If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the ~~registrant is~~registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).


Item 1.			Legal Proceedings		164
Item 1A.			~~PART II. Other Information~~Risk Factors		~~108~~ 164

~~Item 1.~~	~~Legal Proceedings~~	~~108~~
~~Item 1A.~~	~~Risk Factors~~	~~108~~
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds			~~109~~ 164
Item 6. 3.			~~Exhibits~~Defaults Upon Senior Securities		~~110~~ 164
Item 4.			Mine Safety Disclosures

~~GLOSSARY OF TERMS~~

~~The following abbreviations or acronyms used in this Form 10-Q are defined below:~~

~~Abbreviation or Acronym~~	~~Definition~~
~~2019 Equity Units~~ Item 5.		Other Information	Dominion Energy’s 2019 Series A Equity Units issued in June 2019, initially in the form of 2019 Series A Corporate Units, consisting of a stock purchase contract and a 1/10 interest in a share of the Series A Preferred Stock 165
~~2017 Tax Reform Act~~ Item 6.		Exhibits	An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017 165
~~ACE Rule~~ Signatures			~~Affordable Clean Energy Rule~~
~~AFUDC~~	~~Allowance for funds used during construction~~
~~AMI~~	~~Advanced Metering Infrastructure~~
~~AOCI~~	~~Accumulated other comprehensive income (loss)~~
~~ARO~~	~~Asset retirement obligation~~
~~Atlantic Coast Pipeline~~	~~Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy and Duke~~
~~Atlantic Coast Pipeline Project~~	~~The approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which will be owned by Dominion Energy and Duke to be constructed and operated by DETI~~
~~BACT~~	~~Best available control technology~~
~~bcf~~	~~Billion cubic feet~~
~~Blue Racer~~	~~Blue Racer Midstream, LLC, a joint venture between Caiman Energy II, LLC and FR BR Holdings, LLC~~
~~Brookfield~~	~~Brookfield Super-Core Infrastructure Partners, an infrastructure fund managed by Brookfield Asset Management Inc.~~
~~CAA~~	~~Clean Air Act~~
~~CARES Act~~	~~Coronavirus Aid, Relief and Economic Security Act, enacted on March 27, 2020~~
~~CCR~~	~~Coal combustion residual~~
~~CEO~~	~~Chief Executive Officer~~
~~CEP~~	~~Capital Expenditure Program, as established by House Bill 95, Ohio legislation enacted in 2011, deployed by East Ohio to recover certain costs associated with capital investment~~
~~CERCLA~~	~~Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund~~
~~CFO~~	~~Chief Financial Officer~~
CO₂	~~Carbon dioxide~~
~~Colonial Trail West~~	~~A 142 MW utility-scale solar power station located in Surry County, Virginia~~
~~Companies~~	~~Dominion Energy, Virginia Power and Dominion Energy Gas, collectively~~
~~Contracted Generation~~	~~Contracted Generation operating segment~~
~~Cooling degree days~~	Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, or 75 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 75 degrees, as applicable, and the average temperature for that day
~~Cove Point~~	~~Dominion Energy Cove Point LNG, LP~~
~~Cove Point LNG Facility~~	~~An LNG import/export and storage facility, including the Liquefaction Facility, located on the Chesapeake Bay in Lusby, Maryland~~
~~CPCN~~	~~Certificate of Public Convenience and Necessity~~ 168

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.

~~CWA~~		~~Clean Water Act~~
~~DCP~~ Berkshire Hathaway Energy Company and Related Entities
BHE				~~The legal entity, Dominion Cove Point, LLC, one or more of its consolidated subsidiaries,~~Berkshire Hathaway Energy Company
Berkshire Hathaway				Berkshire Hathaway Inc.
Berkshire Hathaway Energy or the ~~entirety of Dominion Cove Point,~~Company				Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp				PacifiCorp and its subsidiaries
MidAmerican Funding				MidAmerican Funding, LLC and its ~~consolidated~~ subsidiaries
~~DECG~~ MidAmerican Energy				~~Dominion~~MidAmerican Energy ~~Carolina Gas Transmission, Inc.~~ Company
~~DECGS~~ NV Energy				~~Dominion Energy Carolina Gas Services, Inc.~~
~~DEQPS~~		~~Dominion Energy Questar Pipeline Services, Inc.~~
~~DES~~		~~Dominion Energy Services, Inc.~~
~~DESC~~		The legal entity, Dominion Energy South Carolina, Inc., one or more of its consolidated entities or operating segment, or the entirety of Dominion Energy South Carolina, Inc. and its consolidated entities
~~DETI~~		~~Dominion Energy Transmission, Inc.~~
~~DGI~~		~~Dominion Generation, Inc.~~
~~DGP~~		~~Dominion Gathering and Processing, Inc.~~
~~DMLPHCII~~		~~Dominion MLP Holding Company II, LLC~~
~~DOE~~		~~U.S. Department of Energy~~
~~Dominion Energy~~		~~The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Energy Gas) or operating segments, or the entirety of Dominion~~NV Energy, Inc. and its ~~consolidated~~ subsidiaries
~~Dominion~~Nevada Power				Nevada Power Company and its subsidiaries
Sierra Pacific				Sierra Pacific Power Company and its subsidiaries
Nevada Utilities				Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Eastern Energy Gas				~~The legal entity, Dominion Energy Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion~~Eastern Energy Gas Holdings, LLC and its ~~consolidated~~ subsidiaries
~~Dominion~~Registrants				Berkshire Hathaway Energy Company, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries and Eastern Energy Gas ~~Restructuring~~ Holdings, LLC and its subsidiaries
Northern Powergrid				Northern Powergrid Holdings Company
BHE Pipeline Group				BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE GT&S				BHE GT&S, LLC
Northern Natural Gas				Northern Natural Gas Company
Kern River				Kern River Gas Transmission Company
BHE Transmission				BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada				BHE Canada Holdings Corporation
AltaLink				AltaLink, L.P.
BHE U.S. Transmission				BHE U.S. Transmission, LLC
BHE Renewables				BHE Renewables, LLC and CalEnergy Philippines
HomeServices				HomeServices of America, Inc. and its subsidiaries
Utilities				PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Domestic Regulated Businesses				PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
GT&S Transaction				The acquisition of ~~DCP~~substantially all of the natural gas transmission and ~~DMLPHCII from, and the disposition of East Ohio and DGP to, Dominion~~
	~~Energy by Dominion Energy Gas on November 6, 2019~~
~~Dominion Energy Midstream~~		~~The legal entity, Dominion Energy Midstream Partners, LP, one or more of its consolidated subsidiaries, or the entirety~~storage business of Dominion Energy ~~Midstream Partners, LP~~ and ~~its consolidated subsidiaries~~ Dominion Questar, exclusive of the Questar Pipeline Group on November 1, 2020
DEI				Dominion Energy, ~~Questar Pipeline~~ Inc.
			~~The legal entity, Dominion Energy~~ Questar Pipeline ~~LLC, one or more of its consolidated subsidiaries, o~~Group		~~r the entirety of~~ Dominion Energy Questar Pipeline, LLC and ~~its consolidated subsidiaries~~related entities
~~Dominion Energy South Carolina~~				~~Dominion Energy South Carolina operating segment~~
~~Dominion Energy Virginia~~				~~Dominion Energy Virginia operating segment~~
~~DSM~~				~~Demand-side management~~
~~Dth~~				~~Dekatherm~~
~~Duke~~				~~The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries, or the entirety of Duke Energy Corporation and its consolidated subsidiaries~~
~~East Ohio~~				~~The East Ohio Gas Company, doing business as Dominion Energy Ohio~~
~~EPA~~				~~U.S.~~


Certain Industry Terms
2017 Tax Reform		The Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018


AFUDC		Allowance for Funds Used During Construction
AUC		Alberta Utilities Commission
BART		Best Available Retrofit Technology

COVID-19		Coronavirus Disease 2019

CSAPR		Cross-State Air Pollution Rule
D.C. Circuit		United States Court of Appeals for the District of Columbia Circuit
DEAA		Deferred Energy Accounting Adjustment
Dth		Decatherm
EBA		Energy Balancing Account
ECAM		Energy Cost Adjustment Mechanism
EPA		United States Environmental Protection Agency
~~EPS~~ FERC		~~Earnings per share~~
~~Export Customers~~	~~ST Cove Point, LLC, a joint venture of Sumitomo Corporation and Tokyo Gas Co., LTD., and GAIL Global (USA) LNG, LLC~~
~~FERC~~	Federal Energy Regulatory Commission
~~FILOT~~		~~Fee in lieu of taxes~~

~~Four Brothers~~	~~Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy and Four Brothers Holdings, LLC, a subsidiary of GIP~~
~~FTRs~~ GAAP		~~Financial transmission rights~~ Accounting principles generally accepted in the United States of America
~~GAAP~~ GEMA		~~U.S. generally accepted accounting principles~~ Gas and Electricity Markets Authority
~~Gal~~ GHG		~~Gallon~~ Greenhouse Gases
~~Gas Distribution~~ GWh		~~Gas Distribution operating segment~~ Gigawatt Hour
~~Gas Transmission & Storage~~ GTA		~~Gas Transmission & Storage operating segment~~ General Tariff Application
~~GENCO~~ IPUC		~~South Carolina Generating Company, Inc.~~ Idaho Public Utilities Commission
~~GHG~~ ICC		~~Greenhouse gas~~ Illinois Commerce Commission
~~GIP~~ IRP		~~The legal entity, Global Infrastructure Partners, one or more of its consolidated subsidiaries, or the entirety of Global Infrastructure Partners and its consolidated subsidiaries~~ Integrated Resource Plan
~~Granite Mountain~~ IUB		~~Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy and Granite Mountain Renewables, LLC, a subsidiary of GIP~~ Iowa Utilities Board
~~GTSA~~ kV		~~Virginia Grid Transformation and Security Act of 2018~~ Kilovolt
GW KHSA		~~Gigawatt~~ Klamath Hydroelectric Settlement Agreement
~~Heating degree days~~		Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, or 60 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 60 degrees, as applicable, and the average temperature for that day
~~Hope~~ MW		~~Hope Gas, Inc., doing business as Dominion Energy West Virginia~~ Megawatt
~~Iron Springs~~ MWh		~~Iron Springs Holdings, LLC, a limited liability company owned by Dominion Energy and Iron Springs Renewables, LLC, a subsidiary of GIP~~ Megawatt Hour
~~Iroquois~~ NAAQS		~~Iroquois Gas Transmission System, L.P.~~ National Ambient Air Quality Standards
~~ISO~~ NOx		~~Independent system operator~~ Nitrogen Oxides
~~Jones Act~~		~~The Coastwise Merchandise Statute (commonly known as the Jones Act) 46 U.S.C. 55102 regulating U.S. maritime commerce~~
~~June 2006 hybrids~~ Ofgem		~~Dominion Energy’s 2006 Series A Enhanced Junior Subordinated Notes due 2066~~ Office of Gas and Electric Markets
~~Kewaunee~~ OPUC		~~Kewaunee nuclear power station~~ Oregon Public Utility Commission
~~Liquefaction Facility~~ PTC		~~A natural gas export/liquefaction facility at the Cove Point LNG Facility~~ Production Tax Credit
~~LNG~~ PUCN		~~Liquefied natural gas~~
~~MATS~~	~~Utility Mercury and Air Toxics Standard Rule~~
~~MD&A~~	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~
~~MGD~~	~~Million gallons a day~~
~~Millstone~~	~~Millstone nuclear power station~~
~~Millstone 2019 power purchase agreements~~	~~Power purchase agreements with Eversource Energy and The United Illuminating Company for Millstone to provide nine million MWh per year of electricity for ten years~~
MW	~~Megawatt~~
~~MWh~~	~~Megawatt hour~~
~~NAV~~	~~Net asset value~~
~~NGL~~	~~Natural gas liquid~~
~~NND Project~~	V.C. Summer Units 2 and 3 nuclear development project under which DESC and Santee Cooper undertook to construct two Westinghouse AP1000 Advanced Passive Safety nuclear units in Jenkinsville, South Carolina

~~North Carolina Commission~~	~~North Carolina Utilities Commission~~
~~NRC~~	~~U.S. Nuclear Regulatory Commission~~
~~NSPS~~	~~New Source Performance Standards~~
~~NWP 12~~	A nationwide permit from the Army Corp of Engineers authorizing activities required for the construction, maintenance, repair and removal of utility lines, including electric transmission, gas pipelines, water and communications conduit and associated facilities in waters of the U.S.
~~NYSE~~	~~New York Stock Exchange~~
~~Ohio Commission~~	Public Utilities Commission of ~~Ohio~~ Nevada
~~Order 1000~~ RAC		~~Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development~~ Renewable Adjustment Clause
~~PIR~~ REC		~~Pipeline Infrastructure Replacement program deployed by East Ohio~~ Renewable Energy Credit
~~PJM~~ RFP		~~PJM Interconnection, L.L.C.~~ Request for Proposal
~~Predecessor~~ RPS		~~Dominion Energy as the predecessor for accounting purposes for the period of Dominion Energy’s ownership of DCP and DMLPHCII until the completion of the Dominion Energy Gas Restructuring~~ Renewable Portfolio Standards
~~PSD~~ RRA		~~Prevention of significant deterioration~~ Renewable Energy Credit and Sulfur DioxideRevenue Adjustment Mechanism
~~PSNC~~ SCR		~~Public Service Company of North Carolina, Incorporated, doing business as Dominion Energy North Carolina~~ Selective Catalytic Reduction
~~Questar Gas~~ SEC		~~Questar Gas Company, doing business as Dominion Energy Utah, Dominion Energy Wyoming and Dominion Energy Idaho~~
~~RCC~~	~~Replacement Capital Covenant~~
~~RGGI~~	~~Regional Greenhouse Gas Initiative~~
~~RICO~~	~~Racketeer Influenced and Corrupt Organizations Act~~
~~Rider US-3~~	~~A rate adjustment clause associated with the recovery of costs related to Colonial Trail West and Spring Grove 1~~
~~Rider US-4~~	~~A rate adjustment clause associated with the recovery of costs related to Sadler Solar~~
~~ROE~~	~~Return on equity~~
~~RTO~~	~~Regional transmission organization~~
~~Sadler Solar~~	~~An approximately 100 MW proposed utility-scale solar power station located in Greensville County, Virginia~~
~~Santee Cooper~~	~~South Carolina Public Service Authority~~
~~SBL Holdco~~	~~SBL Holdco, LLC, a wholly-owned subsidiary of DGI~~
~~SCANA~~	~~The legal entity, SCANA Corporation, one or more of its consolidated subsidiaries, or the entirety of SCANA Corporation and its consolidated subsidiaries~~
~~SCANA Combination~~	~~Dominion Energy’s acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA~~
~~SCANA Merger Approval Order~~	~~Final order issued by the South Carolina Commission on December 21, 2018 setting forth its approval of the SCANA Combination~~
~~SCDHEC~~	~~South Carolina Department of Health and Environmental Control~~
~~SCDOR~~	~~South Carolina Department of Revenue~~
~~SEC~~	~~U.S.~~United States Securities and Exchange Commission
~~SEMI~~ SIP		~~SCANA Energy Marketing, LLC (formerly known as SCANA Energy Marketing, Inc.), a subsidiary of SCANA through December 2019, and effective December 2019, a subsidiary of Wrangler~~ State Implementation Plan
~~September 2006 hybrids~~ SO2		~~Dominion Energy’s 2006 Series B Enhanced Junior Subordinated Notes due 2066~~ 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 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, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism, pandemics (including potentially in relation to COVID-19), embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;

•the ability to economically obtain insurance coverage, or any insurance coverage at all, sufficient to cover losses arising from catastrophic events, such as wildfires where the Registrants may be found liable for property damages regardless of fault;

•a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;

•changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;

•the financial condition, creditworthiness and operational stability of the respective Registrant's significant customers and suppliers;

•changes in business strategy or development plans;

•availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates;

•changes in the respective Registrant's credit ratings;

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

•hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;

•the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;

•the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;

•fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;

•increases in employee healthcare costs;

•the impact of investment performance, certain participant elections such as lump sum distributions and changes in interest rates, legislation, healthcare cost trends, mortality, morbidity on pension and other postretirement benefits expense and funding requirements;

•changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and franchising transactions;

•the ability to successfully integrate the portion of the natural gas transmission and storage business acquired from DEI on November 1, 2020, and future acquired operations into a Registrant's business;

•the expected timing and likelihood of completion of the proposed transaction to acquire the remaining portion of DEI's natural gas transmission and storage business, including the ability to obtain the required clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;

•unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;

•the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;

•the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and

•other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the SEC, including Part II, Item 1A and other discussions contained in this Form 10-Q. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.

Item 1.Financial Statements

~~Series A Preferred Stock~~	~~Dominion Energy’s 1.75% Series A Cumulative Perpetual Convertible Preferred Stock, without par value, with a liquidation preference of $1,000 per share~~
~~Series B Preferred Stock~~		~~Dominion Energy’s 4.65% Series B Fixed-Rate Cumulative Redeemable Perpetual Preferred Stock, without par value, with a liquidation preference of $1,000 per share~~
~~South Carolina Commission~~	~~Public Service Commission of South Carolina~~
~~Southern~~	~~The legal entity, The Southern Company, one or more of its consolidated subsidiaries, or the entirety of The Southern~~Berkshire Hathaway Energy Company and its ~~consolidated~~ subsidiaries
~~Spring Grove 1~~ Report of Independent Registered Public Accounting Firm			~~An approximately 98 MW proposed utility-scale solar power station located in Surry County, Virginia~~ 4
~~Standard & Poor’s~~ Consolidated Balance Sheets			~~Standard & Poor’s Ratings Services, a division of S&P Global Inc.~~ 5
~~Surry~~ Consolidated Statements of Operations			~~Surry nuclear power station~~ 7
~~Terra Nova Renewable Partners~~ Consolidated Statements of Comprehensive Income			~~A partnership comprised primarily of institutional investors advised by J.P. Morgan Asset Management-Global Real Assets~~ 8
~~Three Cedars~~ Consolidated Statements of Changes in Equity			~~Granite Mountain and Iron Springs, collectively~~ 9
~~Utah Commission~~ Consolidated Statements of Cash Flows			~~Utah Public Service Commission~~ 10
~~VCEA~~ Notes to Consolidated Financial Statements			~~Virginia Clean Economy Act, passed by the Virginia General Assembly in March 2020 and enacted on April~~ 11 ~~2020~~
~~VDEQ~~ PacifiCorp and its subsidiaries			~~Virginia Department of Environmental Quality~~
~~VEBA~~ Report of Independent Registered Public Accounting Firm			~~Voluntary Employees' Beneficiary Association~~ 48
~~VIE~~ Consolidated Balance Sheets			~~Variable interest entity~~ 49
~~Virginia Commission~~ Consolidated Statements of Operations			~~Virginia State Corporation Commission~~ 51
~~Virginia Power~~ Consolidated Statements of Changes in Shareholders' Equity			~~The legal entity, Virginia Electric~~ 52
Consolidated Statements of Cash Flows			53
Notes to Consolidated Financial Statements			54
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm			71
Balance Sheets			72
Statements of Operations			74
Statements of Changes in Shareholder's Equity			75
Statements of Cash Flows			76
Notes to Financial Statements			77
MidAmerican Funding, LLC and ~~Power Company, one or more~~its subsidiaries
Report of ~~its consolidated subsidiaries or operating segment, or the entirety~~Independent Registered Public Accounting Firm			85
Consolidated Balance Sheets			86
Consolidated Statements of ~~Virginia Electric and~~Operations			88
Consolidated Statements of Changes in Member's Equity			89
Consolidated Statements of Cash Flows			90
Notes to Consolidated Financial Statements			91
Nevada Power Company and its ~~consolidated~~ subsidiaries
~~VOC~~ Report of Independent Registered Public Accounting Firm			~~Volatile organic compounds~~ 106
~~WECTEC~~ Consolidated Balance Sheets			~~WECTEC Global Project Services, Inc., a wholly-owned subsidiary of Westinghouse~~ 107
~~Westinghouse~~ Consolidated Statements of Operations			~~Westinghouse Electric Company LLC~~ 108
~~Wexpro~~ Consolidated Statements of Changes in Shareholder's Equity			~~The legal entity, Wexpro Company, one or more~~ 109
Consolidated Statements of ~~its consolidated subsidiaries, or the entirety of Wexpro~~Cash Flows			110
Notes to Consolidated Financial Statements			111
Sierra Pacific Power Company and its ~~consolidated~~ subsidiaries
~~White River Hub~~ Report of Independent Registered Public Accounting Firm			~~White River Hub, LLC~~ 122
~~Wrangler~~ Consolidated Balance Sheets			~~Wrangler Retail~~ 123
Consolidated Statements of Operations			124
Consolidated Statements of Changes in Shareholder's Equity			125
Consolidated Statements of Cash Flows			126
Notes to Financial Statements			127
Eastern Energy Gas Holdings, LLC ~~a partnership between Dominion Energy~~ and ~~Interstate Gas Supply, Inc.~~ its subsidiaries
~~Wyoming Commission~~ Report of Independent Registered Public Accounting Firm			~~Wyoming Public Service Commission~~ 141
Consolidated Balance Sheets			142
Consolidated Statements of Operations			144
Consolidated Statements of Comprehensive Income			145
Consolidated Statements of Changes in Equity			146
Consolidated Statements of Cash Flows			147
Notes to Consolidated Financial Statements			148

~~PART I. FINANCIAL INFORMATION~~

~~ITEM 1. FINANCIAL STATEMENTS~~

~~DOMINION ENERGY, INC.~~

~~CONSOLIDATED STATEMENTS OF INCOME~~

~~(Unaudited)~~

Three Months Ended March 31,

2020

2019

(millions, except per share amounts)

Operating Revenue⁽¹⁾

$
4,496

$
3,858

Operating Expenses

Electric fuel and other energy-related purchases

668

791

Purchased electric capacity

2

39

Purchased gas

427

730

Other operations and maintenance

1,043

1,002

Depreciation, depletion and amortization

673

651

Other taxes

284

292

Impairment of assets and other charges

768

835

Total operating expenses

3,865

4,340

Income (loss) from operations

631

(482
)
Other income (expense)

(399
)

388

Interest and related charges

490

469

Loss from operations including noncontrolling interests
before income tax expense (benefit)

(258
)

(563
)
Income tax expense (benefit)

(19
)

114

Net Loss Including Noncontrolling Interests

(239
)

(677
)
Noncontrolling Interests

31

3

Net Loss Attributable to Dominion Energy

$
(270
)

$
(680
)
Earnings Per Common Share

Net loss attributable to Dominion Energy - Basic

$
(0.34
)

$
(0.86
)
Net loss attributable to Dominion Energy - Diluted

(0.34
)

(0.86
)

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

~~(1)~~	~~See Note 10 for amounts attributable to related parties.~~
Berkshire Hathaway Energy Company and its subsidiaries		29
PacifiCorp and its subsidiaries		63
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		95
Nevada Power Company and its subsidiaries		116
Sierra Pacific Power Company and its subsidiaries		133
Eastern Energy Gas Holdings, LLC and its subsidiaries		159

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of March 31, 2021, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the three-month periods ended March 31, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2020, 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 26, 2021, 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, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

April 30, 2021

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	March 31,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	1,276	$	1,290
Restricted cash and cash equivalents	117		140
Trade receivables, net	2,416		2,107

Inventories	1,110		1,168
Mortgage loans held for sale	2,065		2,001

Other current assets	3,236		2,741
Total current assets	10,220		9,447

Property, plant and equipment, net	86,757		86,128
Goodwill	11,534		11,506
Regulatory assets	3,221		3,157
Investments and restricted cash and cash equivalents and investments	13,010		14,320
Other assets	2,780		2,758

Total assets	$	127,522	$	127,316

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED ~~STATEMENTS OF COMPREHENSIVE INCOME~~

BALANCE SHEETS (Unaudited)

Three Months Ended March 31,

2020

2019

(millions)

Net loss including noncontrolling interests

$
(239
)

$
(677
)
Other comprehensive income (loss), net of taxes:

Net deferred losses on derivatives-hedging activities⁽¹⁾

(266
)

(24
)
Changes in unrealized net gains on investment
securities⁽²⁾

9

16

Amounts reclassified to net income (loss):

Net derivative (gains) losses-hedging activities⁽³⁾

22

(31
)
Net realized (gains) losses on investment securities⁽⁴⁾

(9
)

—

Net pension and other postretirement benefit costs⁽⁵⁾

19

8

Total other comprehensive loss

(225
)

(31
)
Comprehensive loss including noncontrolling interests

(464
)

(708
)
Comprehensive income attributable to noncontrolling interests

31

3

Comprehensive loss attributable to Dominion Energy

$
(495
)

$
(711
)

~~(1)~~

~~Net of $93million and $5 million tax for the three months ended March 31, 2020 and 2019, respectively.~~

(continued)

~~(2)~~

~~Net of $(4) million and $(6) million tax for the three months ended March 31, 2020 and 2019, respectively.~~

(Amounts in millions)

~~(3)~~

~~Net of $(7) million and $10 million tax for the three months ended March 31, 2020 and 2019, respectively.~~

~~(4)~~

~~Net of $4 million and $— million tax for the three months ended March 31, 2020 and 2019, respectively.~~


