



Operating revenue by country:
United States	$	4,869	$	4,697	$	12,793	$	12,185
United Kingdom	221		220		685		748
Canada	182		170		506		313
Philippines and other	11		5		19		8
Total operating revenue by country	$	5,283	$	5,092	$	14,003	$	13,254



Income before income tax expense and equity income by country:
United States	$	1,113	$	1,089	$	2,065	$	1,945
United Kingdom	49		74		213		284
Canada	47		43		127		114
Philippines and other	23		4		62		42
Total income before income tax expense and equity income by country	$	1,232	$	1,210	$	2,467	$	2,385


~~(1)~~	The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.



	Third Quarter											First Nine Months
	2017			2016			Change					2017			2016			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	263		$	254		$	9		4	%	$	618		$	596		$	22		4	%
MidAmerican Funding	383			318			65			20		616			518			98			19
NV Energy	223			222			1			—		347			319			28			9
Northern Powergrid	39			60			(21		)	(35	)	174			228			(54		)	(24	)
BHE Pipeline Group	35			36			(1		)	(3	)	183			175			8			5
BHE Transmission	58			57			1			2		171			173			(2		)	(1	)
BHE Renewables	89			98			(9		)	(9	)	194			142			52			37
HomeServices	45			49			(4		)	(8	)	107			105			2			2
BHE and Other	(67		)	(58		)	(9		)	(16	)	(212		)	(194		)	(18		)	(9	)
Total net income attributable to BHE shareholders	$	1,068		$	1,036		$	32		3		$	2,198		$	2,062		$	136		7


															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



Capital expenditures by type:
Wind generation	$	1,110	$	804	$	1,292
Solar generation	15		95		125
Electric transmission	339		267		330
Environmental	52		56		111
Other growth	302		400		560
Operating	1,703		1,557		2,449
Total	$	3,521	$	3,179	$	4,867





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)~~	PacifiCorp's commodity derivatives are generally included in rates and as of September 30, 2017 and December 31, 2016, a regulatory asset of $97 million and $73 million, respectively, was recorded related to the net derivative liability of $100 million and $77 million, respectively.



	Common Stock		Retained Earnings			Accumulated Other Comprehensive Loss, Net			Total Equity

Balance, December 31, 2015	$	561	$	4,174		$	(30	)	$	4,705
Net income	—		527			—			527
Other comprehensive income	—		—			2			2
Dividend	—		(117		)	27			(90		)
Other equity transactions	—		(1		)	—			(1		)
Balance, September 30, 2016	$	561	$	4,583		$	(1	)	$	5,143

Balance, December 31, 2016	$	561	$	4,599		$	—		$	5,160
Net income	—		624			—			624
Balance, September 30, 2017	$	561	$	5,223		$	—		$	5,784



	As of
	September 30, 2017		December 31, 2016
Assets:
Regulated electric	$	15,556	$	14,113
Regulated gas	1,339		1,345
Other	7		1
Total assets	$	16,902	$	15,459