	As of
	March 31,		December 31,
	2021		2020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,548	$	1,867
Accrued interest	642		555
Accrued property, income and other taxes	515		582
Accrued employee expenses	412		383
Short-term debt	2,699		2,286
Current portion of long-term debt	2,011		1,839
Other current liabilities	1,948		1,626
Total current liabilities	9,775		9,138

BHE senior debt	12,999		12,997
BHE junior subordinated debentures	100		100
Subsidiary debt	34,351		34,930
Regulatory liabilities	7,355		7,221
Deferred income taxes	11,630		11,775
Other long-term liabilities	4,261		4,178
Total liabilities	80,471		80,339

Commitments and contingencies (Note 9)			0

Equity:
BHE shareholders' equity:
Preferred stock - 100 shares authorized, $0.01 par value, 4 shares issued and outstanding	3,750		3,750
Common stock - 115 shares authorized, 0 par value, 76 shares issued and outstanding	0		0
Additional paid-in capital	6,377		6,377
Long-term income tax receivable	(658)		(658)
Retained earnings	35,060		35,093
Accumulated other comprehensive loss, net	(1,440)		(1,552)
Total BHE shareholders' equity	43,089		43,010
Noncontrolling interests	3,962		3,967
Total equity	47,051		46,977

Total liabilities and equity	$	127,522	$	127,316

~~(5)~~

~~Net of $(5) million and $(14) million tax for the three months ended March 31, 2020 and 2019, respectively.~~

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED ~~BALANCE SHEETS~~

STATEMENTS OF OPERATIONS (Unaudited)

March 31, 2020

December 31, 2019⁽¹⁾

(millions)

ASSETS

Current Assets

Cash and cash equivalents

$
1,192

$
166

Customer receivables (less allowance for doubtful accounts of $20 at both dates)

2,177

2,278

Other receivables (less allowance for doubtful accounts of $3 at both dates)⁽²⁾

248

367

Inventories

1,677

1,742

Regulatory assets

668

879

Other

574

656

Total current assets

6,536

6,088

Investments

Nuclear decommissioning trust funds

5,313

6,192

Investment in equity method affiliates

1,886

1,646

Other

376

379

Total investments

7,575

8,217

Property, Plant and Equipment

Property, plant and equipment

95,341

97,466

Accumulated depreciation, depletion and amortization

(27,945
)

(28,384
)
Total property, plant and equipment, net

67,396

69,082

Deferred Charges and Other Assets

Goodwill

8,946

8,946

Regulatory assets

9,564

7,687

Other

4,109

3,803

Total deferred charges and other assets

22,619

20,436

Total assets

$
104,126

$
103,823

~~(1)~~

~~Dominion Energy’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 10 for amounts attributable to related parties.~~

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue:
Energy		$	4,849	$	3,634
Real estate		1,232		893
Total operating revenue		6,081		4,527

Operating expenses:
Energy:
Cost of sales		1,569		1,038
Operations and maintenance		934		737
Depreciation and amortization		915		809
Property and other taxes		210		151
Real estate		1,120		873
Total operating expenses		4,748		3,608

Operating income		1,333		919

Other income (expense):
Interest expense		(530)		(483)
Capitalized interest		14		17
Allowance for equity funds		26		34
Interest and dividend income		21		20
(Losses) gains on marketable securities, net		(1,118)		27
Other, net		8		(27)
Total other income (expense)		(1,579)		(412)

(Loss) income before income tax benefit and equity loss		(246)		507
Income tax benefit		(535)		(184)
Equity loss		(179)		(18)
Net income		110		673
Net income attributable to noncontrolling interests		106		3
Net income attributable to BHE shareholders		4		670
Preferred dividends		38		0
(Loss) earnings on common shares		$	(34)	$	670

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED ~~BALANCE SHEETS—(Continued)~~

STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

March 31, 2020

December 31, 2019⁽¹⁾

(millions)

LIABILITIES AND EQUITY

Current Liabilities

Securities due within one year

$
2,919

$
3,162

Short-term debt

2,190

911

Accounts payable

842

1,115

Accrued interest, payroll and taxes

1,089

1,323

Regulatory liabilities

641

497

Reserves for SCANA legal proceedings

560

696

Derivative liabilities

793

408

Other⁽²⁾

1,414

1,827

Total current liabilities

10,448

9,939

Long-Term Debt

Long-term debt

31,097

30,313

Junior subordinated notes

3,407

3,406

Finance leases

111

105

Total long-term debt

34,615

33,824

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

6,158

6,277

Regulatory liabilities

10,589

11,001

Derivative liabilities

853

332

Other⁽²⁾

8,711

8,417

Total deferred credits and other liabilities

26,311

26,027

Total liabilities

71,374

69,790

Commitments and Contingencies (see Note 17)

Equity

Preferred stock (See Note 16)

2,387

2,387

Common stock – no par⁽³⁾

23,902

23,824

Retained earnings

6,455

7,576

Accumulated other comprehensive loss

(2,018
)

(1,793
)
Total shareholders' equity

30,726

31,994

Noncontrolling interests

2,026

2,039

Total equity

32,752

34,033

Total liabilities and equity

$
104,126

$
103,823

(Amounts in millions)

~~(1) Dominion Energy’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2) See Note 10 for amounts attributable to related parties~~

~~(3) 1.8 billion shares authorized; 839 million shares and 838 million shares outstanding at March 31, 2020 and December 31, 2019, respectively.~~


	Three-Month Periods
	Ended March 31,
		2021		2020

Net income		$	110	$	673

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $4 and $11		7		34
Foreign currency translation adjustment		91		(548)
Unrealized gains (losses) on cash flow hedges, net of tax of $5 and $(10)		14		(33)
Total other comprehensive income (loss), net of tax		112		(547)

Comprehensive income		222		126
Comprehensive income attributable to noncontrolling interests		106		3
Comprehensive income attributable to BHE shareholders		$	116	$	123

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

Preferred Stock

Common Stock

Dominion Energy Shareholders

Total

Shares

Amount

Shares

Amount

Retained Earnings

AOCI

Shareholders'
Equity

Noncontrolling
Interests

Total
Equity

(millions, except per share amounts)

December 31, 2018

681

$
12,588

$
9,219

$
(1,700
)

$
20,107

$
1,941

$
22,048

Net income (loss) including noncontrolling interests

(680
)

(680
)

3

(677
)
Issuance of common stock

3

247

247

247

Acquisition of SCANA

96

6,818

6,818

6,818

Acquisition of public interest in Dominion Energy Midstream

22

1,181

1,181

(1,221
)

(40
)
Dividends ($0.9175 per common share) and distributions

(733
)

(733
)

(33
)

(766
)
Other comprehensive loss, net of tax

(31
)

(31
)

(31
)
March 31, 2019

—

$
—

802

$
20,834

$
7,806

$
(1,731
)

$
26,909

$
690

$
27,599

December 31, 2019

2

$
2,387

838

$
23,824

$
7,576

$
(1,793
)

$
31,994

$
2,039

$
34,033

Cumulative-effect of changes in accounting principles

(48
)

(48
)

(48
)
Net income (loss) including noncontrolling interests

(270
)

(270
)

31

(239
)
Issuance of stock

1

78

78

78

Preferred stock dividends (See Note 16)

(16
)

(16
)

(16
)
Common stock dividends ($0.940 per share) and distributions

(788
)

(788
)

(44
)

(832
)
Other comprehensive loss, net of tax

(225
)

(225
)

(225
)
Other

1

1

1

March 31, 2020

2

$
2,387

839

$
23,902

$
6,455

$
(2,018
)

$
30,726

$
2,026

$
32,752

(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, December 31, 2019	$	0	$	0	$	6,389	$	(530)	$	28,296	$	(1,706)	$	129	$	32,578
Net income	—		0		0		—		670		0		3		673
Other comprehensive loss	—		0		0		—		0		(547)		0		(547)
Common stock purchases	—		0		(6)		—		(120)		0		0		(126)
Distributions	—		0		0		—		0		0		(5)		(5)
Other equity transactions	—		0		(1)		—		0		0		0		(1)
Balance, March 31, 2020	$	0	$	0	$	6,382	$	(530)	$	28,846	$	(2,253)	$	127	$	32,572










Balance, December 31, 2020	$	3,750	$	0	$	6,377	$	(658)	$	35,093	$	(1,552)	$	3,967	$	46,977
Net income	—		0		0		—		4		0		106		110
Other comprehensive income	—		0		0		—		0		112		0		112
Preferred stock dividend	—		—		—		—		(38)		—		—		(38)

Distributions	—		0		0		0		0		0		(113)		(113)

Other equity transactions	—		0		0		0		1		0		2		3
Balance, March 31, 2021	$	3,750	$	0	$	6,377	$	(658)	$	35,060	$	(1,440)	$	3,962	$	47,051

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Three Months Ended March 31,

2020

2019

(millions)

Operating Activities

Net loss including noncontrolling interests

$
(239
)

$
(677
)
Adjustments to reconcile net loss including noncontrolling interests to net cash provided by operating activities:

Depreciation, depletion and amortization (including nuclear fuel)

759

734

Deferred income taxes and investment tax credits

(65
)

106

Provision for refunds and rate credits to electric utility customers

—

988

Impairment of assets and other charges

768

835

Net losses (gains) on nuclear decommissioning trust funds and other investments

526

(271
)
Revision to future ash pond and landfill closure costs

—

(113
)
Other adjustments

4

(11
)
Changes in:

Accounts receivable

245

153

Inventories

71

53

Deferred fuel and purchased gas costs, net

162

27

Prepayments

38

89

Accounts payable

(164
)

(284
)
Accrued interest, payroll and taxes

(234
)

(329
)
Customer deposits

(13
)

(35
)
Margin deposit assets and liabilities

46

93

Other operating assets and liabilities

(271
)

(187
)
Net cash provided by operating activities

1,633

1,171

Investing Activities

Plant construction and other property additions (including nuclear fuel)

(1,462
)

(1,002
)
Cash and restricted cash acquired in the SCANA Combination

—

389

Acquisition of solar development projects

(8
)

(29
)
Proceeds from sales of securities

602

506

Purchases of securities

(631
)

(494
)
Proceeds from sales of assets and equity method investments

14

154

Contributions to equity method affiliates

(11
)

(69
)
Acquisitions of equity method investments

(178
)

—

Other

33

(7
)
Net cash used in investing activities

(1,641
)

(552
)
Financing Activities

Issuance of short-term debt, net

1,279

1,905

Issuance of short-term notes

500

—

Repayment of credit facility borrowings

—

(113
)
Issuance of long-term debt

950

600

Repayment of long-term debt, including redemption premiums

(932
)

(2,217
)
Issuance of common stock

78

247

Common dividend payments

(788
)

(733
)
Other

(81
)

(72
)
Net cash provided by (used in) financing activities

1,006

(383
)
Increase in cash, restricted cash and equivalents

998

236

Cash, restricted cash and equivalents at beginning of period

269

391

Cash, restricted cash and equivalents at end of period

$
1,267

$
627

Supplemental Cash Flow Information

Significant noncash investing and financing activities:⁽¹⁾⁽²⁾

Accrued capital expenditures

$
343

$
201

Financing leases

17

11

~~(1)~~

~~See Note 3 for noncash investing and financing activities related to the SCANA Combination.~~

~~(2)~~

~~See Note 16 for noncash financing activities related to the acquisition of the public interest in Dominion Energy Midstream.~~

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income	$	110	$	673
Adjustments to reconcile net income to net cash flows from operating activities:
Losses (gains) on marketable securities, net	1,118		(27)
Depreciation and amortization	927		821
Allowance for equity funds	(26)		(34)
Equity loss, net of distributions	221		29
Changes in regulatory assets and liabilities	(9)		0
Deferred income taxes and amortization of investment tax credits	(135)		47
Other, net	9		63
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(249)		(118)
Derivative collateral, net	14		(19)
Pension and other postretirement benefit plans	(21)		(23)
Accrued property, income and other taxes, net	(453)		(364)
Accounts payable and other liabilities	19		117
Net cash flows from operating activities	1,525		1,165

Cash flows from investing activities:
Capital expenditures	(1,295)		(1,356)

Purchases of marketable securities	(128)		(188)
Proceeds from sales of marketable securities	104		180
Equity method investments	(26)		(153)
Other, net	(29)		43
Net cash flows from investing activities	(1,374)		(1,474)

Cash flows from financing activities:
Proceeds from BHE senior debt	0		3,231
Repayments of BHE senior debt	(450)		(350)

Common stock purchases	0		(126)
Proceeds from subsidiary debt	0		1,093
Repayments of subsidiary debt	(26)		(1,347)
Net proceeds from (repayments of) short-term debt	409		(1,109)

Distributions to noncontrolling interests	(115)		(2)
Other, net	(9)		(32)
Net cash flows from financing activities	(191)		1,358

Effect of exchange rate changes	1		(13)

Net change in cash and cash equivalents and restricted cash and cash equivalents	(39)		1,036
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,445		1,268
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,406	$	2,304

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~VIRGINIA ELECTRIC~~

BERKSHIRE HATHAWAY ENERGY COMPANY AND ~~POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF INCOME~~

~~(Unaudited)~~

Three Months Ended March 31,

2020

2019

(millions)

Operating Revenue⁽¹⁾

$
1,930

$
1,965

Operating Expenses

Electric fuel and other energy-related purchases⁽¹⁾

492

596

Purchased (excess) electric capacity

(9
)

33

Other operations and maintenance:

Affiliated suppliers

87

86

Other

331

193

Depreciation and amortization

311

304

Other taxes

87

85

Impairment of assets and other charges

764

546

Total operating expenses

2,063

1,843

Income (loss) from operations

(133
)

122

Other income (loss)

(52
)

37

Interest and related charges⁽¹⁾

126

135

Income (loss) before income tax expense

(311
)

24

Income tax expense (benefit)

(31
)

4

Net Income (Loss)

$
(280
)

$
20

~~(1)~~

~~See Note 19 for amounts attributable to affiliates.~~

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~(Unaudited)~~

Three Months Ended March 31,

2020

2019

(millions)

Net income (loss)

$
(280
)

$
20

Other comprehensive income (loss), net of taxes:

Net deferred losses on derivatives-hedging activities⁽¹⁾

(45
)

(7
)

Changes in unrealized net gains (losses) on nuclear
decommissioning trust funds⁽²⁾

(2
)

2

Amounts reclassified to net income (loss):

Net realized losses on nuclear decommissioning
trust funds⁽³⁾

1

—

Total other comprehensive loss

(46
)

(5
)

Comprehensive income (loss)

$
(326
)

$
15

~~(1)~~

~~Net of $16 million and $2 million tax for the three months ended March 31, 2020 and 2019, respectively.~~

SUBSIDIARIES

~~(2)~~

~~Net of $— million and $(1) million tax for the three months ended March 31, 2020 and 2019, respectively.~~

~~(3)~~

~~Net of $(1) million and $— million tax for the three months ended March 31, 2020 and 2019, respectively.~~

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

March 31, 2020

December 31, 2019⁽¹⁾

(millions)

ASSETS

Current Assets

Cash and cash equivalents

$
71

$
17

Customer receivables (less allowance for doubtful accounts of $8 and $9)

1,063

1,163

Other receivables (less allowance for doubtful accounts of $2 at both dates)

93

106

Affiliated receivables

3

27

Inventories (average cost method)

868

873

Regulatory assets

295

433

Other⁽²⁾

54

57

Total current assets

2,447

2,676

Investments

Nuclear decommissioning trust funds

2,468

2,881

Other

3

3

Total investments

2,471

2,884

Property, Plant and Equipment

Property, plant and equipment

44,446

47,038

Accumulated depreciation and amortization

(13,434
)

(14,156
)
Total property, plant and equipment, net

31,012

32,882

Deferred Charges and Other Assets

Regulatory assets

3,724

1,863

Other⁽²⁾

1,394

1,123

Total deferred charges and other assets

5,118

2,986

Total assets

$
41,048

$
41,428

~~(1)~~

~~Virginia Power’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 19 for amounts attributable to affiliates.~~

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED BALANCE SHEETS—(Continued)~~

~~(Unaudited)~~

March 31, 2020

December 31, 2019⁽¹⁾

(millions)

LIABILITIES AND SHAREHOLDER’S EQUITY

Current Liabilities

Securities due within one year

$
5

$
4

Short-term debt

135

243

Accounts payable

261

334

Payables to affiliates

339

210

Affiliated current borrowings

—

107

Accrued interest, payroll and taxes

270

253

Asset retirement obligations

78

340

Derivative liabilities⁽²⁾

481

243

Other

732

738

Total current liabilities

2,301

2,472

Long-Term Debt

Long-term debt

12,327

12,325

Finance leases

23

16

Total long-term debt

12,350

12,341

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

2,807

2,962

Asset retirement obligations

3,516

3,241

Regulatory liabilities

4,820

5,074

Other⁽²⁾

1,698

1,349

Total deferred credits and other liabilities

12,841

12,626

Total liabilities

27,492

27,439

Commitments and Contingencies (see Note 17)

Common Shareholder’s Equity

Common stock – no par⁽³⁾

5,738

5,738

Other paid-in capital

1,113

1,113

Retained earnings

6,780

7,167

Accumulated other comprehensive loss

(75
)

(29
)
Total common shareholder’s equity

13,556

13,989

Total liabilities and shareholder’s equity

$
41,048

$
41,428

~~(1)~~

~~Virginia Power’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 19 for amounts attributable to affiliates.~~

~~(3)~~

~~500,000 shares authorized; 274,723 sharesoutstanding at March 31, 2020 and December 31, 2019.~~

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY~~

~~(Unaudited)~~

Common Stock

Shares

Amount

Other Paid-In Capital

Retained Earnings

AOCI

Total

(millions, except for shares)

(thousands)

December 31, 2018

275

$
5,738

$
1,113

$
6,208

$
(12
)

$
13,047

Net income

20

20

Dividends

(118
)

(118
)
Other comprehensive income, net of tax

(5
)

(5
)
March 31, 2019

275

$
5,738

$
1,113

$
6,110

$
(17
)

$
12,944

December 31, 2019

275

$
5,738

$
1,113

$
7,167

$
(29
)

$
13,989

Net loss

(280
)

(280
)
Dividends

(108
)

(108
)
Other comprehensive loss, net of tax

(46
)

(46
)
Other

1

1

March 31, 2020

275

$
5,738

$
1,113

$
6,780

$
(75
)

$
13,556

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

Three Months Ended March 31,

2020

2019

(millions)

Operating Activities

Net income (loss)

$
(280
)

$
20

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation and amortization (including nuclear fuel)

357

346

Deferred income taxes and investment tax credits

(135
)

(49
)
Revision to future ash pond and landfill closure costs

—

(113
)
Impairment of assets and other charges

764

546

Other adjustments

53

(39
)
Changes in:

Accounts receivable

123

62

Affiliated receivables and payables

24

(63
)
Inventories

5

(19
)
Prepayments

(5
)

(2
)
Deferred fuel expenses, net

70

24

Accounts payable

99

(33
)
Accrued interest, payroll and taxes

13

15

Net realized and unrealized changes related to derivative activities

(12
)

14

Asset retirement obligations

14

—

Other operating assets and liabilities

59

(66
)
Net cash provided by operating activities

1,149

643

Investing Activities

Plant construction and other property additions

(764
)

(563
)
Purchases of nuclear fuel

(25
)

(11
)
Acquisition of solar development projects

(6
)

(27
)
Proceeds from sales of securities

294

253

Purchases of securities

(310
)

(269
)
Other

37

(3
)
Net cash used in investing activities

(774
)

(620
)
Financing Activities

Issuance (repayment) of short-term debt, net

(108
)

281

Repayment of affiliated current borrowings, net

(106
)

(200
)
Common dividend payments to parent

(108
)

(118
)
Other

(1
)

(1
)
Net cash used in financing activities

(323
)

(38
)
Increase (decrease) in cash, restricted cash and equivalents

52

(15
)
Cash, restricted cash and equivalents at beginning of period

24

38

Cash, restricted cash and equivalents at end of period

$
76

$
23

Supplemental Cash Flow Information

Significant noncash investing activities:

Accrued capital expenditures

$
210

$
117

Financing leases

10

5

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED STATEMENTS OF INCOME~~

~~(Unaudited)~~

Three Months Ended March 31,

2020

2019

(millions)

Operating Revenue⁽¹⁾

$
556

$
566

Operating Expenses

Purchased gas⁽¹⁾

8

12

Other energy-related purchases

—

1

Other operations and maintenance:

Affiliated suppliers

40

39

Other

125

137

Depreciation and amortization

93

91

Other taxes

42

39

Total operating expenses

308

319

Income from operations

248

247

Earnings from equity method investees

15

13

Other income⁽¹⁾

49

42

Interest and related charges⁽¹⁾

58

87

Income from continuing operations

254

215

Income tax expense

52

43

Net Income from continuing operations

202

172

Net Income from discontinued operations

—

54

Net Income including noncontrolling interests

202

226

Noncontrolling interests

33

36

Net Income attributable to Dominion Energy Gas

$
169

$
190

~~(1)~~

~~See Note 19 for amounts attributable to related parties.~~

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~(Unaudited)~~

Three Months Ended March 31,

2020

2019

(millions)

Net Income including noncontrolling interests

$
202

$
226

Other comprehensive income (loss), net of taxes:

Net deferred losses on derivatives-hedging activities⁽¹⁾

(91
)

(27
)
Amounts reclassified to net income (loss):

Net derivative losses-hedging activities⁽²⁾

6

3

Net pension and other postretirement benefit costs⁽³⁾

1

1

Total other comprehensive loss

(84
)

(23
)
Comprehensive income including noncontrolling interests

118

203

Comprehensive income attributable to noncontrolling interests

33

35

Comprehensive income attributable to Dominion Energy Gas

$
85

$
168

~~(1)~~

~~Net of $32 million and $9 million tax for the three months ended March 31, 2020 and 2019, respectively.~~

~~(2)~~

~~Net of $(2) million and $— million tax for the three months ended March 31, 2020 and 2019, respectively.~~

~~(3)~~

~~Net of $(1) million tax for both the three months ended March 31, 2020 and 2019.~~

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

March 31, 2020

December 31, 2019⁽¹⁾

(millions)

ASSETS

Current Assets

Cash and cash equivalents

$
46

$
27

Customer receivables (less allowance for doubtful accounts of $2 at both dates)

157

173

Other receivables⁽²⁾

33

26

Affiliated receivables

87

362

Affiliated notes receivable

262

—

Inventories

125

122

Gas imbalances⁽²⁾

39

52

Other

84

96

Total current assets

833

858

Investments

Affiliated notes receivable

3,437

3,437

Investment in equity method affiliates

312

312

Total investments

3,749

3,749

Property, Plant and Equipment

Property, plant and equipment

15,224

15,166

Accumulated depreciation and amortization

(3,620
)

(3,538
)
Total property, plant and equipment, net

11,604

11,628

Deferred Charges and Other Assets

Goodwill

1,471

1,471

Other⁽²⁾

1,087

1,078

Total deferred charges and other assets

2,558

2,549

Total assets

$
18,744

$
18,784

~~(1)~~

~~Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 19 for amounts attributable to related parties.~~

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED BALANCE SHEETS—(Continued)~~

~~(Unaudited)~~

March 31, 2020

December 31, 2019⁽¹⁾

(millions)

LIABILITIES AND EQUITY

Current Liabilities

Securities due within one year

$
699

$
700

Short-term debt

30

62

Accounts payable

40

59

Payables to affiliates

131

82

Affiliated current borrowings

256

260

Accrued interest, payroll and taxes

143

128

Other⁽²⁾

190

161

Total current liabilities

1,489

1,452

Long-Term Debt

Long-term debt

4,817

4,821

Finance leases

5

5

Total long-term debt

4,822

4,826

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

1,277

1,288

Other

1,078

989

Total deferred credits and other liabilities

2,355

2,277

Total liabilities

8,666

8,555

Commitments and Contingencies (see Note 17)

Equity

Membership interests

8,968

9,031

Accumulated other comprehensive loss

(271
)

(187
)
Total members' equity

8,697

8,844

Noncontrolling interests

1,381

1,385

Total equity

10,078

10,229

Total liabilities and equity

$
18,744

$
18,784

~~(1)~~

~~Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 19 for amounts attributable to related parties.~~

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED STATEMENTS OF EQUITY~~

~~(Unaudited)~~

Predecessor Equity

Membership Interests

AOCI

Total
Members'
Equity

Noncontrolling Interests

Total

(millions)

December 31, 2018

$
1,804

$
4,566

$
(169
)

$
6,201

$
2,664

$
8,865

Net income

74

116

190

36

226

Acquisition of public interest in Dominion Energy Midstream

1,181

1,181

(1,221
)

(40
)
Dividends and distributions

(113
)

(113
)

(46
)

(159
)
Other comprehensive loss, net of tax

(22
)

(22
)

(1
)

(23
)
Other

(8
)

(8
)

(8
)
March 31, 2019

$
2,938

$
4,682

$
(191
)

$
7,429

$
1,432

$
8,861

December 31, 2019

$
—

$
9,031

$
(187
)

$
8,844

$
1,385

$
10,229

Net income

169

169

33

202

Dividends and distributions

(232
)

(232
)

(37
)

(269
)
Other comprehensive loss, net of tax

(84
)

(84
)

(84
)
March 31, 2020

$
—

$
8,968

$
(271
)

$
8,697

$
1,381

$
10,078

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

Three Months Ended March 31,

2020

2019

(millions)

Operating Activities

Net income including noncontrolling interest

$
202

$
226

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

93

113

Deferred income taxes and investment tax credits

15

21

Other adjustments

(8
)

4

Changes in:

Accounts receivable

9

(32
)
Affiliated receivables and payables

325

(26
)
Inventories

(3
)

(20
)
Prepayments

14

33

Accounts payable

(11
)

(23
)
Accrued interest, payroll and taxes

16

(40
)
Customer deposits

—

(32
)
Pension and other postretirement benefits

(18
)

(35
)
Other operating assets and liabilities

33

(14
)
Net cash provided by operating activities

667

175

Investing Activities

Plant construction and other property additions

(76
)

(150
)
Advances to affiliates

(262
)

—

Other

(4
)

(1
)
Net cash used in investing activities

(342
)

(151
)
Financing Activities

Issuance (repayment) of short-term debt, net

(32
)

270

Repayment of affiliated current borrowings, net

(5
)

(145
)
Repayment of long-term debt

—

(300
)
Issuance of affiliated long-term debt

—

395

Repayment of credit facility borrowings

—

(73
)
Dividends and distributions

(269
)

(159
)
Other

—

(1
)
Net cash used in financing activities

(306
)

(13
)
Increase in cash, restricted cash and equivalents

19

11

Cash, restricted cash and equivalents at beginning of period

39

198

Cash, restricted cash and equivalents at end of period

$
58

$
209

Supplemental Cash Flow Information

Significant noncash investing activities:

Accrued capital expenditures

$
13

$
31

Financing leases

1

2

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~COMBINED~~ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~(Unaudited)~~

~~Note 1. Nature of Operations~~

~~Dominion~~

(1) General

Berkshire Hathaway Energy headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas. Dominion Energy’s operations also include DESC, an equity investment in Atlantic Coast Pipeline and regulated gas distribution operations primarily in the eastern and Rocky Mountain regions of the U.S. Dominion Energy’s nonregulated operations include merchant generation and retail energy marketing operations. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Dominion Energy GasCompany ("BHE") is a holding company that ~~conducts~~owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The Company's operations are organized as 8 business ~~activities~~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 ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC ("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 ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through ~~FERC-regulated~~these locally managed and operated businesses, owns 4 utility companies in the United States serving customers in 11 states, 2 electricity distribution companies in Great Britain, 5 interstate natural gas ~~transmission~~ pipeline companies and ~~underground~~interests in a liquefied natural gas ("LNG") export, import and storage ~~systems~~facility in the ~~eastern~~United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and ~~Rocky Mountain regions~~hydroelectric projects, the largest residential real estate brokerage firm in the United States and 1 of the ~~U.S., as well as~~largest residential real estate brokerage franchise networks in the ~~Cove Point LNG Facility. In addition, Dominion Energy Gas owns a 50% noncontrolling interest~~United States.

The unaudited Consolidated Financial Statements have been prepared in ~~both Iroquois~~accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and ~~White River Hub. See Note 3 for additional information on~~ the ~~Dominion Energy Gas Restructuring.~~

~~Note 2. Significant Accounting Policies~~

~~As permitted by 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 ~~SEC,~~disclosures required by GAAP for annual financial statements. Management believes the ~~Companies’ accompanying~~ unaudited Consolidated Financial Statements contain ~~certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. These~~all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements ~~should~~as of March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month period ended March 31, 2021 are not necessarily indicative of the results to be ~~read~~expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in ~~conjunction~~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 ~~Companies’~~Company's Annual Report on Form 10-K for the year ended December 31, ~~2019.~~

In2020 describes the ~~Companies’ opinion,~~most significant accounting policies used in the ~~accompanying~~preparation of the unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position at March 31, 2020 and their results of operations, changes in equity and cash flows for the three months ended March 31, 2020 and 2019. Such adjustments are normal and recurring in nature unless otherwise noted.

The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

The Companies’ accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. At March 31, 2020, Dominion Energy owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its right to control operations. GIP’s ownership interest in Four Brothers and Three Cedars, Terra Nova Renewable Partners’ 33% interest in certain Dominion Energy merchant solar projects, Brookfield’s 25% interest in Cove Point (effective December 2019) and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in certain merchant projects upon the occurrence of certain events, none of which are expected to occur in the next 12 months. Brookfield’s 25% interest in Cove Point (effective December 2019) and the public’s ownership interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest in Dominion Energy Gas’ Consolidated Financial Statements.

The results of operations for interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, electric fuel and other energy-related purchases, purchased gas expenses and other factors.

Certain amounts in the Companies’ 2019 Consolidated Financial Statements and Notes have been reclassified to conform to the 2020 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

~~Amounts disclosed for Dominion Energy are inclusive of Virginia Power and/or Dominion Energy Gas, where applicable.~~ There have been no significant changes ~~from Note 2 to the Consolidated Financial Statements~~ in the ~~Companies’ Annual Report on Form 10-K for~~Company's assumptions regarding significant accounting estimates and policies during the ~~year~~three-month period ended ~~December~~March 31, ~~2019, with the exception~~2021.

(2) Business Acquisition

BHE GT&S Acquisition

Transaction Description

On November 1, 2020, BHE completed its acquisition of substantially all of the ~~items described below.~~

natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.5 billion in cash, after post-closing adjustments (the "GT&S Cash ~~Restricted Cash~~Consideration"), and ~~Equivalents~~

~~The following table provides~~assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments, for 100% of the equity interests of Eastern Gas Transmission and Storage, Inc. ("EGTS") (formerly known as Dominion Energy Transmission, Inc.) and Carolina Gas Transmission, LLC (formerly known as Dominion Energy Carolina Gas Transmission, LLC); 50% of the equity interests of Iroquois Gas Transmission System L.P. ("Iroquois"); and a ~~reconciliation~~25% economic interest in Cove Point LNG, LP ("Cove Point") (formerly known as Dominion Energy Cove Point LNG, LP), consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE became the operator of Cove Point after the GT&S Transaction. The GT&S Transaction received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval") in October 2020, and approval by the Department of Energy with respect to a change in control of Cove Point and the Federal Communications Commission with respect to the transfer of certain licenses earlier in 2020.

On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval, which is currently anticipated in the first half of 2021, for a cash ~~restricted~~purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and ~~equivalents reported~~indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. DEI is also a party to the Q-Pipe Purchase Agreement, as guarantor for certain provisions regarding the Purchase Price Repayment Amount (as defined below) and other matters.

Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately $1.3 billion, which is included in other current assets on the Consolidated Balance Sheet as of March 31, 2021 and December 31, 2020, to Dominion Questar on November 2, 2020. If the Q-Pipe Transaction does not close, Dominion Questar has agreed to repay all or (depending on the repayment date) substantially all of the Q-Pipe Cash Consideration (the "Purchase Price Repayment Amount") to BHE on or prior to December 31, 2021. If HSR Approval has not been obtained by June 30, 2021, upon BHE's written request, Dominion Questar will seek alternative buyers for all or a material portion of the Questar Pipeline Group (an "Alternative Transaction"). The Purchase Price Repayment Amount may be paid in cash or in shares of common stock, no par value, of DEI, or a combination thereof, subject to certain limitations as to stock repayments set forth in the Q-Pipe Purchase Agreement; provided any payment on or after December 15, 2021 must be paid in cash only.

The assets acquired in the GT&S Transaction include (i) approximately 5,400 miles of operated natural gas transmission, gathering and storage pipelines with approximately 12.5 billion cubic feet ("Bcf") per day of design capacity; (ii) 420 Bcf of operated natural gas storage design capacity, of which 306 Bcf is owned by BHE GT&S; and (iii) an LNG export, import and storage facility with LNG storage capacity of approximately 14.6 billions of cubic feet equivalent.

On October 29, 2020, BHE issued $3.75 billion of its 4.00% Perpetual Preferred Stock to certain subsidiaries of Berkshire Hathaway Inc. in order to fund the GT&S Cash Consideration and the Q-Pipe Cash Consideration.

Included in BHE's Consolidated Statement of Operations within the ~~Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows~~BHE Pipeline Group reportable segment for the ~~three months~~three-month periods ended March 31, ~~2020~~2021, is operating revenue and ~~2019:~~

Cash, Restricted Cash and Equivalents
at End of Period

Cash, Restricted Cash and Equivalents
at Beginning of Period

March 31, 2020

March 31, 2019

December 31, 2019

December 31, 2018

(millions)

Dominion Energy

Cash and cash equivalents

$
1,192

$
422

$
166

$
268

Restricted cash and equivalents⁽¹⁾

75

205

103

123

Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows

$
1,267

$
627

$
269

$
391

Virginia Power

Cash and cash equivalents

$
71

$
14

$
17

$
29

Restricted cash and equivalents⁽¹⁾

5

9

7

9

Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows

$
76

$
23

$
24

$
38

Dominion Energy Gas

Cash and cash equivalents⁽²⁾

$
46

$
147

$
27

$
108

Restricted cash and equivalents ⁽¹⁾

12

62

12

90

Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows

$
58

$
209

$
39

$
198

~~(1)~~

~~Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.~~

~~(2)~~

~~At March 31, 2019 and December 31, 2018, Dominion Energy Gas had $4~~net income attributable to BHE shareholders of $559 million ~~and $9 million of cash and cash equivalents included in current assets of discontinued operations, respectively.~~

~~Property, Plant~~ and ~~Equipment~~

In January 2019, Virginia Power committed to a plan to retire certain automated metering reading infrastructure associated with its electric operations before the end of its estimated useful life and replace such equipment with more current AMI technology. As a result, Virginia Power recorded a charge of $160$107 million, ($119 million after-tax), included in impairment of assets and other charges in its Consolidated Statements of Income. This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13 to the Consolidated Financial Statements in Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2019.

In March 2019, Virginia Power committed to retire certain electric generating units before the end of their useful lives and completed the retirement of certain units at 6 facilities representing 1,292 MW of electric generating capacity, which had previously been placed in cold reserve. An additional unit at Possum Point power station will be retired after it meets its capacity obligation to PJM in 2021. As a result, Virginia Power recorded a charge of $369 million ($275 million after-tax), primarily included in impairment of assets and other charges in its Consolidated Statements of Income. This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13 to the Consolidated Financial Statements in Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2019.

In March 2020, Virginia Power committed to retire certain coal- and oil-fired generating units before the end of their useful lives based on economic and other factors, including but not limited to market power prices and the VCEA. These units will be retired after they meet their capacity obligations to PJM in 2023.As a result, Virginia Power recorded a charge of $754 million ($561 million after-tax), primarily included in impairment of assets and other charges in its Consolidated Statements of Income. This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13 to the Consolidated Financial Statements in Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2019.

~~In the first quarter of 2020, Virginia Power updated depreciation rates for its nuclear plants to reflect lower depreciation rates~~respectively, as a result of ~~the expected approval~~including BHE GT&S from November 1, 2020.

Preliminary Allocation of license extensions from the NRC. This adjustment resulted in a decrease of $8 million ($6 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income and a $0.01 increase in Dominion Energy’s EPS, for the three months ended March 31, 2020. This revision is expected to decrease annual depreciation expense by approximately $31 million ($23 million after-tax) and increase Dominion Energy’s EPS by $0.03 for the year ended December 31, 2020.

~~Credit Risk~~

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

Effective January 2020, expected credit losses are estimated and recorded based on historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of financial assets held at amortized cost as well as expected credit losses on commitments with respect to financial guarantees.

~~Investments~~

~~Debt and Equity Securities with Readily Determinable Fair Value~~

Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.

• Purchase Price

~~Debt securities classified as trading securities~~
include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

• ~~Debt securities classified as available-for-sale securities~~ include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any credit-related impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are deferred to a regulatory asset or liability as applicable for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any credit-related impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

~~In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.~~

Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by Dominion Energy and Virginia Power in the nuclear decommissioning trusts. Dominion Energy and Virginia Power record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, Dominion Energy and Virginia Power may elect a measurement alternative for equity securities without a readily determinable fair value. Under the measurement alternative, equity securities are reported at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. Dominion Energy and Virginia Power qualitatively assess equity securities reported using the measurement alternative to determine whether an investment is impaired on an ongoing basis. Net realized and unrealized gains and losses on equity securities held in Virginia Power’s nuclear decommissioning trusts are deferred to a regulatory asset or liability, as applicable, for certain jurisdictions subject to cost-based regulation. For all other equity securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts and rabbi trusts, net realized and unrealized gains and losses are included in other income in the Consolidated Statements of Income.

~~Equity Securities without Readily Determinable Fair Values~~

The Companies account for illiquid and privately held securities without readily determinable fair values under either the equity method or cost method. Equity securities without readily determinable fair values include:

• ~~Equity method investments~~ when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy and Dominion Energy Gas’ investments are included in investments in equity method affiliates in their Consolidated Balance Sheets. Dominion Energy and Dominion Energy Gas record equity method adjustments in other income and earnings from equity method investees, respectively, in their Consolidated Statements of Income, including their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

• ~~Cost method investments~~ when Dominion Energy and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion Energy and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.

~~Other-Than-Temporary Impairment~~

The Companies periodically review their equity method investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in the fair value of any equity method investment is determined to be other-than-temporary, the investment is written down to its fair value at the end of the reporting period.

~~Credit Impairment~~

Effective January 2020, Dominion Energy and Virginia Power periodically review their available-for-sale debt securities to determine whether a decline in fair value should be considered credit related. If a decline in the fair value of any available-for-sale debt security is determined to be credit related, the credit-related impairment is recorded to an allowance included in nuclear decommissioning trust funds in Dominion Energy and Virginia Power’s Consolidated Balance Sheets at the end of the reporting period, with such allowance for credit losses subject to reversal in subsequent evaluations.

Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion Energy and Virginia Power record in earnings, or defer as applicable for certain jurisdictions subject to cost-based regulation, any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, Dominion Energy and Virginia Power record the credit loss in earnings with the remaining non-credit portion of the unrealized loss recorded in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

~~Note 3. Acquisitions and Dispositions~~

~~Acquisition of SCANA~~

In January 2019, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock, in connection with the completion of the SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, at the closing of the SCANA Combination, SCANA marketed natural gas to retail customers in the southeast U.S. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In addition, SCANA’s debt totaled $6.9 billion at closing. The SCANA Combination expanded Dominion Energy’s portfolio of regulated electric generation, transmission and distribution and regulated natural gas distribution infrastructure operations.

See Note 3 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information on the SCANA Combination, including merger approval and conditions, information onBHE GT&S' assets acquired and liabilities assumed were measured at estimated fair value at closing. The majority of BHE GT&S' operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission ("FERC") and are accounted for pursuant to GAAP, including the authoritative guidance for regulated operations. The rate-setting and cost-recovery provisions provide for revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of BHE GT&S' assets acquired and liabilities assumed subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, no fair value adjustments have been reflected related to these amounts.

The fair value of BHE GT&S' assets acquired and liabilities assumed not subject to the rate-setting provisions discussed above was determined using an income and cost approach. The income approach is based on significant estimates and assumptions, including Level 3 inputs, which are judgmental in nature. The estimates and assumptions include the projected timing and amount of future cash flows, discount rates reflecting the risk inherent in the future cash flows and future market prices. Additionally, the fair value of long-term debt assumed was determined based on quoted market prices, which is considered a Level 2 fair value measurement.

The fair value of certain contracts and property, plant and equipment related to non-regulated operations, certain regulatory assets and other items included in rate base, an equity method investment and deferred income tax amounts are provisional and are subject to revision for up to 12 months following the acquisition date until the related valuations are completed. These items may be adjusted through regulatory assets or liabilities, to the extent recoverable in rates, or goodwill provided additional information is obtained about the facts and circumstances that existed as of the acquisition date. Such information includes, but is not limited to, the receipt of further information regarding the fair value of the contracts and property, plant and equipment related to non-regulated operations, the equity method investment and any associated deferred income tax amounts as well as the evolution of the rate-making process for regulated operations.

The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):


	Fair Value

Current assets, including cash and cash equivalents of $104	$	569
Property, plant and equipment	9,254
Goodwill	1,732
Regulatory assets	108
Deferred income taxes	275
Other long-term assets	1,424
Total assets	13,362

Current liabilities, including current portion of long-term debt of $1,200	1,567
Long-term debt, less current portion	4,415
Regulatory liabilities	661
Other long-term liabilities	289
Total liabilities	6,932
Noncontrolling interest	3,916
Net assets acquired	$	2,514

Goodwill

The excess of the purchase price ~~allocation. In addition, see Note 17~~paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1.7 billion and is reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily for the long-term opportunity to improve operating results through the efficient management of operating expenses and the deployment of capital. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. For income tax purposes, the GT&S Acquisition is treated as a ~~discussion~~deemed asset acquisition resulting from tax elections being made, therefore all tax goodwill is deductible. Due to book and tax basis differences of certain ~~legal proceedings involving Dominion Energy, SCANA or DESC relating to events occurring before closing~~items, book and tax goodwill will differ. The amount of ~~the SCANA Combination.~~

~~In accordance with the SCANA Merger Approval Order, Dominion Energy incurred certain charges to its Consolidated Statements of Income for the following:~~

•

In the first quarter of 2019, DESC recorded a reduction in operating revenue and a corresponding regulatory liability of $1.0 billion representing a refund of amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated 11-year period, effective January 2019, As a result, Dominion Energy’s Consolidated Statement of Income for the three months ended March 31, 2019 includes a $756 million after-tax charge.

tax goodwill is approximately $0.9 billion and will be amortized over 15 years.

•

Dominion Energy committed to forgo recovery of $105 million of certain property, plant and equipment associated with the NND Project. As a result, Dominion Energy’s Consolidated Statements of Income for the three months ended March 31, 2019 includes a charge of $105 million ($79 million after-tax), included in impairment of assets and other charges.

•

Dominion Energy committed to forgo recovery of $264 million of certain income tax-related regulatory assets associated with the NND Project. As a result, Dominion Energy’s Consolidated Statement of Income for the three months ended March 31, 2019 includes a charge of $198 million included in income tax expense.

~~Results of Operations and Unaudited~~ Pro Forma Financial Information

The impact of the SCANA Combination on Dominion Energy’s operating revenue was an increase of $914 million and $170 million for the three months ended March 31, 2020 and 2019, respectively, in the Consolidated Statements of Income. The impact of the SCANA Combination on net income attributable to Dominion Energy was an increase of $54 million and a decrease of $1.1 billion for the three months ended March 31, 2020 and 2019, respectively, in the Consolidated Statements of Income.

Dominion Energy incurred merger and integration-related costs of $19 million for the three months ended March 31, 2020, recorded in other operations and maintenance expense in the Consolidated Statements of Income. For the three months ended March 31, 2019, Dominion Energy incurred merger and integration-related costs of which $115 million was recorded in other operations and maintenance expense and $9 million was recorded in interest and related charges in the Consolidated Statements of Income. These costs consist of professional fees, charitable contribution commitments, employee-related expenses, certain financing costs and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of ~~Dominion Energy~~BHE and the amortization of the purchase price adjustments assuming the ~~SCANA Combination~~acquisition had taken place on January 1, ~~2018.~~ 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):


	Three-Month Period
	Ended March 31, 2020

Operating revenue	$	5,056

Net income attributable to BHE shareholders	$	773

(3) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):


		As of
	Depreciable	March 31,		December 31,
	Life	2021		2020
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	87,898	$	86,730
Interstate natural gas pipeline assets	3-80 years	16,712		16,667
		104,610		103,397
Accumulated depreciation and amortization		(31,653)		(30,662)
Regulated assets, net		72,957		72,735

Nonregulated assets:
Independent power plants	5-30 years	7,034		7,012
Other assets	3-40 years	5,794		5,659
		12,828		12,671
Accumulated depreciation and amortization		(2,337)		(2,586)
Nonregulated assets, net		10,491		10,085

Net operating assets		83,448		82,820
Construction work-in-progress		3,309		3,308
Property, plant and equipment, net		$	86,757	$	86,128

Construction work-in-progress includes $2.9 billion as of March 31, 2021 and $3.2 billion as of December 31, 2020, related to the construction of regulated assets.

(4) Investments and Restricted Cash and Cash Equivalents and Investments

Investments and restricted cash and cash equivalents and investments consists of the following (in millions):


	As of
	March 31,		December 31,
	2021		2020
Investments:
BYD Company Limited common stock	$	4,773	$	5,897
Rabbi trusts	452		440
Other	288		263
Total investments	5,513		6,600

Equity method investments:
BHE Renewables tax equity investments	5,399		5,626
Iroquois Gas Transmission System, L.P.	586		580
Electric Transmission Texas, LLC	581		594
JAX LNG, LLC	80		75
Bridger Coal Company	68		74
Other	113		118
Total equity method investments	6,827		7,067

Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	697		676
Other restricted cash and cash equivalents	130		155
Total restricted cash and cash equivalents and investments	827		831

Total investments and restricted cash and cash equivalents and investments	$	13,167	$	14,498

Reflected as:
Current assets	$	157	$	178
Noncurrent assets	13,010		14,320
Total investments and restricted cash and cash equivalents and investments	$	13,167	$	14,498

Investments

(Losses) gains on marketable securities, net recognized during the period consists of the following (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020
Unrealized (losses) gains recognized on marketable securities still held at the reporting date		$	(1,119)	$	25
Net gains recognized on marketable securities sold during the period		1		2
(Losses) gains on marketable securities, net		$	(1,118)	$	27

Equity Method Investments

The ~~unaudited pro forma financial information~~Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project. Certain of the Company's tax equity investments are located in Texas and have physical settlement hedge obligations that were negatively impacted due to production shortfalls during periods of extreme market pricing volatility as a result of the February 2021 polar vortex weather event. The Company recognized pre-tax equity losses of $218 million, or after-tax losses of $23 million inclusive of production tax credits ("PTCs") of $148 million and other income tax benefits of $47 million, during the three-month period ended March 31, 2021, on its tax equity investments, largely due to the February 2021 polar vortex weather event. The losses for the impacted tax equity investments were based upon the terms of each partnership agreement, as amended, and are subject to change as project-by-project discussions are ongoing among the Company and the respective hedge provider and project sponsor. As of March 31, 2021, the carrying value of the impacted tax equity investments totaled $2.8 billion.

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States 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 as of March 31, 2021 and December 31, 2020, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and 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 of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2021		2020
Cash and cash equivalents	$	1,276	$	1,290
Restricted cash and cash equivalents	117		140
Investments and restricted cash and cash equivalents and investments	13		15
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,406	$	1,445

(5) Recent Financing Transactions

Long-Term Debt

In April 2021, Northern Natural Gas issued $550 million of 3.40% Senior Bonds due October 2051. Northern Natural Gas used the net proceeds to early redeem in April 2021 all of its $200 million, 4.25% Senior Notes originally due June 2021 and for general corporate purposes.

Credit Facilities

In April 2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one-year revolving credit facility to April 2022, by exercising a one-year extension option.

(6) Income Taxes

The effective income tax rate for the three-month period ended March 31, 2021, is 217% and results from a $535 million income tax benefit associated with a $246 million pre-tax loss, primarily relating to a pre-tax unrealized loss of $1,124 million on the Company's investment in BYD Company Limited. The $535 million income tax benefit is primarily comprised of a $52 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss, a $334 million benefit (136%) from income tax credits and a $51 million benefit (21%) from state income tax benefits, net of federal income tax impacts.

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax benefit is as follows:


	Three-Month Periods
	Ended March 31,
		2021		2020

Federal statutory income tax rate		21	%	21	%
Income tax credits		136		(46)
State income tax, net of federal income tax impacts		21		0
Income tax effect of foreign income		6		(3)
Effects of ratemaking		10		(8)
Equity income		15		(1)
Noncontrolling interest		9		0
Other, net		(1)		1
Effective income tax rate		217	%	(36)	%

Income tax credits relate primarily to PTCs from wind-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods ended March 31, 2021 and 2020 totaled $315 million and $233 million, respectively.

The Company's provision for income taxes has been ~~presented for illustrative purposes only~~computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and ~~is not necessarily indicative~~Iowa state income tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. The Company made 0 payments for federal income taxes to Berkshire Hathaway for the three-month period ended March 31, 2021, and made payments for federal income taxes to Berkshire Hathaway totaling $100 million for the three-month period ended March 31, 2020.

(7) 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
	Ended March 31,
		2021		2020
Pension:
Service cost		$	7	$	3
Interest cost		20		23
Expected return on plan assets		(33)		(35)
Net amortization		6		9
Net periodic benefit cost		$	0	$	0

Other postretirement:
Service cost		$	2	$	1
Interest cost		5		6
Expected return on plan assets		(5)		(9)
Net amortization		(1)		(1)
Net periodic benefit cost (credit)		$	1	$	(3)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $13 million, respectively, during 2021. As of March 31, 2021, $3 million and $3 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

Net periodic benefit credit for the United Kingdom pension plan included the following components (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020

Service cost		$	4	$	4
Interest cost		8		10
Expected return on plan assets		(28)		(25)

Net amortization		14		10
Net periodic benefit credit		$	(2)	$	(1)

Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £50 million during 2021. As of March 31, 2021, £11 million, or $15 million, of contributions had been made to the United Kingdom pension plan.

(8) 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 March 31, 2021
Assets:
Commodity derivatives	$	1	$	72	$	154	$	(18)	$	209
Foreign currency exchange rate derivatives	—		12		—		—		12
Interest rate derivatives	0		33		47		—		80
Mortgage loans held for sale	0		2,065		0		—		2,065
Money market mutual funds(2)	807		0		0		—		807
Debt securities:
United States government obligations	210		0		0		—		210
International government obligations	0		5		0		—		5
Corporate obligations	0		71		0		—		71
Municipal obligations	0		2		0		—		2
Agency, asset and mortgage-backed obligations	0		5		0		—		5
Equity securities:
United States companies	395		0		0		—		395
International companies	4,780		0		0		—		4,780
Investment funds	256		0		0		—		256
	$	6,449	$	2,265	$	201	$	(18)	$	8,897
Liabilities:
Commodity derivatives	$	0	$	(90)	$	(30)	$	39	$	(81)
Foreign currency exchange rate derivatives	—		(1)		—		—		(1)
Interest rate derivatives	(3)		(14)		(6)		—		(23)
	$	(3)	$	(105)	$	(36)	$	39	$	(105)


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2020
Assets:
Commodity derivatives	$	1	$	73	$	135	$	(21)	$	188
Foreign currency exchange rate derivatives	—		20		—		—		20
Interest rate derivatives	0		0		62		—		62
Mortgage loans held for sale	0		2,001		0		—		2,001
Money market mutual funds(2)	873		0		0		—		873
Debt securities:
United States government obligations	200		0		0		—		200
International government obligations	0		5		0		—		5
Corporate obligations	0		73		0		—		73
Municipal obligations	0		2		0		—		2
Agency, asset and mortgage-backed obligations	0		6		0		—		6
Equity securities:
United States companies	381		0		0		—		381
International companies	5,906		0		0		—		5,906
Investment funds	201		0		0		—		201
	$	7,562	$	2,180	$	197	$	(21)	$	9,918
Liabilities:
Commodity derivatives	$	(1)	$	(90)	$	(19)	$	56	$	(54)
Foreign currency exchange rate derivatives	—		(2)		—		—		(2)
Interest rate derivatives	(5)		(60)		0		—		(65)
	$	(6)	$	(152)	$	(19)	$	56	$	(121)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $21 million and $35 million as of March 31, 2021 and December 31, 2020, 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.

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 underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.

The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.

The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):


	Three-Month Periods
	Ended March 31,
				Interest
		Commodity		Rate
		Derivatives		Derivatives
2021:
Beginning balance		$	116	$	62
Changes included in earnings(1)		(6)		(21)
Changes in fair value recognized in OCI		(1)		0
Changes in fair value recognized in net regulatory assets		16		0



Settlements		(1)		0

Ending balance		$	124	$	41







2020:
Beginning balance	$	97	$	14
Changes included in earnings(1)	(3)		31

Changes in fair value recognized in net regulatory assets	(40)		0
Purchases	2		0

Settlements	(4)		0

Ending balance	$	52	$	45

(1)Changes included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.

The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):


	As of March 31, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	49,461	$	55,926	$	49,866	$	60,633

(9) Commitments and Contingencies

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 ~~results~~financial results. The Company is also involved in other kinds of ~~operations that would~~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.

California and Oregon 2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property 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, including residences, destroyed; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.

Several lawsuits have been ~~achieved~~filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.

As of March 31, 2021, PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.

Environmental Laws and Regulations

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

Hydroelectric Relicensing

PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the FERC license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.

In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application by January 16, 2021 to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions.

Guarantees

The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.

(10) 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 energy and nonregulated energy, with further disaggregation of regulated energy by line of business, including a reconciliation to the Company's reportable segment information included in Note 13 (in millions):


	For the Three-Month Period Ended March 31, 2021
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,145	$	452	$	511	$	0	$	0	$	0	$	0	$	0	$	2,108
Retail gas	0		460		38		0		0		0		0		0		498
Wholesale	36		125		15		0		17		0		0		0		193
Transmission and distribution	25		15		21		263		0		172		0		0		496
Interstate pipeline	0		0		0		0		815		0		0		(41)		774
Other	23		0		0		0		2		0		0		0		25
Total Regulated	1,229		1,052		585		263		834		172		0		(41)		4,094
Nonregulated	0		10		0		10		237		8		166		187		618
Total Customer Revenue	1,229		1,062		585		273		1,071		180		166		146		4,712
Other revenue	13		5		6		27		22		0		24		40		137
Total	$	1,242	$	1,067	$	591	$	300	$	1,093	$	180	$	190	$	186	$	4,849


	For the Three-Month Period Ended March 31, 2020
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,122	$	410	$	529	$	0	$	0	$	0	$	0	$	0	$	2,061
Retail gas	0		187		47		0		0		0		0		0		234
Wholesale	0		64		14		0		0		0		0		(1)		77
Transmission and distribution	22		15		23		233		0		169		0		0		462
Interstate pipeline	0		0		0		0		400		0		0		(48)		352
Other	26		0		1		0		0		0		0		0		27
Total Regulated	1,170		676		614		233		400		169		0		(49)		3,213
Nonregulated	0		6		1		7		0		3		159		127		303
Total Customer Revenue	1,170		682		615		240		400		172		159		78		3,516
Other revenue	36		4		7		26		1		0		19		25		118
Total	$	1,206	$	686	$	622	$	266	$	401	$	172	$	178	$	103	$	3,634

(1)The BHE and Other reportable segment represents amounts related principally to other 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
	Ended March 31,
		2021		2020
Customer Revenue:
Brokerage		$	1,022	$	777
Franchise		18		16
Total Customer Revenue		1,040		793
Mortgage and other revenue		192		100
Total		$	1,232	$	893

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 March 31, 2021, by reportable segment (in millions):


	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	2,521	$	20,918	$	23,439
BHE Transmission	513		0		513
Total	$	3,034	$	20,918	$	23,952

(11) BHE Shareholders' Equity

For the three-month period ended March 31, 2020, BHE repurchased 180,358 shares of its common stock for $126 million.

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

The following table shows the change in accumulated other comprehensive income (loss) attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income tax (in millions):


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

Balance, December 31, 2019	$	(417)	$	(1,296)	$	7	$	(1,706)

Other comprehensive income (loss)	34		(548)		(33)		(547)
Balance, March 31, 2020	$	(383)	$	(1,844)	$	(26)	$	(2,253)

Balance, December 31, 2020	$	(482)	$	(1,062)	$	(8)	$	(1,552)
Other comprehensive income	7		91		14		112
Balance, March 31, 2021	$	(475)	$	(971)	$	6	$	(1,440)

(13) Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue:
PacifiCorp		$	1,242	$	1,206
MidAmerican Funding		1,067		686
NV Energy		591		622
Northern Powergrid		300		266
BHE Pipeline Group		1,093		401
BHE Transmission		180		172
BHE Renewables		190		178
HomeServices		1,232		893
BHE and Other(1)		186		103
Total operating revenue		$	6,081	$	4,527





Depreciation and amortization:
PacifiCorp	$	264	$	252
MidAmerican Funding	207		176
NV Energy	136		124
Northern Powergrid	71		63
BHE Pipeline Group	118		64
BHE Transmission	58		60
BHE Renewables	60		71
HomeServices	11		11
BHE and Other(1)	2		0
Total depreciation and amortization	$	927	$	821


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating income:
PacifiCorp		$	234	$	234
MidAmerican Funding		48		102
NV Energy		70		79
Northern Powergrid		151		132
BHE Pipeline Group		618		249
BHE Transmission		81		76
BHE Renewables		33		17
HomeServices		112		20
BHE and Other(1)		(14)		10
Total operating income		1,333		919
Interest expense		(530)		(483)
Capitalized interest		14		17
Allowance for equity funds		26		34
Interest and dividend income		21		20
(Losses) gains on marketable securities, net		(1,118)		27
Other, net		8		(27)
Total (loss) income before income tax benefit and equity loss		$	(246)	$	507





Interest expense:
PacifiCorp	$	107	$	102
MidAmerican Funding	78		81
NV Energy	52		58
Northern Powergrid	33		32
BHE Pipeline Group	38		14
BHE Transmission	38		38
BHE Renewables	40		42
HomeServices	1		5
BHE and Other(1)	143		111
Total interest expense	$	530	$	483


(Loss) earnings on common shares:
PacifiCorp	$	169	$	176
MidAmerican Funding	144		150
NV Energy	34		20
Northern Powergrid	104		87
BHE Pipeline Group	383		179
BHE Transmission	59		55
BHE Renewables	16		95
HomeServices	84		10
BHE and Other	(1,027)		(102)
(Loss) earnings on common shares	$	(34)	$	670


	As of
	March 31,		December 31,
	2021		2020
Assets:
PacifiCorp	$	26,956	$	26,862
MidAmerican Funding	24,098		23,530
NV Energy	14,594		14,501
Northern Powergrid	8,980		8,782
BHE Pipeline Group	19,651		19,541
BHE Transmission	9,341		9,208
BHE Renewables	11,935		12,004
HomeServices	5,186		4,955
BHE and Other(1)	6,781		7,933
Total assets	$	127,522	$	127,316

(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue by country:
United States		$	5,597	$	4,089
United Kingdom		300		266
Canada		177		171
Philippines and other		7		1
Total operating revenue by country		$	6,081	$	4,527


(Loss) income before income tax benefit and equity loss by country:
United States	$	(423)	$	354
United Kingdom	132		109
Canada	39		40
Philippines and other	6		4
Total (loss) income before income tax benefit and equity loss by country	$	(246)	$	507

The following table shows the change in the carrying amount of goodwill by reportable segment for the three-month period ended March 31, 2021 (in millions):


									BHE Pipeline Group
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid				BHE Transmission		BHE Renewables		HomeServices
																	Total

December 31, 2020	$	1,129	$	2,102	$	2,369	$	1,000	$	1,803	$	1,551	$	95	$	1,457	$	11,506
Acquisitions	—		—		—		—		—		—		—		1		1
Foreign currency translation	0		0		0		6		0		21		0		0		27

March 31, 2021	$	1,129	$	2,102	$	2,369	$	1,006	$	1,803	$	1,572	$	95	$	1,458	$	11,534

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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the ~~combined company.~~

Three Months Ended
March 31, 2019⁽¹⁾

(millions, except EPS)

Operating Revenue

$
4,887

Net income attributable to Dominion Energy

605

Earnings Per Common Share – Basic

$
0.76

Earnings Per Common Share – Diluted

$
0.76

~~(1)~~

~~Amounts include adjustments for non-recurring costs directly related to the SCANA Combination.~~

~~Dominion Energy Gas Restructuring~~

~~The Dominion Energy Gas Restructuring is considered to be a reorganization of entities under common control. As a result, Dominion Energy Gas’ basis in DCP and DMLPHCII, which includes~~Company during the general partner of Dominion Energy Midstream, a controlling 75% interest in Cove Point, DECG, Dominion Energy Questar Pipeline, a 50% noncontrolling interest in White River Hub and a 25.93% noncontrolling interest in Iroquois, is equal to Dominion Energy’s cost basis in the assets and liabilities of such entities since the applicable inception dates of common control. In November 2019, following completionperiods included herein. Explanations include management's best estimate of the ~~Dominion Energy Gas Restructuring, DCP~~impact of weather, customer growth, usage trends and ~~DMLPHCII are wholly-owned subsidiaries of Dominion Energy Gas and therefore are consolidated by Dominion Energy Gas. The accompanying~~other factors. This discussion should be read in conjunction with the Company's historical unaudited Consolidated Financial Statements and Notes ~~of Dominion Energy Gas have been retrospectively adjusted~~ to include the historical results and financial position of DCP and DMLPHCII. The 25% interest in Cove Point retained by Dominion Energy, and subsequently sold to Brookfield in December 2019, and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest.

The Dominion Energy Gas Restructuring includes the disposition of East Ohio and DGP by Dominion Energy Gas in November 2019. This restructuring represents a strategic shift in the operations of Dominion Energy Gas as Dominion Energy Gas’ operations consist of LNG import/export and storage and regulated gas transmission and storage operations. As a result, the accompanying Consolidated Financial Statements and Notes of Dominion Energy Gas have been retrospectively adjusted to include the historical results and financial position of East Ohio and DGP as discontinued operations until November 2019, presented within the Corporate and Other segment. As the Dominion Energy Gas Restructuring is considered to be a reorganization of entities under common control, Dominion Energy Gas has reflected the disposition as an equity transaction. The following table represents selected information regarding the results of operations of East Ohio, which are reported as discontinued operations in Dominion Energy Gas’ Consolidated Statements of Income:

Three Months Ended
March 31, 2019

(millions)

Operating revenue

$
229

Depreciation and amortization

21

Other operating expenses

148

Other income

18

Interest and related charges

10

Income tax expense

14

Net income from discontinued operations
$
54

~~Capital expenditures and significant noncash items relating to East Ohio included the following:~~

Three Months Ended
March 31, 2019

(millions)

Capital expenditures

$
65

Significant noncash items

Accrued capital expenditures

6

The following table represents selected information regarding the results of operations of DGP, which are reported as discontinued operations in Dominion Energy Gas’ Consolidated Statements of Income:

Three Months Ended
March 31, 2019

(millions)

Operating revenue

$
45

Depreciation and amortization

1

Other operating expenses

44

Net income from discontinued operations

$
—

~~Capital expenditures and significant noncash items of DGP included the following:~~

Three Months Ended
March 31, 2019

(millions)

Capital expenditures

$
3

~~Note 4. Operating Revenue~~

~~The Companies’ operating revenue consists of the following:~~

Three Months Ended March 31,

2020

2019

(millions)

Dominion Energy

Regulated electric sales:

Residential

$
1,158

$
646

Commercial

798

496

Industrial

182

30

Government and other retail

219

200

Wholesale

33

48

Nonregulated electric sales

232

316

Regulated gas sales:

Residential

548

602

Commercial

191

191

Other

28

38

Nonregulated gas sales

83

247

Regulated gas transportation and storage:

FERC-regulated

281

277

State-regulated

232

213

Nonregulated gas transportation and storage

175

174

Other regulated revenues⁽¹⁾

75

58

Other nonregulated revenues⁽¹⁾⁽²⁾

88

95

Total operating revenue from contracts
   with customers

4,323

3,631

Other revenues⁽³⁾

173

227

Total operating revenue

$
4,496

$
3,858

Virginia Power

Regulated electric sales:

Residential

$
896

$
923

Commercial

614

636

Industrial

97

112

Government and other retail

203

204

Wholesale

24

37

Other regulated revenues⁽²⁾

62

33

Other nonregulated revenues⁽¹⁾⁽²⁾

13

6

Total operating revenue from contracts
   with customers

1,909

1,951

Other revenues⁽²⁾⁽³⁾

21

14

Total operating revenue

$
1,930

$
1,965

Dominion Energy Gas

Regulated gas sales - wholesale

$
2

$
2

Nonregulated gas sales⁽²⁾

1

2

Regulated gas transportation and storage

344

340

Nonregulated gas transportation and storage

175

174

Management service revenue⁽²⁾

31

44

Other regulated revenues⁽¹⁾⁽²⁾

1

3

Other nonregulated revenues⁽¹⁾⁽²⁾

1

—

Total operating revenue from contracts
   with customers

555

565

Other revenues

1

1

Total operating revenue

$
556

$
566

~~Amounts above include sales which are considered to be goods transferred at a point in time. For the three months ended March 31, 2020 and 2019, such amounts included $~~39 million and $48 million, respectively, at Dominion Energy and $1 million for both the three months ended March 31, 2020 and 2019, at Dominion Energy Gas, consisting of NGL sales. Additionally, amounts above include sales of renewable energy credits. For the three months ended March 31, 2020 and 2019, such sales were $4 million and $3 million, respectively, at Dominion Energy and $3 million and $1 million, respectively, at Virginia Power.

2)	~~See Notes 10 and 19 for amounts attributable to related parties and affiliates.~~

3)	Includes alternative revenue. For the three months ended March 31, 2020 and 2019, such amounts included $36 million and $14 million, respectively, at Dominion Energy and $17 million and $8 million, respectively, at Virginia Power.

The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when the Companies expect to recognize this revenue. These revenues relate to contracts containing fixed prices where the Companies will earn the associated revenue over time as they stand ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which the Companies elect to recognize revenue in the amount they have a right to invoice.

Revenue expected to be recognized on multi-year
contracts in place at March 31, 2020

2020

2021

2022

2023

2024

Thereafter

Total

(millions)

Dominion Energy

$
1,222

$
1,562

$
1,474

$
1,312

$
1,187

$
13,089

$
19,846

Virginia Power

2

1

—

—

—

—

3

Dominion Energy Gas

1,336

1,714

1,581

1,395

1,242

13,270

20,538

Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. At March 31, 2020 and December 31, 2019, Dominion Energy’s contract asset balances were $26 million and $28 million, respectively. Dominion Energy Gas’ contract asset balances were $37 million and $40 million at March 31, 2020 and December 31, 2019, respectively. Dominion Energy and Dominion Energy Gas’ contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At March 31, 2020 and December 31, 2019, Dominion Energy’s contract liability balances were $86 million and $123 million, respectively. At March 31, 2020 and December 31, 2019, Virginia Power’s contract liability balances were $23 million and $24 million, respectively. At March 31, 2020 and December 31, 2019, Dominion Energy Gas’ contract liability balances were $21 million and $20 million, respectively. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets. The Companies recognize revenue as they fulfill their obligations to provide service to their customers. During the three months ended March 31, 2020 and 2019, Dominion Energy recognized revenue of $105 million and $85 million, respectively, from the beginning contract liability balances. During the three months ended March 31, 2020 and 2019, Virginia Power recognized $24 million and $22 million, respectively, from the beginning contract liability balance. During the three months ended March 31, 2020 and 2019, Dominion Energy Gas recognized $1 million and $25 million from the beginning contract liability balance.

~~Note 5. Income Taxes~~

~~For continuing operations, including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:~~

Dominion Energy

Virginia Power

Dominion Energy Gas

Three Months Ended March 31,

2020

2019

2020

2019

2020

2019

U.S. statutory rate

21.0
%

21.0
%

21.0
%

21.0
%

21.0
%

21.0
%

Increases (reductions) resulting from:

State taxes, net of federal benefit

4.4

2.2

4.8

4.6

2.9

3.4

Investment tax credits

(4.1
)

(1.5
)

(6.4
)

(3.2
)

—

—

Production tax credits

(0.4
)

(0.8
)

(0.8
)

(1.0
)

—

—

Reversal of excess deferred income
taxes

(9.5
)

(5.1
)

(8.1
)

(5.0
)

(0.7
)

(0.7
)

Write-off of regulatory assets

—

(34.1
)

—

—

—

—

AFUDC - equity

(1.6
)

(1.4
)

(0.7
)

—

(0.4
)

(0.5
)

Other, net

(2.5
)

(0.6
)

0.3

0.1

(2.4
)
⁽¹⁾

(3.3
)
⁽¹⁾
Effective tax rate

7.3
%

(20.3
)%

10.1
%

16.5
%

20.4
%

19.9
%

~~(1)~~

~~Includes (2.7)% and (3.6) % relating to the absence of tax on noncontrolling interest in 2020 and 2019, respectively~~.

For the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. The Companies have recorded an estimate of excess deferred income tax amortization in 2020. The reversal of these excess deferred income taxes will impact the effective tax rate and rates charged to customers. See Note 13 to the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the ~~Companies’~~future could differ significantly from the historical results.

Berkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE Transmission (which consists of BHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies, one of which owns an LNG import, export and storage facility, in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.

Results of Operations for the First Quarter of 2021 and 2020

Overview

Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):


	First Quarter
	2021		2020		Change
Operating revenue:
PacifiCorp	$	1,242	$	1,206	$	36	3	%
MidAmerican Funding	1,067		686		381		56
NV Energy	591		622		(31)		(5)
Northern Powergrid	300		266		34		13
BHE Pipeline Group	1,093		401		692		*
BHE Transmission	180		172		8		5
BHE Renewables	190		178		12		7
HomeServices	1,232		893		339		38
BHE and Other	186		103		83		81
Total operating revenue	$	6,081	$	4,527	$	1,554	34	%

(Loss) earnings on common shares:
PacifiCorp	$	169	$	176	$	(7)	(4)	%
MidAmerican Funding	144		150		(6)		(4)
NV Energy	34		20		14		70
Northern Powergrid	104		87		17		20
BHE Pipeline Group	383		179		204		*
BHE Transmission	59		55		4		7
BHE Renewables(1)	16		95		(79)		(83)
HomeServices	84		10		74		*
BHE and Other	(1,027)		(102)		(925)		*
(Loss) earnings on common shares	$	(34)	$	670	$	(704)	*

(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.

* Not meaningful

Earnings on common shares decreased $704 million for the first quarter of 2021 compared to 2020. The first quarter of 2021 included a pre-tax unrealized loss of $1,124 million ($818 million after-tax) compared to a pre-tax unrealized gain in the first quarter of 2020 of $54 million ($39 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first quarter of 2021 was $784 million, an increase of $153 million, or 24%, compared to adjusted earnings on common shares in the first quarter of 2020 of $631 million.

The decrease in earnings on common shares for the first quarter of 2021 compared to 2020 was primarily due to the following:

•$204 million higher net income at BHE Pipeline Group, primarily due to $107 million of incremental net income from BHE GT&S, acquired in November 2020, higher gross margin on gas sales and higher transportation revenue at Northern Natural Gas, largely due to the favorable impact of the February 2021 polar vortex weather event, and the impacts of the 2020 rate case settlement at Northern Natural Gas;

•$79 million lower net income at BHE Renewables, primarily due to lower wind tax equity investment earnings from net losses on existing tax equity investments, largely due to the February 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation;

•$74 million higher net income at HomeServices, primarily due to higher earnings from mortgage services (63% increase in funded mortgage volume) and brokerage services (35% increase in closed transaction volume) largely attributable to the favorable interest rate environment; and

•$925 higher net loss at BHE and Other due to the $857 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.

Reportable Segment Results

PacifiCorp

Operating revenue increased $36 million for the first quarter of 2021 compared to 2020, primarily due to higher retail revenue of $20 million and higher wholesale and other revenue of $16 million. Retail revenue increased due to higher customer volumes of $15 million and price impacts of $5 million from changes in sales mix, partially offset by lower rates due to certain general rate case orders. Retail customer volumes increased 0.3%, primarily due to an increase in the average number of customers and the favorable impact of weather, partially offset by lower customer usage. Wholesale and other revenue increased primarily due to higher wholesale volumes and higher average wholesale market prices.

Net income decreased $7 million for the first quarter of 2021 compared to 2020, primarily due to higher depreciation and amortization expense, including the impacts of a depreciation study effective in January 2021, lower allowances for equity and borrowed funds used during construction of $12 million and higher property taxes of $12 million, partially offset by higher utility margin of $29 million and favorable income tax expense from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service. Utility margin increased primarily due to the higher retail and wholesale revenue and lower purchased power costs, partially offset by higher natural gas-fueled and coal-fueled generation costs and higher net amortization of deferred net power costs in accordance with established adjustment mechanisms.

MidAmerican Funding

Operating revenue increased $381 million for the first quarter of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $303 million and higher electric operating revenue of $74 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold, primarily due to the February 2021 polar vortex weather event resulting in higher purchased gas adjustment recoveries of $304 million (offset in cost of sales). Electric operating revenue increased due to higher retail revenue of $40 million and higher wholesale and other revenue of $32 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to $32 million higher recoveries through the energy adjustment clauses (offset primarily in cost of sales), higher customer volumes of $5 million and price impacts of $5 million from changes in sales mix. Electric retail customer volumes increased 4.9% due to the favorable impact of weather and increased usage of certain industrial customers.

Net income decreased $6 million for the first quarter of 2021 compared to 2020, primarily due to higher depreciation and amortization expense of $31 million from additional assets placed in-service and the expiration of a regulatory mechanism deferring certain depreciation expense and $28 million higher operations and maintenance expenses, partially offset by a favorable income tax benefit and favorable changes in the cash surrender value of corporate-owned life insurance policies. Higher operations and maintenance expenses included increased costs associated with additional wind-powered generating facilities placed in-service as well as higher electric and natural gas distribution costs. The favorable income tax benefit was mainly due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service, partially offset by the impacts of ratemaking. Electric utility margin increased $3 million as the higher retail and wholesale revenue was largely offset by higher generation and purchased power costs.

NV Energy

Operating revenue decreased $31 million for the first quarter of 2021 compared to 2020, primarily due to lower electric operating revenue of $22 million and lower natural gas operating revenue of $9 million. Electric operating revenue decreased primarily due to lower base tariff general rates of $14 million, lower retail customer volumes, lower fully-bundled energy rates (offset in cost of sales) of $4 million and price impacts from changes in sales mix. Electric retail customer volumes, including distribution only service customers, decreased 3.2%, primarily due to the impacts of COVID-19, which resulted in lower distribution only service, industrial and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold (offset in cost of sales).

Net income increased $14 million for the first quarter of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $22 million, primarily from lower regulatory instructed deferrals and amortizations and lower plant operations and maintenance costs, favorable changes in the cash surrender value of corporate-owned life insurance policies, lower interest expense of $7 million and lower income tax expense from the impacts of ratemaking, partially offset by lower electric utility margin of $18 million and higher depreciation and amortization expense of $13 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service. Electric utility margin decreased primarily due to the lower base tariff general rates at Nevada Power, lower retail customer volumes and price impacts from changes in sales mix.

Northern Powergrid

Operating revenue increased $34 million for the first quarter of 2021 compared to 2020, primarily due to $21 million from the weaker United States dollar and higher distribution revenue of $13 million, mainly from increased tariff rates of $10 million. Net income increased $17 million for the first quarter of 2021 compared to 2020, primarily due to the higher distribution revenue and $7 million from the weaker United States dollar.

BHE Pipeline Group

Operating revenue increased $692 million for the first quarter of 2021 compared to 2020, primarily due to $559 million of incremental revenue at BHE GT&S, acquired in November 2020, higher gas sales at Northern Natural Gas of $91 million and higher transportation revenue of $33 million at Northern Natural Gas, largely due to the favorable impacts of the February 2021 polar vortex weather event. Net income increased $204 million for the first quarter of 2021 compared to 2020, primarily due to $107 million of incremental net income at BHE GT&S and higher earnings of $98 million at Northern Natural Gas. Northern Natural Gas' improved performance was primarily due to higher gross margin on gas sales of $75 million, higher transportation revenue and the impacts of the 2020 rate case settlement.

BHE Transmission

Operating revenue increased $8 million for the first quarter of 2021 compared to 2020, primarily due to $10 million from the stronger United States dollar and higher revenue from the Montana-Alberta Tie-Line, acquired in May 2020, partially offset by the impacts of a regulatory decision received in November 2020 at AltaLink. Net income increased $4 million for the first quarter of 2021 compared to 2020, primarily due to higher earnings from the Montana-Alberta Tie-Line and lower non-regulated interest expense at BHE Canada.

BHE Renewables

Operating revenue increased $12 million for the first quarter of 2021 compared to 2020, primarily due to higher hydro, geothermal and solar revenues from higher generation as well as favorable pricing at the geothermal facilities. Net income decreased $79 million for the first quarter 2021 compared to 2020, primarily due to lower wind tax equity investment earnings of $93 million, partially offset by the higher operating revenue. Wind tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $138 million, primarily due to the February 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation.

HomeServices

Operating revenue increased $339 million for the first quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $228 million from a 35% increase in closed transaction volume and higher mortgage revenue of $92 million from a 63% increase in funded mortgage volume due to an increase in refinance activity from the favorable interest rate environment. Net income increased $74 million for the first quarter of 2021 compared to 2020, primarily due to higher earnings from mortgage services of $36 million and brokerage services of $27 million largely attributable to the favorable interest rate environment.

BHE and Other

Operating revenue increased $83 million for the first quarter of 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes. Net loss increased $925 million for the first quarter of 2021 compared to 2020, primarily due to the $857 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.

Liquidity and Capital Resources

Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 for ~~more information.~~

~~In March 2020,~~further discussion regarding the ~~CARES Act was enacted which includes several significant business tax provisions that modify or temporarily suspend certain provisions~~limitation of ~~the 2017 Tax Reform Act. The CARES Act provisions are intended to improve cash flow and liquidity by, among other things, providing a temporary~~ ~~five-year~~ carryback for certain net operating losses, accelerating the refund of previously generated corporate alternative minimum tax credits and temporarily loosening the business interest limitation to 50% of adjusted taxable income for certain businesses. While Dominion Energy intends to utilize the income tax provisions of the CARES Act to accelerate the recognition of certain tax attributes, where applicable, they are not expected to provide a material benefit.

In connection with the SCANA Combination, Dominion Energy committed to forgo, or limit, the recovery of certain income tax-related regulatory assets associated with the NND Project. Dominion Energy’s 2019 effective tax rate reflects deferred income tax expense of $198 million in satisfaction of this commitment. Dominion Energy’s 2019 effective tax rate also reflects the changes in consolidated state income taxes resultingdistributions from ~~the SCANA Combination.~~

BHE's subsidiaries.

As of March 31, 2021, the Company's total net liquidity was as follows (in millions):


					MidAmerican		NV		Northern		BHE
	BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		Other		Total

Cash and cash equivalents	$	418	$	43	$	38	$	103	$	83	$	71	$	520	$	1,276

Credit facilities	3,500		1,200		1,509		650		207		935		3,232		11,233
Less:
Short-term debt	—		(95)		(387)		(55)		—		(218)		(1,944)		(2,699)
Tax-exempt bond support and letters of credit	—		(218)		(370)		—		—		(2)		—		(590)
Net credit facilities	3,500		887		752		595		207		715		1,288		7,944

Total net liquidity	$	3,918	$	930	$	790	$	698	$	290	$	786	$	1,808	$	9,220
Credit facilities:
Maturity dates	2022		2022		2021, 2022		2022		2023		2021, 2024		2021, 2022

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $1.5 billion and $1.2 billion, respectively. The increase was primarily due to improved operating results and favorable income tax cash flows, partially offset by changes in working capital.

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

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(1.4) billion and $(1.5) billion, respectively. The change was primarily due to lower funding of tax equity investments and lower capital expenditures of $61 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2021 was $(191) million. Sources of cash totaled $409 million and consisted of net proceeds from short-term debt. Uses of cash totaled $600 million and consisted mainly of repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $115 million and repayments of subsidiary debt totaling $26 million.

For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the three-month period ended March 31, 2020 was $1.4 billion. Sources of cash totaled $4.3 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and subsidiary debt issuances totaling $1.1 billion. Uses of cash totaled $3.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.3 billion, net repayments of short-term debt totaling $1.1 billion, repayments of BHE senior debt totaling $350 million and common stock repurchases totaling $126 million.

The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.

The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2020		2021		2021
Capital expenditures by business:
PacifiCorp	$	366	$	439	$	1,897
MidAmerican Funding	472		298		2,200
NV Energy	163		167		854
Northern Powergrid	159		179		732
BHE Pipeline Group	120		102		1,204
BHE Transmission	56		77		279
BHE Renewables	12		18		95
HomeServices	7		8		39
BHE and Other(1)	1		7		78
Total	$	1,356	$	1,295	$	7,378





Capital expenditures by type:
Wind generation	$	273	$	97	$	1,158
Electric distribution	365		427		1,849
Electric transmission	185		157		1,006
Natural gas transmission and storage	49		85		1,032
Solar generation	—		4		295
Other	484		525		2,038
Total	$	1,356	$	1,295	$	7,378

(1)BHE and Other represents amounts related principally to other entities, corporate functions and intersegment eliminations.

The Company's historical and forecast capital expenditures consisted mainly of the following:

•Wind generation expenditures include the following:

◦Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $154 million for the three-month period ended March 31, 2020. MidAmerican Energy's forecast expenditures in 2021 for the construction of additional wind-powered generating facilities total $391 million and include 202 MWs of wind-powered generating facilities expected to be placed in-service in 2021.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $24 million and $6 million for the three-month periods ended March 31, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $379 million for the remainder of 2021. 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. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of March 31, 2021, 80 MWs are currently expected to qualify for 100% of the federal PTCs available for 10 years following each facility's return to service, 591 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.

◦Construction of wind-powered generating facilities at PacifiCorp totaling $27 million and $89 million for the three-month periods ended March 31, 2021 and 2020, respectively, and includes the 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs expected to be placed in-service in 2021. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $100 million for 2021.

◦Repowering existing wind-powered generating facilities at PacifiCorp totaling $5 million and $16 million for the three-month periods ended March 31, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects were placed in service in 2019 and 2020 and the remaining repowering projects are expected to be placed in-service in 2021. The energy production from such repowered facilities is expected to qualify for 100% of the federal PTCs available for 10 years following each facility's return to service. Planned additional spending for certain existing wind-powered generating facilities totals $6 million for 2021.

◦Acquisition and repowering of wind-powered generating facilities at PacifiCorp totaling $1 million for the three-month period ended March 31, 2021. Planned additional spending for these wind-powered generating facilities totals $44 million for 2021.

•Electric distribution includes both growth and operating expenditures. Growth expenditures include new customer connections and enhancements to existing customer connections. Operating expenditures include ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, damage restoration and storm damage repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.

•Electric transmission includes both growth and operating expenditures. Growth expenditures include PacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020, the Nevada Utilities' Greenlink Nevada transmission expansion program and AltaLink's directly assigned projects from the Alberta Electric System Operator. Operating expenditures include system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.

•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, the Northern Natural Gas New Lisbon Expansion and Twin Cities Area Expansion projects. Operating expenditures include, among other items, asset modernization and pipeline integrity projects.

•Solar generation includes growth expenditures, including MidAmerican Energy's current plan for the construction of 117 MWs of small- and utility-scale solar generation during 2021, of which 37 MWs are expected to be placed in-service in 2021. Nevada Power's solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility. Commercial operation at Dry Lake is expected by the end of 2023.

•Other capital expenditures includes both growth and operating expenditures, including routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.

Other Renewable Investments

The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made no contributions for the three-month period ended March 31, 2021, and has commitments as of March 31, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $616 million for the remainder of 2021 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.

Contractual Obligations

As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the ~~Companies’ unrecognized tax benefits or possible changes that could reasonably be expected to occur during~~information provided in Item 7 of the ~~next twelve months. See Note 5 to the Consolidated Financial Statements in the Companies’~~Company's Annual Report on Form 10-K for the year ended December 31, 2020 other than the recent financing transactions and renewable tax equity investments previously discussed.

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. 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 ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.

The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.

~~Note 6. Earnings Per Share~~

~~The following table presents~~the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding. In November 2020, the PJM announced that the next capacity auction will be conducted in May 2021.

On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of ~~Dominion Energy’s basic and diluted EPS:~~

Three Months Ended March 31,

2020

2019

(millions, except EPS)

Net loss attributable to Dominion Energy

$
(270
)

$
(680
)
Preferred stock dividends (see Note 16)

(16
)

—

Net loss attributable to Dominion Energy – Basic & Diluted

(286
)

(680
)
Average shares of common stock outstanding – Basic & Diluted

838.2

793.1

Earnings Per Common Share – Basic & Diluted

$
(0.34
)

$
(0.86
)

~~As a result of a net loss for both the three months ended March 31, 2020 and 2019, the issuance of common stock under potentially-dilutive securities, as discussed in Note 8~~MOPR levels. In approving reforms to the ~~Consolidated Financial Statements~~PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the ~~Companies’~~capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.

Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be removed from the PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station.

Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020 and new regulatory matters occurring in 2021.

PacifiCorp

Utah

In March 2020, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $37 million of deferred power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. This reflected a 1.0% increase compared to current rates. The UPSC approved the request in February 2021 for rates effective March 1, 2021.

Oregon

In February 2020, PacifiCorp filed a general rate case, and in December 2020, the OPUC approved a net rate decrease of approximately $24 million, or 1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to the exclusion of the impacts of repowered wind facilities, new wind facilities and certain other new investments that had not been placed in service at the time of the filing. Additional compliance filings will be made to include these investments in rates concurrent when they are placed in service. In January 2021, the OPUC approved the second compliance filing to add the remainder of the Ekola Flats wind facility to rates, resulting in a rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2021, the OPUC approved the third compliance filing to add the Foote Creek repowered wind facility and the Pryor Mountain new wind facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021.

Wyoming

In September 2018, PacifiCorp filed an application for depreciation rate changes with the WPSC based on PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Updates since September 2018 include the filing of PacifiCorp's 2020 decommissioning studies in which a third‑party consultant was ~~considered antidilutive~~engaged to estimate decommissioning costs associated with coal-fueled generating facilities and ~~therefore excluded~~removal of Cholla Unit 4. In April 2020, PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in PacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp's general rate case, including depreciation for coal-fueled generating facilities and associated incremental decommissioning costs reflected in decommissioning studies and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing in August 2020 and a subsequent written order in December 2020. The general rate case hearing was rescheduled for February 2021. As a result of the hearing date change, PacifiCorp filed an application in October 2020 with the WPSC requesting authorization to defer costs associated with impacts of the depreciation study. A hearing for this deferral application is scheduled to occur in July 2021.

In March 2020, PacifiCorp filed a general rate case with the WPSC which reflected recovery of Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested a revision to the ECAM to eliminate the sharing band and requested authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the recovery of the depreciation of certain coal-fueled generation units over time periods that extend beyond the depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that modified its requested increase in base rates from $7 million to $9 million, or 1.3%, and reflected an update to the ~~calculation~~rate mitigation measures for using the 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC re-noticed PacifiCorp's case and rescheduled the hearings. The hearings began February 2021 and were completed in March 2021. The WPSC decision is pending. PacifiCorp has requested a rate effective date of ~~diluted EP~~July 1, 2021.

S
.

~~Note 7. Accumulated Other Comprehensive Income~~

~~Dominion Energy~~

~~The following table presents Dominion Energy’s~~

In April 2021, PacifiCorp filed its annual ECAM and RRA application with the WPSC requesting to refund $15 million of deferred net power costs and RECs to customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflects a 2.4% decrease compared to current rates. PacifiCorp has requested an interim rate effective date of July 1, 2021.

Idaho

In March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $14 million for deferred costs in 2020. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, changes in ~~AOCI by component, net of tax:~~

Deferred
gains and
losses on
derivatives-
hedging
activities

Unrealized
gains and
losses on
investment
securities

Unrecognized
pension and
other
postretirement
benefit costs

Other
comprehensive
loss from
equity method
investees

Total

(millions)

Three Months Ended March 31, 2020

Beginning balance

$
(407
)

$
37

$
(1,421
)

$
(2
)

$
(1,793
)
Other comprehensive income before reclassifications:
gains (losses)

(266
)

9

—

—

(257
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

22

(9
)

19

—

32

Net current period other comprehensive income (loss)

(244
)

—

19

—

(225
)
Ending balance

$
(651
)

$
37

$
(1,402
)

$
(2
)

$
(2,018
)
Three Months Ended March 31, 2019

Beginning balance

$
(235
)

$
2

$
(1,465
)

$
(2
)

$
(1,700
)
Other comprehensive income before reclassifications:
gains (losses)

(24
)

16

—

—

(8
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

(31
)

—

8

—

(23
)
Net current period other comprehensive income (loss)

(55
)

16

8

—

(31
)
Ending balance

$
(290
)

$
18

$
(1,457
)

$
(2
)

$
(1,731
)

~~(1)~~

~~See table below for details about these reclassifications.~~

~~The following table presents Dominion Energy’s reclassifications out of AOCI by component:~~

Details about AOCI components

Amounts
reclassified
from AOCI

Affected line item in the
Consolidated Statements of
Income
(millions)

Three Months Ended March 31, 2020

Deferred (gains) and losses on derivatives-hedging activities:

Commodity contracts

$
(7
)

Operating revenue

3

Purchased gas
Interest rate contracts

27

Interest and related charges
Foreign currency contracts

6

Other income (expense)
Total

29

Tax

(7
)

Income tax expense (benefit)
Total, net of tax

$
22

Unrealized (gains) and losses on investment securities:

Realized (gains) losses on sale of securities

$
(13
)

Other income (expense)
Total

(13
)

Tax

4

Income tax expense (benefit)
Total, net of tax

$
(9
)

Unrecognized pension and other postretirement benefit costs:

Amortization of prior-service costs (credits)

$
(6
)

Other income (expense)
Amortization of actuarial losses

30

Other income (expense)
Total

24

Tax

(5
)

Income tax expense (benefit)
Total, net of tax

$
19

Three Months Ended March 31, 2019

Deferred (gains) and losses on derivatives-hedging activities:

Commodity contracts

$
(54
)

Operating revenue

(3
)

Purchased gas
Interest rate contracts

10

Interest and related charges
Foreign currency contracts

6

Other income (expense)
Total

(41
)

Tax

10

Income tax expense (benefit)
Total, net of tax

$
(31
)

Unrecognized pension and other postretirement benefit costs:

Amortization of prior-service costs (credits)

$
(5
)

Other income (expense)
Amortization of actuarial losses

27

Other income (expense)
Total

22

Tax

(14
)

Income tax expense (benefit)
Total, net of tax

$
8

~~Virginia Power~~

~~The following table presents Virginia Power’s changes in AOCI by component, net of tax:~~

Deferred gains
and losses on
derivatives-
hedging
activities

Unrealized gains
and losses on
investment
securities

Total

(millions)

Three Months Ended March 31, 2020

Beginning balance

$
(34
)

$
5

$
(29
)
Other comprehensive income before reclassifications:
gains (losses)

(45
)

(2
)

(47
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

—

1

1

Net current period other comprehensive income (loss)

(45
)

(1
)

(46
)
Ending balance

$
(79
)

$
4

$
(75
)
Three Months Ended March 31, 2019

Beginning balance

$
(13
)

$
1

$
(12
)
Other comprehensive income before reclassifications:
gains (losses)

(7
)

2

(5
)
Amounts reclassified from AOCI: (gains) losses

—

—

—

Net current period other comprehensive income (loss)

(7
)

2

(5
)
Ending balance

$
(20
)

$
3

$
(17
)

~~(1)~~

~~See table below for details about these reclassifications.~~

~~The following table presents Virginia Power’s reclassifications out of AOCI by component:~~

Details about AOCI components

Amounts
reclassified
from AOCI

Affected line item in the
Consolidated Statements of
Income
(millions)

Three Months Ended March 31, 2020

Unrealized (gains) and losses on investment securities:

Realized (gains) losses on sale of securities

$
2

Other income (loss)
Total

2

Tax

(1
)

Income tax expense (benefit)
Total, net of tax

$
1

~~Dominion Energy Gas~~

~~The following table presents Dominion Energy Gas’ changes in AOCI by component, net of tax:~~

Deferred gains
and losses on
derivatives-
hedging
activities

Unrecognized
pension costs

Total

(millions)

Three Months Ended March 31, 2020

Beginning balance

$
(81
)

$
(106
)

$
(187
)
Other comprehensive income before reclassifications:
   gains (losses)

(91
)

—

(91
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

6

1

7

Net current period other comprehensive income (loss)

(85
)

1

(84
)
Ending balance

$
(166
)

$
(105
)

$
(271
)
Three Months Ended March 31, 2019

Beginning balance

$
(25
)

$
(144
)

$
(169
)
Other comprehensive income before reclassifications:
   gains (losses)

(27
)

—

(27
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

3

1

4

Net current period other comprehensive income (loss)

(24
)

1

(23
)
Less other comprehensive income (loss) attributable to noncontrolling
   interest

(1
)

—

(1
)
Ending balance

$
(48
)

$
(143
)

$
(191
)

~~(1)~~

~~See table below for details about these reclassifications.~~

~~The following table presents Dominion Energy Gas’ reclassifications out of AOCI by component:~~

~~Note 8. Fair Value Measurements~~

~~The Companies’ fair value measurements are made in accordance~~PTCs, RECs, and a resource tracking mechanism to match costs with the ~~policies discussed~~benefits of new wind and wind repowering projects until they are reflected in ~~Note 6~~base rates. This reflects a 1.1% decrease compared to current rates.

California

California Senate Bill 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the ~~Consolidated Financial Statements~~utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp submitted its 2021 California Wildfire Mitigation Plan Update in March 2021.

FERC Show Cause Order

On April 15, 2021, the ~~Companies’ Annual Report on Form 10-K for the year ended December 31, 2019. See Note 9 in this report for further information about the Companies’ derivatives~~FERC issued an order to show cause and ~~hedge accounting activities.~~

The Companies enter into certain physical and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards, futures, and swaps contracts. An option model is used to value Level 3 physical options. The discounted cash flow model for forwards, futures, and swaps calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free ratenotice of return, and credit spreads. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, certain forward market prices and implied price volatilities are considered unobservable.

The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at March 31, 2020. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

Fair Value
(millions)

Valuation Techniques

Unobservable Input

Range

Weighted
Average⁽¹⁾

Assets

Physical and financial forwards:

Natural gas⁽²⁾

$
48

Discounted cash flow

Market price (per Dth)
⁽³⁾

(2) - 3

(1
)
FTRs

1

Discounted cash flow

Market price (per MWh)
⁽³⁾

(1) - 2

—

Total assets

$
49

Liabilities

Financial forwards:

FTRs

$
4

Discounted cash flow

Market price (per MWh)
⁽³⁾

(2) - 2

—

Physical options:

Natural gas

2

Option model

Market price (per Dth)
⁽³⁾

1 - 2

1

Price volatility
⁽⁴⁾

45% - 83%

57
%
Total liabilities

$
6

~~(1)~~

~~Averages weighted by volume.~~

~~(2)~~

~~Includes basis.~~

~~(3)~~

~~Represents market prices beyond defined terms for Levels 1 and 2.~~

~~(4)~~

~~Represents volatilities unrepresented in published markets.~~

~~Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:~~

~~Significant Unobservable Inputs~~	~~Position~~	~~Change to Input~~	~~Impact on Fair Value~~ ~~Measurement~~
~~Market price~~	~~Buy~~	~~Increase (decrease)~~	~~Gain (loss)~~
~~Market price~~	~~Sell~~	~~Increase (decrease)~~	~~Loss (gain)~~
~~Price volatility~~	~~Buy~~	~~Increase (decrease)~~	~~Gain (loss)~~
~~Price volatility~~	~~Sell~~	~~Increase (decrease)~~	~~Loss (gain)~~

~~Recurring Fair Value Measurements~~

~~Dominion Energy~~

~~The following table presents Dominion Energy’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:~~

Level 1

Level 2

Level 3

Total

(millions)

At March 31, 2020

Assets

Derivatives:

Commodity

$
—

$
72

$
49

$
121

Interest rate

—

29

—

29

Investments⁽¹⁾:

Equity securities:

U.S.

3,313

—

—

3,313

Fixed income:

Corporate debt instruments

—

496

—

496

Government securities

437

739

—

1,176

Cash equivalents and other

18

2

—

20

Total assets

$
3,768

$
1,338

$
49

$
5,155

Liabilities

Derivatives:

Commodity

$
—

$
43

$
6

$
49

Interest rate

—

1,580

—

1,580

Foreign currency

—

17

—

17

Total liabilities

$
—

$
1,640

$
6

$
1,646

At December 31, 2019

Assets

Derivatives:

Commodity

$
—

$
55

$
19

$
74

Interest rate

—

11

—

11

Foreign currency

—

8

—

8

Investments⁽¹⁾:

Equity securities:

U.S.

4,195

—

—

4,195

Fixed income:

Corporate debt instruments

—

463

—

463

Government securities

473

719

—

1,192

Cash equivalents and other

19

1

—

20

Total assets

$
4,687

$
1,257

$
19

$
5,963

Liabilities

Derivatives:

Commodity

$
—

$
75

$
56

$
131

Interest rate

—

606

—

606

Foreign currency

—

3

—

3

Total liabilities

$
—

$
684

$
56

$
740

~~(1)~~

Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $277 million and $274 million of assets at March 31, 2020 and December 31, 2019, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

~~The following table presents the net change in Dominion Energy's assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:~~

Three Months Ended

March 31,

2020

2019

(millions)

Beginning balance

$
(37
)

$
64

Total realized and unrealized gains (losses):

Included in earnings:

Operating revenue

—

(1
)
Electric fuel and other energy-related purchases

(22
)

(4
)
Included in regulatory assets/liabilities

80

7

Settlements

22

(1
)
Purchases

—

(10
)
Transfers out of Level 3

—

(2
)
Ending balance

$
43

$
53

~~There are 0 unrealized gains and losses included in earnings in the Level 3 fair value category~~proposed penalty related to ~~assets/liabilities still held at the reporting date for the quarters ended March 31, 2020 and 2019.~~

~~Virginia Power~~

allegations made by FERC Office of Enforcement staff that PacifiCorp failed to comply with certain North American Electric Reliability Corporation (the "NERC") reliability standards associated with facility ratings on PacifiCorp's bulk electric system. The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at March 31, 2020. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

Fair Value
(millions)

Valuation Techniques

Unobservable Input

Range

Weighted
Average⁽¹⁾

Assets

Physical and financial forwards:

Natural gas⁽²⁾

$
48

Discounted cash flow

Market price (per Dth)
⁽³⁾

(2) - 2

(1
)
FTRs

1

Discounted cash flow

Market price (per MWh)
⁽³⁾

(1) - 2

—

Total assets

$
49

Liabilities

Financial forwards:

FTRs

$
4

Discounted cash flow

Market price (per MWh)
⁽³⁾

(2) - 2

—

Physical options:

Natural gas

2

Option model

Market price (per Dth)
⁽³⁾

1 - 2

1

Price volatility
⁽⁴⁾

45% - 83%

57
%
Total liabilities

$
6

~~(1)~~

~~Averages weighted by volume.~~

~~(2)~~

~~Includes basis.~~

~~(3)~~

~~Represents market prices beyond defined terms for Levels 1 and 2.~~

~~(4)~~

~~Represents volatilities unrepresented in published markets~~.

~~Sensitivity~~order directs PacifiCorp to show cause as to why it should not be assessed a civil penalty of ~~the fair value measurements to changes in the significant unobservable inputs is as follows:~~

~~Significant Unobservable Inputs~~	~~Position~~	~~Change to Input~~	~~Impact on Fair Value~~ ~~Measurement~~
~~Market price~~	~~Buy~~	~~Increase (decrease)~~	~~Gain (loss)~~
~~Market price~~	~~Sell~~	~~Increase (decrease)~~	~~Loss (gain)~~
~~Price volatility~~	~~Buy~~	~~Increase (decrease)~~	~~Gain (loss)~~
~~Price volatility~~	~~Sell~~	~~Increase (decrease)~~	~~Loss (gain)~~

~~The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:~~

Level 1

Level 2

Level 3

Total

(millions)

At March 31, 2020

Assets

Derivatives:

Commodity

$
—

$
2

$
49

$
51

Investments⁽¹⁾:

Equity securities:

U.S.

1,506

—

—

1,506

Fixed income:

Corporate debt instruments

—

285

—

285

Government securities

162

357

—

519

Total assets

$
1,668

$
644

$
49

$
2,361

Liabilities

Derivatives:

Commodity

$
—

$
18

$
6

$
24

Interest rate

—

991

—

991

Total liabilities

$
—

$
1,009

$
6

$
1,015

At December 31, 2019

Assets

Derivatives:

Commodity

$
—

$
3

$
19

$
22

Interest rate

—

2

—

2

Investments⁽¹⁾:

Equity securities:

U.S.

1,920

—

—

1,920

Fixed income:

Corporate debt instruments

—

256

—

256

Government securities

186

361

—

547

Cash equivalents and other

—

1

—

1

Total assets

$
2,106

$
623

$
19

$
2,748

Liabilities

Derivatives:

Commodity

$
—

$
47

$
56

$
103

Interest rate

—

363

—

363

Total liabilities

$
—

$
410

$
56

$
466

~~(1)~~

~~Includes investments held in the nuclear decommissioning trusts. Excludes $157~~$42 million and $159 million of assets at March 31, 2020 and December 31, 2019, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

~~The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:~~

Three Months Ended

March 31,

2020

2019

(millions)

Beginning balance

$
(37
)

$
60

Total realized and unrealized losses:

Included in earnings:

Electric fuel and other energy-related purchases

(22
)

(4
)
Included in regulatory assets/liabilities

80

8

Settlements

22

(5
)
Ending balance

$
43

$
59

There were 0 unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three months ended March 31, 2020 and 2019.

~~Dominion Energy Gas~~

The following table presents Dominion Energy Gas’ assets and liabilities for derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions.

Level 1

Level 2

Level 3

Total

(millions)

At March 31, 2020

Liabilities

Interest rate

$
—

$
190

$
—

$
190

Foreign currency

—

17

—

17

Total liabilities

$
—

$
207

$
—

$
207

At December 31, 2019

Assets

Foreign currency

$
—

$
8

$
—

$
8

Total assets

$
—

$
8

$
—

$
8

Liabilities

Interest rate

$
—

$
83

$
—

$
83

Foreign currency

—

3

—

3

Total liabilities

$
—

$
86

$
—

$
86

~~Fair Value of Financial Instruments~~

Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash, restricted cash and equivalents, customer and other receivables, affiliated receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies' financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

March 31, 2020

December 31, 2019

Carrying
Amount

Estimated
Fair
Value⁽¹⁾

Carrying
Amount

Estimated
Fair
Value⁽¹⁾

(millions)

Dominion Energy

Long-term debt⁽²⁾

$
32,984

$
35,685

$
32,055

$
36,155

Junior subordinated notes⁽³⁾

4,407

4,381

4,797

4,953

Virginia Power

Long-term debt⁽³⁾

$
12,327

$
13,998

$
12,326

$
14,281

Dominion Energy Gas

Long-term debt⁽⁴⁾

$
5,516

$
5,479

$
5,520

$
5,738

~~(1)~~

Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

~~(2)~~

Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs, discount or premium and foreign currency remeasurement adjustments. At March 31, 2020 and December 31, 2019, includes the valuation of certain fair value hedges associated with fixed rate debt of $4 million and $4 million, respectively.

~~(3)~~

~~Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs, discount or premium.~~

~~(4)~~

~~Note 9. Derivatives and Hedge Accounting Activities~~

The Companies’ accounting policies, objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019. See Note 8 in this report for further information about fair value measurements and associated valuation methods for derivatives.

Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Dominion Energy’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Virginia Power and Dominion Energy Gas’ derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.

In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure. See Note 18 for further information regarding credit-related contingent features for the Companies’ derivative instruments.

~~Dominion Energy~~

~~Balance Sheet Presentation~~

The tables below present Dominion Energy’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

March 31, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Assets
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

Gross Assets
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
55

$
3

$
—

$
52

$
35

$
21

$
—

$
14

Exchange

64

16

34

14

37

21

—

16

Interest rate contracts:

Over-the-counter

29

21

—

8

11

3

—

8

Foreign currency contracts:

Over-the-counter

—

—

—

—

8

8

—

—

Total derivatives, subject to a
master netting or similar
arrangement

$
148

$
40

$
34

$
74

$
91

$
53

$
—

$
38

~~(1)~~

~~Excludes $2million and $2 million of derivative assets at March 31, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.~~

March 31, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross
Liabilities
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

Gross
Liabilities
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
27

$
3

$
1

$
23

$
105

$
21

$
—

$
84

Exchange

16

16

—

—

21

21

—

—

Interest rate contracts:

Over-the-counter

1,580

21

23

1,536

606

8

35

563

Foreign currency contracts:

Over-the-counter

17

—

—

17

3

3

—

—

Total derivatives, subject to a
master netting or similar
arrangement

$
1,640

$
40

$
24

$
1,576

$
735

$
53

$
35

$
647

~~(1)~~

~~Excludes $6million and $5 million of derivative liabilities at March 31, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.~~

~~Volumes~~

The following table presents the volume of Dominion Energy’s derivative activity at March 31, 2020. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.

Current

Noncurrent

Natural Gas (bcf):

Fixed price⁽¹⁾

81

36

Basis

268

574

Electricity (MWh):

Fixed price

3,088,875

—

FTRs

18,836,472

—

Liquids (Gal)⁽²⁾

39,690,000

—

Interest rate⁽³⁾

$
2,450,000,000

$
5,582,850,761

Foreign currency⁽³⁾

€
-

€
250,000,000

~~(1)~~

~~Includes options.~~

~~(2)~~

~~Includes NGLs.~~

~~(3)~~

~~Maturity is determined based on final settlement period.~~

~~AOCI~~

~~The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy’s Consolidated Balance Sheet at March 31, 2020:~~

AOCI
After-Tax

Amounts Expected to be
Reclassified to Earnings
During the Next 12 Months
After-Tax

Maximum Term
(millions)

Commodities:

Gas

$
(2
)

$
(2
)

21 months
Electricity

14

14

9 months
NGL

1

1

9 months
Interest rate

(655
)

(50
)

381 months
Foreign currency

(9
)

(1
)

75 months
Total

$
(651
)

$
(38
)

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of ~~changes in market prices, interest rates~~the alleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and ~~foreign currency exchange rates.~~

~~Fair Value Hedges~~

~~For derivative instruments that are designated~~remediate certain discrepancies resulting from transmission facility design and ~~qualify as~~actual field conditions, including transmission line clearances. PacifiCorp will file a ~~fair value hedge, the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable~~response to the ~~hedged risk are recognized~~allegations with the FERC.

MidAmerican Energy

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the central United States caused disruptions in ~~current earnings~~natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and ~~presented~~caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the ~~same line item. There were 0 derivative instruments designated~~impact to customers, the IUB ordered the recovery of these higher costs to be applied to natural gas sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in ~~fair value hedges~~higher working capital requirements during the ~~three months~~three-month period ended March 31, ~~2020. Gains~~2021.

NV Energy (Nevada Power and ~~losses on derivatives in fair value hedge relationships were immaterial for~~Sierra Pacific)

Price Stability Tariff

In November 2018, the ~~three months ended March 31, 2019.~~

Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The ~~following table presents~~Nevada Utilities have designed the ~~amounts recorded on~~CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the ~~balance sheet related to cumulative basis adjustments for fair value hedges:~~

Carrying Amount of the Hedged Asset
(Liability)⁽¹⁾

Cumulative Amount of Fair Value Hedging
Adjustments Included in the Carrying Amount
of the Hedged Assets (Liabilities)⁽²⁾

March 31, 2020

December 31, 2019

March 31, 2020

December 31, 2019

(millions)

Long-term debt

$
(1,154
)

$
(1,154
)

$
(4
)

$
(4
)

~~(1)~~

~~Includes $(1.1) billion and $(397) million related to discontinued hedging relationships at March 31, 2020 and December 31, 2019, respectively.~~

~~(2)~~

~~Includes $(4) million and $3 million of hedging adjustments on discontinued hedging relationships at March 31, 2020 and December 31, 2019, respectively.~~

~~Fair Value and Gains and Losses on Derivative Instruments~~

~~The following table presents the fair values of Dominion Energy’s derivatives and where they are presented in its Consolidated Balance Sheets:~~

Fair Value –
Derivatives under
Hedge
Accounting

Fair Value –
Derivatives not under
Hedge
Accounting

Total Fair Value

(millions)

March 31, 2020

ASSETS

Current Assets

Commodity

$
—

$
80

$
80

Interest rate

—

11

11

Total current derivative assets⁽¹⁾

—

91

91

Noncurrent Assets

Commodity

—

41

41

Interest rate

—

18

18

Total noncurrent derivative assets⁽²⁾

—

59

59

Total derivative assets

$
—

$
150

$
150

LIABILITIES

Current Liabilities

Commodity

$
—

$
45

$
45

Interest rate

515

232

747

Foreign currency

1

—

1

Total current derivative liabilities

516

277

793

Noncurrent Liabilities

Commodity

—

4

4

Interest rate

722

111

833

Foreign currency

16

—

16

Total noncurrent derivative liabilities

738

115

853

Total derivative liabilities

$
1,254

$
392

$
1,646

December 31, 2019

ASSETS

Current Assets

Commodity

$
30

$
37

$
67

Interest rate

1

—

1

Total current derivative assets⁽¹⁾

31

37

68

Noncurrent Assets

Commodity

1

6

7

Interest rate

10

—

10

Foreign currency

8

—

8

Total noncurrent derivative assets⁽²⁾

19

6

25

Total derivative assets

$
50

$
43

$
93

LIABILITIES

Current Liabilities

Commodity

$
6

$
77

$
83

Interest rate

321

1

322

Foreign currency

3

—

3

Total current derivative liabilities

330

78

408

Noncurrent Liabilities

Commodity

1

47

48

Interest rate

267

17

284

Total noncurrent derivative liabilities

268

64

332

Total derivative liabilities

$
598

$
142

$
740

~~(1)~~

~~Current derivative assets are presented in other current assets in Dominion Energy’s Consolidated Balance Sheets.~~

~~(2)~~

~~Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy’s Consolidated Balance Sheets.~~

~~The following tables present the gains and losses on Dominion Energy’s derivatives, as well as where the associated activity~~Nevada Revised Statutes, with a market-based pricing option that is ~~presented in its Consolidated Balance Sheets and Statements of Income.~~

Derivatives in cash flow hedging relationships

Amount of Gain
(Loss) Recognized
in AOCI on
Derivatives⁽¹⁾

Amount of Gain
(Loss) Reclassified
From AOCI to
Income

Increase
(Decrease) in
Derivatives
Subject to
Regulatory
Treatment⁽²⁾

(millions)

Three Months Ended March 31, 2020

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
7

Purchased gas

(3
)

Total commodity

$
—

$
4

$
—

Interest rate⁽³⁾

(336
)

(27
)

(563
)
Foreign currency⁽⁴⁾

(23
)

(6
)

—

Total

$
(359
)

$
(29
)

$
(563
)
Three Months Ended March 31, 2019

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
54

Purchased gas

3

Total commodity

$
66

$
57

$
—

Interest rate⁽³⁾

(84
)

(10
)

(84
)
Foreign currency⁽⁴⁾

(11
)

(6
)

—

Total

$
(29
)

$
41

$
(84
)

~~(1)~~

~~Amounts deferred into AOCI have no associated effect in Dominion Energy’s Consolidated Statements of Income.~~

~~(2)~~

Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income.

~~(3)~~

~~Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in interest and related charges.~~

~~(4)~~

~~Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in other income (expense).~~

Derivatives not designated as hedging instruments

Amount of Gain (Loss) Recognized
in Income on Derivatives⁽¹⁾

Three Months Ended

March 31,

2020

2019

(millions)

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
65

$
3

Purchased gas

(14
)

3

Electric fuel and other energy-related purchases

(65
)

(9
)
Interest rate⁽²⁾

(61
)

—

Total

$
(75
)

$
(3
)

~~(1)~~

Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income.

~~(2)~~

~~Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in interest and related charges.~~

~~Virginia Power~~

~~Balance Sheet Presentation~~

The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

March 31, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Assets Presented
in the
Consolidated
Balance Sheet⁽¹⁾

Financial Instruments

Cash
Collateral
Received

Net
Amounts

Gross
Assets Presented
in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
48

$
1

$
—

$
47

$
19

$
18

$
—

$
1

Interest rate contracts:

Over-the-counter

—

—

—

—

2

—

—

2

Total derivatives, subject to a
master netting or similar
arrangement

$
48

$
1

$
—

$
47

$
21

$
18

$
—

$
3

~~(1)~~

~~Excludes $3million and $3 million of derivative assets at March 31, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.~~

March 31, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross
Liabilities
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

Gross
Liabilities
Presented in the Consolidated Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
4

$
1

$
1

$
2

$
59

$
18

$
—

$
41

Interest rate contracts:

Over-the-counter

991

—

—

991

363

—

—

363

Total derivatives, subject to a
master netting or similar
arrangement

$
995

$
1

$
1

$
993

$
422

$
18

$
—

$
404

~~(1)~~

~~Excludes $20million and $44 million of derivative liabilities at March 31, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.~~

~~Volumes~~

~~The following table presents the volume of Virginia Power’s derivative activity at March 31, 2020. These volumes are~~ based on ~~open derivative positions~~renewable resources. The CPST provides for an energy rate that would replace the Base Tariff Energy Rate and ~~represent~~DEAA. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the ~~combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.~~

Current

Noncurrent

Natural Gas (bcf):

Fixed price⁽¹⁾

37

14

Basis

160

536

Electricity (MWh):

FTRs

18,836,472

—

Interest rate⁽²⁾

$
900,000,000

$
1,150,000,000

~~(1)~~

~~Includes options.~~

~~(2)~~

~~Maturity is determined based on final settlement period.~~

~~AOCI~~

~~The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at March 31, 2020:~~

AOCI
After-Tax

Amounts Expected to be
Reclassified to Earnings
During the Next 12
Months After-Tax

Maximum Term
(millions)

Interest rate

$
(79
)

$
(1
)

381 months
Total

$
(79
)

$
(1
)

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of interest rates contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates.

~~Fair Value and Gains and Losses on Derivative Instruments~~

~~The following table presents the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:~~

Fair Value –
Derivatives under
Hedge
Accounting

Fair Value –
Derivatives not under
Hedge
Accounting

Total Fair Value

(millions)

March 31, 2020

ASSETS

Current Assets

Commodity

$
—

$
14

$
14

Total current derivative assets⁽¹⁾

—

14

14

Noncurrent Assets

Commodity

—

37

37

Total noncurrent derivative assets⁽²⁾

—

37

37

Total derivative assets

$
—

$
51

$
51

LIABILITIES

Current Liabilities

Commodity

$
—

$
23

$
23

Interest rate

458

—

458

Total current derivative liabilities

458

23

481

Noncurrent Liabilities

Commodity

—

1

1

Interest rate

533

—

533

Total noncurrent derivatives liabilities⁽³⁾

533

1

534

Total derivative liabilities

$
991

$
24

$
1,015

December 31, 2019

ASSETS

Current Assets

Commodity

$
—

$
20

$
20

Total current derivative assets⁽¹⁾

—

20

20

Noncurrent Assets

Commodity

—

2

2

Interest rate

2

—

2

Total noncurrent derivative assets⁽²⁾

2

2

4

Total derivative assets

$
2

$
22

$
24

LIABILITIES

Current Liabilities

Commodity

$
—

$
58

$
58

Interest rate

185

—

185

Total current derivative liabilities

185

58

243

Noncurrent Liabilities

Commodity

—

45

45

Interest rate

178

—

178

Total noncurrent derivatives liabilities⁽³⁾

178

45

223

Total derivative liabilities

$
363

$
103

$
466

~~(1)~~

~~Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets.~~

~~(2)~~

~~Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheets.~~

~~(3)~~

~~Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets.~~

~~The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:~~

~~(1)~~

~~Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income.~~

~~(2)~~

Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

~~(3)~~

~~Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.~~

~~(1)~~

Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

~~(2)~~

~~Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.~~

~~Dominion Energy Gas~~

~~Balance Sheet Presentation~~

The tables below present Dominion Energy Gas’ derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

March 31, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Assets
Presented in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

Gross Assets
Presented in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Foreign currency contracts:

Over-the-counter

$
—

$
—

$
—

$
—

$
8

$
8

$
—

$
—

Total derivatives, subject to a
master netting or similar
arrangement

$
—

$
—

$
—

$
—

$
8

$
8

$
—

$
—

March 31, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross
Liabilities Presented
in the Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

Gross
Liabilities Presented
in the Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Interest rate contracts:

Over-the-counter

$
190

$
—

$
—

$
190

$
83

$
5

$
—

$
78

Foreign currency contracts:

Over-the-counter

17

—

—

17

3

3

—

—

Total derivatives, subject to a
master netting or similar
arrangement

$
207

$
—

$
—

$
207

$
86

$
8

$
—

$
78

~~Volumes~~

The following table presents the volume of Dominion Energy Gas’ derivative activity at March 31, 2020. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.

Current

Noncurrent

Interest rate⁽¹⁾

$
250,000,000

$
1,050,000,000

Foreign currency⁽¹⁾

€
-

€
250,000,000

~~(1)~~

~~Maturity is determined based on final settlement period.~~

~~AOCI~~

~~The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at March 31, 2020:~~

AOCI
After-Tax

Amounts Expected
to be Reclassified to
Earnings During the
Next 12 Months
After-Tax

Maximum Term
(millions)

Interest rate

$
(157
)

$
(11
)

297 months
Foreign currency

(9
)

(1
)

75 months
Total

$
(166
)

$
(12
)

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates and foreign currency exchange rates.

~~Fair Value and Gains and Losses on Derivative Instruments~~

~~The following tables present the fair values of Dominion Energy Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:~~

Fair Value-
Derivatives
Under Hedge
Accounting

Fair Value-Derivatives
Not Under Hedge
Accounting

Total Fair Value

(millions)

March 31, 2020

LIABILITIES

Current Liabilities

Interest rate

$
57

$
11

$
68

Foreign currency

1

—

1

Total current derivative liabilities⁽²⁾

58

11

69

Noncurrent Liabilities

Interest rate

119

3

122

Foreign currency

16

—

16

Total noncurrent derivative liabilities⁽³⁾

135

3

138

Total derivative liabilities

$
193

$
14

$
207

December 31, 2019

ASSETS

Noncurrent Assets

Foreign currency

$
8

$
—

$
8

Total noncurrent derivative assets⁽¹⁾

8

—

8

Total derivative assets

$
8

$
—

$
8

LIABILITIES

Current Liabilities

Interest rate

$
30

$
—

$
30

Foreign currency

3

—

3

Total current derivative liabilities⁽²⁾

33

—

33

Noncurrent Liabilities

Interest rate

53

—

53

Total noncurrent derivative liabilities⁽³⁾

53

—

53

Total derivative liabilities

$
86

$
—

$
86

~~(1)~~

~~Noncurrent derivatives assets are presented in other deferred charges and other assets in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(2)~~

~~Current derivative liabilities are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(3)~~

~~Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

The following table presents the gains and losses on Dominion Energy Gas’ derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:

Derivatives in cash flow hedging relationships

Amount of Gain
(Loss) Recognized in AOCI on
Derivatives⁽¹⁾

Amount of Gain
(Loss) Reclassified From AOCI
to Income

(millions)

Three Months Ended March 31, 2020

Derivative Type and Location of Gains (Losses):

Interest rate⁽²⁾

$
(100
)

$
(2
)
Foreign currency⁽³⁾

(23
)

(6
)
Total

$
(123
)

$
(8
)
Three Months Ended March 31, 2019

Derivative Type and Location of Gains (Losses):

Commodity:

Net income from discontinued operations

$
2

Total commodity

$
(1
)

$
2

Interest rate⁽²⁾

(24
)

1

Foreign currency⁽³⁾

(11
)

(6
)
Total

$
(36
)

$
(3
)

~~(1)~~

~~Amounts deferred into AOCI have no associated effect in Dominion Energy Gas’ Consolidated Statements of Income.~~

~~(2)~~

~~Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in interest and related charges.~~

~~(3)~~

~~Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in other income.~~

Derivatives not designated as hedging instruments

Amount of Gain (Loss) Recognized in Income on Derivatives

Three Months Ended

March 31,

2020

2019

(millions)

Derivative type and location of gains (losses):

Interest rate⁽¹⁾

$
(8
)

$
—

Total

$
(8
)

$
—

~~(1)~~

~~Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in interest and related charges.~~

~~Note 10. Investments~~

~~Dominion Energy~~

~~Equity and Debt Securities~~

~~Rabbi Trust Securities~~

~~Equity and fixed income securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $116million and $120 million at March 31, 2020 and December 31, 2019, respectively.~~

~~Decommissioning Trust Securities~~

Dominion Energy holds equity and fixed income securities, insurance contracts and cash equivalents in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below:

Amortized
Cost

Total
Unrealized
Gains

Total
Unrealized
Losses

Allowance for Credit Losses

Fair
Value

(millions)

March 31, 2020

Equity securities:⁽¹⁾

U.S.

$
1,813

$
1,709

$
(161
)

$
—

$
3,361

Fixed income securities:⁽²⁾

Corporate debt instruments

491

18

—

(13
)

496

Government securities

1,084

55

—

(6
)

1,133

Common/collective trust funds

118

2

—

(2
)

118

Insurance contracts

209

—

—

—

209

Cash equivalents and other⁽³⁾

—

—

(4
)

—

(4
)
Total

$
3,715

$
1,784

$
(165
)
⁽⁴⁾
$
(21
)

$
5,313

December 31, 2019

Equity securities:⁽¹⁾

U.S.

$
1,807

$
2,451

$
(20
)

$
—

$
4,238

Fixed income securities:⁽²⁾

Corporate debt instruments

434

29

—

—

463

Government securities

1,108

39

(2
)

—

1,145

Common/collective trust funds

115

4

—

—

119

Insurance contracts

214

—

—

—

214

Cash equivalents and other⁽³⁾

13

—

—

—

13

Total

$
3,691

$
2,523

$
(22
)
⁽⁴⁾
$
—

$
6,192

~~(1)~~

U~~nrealized gains and losses on equity securities are included in other income and the nuclear decommissioning trust regulatory liability.~~

~~(2)~~

Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability. Effective January 2020, changes in allowance for credit losses are included in other income (expense).

~~(3)~~

~~Includes pending purchases of securities of $12 million and $1 million at March 31, 2020 and December 31, 2019, respectively~~.

~~(4)~~

~~The fair value of securities in an unrealized loss position was $415 million and $298 millionat March 31, 2020 and December 31, 2019, respectively.~~

~~The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below:~~

Three Months Ended March 31,

2020

2019

(millions)

Net gains (losses) recognized during the period

$
(898
)

$
414

Less: Net (gains) losses recognized during the period
on securities sold during the period

14

(19
)
Unrealized gains (losses) recognized during the period
on securities still held at March 31, 2020 and 2019⁽¹⁾

$
(884
)

$
395

~~(1)~~

~~Included in other income and the nuclear decommissioning trust regulatory liability.~~

~~The fair value of Dominion Energy’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at March 31, 2020 by contractual maturity is as follows:~~

Amount

(millions)

Due in one year or less

$
178

Due after one year through five years

430

Due after five years through ten years

389

Due after ten years

750

Total

$
1,747

~~Presented below is selected information regarding Dominion Energy’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds.~~

Three Months Ended March 31,

2020

2019

(millions)

Proceeds from sales

$
602

$
506

Realized gains⁽¹⁾

66

43

Realized losses⁽¹⁾

69

23

~~(1)~~

~~Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability.~~

~~Virginia Power~~

Virginia Power holds equity and fixed income securities and cash equivalents in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:

Amortized
Cost

Total
Unrealized
Gains

Total
Unrealized
Losses

Allowance for Credit Losses

Fair
Value

(millions)

March 31, 2020

Equity securities:⁽¹⁾

U.S.

$
898

$
796

$
(80
)

$
—

$
1,614

Fixed income securities:⁽²⁾

Corporate debt instruments

284

9

—

(8
)

285

Government securities

504

18

—

(4
)

518

Common/collective trust funds

49

—

—

—

49

Cash equivalents and other⁽³⁾

2

—

—

—

2

Total

$
1,737

$
823

$
(80
)
⁽⁴⁾
$
(12
)

$
2,468

December 31, 2019

Equity securities:⁽¹⁾

U.S.

$
894

$
1,144

$
(11
)

$
—

$
2,027

Fixed income securities:⁽²⁾

Corporate debt instruments

241

15

—

—

256

Government securities

534

14

(2
)

—

546

Common/collective trust funds

51

—

—

—

51

Cash equivalents and other

1

—

—

—

1

Total

$
1,721

$
1,173

$
(13
)
⁽⁴⁾
$
—

$
2,881

~~(1)~~

~~Unrealized gains and losses on equity securities are included in other income and the nuclear decommissioning trust regulatory liability.~~

~~(2)~~

~~Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability~~. ~~Effective January 2020, changes in allowance for credit losses are included in other income (expense).~~

~~(3)~~

~~Includes pending sales of securities of $2 million at March 31, 2020.~~

~~(4)~~

~~The fair value of securities in an unrealized loss position was $241 million and $185 millionat March 31, 2020 and December 31, 2019, respectively.~~

~~The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below:~~

Three Months Ended March 31,

2020

2019

(millions)

Net gains (losses) recognized during the period

$
(423
)

$
186

Less: Net (gains) losses recognized during the period
on securities sold during the period

6

(1
)
Unrealized gains (losses) recognized during the period
on securities still held at March 31, 2020 and 2019⁽¹⁾

$
(417
)

$
185

~~(1)~~

~~Included in other income and the nuclear decommissioning trust regulatory liability.~~

~~The fair value of Virginia Power’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at March 31, 2020 by contractual maturity is as follows:~~

Amount

(millions)

Due in one year or less

$
73

Due after one year through five years

200

Due after five years through ten years

211

Due after ten years

368

Total

$
852

~~Presented below is selected information regarding Virginia Power’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds.~~

Three Months Ended March 31,

2020

2019

(millions)

Proceeds from sales

$
294

$
253

Realized gains⁽¹⁾

31

10

Realized losses⁽¹⁾

31

9

~~(1)~~

~~Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability.~~

~~Equity Method Investments~~

~~Dominion Energy~~

~~Atlantic Coast Pipeline~~

In March 2020, Dominion Energy completed the acquisition from Southern of its 5% membership interest in Atlantic Coast Pipeline and its 100% ownership interest in Pivotal LNG, Inc., for $184 million in aggregate, subject to certain purchase price adjustments. Pivotal LNG, Inc. includes a 50% noncontrolling interest in JAX LNG, LLC, an LNG supplier in Florida serving the growing marine and truck LNG markets. Following completion of the acquisition, Dominion Energy owns a 53% noncontrolling membership interest in Atlantic Coast Pipeline with Duke owning the remaining interest.

Atlantic Coast Pipeline continues to be reflected as an equity method investment as the power to direct the activities most significant to Atlantic Coast Pipeline is shared with Duke. As a result, Dominion Energy hasPUCN granted several intervenors the ability to ~~exercise significant influence, but not control, over the investee.~~

Dominion Energy recorded contributions of $16 million and $95 million during the three months ended March 31, 2020 and 2019, respectively, to Atlantic Coast Pipeline. At March 31, 2020 and December 31, 2019, Dominion Energy had $5 million and $7 million, respectively, of contributions payable to Atlantic Coast Pipeline included within other current liabilitiesparticipate in the ~~Consolidated Balance Sheets.~~

~~In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under its credit facility. See Note 17 for more information.~~

The Atlantic Coast Pipeline Project is the subject of challenges in federal courts including, among others, challenges of the Atlantic Coast Pipeline Project’s biological opinion and incidental take statement, permits providing right of way crossings of certain federal lands, the Army Corps of Engineers 404 permit, the air permit for a compressor station at Buckingham, Virginia, and the FERC order approving the CPCN. Each of these challenges alleges non-compliance on the part of federal and state permitting authorities and adverse ecological consequences if the Atlantic Coast Pipeline Project is permitted to proceed. Since December 2018, notable developments in these challenges include a stay in December 2018 issued by the U.S. Court of Appeals for the Fourth Circuit and the same court’s July 2019 vacatur of the biological opinion and incidental take statement (which stay and subsequent vacatur halted most project construction activity), U.S. Court of Appeals for the Fourth Circuit decisions vacating the permits to cross certain federal forests and the air permit for a compressor station at Buckingham, Virginia, the U.S. Court of Appeals for the Fourth Circuit’s remand to Army Corps of Engineers of Atlantic Coast Pipeline’s Huntington District 404 verification and the U.S. Court of Appeals for the Fourth Circuit’s remand to the National Park Service of Atlantic Coast Pipeline’s Blue Ridge Parkway right-of-way. Atlantic Coast Pipeline continues to vigorously defend these challenges and is coordinating with the federal and state authorities to obtain new authorizations. Atlantic Coast Pipeline continues coordinating and working with U.S. Fish and Wildlife Service and other parties in preparation for a reissuance of the biological opinion and incidental take statement.proceeding. In June 2019, the ~~Solicitor General of the U.S. and Atlantic Coast Pipeline filed petitions requesting that the Supreme Court of the U.S. hear the case regarding the Appalachian Trail crossing.~~Nevada Utilities withdrew their filings. In ~~February~~May 2020, the ~~Supreme Court of~~Nevada Utilities refiled the ~~U.S. heard oral arguments in~~CPST incorporating the case and is expected to issue a ruling no later than June 2020. If a favorable ruling is not received, Atlantic Coast Pipeline is also evaluating possible legislative and administrative remedies to this issue.

~~Given~~considerations raised by the legal challenges described above, the project is expected to enter full in-service in early 2022, with project costs estimated to be approximately $8 billion, excluding financing costs. Atlantic Coast Pipeline has reached agreements in principle with major customers to amend the contracted rate to share in certain delay cost increases, pending certain regulatory approvals. Project construction activities, schedules and costs are also subject to uncertainty due to permitting and/or work delays (including due to judicial or regulatory action), abnormal weatherPUCN and other ~~conditions that could result~~intervenors and a hearing was held in further cost or schedule modifications, a suspension of AFUDC for Atlantic Coast Pipeline and/or impairment charges potentially material to Dominion Energy’s cash flows, financial position and/or results of operations.

~~Blue Racer~~

In the first quarter of 2019, Dominion Energy received $151 million of additional consideration, including applicable interest, in connection with the sale of Dominion Energy’s 50% limited partnership interest in Blue Racer in December 2018, as discussed in Note 9 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~Dominion Energy Gas~~

~~Dominion~~ Energy Gas’ equity earnings totaled $15 million and $13 million for the three months ended March 31, 2020 and 2019, respectively. Dominion Energy Gas received distributions of $15 million for both the three months ended March 31, 2020 and 2019. At both March 31, 2020 and December 31, 2019, the carrying amount of Dominion Energy Gas’ investment of $312 million, exceeded its share of underlying equity in net assets by $146 million. The difference reflects equity method goodwill and is not being amortized.

~~Atlantic Coast Pipeline~~

DETI provides services to Atlantic Coast Pipeline which totaled $20 million and $31 million for the three months ended March 31, 2020 and 2019, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $8 million and $7 million at March 31, 2020 and December 31, 2019, respectively, composed entirely of accrued unbilled revenue, included in other receivables in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

~~Note 11. Property, Plant and Equipment~~

~~Acquisitions of Solar Projects~~

There have been no updates to acquisitions of solar projects by Dominion Energy or Virginia Power from those discussed in Note 10 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~Acquisition of Gathering and Processing Assets~~

In March 2020, Wexpro closed on an agreement with a natural gas gathering systems operator to purchase existing natural gas gathering systems including pipelines, compressors and dehydration equipment for total consideration of $38 million. These facilities gather natural gas in Colorado, Utah and Wyoming.

~~Note 12. Regulatory Assets and Liabilities~~

~~Regulatory assets and liabilities include the following:~~

March 31, 2020

December 31, 2019

(millions)

Dominion Energy

Regulatory assets:

Deferred cost of fuel used in electric generation⁽¹⁾

$
21

$
48

Deferred project costs and DSM programs for gas utilities⁽²⁾

12

21

Unrecovered gas costs⁽³⁾

31

102

Deferred rate adjustment clause costs for Virginia electric utility⁽⁴⁾⁽⁵⁾

119

109

Deferred nuclear refueling outage costs⁽⁶⁾

52

68

NND Project costs⁽⁷⁾

138

138

PJM transmission rates⁽⁸⁾

42

121

Other

253

272

Regulatory assets-current

668

879

Pension and other postretirement benefit costs⁽⁹⁾

1,410

1,431

Deferred rate adjustment clause costs for Virginia electric utility^(4)(5)(10)

353

235

PJM transmission rates⁽⁸⁾

154

85

Deferred project costs for gas utilities⁽²⁾

560

521

Interest rate hedges⁽¹¹⁾

1,319

741

AROs and related funding⁽¹²⁾

324

311

Cost of reacquired debt⁽¹³⁾

257

262

NND Project costs⁽⁷⁾

2,468

2,503

Ash pond and landfill closure costs⁽¹⁴⁾

2,118

1,016

Other

601

582

Regulatory assets-noncurrent

9,564

7,687

Total regulatory assets

$
10,232

$
8,566

Regulatory liabilities:

Provision for future cost of removal and AROs⁽¹⁵⁾

$
142

$
142

Reserve for refunds and rate credits to electric utility customers⁽¹⁶⁾

138

143

Cost-of-service impact of 2017 Tax Reform Act⁽¹⁷⁾

48

4

Income taxes refundable through future rates⁽¹⁸⁾

138

77

Monetization of guarantee settlement⁽¹⁹⁾

67

67

Other

108

64

Regulatory liabilities-current

641

497

Income taxes refundable through future rates⁽¹⁸⁾

5,016

5,088

Provision for future cost of removal and AROs⁽¹⁵⁾

2,329

2,302

Nuclear decommissioning trust⁽²⁰⁾

1,110

1,471

Monetization of guarantee settlement⁽¹⁹⁾

953

970

Reserve for refunds and rate credits to electric utility customers⁽¹⁶⁾

622

656

Overrecovered other postretirement benefit costs⁽²¹⁾

197

189

Other

362

325

Regulatory liabilities-noncurrent

10,589

11,001

Total regulatory liabilities

$
11,230

$
11,498

~~(1)~~

~~Reflects deferred fuel expenses for the Virginia, North Carolina and South Carolina jurisdictions of Dominion Energy’s electric generation operations.~~

~~(2)~~

~~Primarily~~reflects amounts expected to be collected from or owed to gas customers in Dominion Energy’s service territories associated with current and prospective rider projects, including CEP, PIR and pipeline integrity management. See Note 13 for more information.

~~(3)~~

~~Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with the applicable regulatory authority.~~

~~(4)~~

Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects, net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power. See Note 13 for more information.

~~(5)~~

As a result of actions from the Virginia Commission in the first quarter of 2019 regarding the ratemaking treatment of excess deferred taxes from the adoption of the 2017 Tax Reform Act for all existing rate adjustment clauses, Virginia Power recorded a $29 million ($22 million after-tax) charge in operating revenue in the Consolidated Statements of Income for amounts which are probable of being returned to customers.

~~(6)~~

Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months.

~~(7)~~

Reflects expenditures by DESC associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from DESC electric service customers over a 20-year period ending in 2039. See Note 3 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information.

~~(8)~~

~~Reflects amounts to be recovered through retail rates in Virginia for payments Virginia Power will make to PJM over a~~ ~~ten-year~~ ~~period ending 2028 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter.~~

~~(9)~~

Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered or refunded through future rates generally over the expected remaining service period of plan participants by certain of Dominion Energy's rate-regulated subsidiaries.

~~(10)~~

During the first quarter of 2019, Virginia Power recorded a charge of $17 million ($13 million after-tax) in impairment of assets and other charges to write-off the balance of a regulatory asset for which it is no longer seeking recovery.

~~(11)~~

Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted-average useful life of approximately 27 years as of March 31,September 2020.

~~(12)~~

Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including V.C. Summer nuclear power station, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.

~~(13)~~

Costs of the reacquisition of debt are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt. The reacquired debt costs had a weighted-average life of approximately 26 years as of March 31, 2020.

~~(14)~~

Primarily reflects legislation enacted in Virginia in March 2019 which requires any CCR unit located at certain Virginia Power stations to be closed by removing the CCRs to an approved landfill or through recycling for beneficial reuse. Subject to approval by the Virginia Commission, amounts are expected to be collected over a period between 15 and 18 years commencing no earlier than 2021.Virginia Power is entitled to collect carrying costs once expenditures have been made. See Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for additional information.~~As a result of the March 2020 planned early retirement of certain facilities, amounts recoverable through riders were reclassified from property, plant and equipment.~~

~~(15)~~

Rates charged to customers by Dominion Energy’s regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

~~(16)~~

Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated 11-year period effective February 2019, in connection with the SCANA Merger Approval Order. See Notes 3 and 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information.

~~(17)~~

Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Notes 3 and 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information.

~~(18)~~

Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will primarily reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity.

~~(19)~~

Reflects amounts to be refunded to DESC electric service customers over a 20-year period ending in 2039 associated with the monetization of a bankruptcy settlement agreement. See Note 3 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information.

~~(20)~~

Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon, as applicable) for the future decommissioning of Dominion Energy’s utility nuclear generation stations, in excess of the related AROs.

~~(21)~~

~~Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.~~

March 31, 2020

December 31, 2019

(millions)

Virginia Power

Regulatory assets:

Deferred cost of fuel used in electric generation⁽¹⁾

$
21

$
48

Deferred rate adjustment clause costs⁽²⁾⁽³⁾

119

109

Deferred nuclear refueling outage costs⁽⁴⁾

52

68

PJM transmission rates⁽⁵⁾

42

121

Other

61

87

Regulatory assets-current

295

433

Deferred rate adjustment clause costs^(2)(3)(6)

353

235

PJM transmission rates⁽⁵⁾

154

85

Interest rate hedges⁽⁷⁾

969

404

Ash pond and landfill closure costs⁽⁸⁾

2,118

1,016

Other

130

123

Regulatory assets-noncurrent

3,724

1,863

Total regulatory assets

$
4,019

$
2,296

Regulatory liabilities:

Provision for future cost of removal⁽⁹⁾

$
103

$
103

Income taxes refundable through future rates⁽¹⁰⁾

54

54

Other

24

10

Regulatory liabilities-current⁽¹¹⁾

181

167

Income taxes refundable through future rates⁽¹⁰⁾

2,441

2,438

Nuclear decommissioning trust⁽¹²⁾

1,110

1,471

Provision for future cost of removal⁽⁹⁾

1,078

1,054

Deferred cost of fuel used in electric generation⁽¹⁾

75

30

Other

116

81

Regulatory liabilities-noncurrent

4,820

5,074

Total regulatory liabilities

$
5,001

$
5,241

~~(1)~~

~~Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Virginia Power’s generation operations.~~

~~(2)~~

~~(3)~~

~~(4)~~

~~(5)~~

~~(6)~~

~~(7)~~

~~(8)~~

Primarily reflects legislation enacted in Virginia in March 2019 which requires any CCR unit located at certain Virginia Power stations to be closed by removing the CCR to an approved landfill or through recycling for beneficial reuse. Subject to approval by the Virginia Commission, amounts are expected to be collected over a period between 15 and 18 years commencing no earlier than 2021. Virginia Power is entitled to collect carrying costs once expenditures have been made. See Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for additional information. As a result of the March 2020 planned early retirement of certain facilities, amounts recoverable through riders were reclassified from property, plant and equipment.

~~(9)~~

~~Rates charged to customers by Virginia Power's regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.~~

~~(10)~~

Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity.

~~(11)~~

~~Current regulatory liabilities are presented in other current liabilities in Virginia Power’s Consolidated Balance Sheets.~~

~~(12)~~

Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related AROs.

March 31, 2020

December 31, 2019

(millions)

Dominion Energy Gas

Regulatory assets:

Unrecovered gas costs⁽¹⁾

$
4

$
2

Other

6

6

Regulatory assets-current⁽²⁾

10

8

Interest rate hedges⁽³⁾

32

32

Other

8

8

Regulatory assets-noncurrent⁽⁴⁾

40

40

Total regulatory assets

$
50

$
48

Regulatory liabilities:

Provision for future cost of removal and AROs⁽⁵⁾

$
18

$
18

Overrecovered gas costs⁽¹⁾

6

8

Other

14

15

Regulatory liabilities-current⁽⁶⁾

38

41

Income taxes refundable through future rates⁽⁷⁾

556

560

Provision for future cost of removal and AROs⁽⁵⁾

93

95

Overrecovered other postretirement benefit costs⁽⁸⁾

142

133

Other

13

12

Regulatory liabilities-noncurrent⁽⁹⁾

804

800

Total regulatory liabilities

$
842

$
841

~~(1)~~

~~Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with FERC.~~

~~(2)~~

~~Current regulatory assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(3)~~

~~(4)~~

~~Noncurrent regulatory assets are presented in other deferred charges and other assets in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(5)~~

Rates charged to customers by Dominion Energy Gas' regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

~~(6)~~

~~Current regulatory liabilities are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(7)~~

~~(8)~~

~~Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.~~

~~(9)~~

~~Noncurrent regulatory liabilities are presented in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

At March 31, 2020, Dominion Energy, Virginia Power and Dominion Energy Gas’ regulatory assets include $4.8 billion, $3.4 billion and $48 million, respectively, on which they do not expect to earn a return during the applicable recovery period. With the exception of certain items discussed above, the majority of these expenditures are expected to be recovered within the next two years.

~~Note 13. Regulatory Matters~~

~~Regulatory Matters Involving Potential Loss Contingencies~~

As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For regulatory matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.

~~FERC – Gas~~

~~DETI~~

In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report which could have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI reached resolution of certain matters with FERC in the fourth quarter of 2018. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the remaining finding and no amounts have been recognized.

~~2017 Tax Reform Act~~

Other than the items discussed below, which are pending or have been resolved during the period, there have been no changes to the 2017 Tax Reform Act matters discussed in Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

In March 2019, Questar Gas filed with the Utah and Wyoming Commissions as to the impact of excess deferred income taxes resulting from the 2017 Tax Reform Act. Questar Gas proposed to return the 2018 amortization of excess deferred income taxes to customers and to incorporate the remaining excess deferred income tax impact in its next general rate cases in each jurisdiction. In March 2020, the ~~Utah Commission~~PUCN issued an order approving ~~Questar Gas’ proposal~~the tariff with modified pricing and directing the Nevada Utilities to ~~refund~~develop a methodology by which all eligible participants may have the January 2019 through February 2020 amortization of excess deferred income taxes over 12 months beginning in June 2020. In April 2020, at the request of the Wyoming Commission, this matter will be considered in conjunction with the base rate case that was filed in November 2019. This matter is pending.

In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. In December 2019, the Ohio Commission issued an order approving customer credits of approximately $600 million that will be shared with customers primarily over the remaining book life of the property to which the excess deferred income taxes relate. In addition, East Ohio will reduce rates approximately $19 million per year to account for the 2017 Tax Reform Act’s impact on its equity return component of rates charged to customers. A tax savings credit, which passes through the reduction in the federal income tax rate under the 2017 Tax Reform Act to customers in accordance with the settlement agreement approved by the Ohio Commission, became effective with the first billing cycle in April 2020.

~~Other Regulatory Matters~~

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~Virginia Regulation~~

~~Virginia 2020 Legislation~~

In April 2020, the Governor of Virginia signed into law the VCEA, which along with related legislation forms a comprehensive framework affecting Virginia Power’s operations. The VCEA replaces Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and directs Virginiaopportunity to participate in the CPST program up to a carbon trading program. While the legislation affects several portions of Virginia Power’s operations, key provisions of the GTSA remain in effect, including the triennial review structure and timing, the use of the customer credit reinvestment offset and the $50 million cap on revenue reductions in the first triennial review proceeding. Key provisions of the VCEA and related legislation passed include the following:

~~FossilFuel Electric Generation~~: The legislation mandates Chesterfield Power Station Units 5 & 6 and Yorktown Power Station Unit 3 to be retired by the end of 2024, Altavista, Southampton and Hopewell to be retired by the end of 2028 and Virginia Power’s remaining fossil fuel units to be retired by the end of 2045, unless the retirement of such generating units will compromise grid reliability or security. The legislation also imposes a temporary moratorium on CPCNs for fossil fuel

generation, unless the resources are needed for grid reliability. In addition, the Virginia Commission shall determine the amortization period for recovery of any appropriate costs due to the early retirement of any electric generation facilities, which could result in the reversal of previous retirement costs deemed recovered during the review period ending 2020. As discussed in Note 2, Virginia Power had recorded charges for early retirement of certain coal- and -oil fired generating units in the first quarters of 2020 and 2019. Virginia Power is currently evaluating the prospective impacts to depreciation rates for fossil fuel units that either must or may be retired before the end of their useful lives as a result of the legislation, excluding gas-fired generating facilities that are currently expected to be required for reliability. ~~Any changes in depreciation rates are not expected to have a material impact to Virginia Power’s results of operations or cash flows based on the existing regulatory framework.~~

~~Renewable Generation:~~ The legislation provides a detailed renewable energy portfolio standard to achieve 100% zero-carbon generation by the end of 2045, excluding existing nuclear generation and certain new carbon-free resources. Components include requirements to petition the Virginia Commission for approval to construct or acquire new generating capacity to reach 16.1 GW of installed solar and onshore wind by the end of 2035, which includes specific requirements for utility-scale solar of 3.0 GW by the end of 2024, up to 15.0 GW by the end of 2035 and 1.1 GW of small-scale solar by the end of 2035. The legislation deems 2,700 MW of energy storage, including up to 800 MW for any one project which may include a pumped storage facility, by the end of 2035 to be in the public interest. The legislation also deems the construction or purchase of an offshore wind facility constructed off the Virginia coast with a capacity of up to 5,200 MW before 2035 to be in the public interest and provides certain presumptions facilitating cost recovery. The costs of such a facility constructed by the utility with a capacity between 2,500 and 3,000 MW will be presumed reasonably and prudently incurred if the Virginia Commission finds that the project meets competitive procurement requirements, the projected cost of the facility does not exceed a specified industry benchmark and the utility commences construction by the end of 2023 or has a plan for the facility to be in service by the end of 2027. The Virginia Commission must approve all projects to meet those requirements.

~~Energy Efficiency:~~The legislation includes an energy efficiency target of 5% energy savings, as measured from a 2019 baseline, through verifiable energy efficiency programs by the end of 2025 with future targets to be set by the Virginia Commission. Virginia Power has the opportunity to offset the lost revenues with margins on program spend if certain targets are achieved and can also seek recovery of the lost revenues associated with energy efficiency programs if such reductions are found to have caused Virginia Power to earn more than 50 basis points below a fair rate of return on its rates for generation and distribution services.

~~Carbon trading program~~: The legislation directs Virginia Power to participate in a market-based carbon trading program consistent with RGGI through 2050. All costs of the carbon trading program are recoverable through an environmental rider.

~~Low-income customers~~: The legislation includes the establishment of a percentage of income payment program to be administered by the Virginia Department of Housing and Community Development and the Virginia Department of Social Services. To fund the program, Virginia Power will remit amounts collected from customers under a universal service fee established and set by the Virginia Commission. As such, this program will not affect Virginia Power’s results of operations, financial position or cash flows.

~~Virginia Power expects to incur significant costs, including capital expenditures, to comply~~limit with the ~~legislative requirements discussed above. The legislation allows~~same proportion of governmental entities' and non-governmental entities' MWh reserved for ~~cost recovery under the existing or modified regulatory framework through rate adjustment clauses, rates for generation and distribution services or Virginia Power’s fuel factor,~~potentially interested customers as approved by the Virginia Commission. Costs allocated to the North Carolina jurisdiction will be recovered, subject to approval by the North Carolina Commission, in accordance with the existing regulatory framework.

~~Grid Transformation and Security Act of 2018~~

filed. In July 2018, Virginia Power filed a petition with the Virginia Commission for approval of the first three years of its ten-year plan for electric distribution grid transformation projects as authorized by the GTSA. During the first three years of the plan, Virginia Power proposed to focus on the following seven foundational components of the overall grid transformation plan: (i) smart meters; (ii) customer information platform; (iii) reliability and resilience; (iv) telecommunications infrastructure; (v) cyber and physical security; (vi) predictive analytics; and (vii) emerging technology. The total estimated capital investment during 2019-2021 was $816 million and the proposed operations and maintenance expenses were $102 million. In January 2019, the Virginia Commission issued its final order approving capital spending for the first three years of the plan totaling $68 million on cyber and physical security and related telecommunications infrastructure (Phase IA). The Virginia Commission declined to approve the remainder of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding.

In September 2019, Virginia Power filed a revised plan which includes six components: (i) smart meters; (ii) customer information platform; (iii) grid improvement projects; (iv) telecommunications infrastructure; (v) cyber security; and (vi) a smart charging electric vehicle infrastructure pilot program (Phase IB). For Phase IB, the total proposed capital investment during 2019 – 2021 was $~~503~~ ~~million and the proposed operations and maintenance investment was $78 million. In March~~December 2020, the Virginia Commission issued an order approving $212 million of costs related to a new customer information platform, targeted grid hardening and corridor improvements, an electric vehicle Smart Charging Infrastructure Pilot Program, cyber security, stakeholder engagement and customer education and denied the costs associated with AMI, self-healing grid and certain other grid hardening projects alleging that the Company did not prove the reasonableness and prudency of these costs. In April 2020, Virginia PowerNevada Utilities filed a petition for reconsideration of the Virginia Commission’s order and requested clarification of certain matters, including the Smart Charging Infrastructure Pilot Program. Additionally, Virginia Power requested clarification of certain matters relating to an AMI time-of-use rate and the smart charging electric vehicle infrastructure pilot program. Subsequently, in April 2020, the Virginia Commission denied in full Virginia Power’s petition for reconsideration; however, it stated that its March 2020 order contained all necessary approvals for the smart charging electric vehicle infrastructure pilot program. Virginia Power intends to file a revised plan as early as late 2020 that will address the elements needed for a comprehensive plan, as outlined by the Virginia Commission in its order.

~~Solar Facility Projects~~

In July 2019, Virginia Power filed an application with the Virginia Commission for a CPCN to construct Sadler Solar, which is estimated to cost approximately $146 million, excluding financing costs. Sadler Solar is expected to commence commercial operations, subject to regulatory approvals associated with the project, in the fourth quarter of 2020. Virginia Power also applied for approval of Rider US-4 associated with this project with a proposed $9 million total revenue requirement for the rate year beginning June 1, 2020. In January 2020, the Virginia Commission issued a final order granting the CPCN to construct Sadler Solar, subject to a 20- year performance guarantee of the facility at a 22% solar capacity factor when normalized for force majeure events. In March 2020, the Virginia Commission approved a $7 million total annual revenue requirement.

~~Virginia Fuel Expenses~~

In February 2020, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.2 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2020 and a projected over-recovery of approximately $81 million for the prior year balance as of June 30, 2020. Virginia Power requested that the new fuel factor rate be implemented on an interim basis two months early, beginning on May 1, 2020. In March 2020, the Virginia Commission approved the interim rates. Virginia Power’s proposed fuel rate represents a fuel revenue decrease of approximately $393 million when applied to projected kilowatt-hour sales for the rate year beginning May 1, 2020. This matter is pending.

~~Rate Adjustment Clauses~~

~~Developments for significant riders associated with various Virginia Power projects are as follows:~~

,Rider Name

Application Date

Approval Date

Rate Year
Beginning

Total Revenue
Requirement
(millions)

Increase (Decrease)
Over Previous Year
(millions)

Rider US-3

July 2019

March 2020

June 2020

$
28

$
18

~~North Carolina Regulation~~

~~North Carolina Base Rate Case~~

In March 2019, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed a non-fuel, base rate increase of $27 million effective November 1, 2019 on an interim basis subject to refund, with any permanent ratespricing ordered by the North Carolina Commission effective January 1, 2020. The base rate increase was proposed to recover the significant investments in generation, transmission and distribution infrastructure for the benefit of North Carolina customers. Virginia Power presented an earned return of 7.52% based upon a fully-adjusted test period, compared to its authorized 9.90% return, and proposed a 10.75% ROE. In September 2019, Virginia Power revised its filing to reduce the non-fuel base rate increase to $24 million.PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020 and denying the ~~North Carolina Commission~~petition for a rehearing. In the first quarter of 2021, the Nevada Utilities filed an update to the CPST program per the November 2020 order and an updated CPST tariff with the PUCN. An order is expected in the second quarter of 2021.

Natural Disaster Protection Plan

The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved ~~a 9.75% ROE and disallowed certain~~the 2019 costs ~~associated with coal ash remediation at Chesterfield power station.~~for recovery starting in October 2020. In ~~February~~October 2020, ~~the North Carolina Commission issued its final order relating to base rates. In April 2020, Virginia Power~~intervening parties filed petitions for reconsideration. Intervenors have filed a petition for ~~reconsideration of~~judicial review with the ~~North Carolina Commission’s order as it relates to certain issues. This matter is pending.~~

~~Pipeline Integrity and Safety Program~~

The North Carolina Commission has authorized PSNC to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are notDistrict Court in ~~current base rates.~~November 2020. In ~~February~~December 2020, the ~~North Carolina Commission approved PSNC’s request~~PUCN issued a second modified final order approving the natural disaster protection plan, as modified, and reopened its investigation and rulemaking on Senate Bill 329 to ~~increase~~address rate design issues raised by intervenors. The comment period for the ~~integrity management annual revenue requirement to $28 million,~~reopened investigation and rulemaking ended in early February 2021 and an ~~increase~~order is expected in the second quarter of ~~$7 million over its previous filing, effective March 2020.~~

~~South Carolina Regulation~~

~~South Carolina Base Rate Case~~

~~Pursuant to the SCANA Merger Approval Order,~~ ~~DESC will not file an application for a general rate case with the South Carolina Commission with a requested effective date for new rates earlier than January~~ 2021. In ~~April 2020,~~March 2021, the ~~South Carolina Commission issued an order vacating the portion of the SCANA Merger Approval Order requiring that new retail electric rates be implemented by January 1, 2021.~~

~~DSM Programs~~

~~DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2020, DESC~~Nevada Utilities filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial natural disaster protection plan that was ordered by the PUCN and filed their first amendment to the 2020 natural disaster protection plan.

Northern Powergrid Distribution Companies

In December 2020, GEMA, through Ofgem, published its final determinations for transmission and gas distribution networks in Great Britain. These determinations do not apply directly to Northern Powergrid, but aspects of the proposals are capable of application at Northern Powergrid's next price control, ("ED2"), which will begin in April 2023. Regarding allowed return on capital, Ofgem determined a cost of equity of 4.55% (plus inflation calculated using the United Kingdom's consumer price index including owner occupiers' housing costs ("CPIH")). In March 2021, all the transmission and gas distribution networks lodged appeals with the ~~South Carolina Commission seeking approval~~Competition and Markets Authority against Ofgem's determination for the cost of equity.

In December 2020, in respect of electricity distribution, GEMA published its decision on the methodology it will use to ~~recover $40 million~~set the ED2 price control and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of ~~costs~~the proposals from the transmission and ~~net lost revenues associated with these programs, along with an incentive~~gas distribution price controls to ~~invest~~electricity distribution.

GEMA published a separate decision in ~~such programs. In April 2020,~~March 2021, confirming that the ~~South Carolina Commission approved~~financial aspects in respect of electricity distribution would broadly follow the ~~filing.~~

~~Cost~~transmission and gas distribution methodology, setting a working assumption for a cost of ~~Fuel~~

~~In February 2020, DESC filed~~equity at 4.65% (plus CPIH), ahead of the final determinations in late 2022. When placed on a ~~proposal with~~comparable footing, by adjusting for differences in the ~~South Carolina Commission to decrease~~assumed equity ratio and the ~~total fuel~~measure of inflation used, the working assumption for ED2 is approximately 150 basis points lower than the current cost ~~component~~ of retail electric rates. DESC’s proposed decrease would reduce annual base fuel component recoveries by $44 million and is projected to return to customers the existing over-collected balance while recovering DESC’s current base fuel costs over the 12-month period beginning with the first billing cycle of May 2020. In addition, DESC proposed an increase to its variable environmental and distributed energy resource components. In April 2020, the South Carolina Commission approved the filing.

~~Ohio Regulation~~

~~PIR Program~~

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In April 2020, the Ohio Commission approved East Ohio’s application to adjust the PIR recovery for 2019 costs. The filing reflects gross plant investment for 2019 of $209 million, cumulative gross plant investment of $1.8 billion and an annual revenue requirement of $218 million.

~~FERC – Gas~~

~~Cove Point~~

equity.

BHE Pipeline Group

BHE GT&S

In ~~February~~November 2020, Cove Point ~~submitted its~~reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual ~~electric power cost adjustment~~revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC ~~requesting approval to recover $28 million.~~in January 2021. In March 2021, the FERC approved the ~~adjustment~~stipulation and agreement and the rate refunds to customers were processed in late April.

BHE Transmission

AltaLink

Tariff Refund Application

In January 2021, driven by the pandemic and economic shutdown that has negatively impacted all Albertans, AltaLink filed an application with the AUC that requested approval of tariff relief measures totaling C$350 million over the three-year period, 2021 to 2023. The tariff relief measures consist of a proposed refund to customers of C$150 million of previously collected future income taxes and C$200 million of surplus accumulated depreciation. The future income tax refund would be evenly distributed over the two-year period, 2021 to 2022, with C$75 million included in each year. The accumulated depreciation surplus would be refunded over the three-year period, 2021 to 2023, with C$60 million included in 2021 and 2022, and C$80 million in 2023. If approved by the AUC, these tariff relief measures would have saved customers an estimated C$317 million over the three-year period, 2021 to 2023.

In March ~~2020.~~

~~Note 14. Leases~~

~~There have been no significant changes regarding~~2021, the ~~Companies’ leases as described~~AUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 tariff refund in ~~Note 15~~the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provides Alberta ratepayers with immediate tariff relief in 2021. The approved 2021 tariff refund includes a refund of C$150 million of previously collected future income tax and a refund of C$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 will be proposed in AltaLink's 2022-2023 GTA.

2019-2021 General Tariff Application

In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposed to provide a further tariff reduction over the three year period by refunding previously collected accumulated depreciation surplus of an additional C$31 million. In April 2019, AltaLink filed an update to its 2019-2021 GTA primarily to reflect its 2018 actual results and the impact of the AUC's decision on AltaLink's 2014-2015 Deferral Accounts Reconciliation Application. The application requested the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively.

In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions that resulted in a net decrease of C$38 million to the ~~Consolidated Financial Statements~~three year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this was offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019, with written arguments filed in January 2020.

In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021 GTA. The AUC approved the negotiated settlement agreement as filed and rendered its decision and directions on the excluded matters. The AUC declined to approve AltaLink's proposed salvage methodology at that time, but indicated it would initiate a generic proceeding to review the matter on an industry-wide basis. The AUC approved, on a placeholder basis, C$13 million of the additional C$20 million AltaLink requested for forecast transmission line clearance capital. The remaining C$7 million of capital investment was reviewed in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital expenditures related to fire risk mitigation were approved, with an additional C$31 million of capital expenditures reviewed in the ~~Companies’~~compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.

In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898 million for 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnership and the KainaiLink Limited Partnership.

The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In September 2020, the AUC granted this review on the basis that there were changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In October 2020, AltaLink filed responses to information requests from the AUC, written argument was filed by intervening parties and written reply argument was filed by AltaLink. In November 2020, the AUC issued its decision on AltaLink's review and variance application. The AUC decided to vary the original decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.

In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.

2022-2023 General Tariff Application

In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs continuing to transition to the AUC-approved salvage recovery method, continuing the use of the flow-through income tax method, and adding only a 1% increase to operations and maintenance expense, with the exception of salaries and wages and other expenses. In addition, similar to the C$80 million refund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further similar tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariff of C$824 million and C$847 million for 2022 and 2023, respectively.

2022 Generic Cost of Capital Proceeding

In December 2020, the AUC initiated the 2022 generic cost of capital proceeding. This proceeding will consider the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the existing uncertainty as a result of the ongoing COVID-19 pandemic, before establishing a process schedule, the commission has requested participants to submit comments that address the following: (i) the continuation of the currently approved return on equity and deemed equity ratios for a further period of time; (ii) the appropriate test period for the proceeding; (iii) the scope of the proceeding, including whether a formula-based approach to return on equity should be utilized; (iv) the considerations to take into account when establishing the process for the proceeding; and (v) the avoidance of duplicative evidence and greater coordination and collaboration between parties.

In January 2021, AltaLink submitted a letter to the AUC stating that due to ongoing capital market volatility and other COVID-19 related uncertainties there are reasonable grounds for extending the currently approved 2021 return on equity and deemed equity ratio on a final basis for 2022. AltaLink further stated there is insufficient time to complete a full generic cost of capital proceeding in 2021, in order to issue a decision prior to the beginning of 2022 and a formula-based approach should not be considered at this time. AltaLink suggested that a proceeding could be restarted in the third quarter of 2021, for 2023 and subsequent years.

In March 2021, the AUC issued its decision with respect to setting the return on equity and deemed equity ratios for AltaLink. The AUC approved an equity return of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and market uncertainties, the unsettled nature of capital markets, and the need for certainty and stability for Alberta ratepayers.

In April 2021, the Utilities Consumer Advocate filed an application with the Court of Appeal of Alberta requesting permission to appeal the AUC's decision that set the return on equity of 8.5% and equity ratio of 37% on a final basis for 2022. In the appeal, the Utilities Consumer Advocate alleges that the AUC erred by failing to fulfil its statutory obligation of establishing a fair return and by failing to apply procedural fairness.

2019 Deferral Accounts Reconciliation Application

In October 2020, AltaLink filed its application with the AUC, which includes ten projects with total gross capital additions of C$129 million, including applicable AFUDC. In December 2020, AltaLink provided responses to AUC information requests, interveners filed written argument and AltaLink filed reply argument.

In March 2021, the AUC issued its decision on AltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approved C$128.0 million of the C$128.5 million of gross capital project additions, disallowing C$0.5 million of capital costs. The AUC also approved the other deferral accounts for taxes other than income taxes, long-term debt and annual structure payments as filed. AltaLink filed its compliance filing in April 2021.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2019.~~

~~Dominion Energy’s Consolidated Statements~~2020, and new environmental matters occurring in 2021.

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 ~~Income~~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 GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021, President Biden announced new climate goals to cut GHG 50%-52% economy-wide by 2030 compared to 2005 levels, and to reach 100% carbon pollution-free electricity by 2035. Additional details on how the United States will implement these goals is anticipated to be released through fall 2021.

Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Registrants' operations as described below.

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration 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 facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through the introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be quickly revisited by the Biden administration. Because the significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will be required to meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule April 5, 2021, remanding it for further proceedings.

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.

In June 2010, the EPA finalized a new NAAQS for SO2. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where SO2 emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2 area designations will continue with the deployment of additional SO2 monitoring networks across the country. On February 25, 2019, the EPA issued a decision to retain the 2010 SO2 NAAQS without revision.

The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three ~~months ended~~phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012 and, as of March ~~31, 2020~~2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and ~~2019 include $32 million and $29 million, respectively, of rental revenue~~the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included ~~in operating revenue and $23 million of depreciation expense for both periods, included in depreciation, depletion and amortization, related to facilities~~as units subject to the first phase of the designations, having emitted more than 2,600 tons of SO2 and having an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyoming as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further action by PacifiCorp is required.

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 United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.

The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from power ~~purchase agreements~~plants in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at power plants in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule.

Regional Haze

The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which ~~Dominion Energy is~~includes the ~~lessor.~~

~~Note 15. Variable Interest Entities~~

~~There have~~updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval at the end of 2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon plant federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and the state of Utah moved to intervene in the litigation, which has been ~~no significant changes regarding~~stayed pending the ~~entities~~Biden administration's review of the ~~Companies consider VIEs as described~~rule.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in ~~Note 16 to~~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 ~~Companies’~~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, ~~2019.~~

~~Dominion Energy~~

At2020. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2020.

PacifiCorp and its subsidiaries

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of March 31, ~~2020~~2021, the related consolidated statements of operations, changes in shareholders' equity and December 31, 2019, Dominion Energy’s securities due within one year included $32 million and $31 million, respectively, and at both March 31, 2020 and December 31, 2019 Dominion Energy’s long-term debt included $267 million of debt issued by SBL Holdco, a VIE, net of issuance costs, that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain merchant solar facilities.

~~Virginia Power~~

Virginia Power had a long-term power and capacity contract with 1 non-utility generator with an aggregate summer generation capacity of approximately 218 MW under a contract which terminated in May 2019. Virginia Power paid $13 million cash flowsfor ~~electric capacity and $1 million for electric energy to~~ the ~~non-utility generator in the three months~~three-month periods ended March 31, ~~2019.~~

~~Dominion Energy Gas~~

~~Dominion Energy Gas purchased shared services from DECGS~~2021 and ~~DEQPS of $4 million and $7 million for the three months ended March 31,~~ 2020, and ~~$4 million and $8 million for~~ the ~~three months ended March 31, 2019. Dominion Energy Gas’ Consolidated Balance Sheets included amounts due~~related notes (collectively referred to ~~both DECGS and DEQPS~~as the "interim financial information"). Based on our reviews, we are not aware of ~~$22 million and $15 million at March 31, 2020 and December 31, 2019, respectively.~~

~~Virginia Power and Dominion Energy Gas~~

Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $93 million and $31 million for the three months ended March 31, 2020, respectively, and $89 million and $28 million for the three months ended March 31, 2019, respectively. Virginia Power’s Consolidated Balance Sheets include amounts due to DES of $180 million and $102 million at March 31, 2020 and December 31, 2019, respectively, recorded in payables to affiliates. Dominion Energy Gas’ Consolidated Balance Sheets include amounts due to DES of $39 million and $27 million at March 31, 2020 and December 31, 2019, respectively, recorded in payables to affiliates.

~~Note 16. Significant Financing Transactions~~

~~Credit Facilities and Short-term Debt~~

The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.

~~Dominion Energy~~

~~At March 31, 2020, Dominion Energy’s commercial paper and letters of credit outstanding, as well as its capacity available under the credit facility, were as follows:~~

Facility
Limit

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

Facility
Capacity
Available

(millions)

Joint revolving credit facility⁽¹⁾

$
6,000

$
2,071

$
86

$
3,843

~~(1)~~

This credit facility matures in March 2023 and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

~~In addition~~any material modifications that should be made to the ~~credit facility mentioned above, Dominion Energy also has a credit facility~~accompanying interim financial information for it to be in conformity with ~~a maturity date in~~ ~~June 2020~~ ~~which allows Dominion Energy to issue up to approximately $21 million in letters of credit. At March 31, 2020, Dominion Energy had $21 million in letters of credit outstanding under this agreement.~~

In March 2020, Dominion Energy entered into a $900 million 364-Day Revolving Credit Agreement. The agreement bears interest at a variable rate. At March 31, 2020, 0 amounts were outstanding. In April 2020, Dominion Energy borrowed $225 million under the agreement. The proceeds were used to provide for general working capital and other general corporate purposes. The maximum allowed total debt to total capital ratio under the agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

DESC’s and Questar Gas’ short-term financings are supported through access as co-borrowers to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At March 31, 2020, the sub-limits for DESC and Questar Gas were $500 million and $250 million, respectively.

In January 2020, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. In March 2020, FERC granted DESC authority through March 2021 to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act) in amounts not to exceed $2.2 billion outstanding with maturity dates of one year or less. In addition, in March 2020, FERC granted GENCO authority through March 2021 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less.

~~In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which had an original stated maturity date of December 2017 with automatic~~ ~~one-year~~ renewals through the maturity of the SBL Holdco term loan agreement in 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which had an original stated maturity date of May 2018 with automatic ~~one-year~~ ~~renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in 2024. At March 31, 2020, 0 amounts were outstanding under either of these facilities.~~

~~In March 2020, Dominion Energy borrowed $500 million under a 364-Day Term Loan Credit Agreement that bears interest at a variable rate.~~ The proceeds were used to provide for general working capital and other general corporate purposes. These borrowings are presented within securities due within one year in Dominion Energy’s Consolidated Balance Sheets at March 31,2020. The maximum allowed total debt to total capital ratio under the agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

~~In April 2020, Dominion Energy borrowed $625 million under a 364-Day Term Loan Credit Agreement that bears interest at a variable rate.~~ The proceeds were used to provide for general working capital and other general corporate purposes. The maximum allowed total debt to total capital ratio under the agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

~~Virginia Power~~

Virginia Power’s short-term financing is supported through its access as co-borrower to the joint revolving credit facility. This credit facility can be used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes.

At March 31, 2020, Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, Dominion Energy Gas, Questar Gas and DESC was as follows:

Facility
Limit⁽¹⁾

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

(millions)

Joint revolving credit facility⁽¹⁾

$
6,000

$
135

$
9

~~(1)~~

The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas, Questar Gas and DESC. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the borrowers under the credit facility multiple times per year. At March 31, 2020, the sub-limit for Virginia Power was $1.5 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

~~Dominion Energy Gas~~

Dominion Energy Gas’ short-term financing is supported through its access as co-borrower to the joint revolving credit facility. This credit facility can be used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes.

At March 31, 2020, Dominion Energy Gas' share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, Virginia Power, Questar Gas and DESC was as follows:

Facility
Limit⁽¹⁾

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

(millions)

Joint revolving credit facility⁽¹⁾

$
1,500

$
30

$
—

~~(1)~~

A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power, Questar Gas and DESC. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the borrowers under the credit facility multiple times per year. At March 31, 2020, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

~~Long-term Debt~~

~~Unless otherwise noted, the proceeds of long-term debt issuances were used for general corporate purposes and/or to repay short-term debt.~~

In February 2020, Dominion Energy redeemed the remaining principal outstanding of $111 million and $286 million of its June 2006 hybrids and its September 2006 hybrids, respectively, both which would have otherwise matured in 2066. All purchases were conducted in compliance with the applicable RCC, each of which was terminated in February 2020. Expenses related to the early redemption of the hybrids were $10 million reflected within interest and related chargesaccounting principles generally accepted in the ~~Consolidated Statements~~United States of ~~Income for the three months ended March 31, 2020.~~

~~In March 2020, SCANA redeemed its floating rate senior notes at the remaining principal balance of $66 million plus accrued interest. The notes would~~America.

We have otherwise matured in June 2034. Expenses related to the early redemption of the senior notes were $7 million reflected within interest and related charges in the Consolidated Statements of Income for the three months ended March 31, 2020.

In March 2020, SCANA redeemed the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums. The notes would have otherwise matured in May 2021 and February 2022, respectively. Total expenses related to the early redemption of the medium-term notes were $14 million reflected within interest and related charges in the Consolidated Statements of Income for the three months ended March 31, 2020.

~~In March 2020, Dominion Energy issued $400 million of 3.30% senior notes and $350 million of 3.60% senior notes that mature in 2025 and 2027, respectively.~~

~~In March 2020, PSNC issued, through private placement, $200 million of 4.05% senior notes that mature in 2030.~~

~~In April 2020, Dominion Energy issued $1.5 billion of 3.375% senior notes that mature in 2030.~~

~~In April 2020, Dominion Energy purchased and canceled $7 million of its 2.579% junior subordinated notes that mature in July 2020.~~

~~Noncontrolling Interest in Dominion Energy Midstream~~

In January 2019, Dominion Energy and Dominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in

Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstreampreviously audited, in accordance with the ~~terms~~standards of ~~Dominion Energy Midstream’s partnership agreement.~~ the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2020, 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 26, 2021, 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, 2020, 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.

/s/ Deloitte & Touche LLP

Portland, Oregon

April 30, 2021

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	March 31,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	43	$	13
Trade receivables, net	650		703
Other receivables, net	48		48
Inventories	475		482

Regulatory assets	107		116
Prepaid expenses	73		79
Other current assets	109		82
Total current assets	1,505		1,523

Property, plant and equipment, net	22,535		22,430
Regulatory assets	1,279		1,279
Other assets	479		470

Total assets	$	25,798	$	25,702

The ~~merger was accounted for by Dominion Energy following the guidance for~~accompanying notes are an integral part of these consolidated financial statements.

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	March 31,		December 31,
	2021		2020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	615	$	772
Accrued interest	114		127
Accrued property, income and other taxes	118		80

Accrued employee expenses	112		84
Short-term debt	95		93
Current portion of long-term debt	879		420
Regulatory liabilities	111		115
Other current liabilities	178		174
Total current liabilities	2,222		1,865

Long-term debt	7,734		8,192
Regulatory liabilities	2,728		2,727
Deferred income taxes	2,666		2,627
Other long-term liabilities	1,106		1,118
Total liabilities	16,456		16,529

Commitments and contingencies (Note 8)	0		0

Shareholders' equity:
Preferred stock	2		2
Common stock - 750 shares authorized, 0 par value, 357 shares issued and outstanding	0		0
Additional paid-in capital	4,479		4,479
Retained earnings	4,880		4,711
Accumulated other comprehensive loss, net	(19)		(19)
Total shareholders' equity	9,342		9,173

Total liabilities and shareholders' equity	$	25,798	$	25,702

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
	Ended March 31,
		2021		2020

Operating revenue		$	1,242	$	1,206

Operating expenses:
Cost of fuel and energy		424		417
Operations and maintenance		259		254
Depreciation and amortization		264		252
Property and other taxes		61		49
Total operating expenses		1,008		972

Operating income		234		234

Other income (expense):
Interest expense		(107)		(102)
Allowance for borrowed funds		6		10
Allowance for equity funds		13		21
Interest and dividend income		6		3
Other, net		6		(4)
Total other income (expense)		(76)		(72)

Income before income tax benefit		158		162
Income tax benefit		(11)		(14)
Net income		$	169	$	176

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, December 31, 2019	$	2	$	0	$	4,479	$	3,972	$	(16)	$	8,437
Net income	—		—		—		176		—		176
Other comprehensive income	—		—		—		0		1		1

Balance, March 31, 2020	$	2	$	0	$	4,479	$	4,148	$	(15)	$	8,614







Balance, December 31, 2020	$	2	$	0	$	4,479	$	4,711	$	(19)	$	9,173
Net income	—		—		—		169		—		169


Balance, March 31, 2021	$	2	$	0	$	4,479	$	4,880	$	(19)	$	9,342

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income	$	169	$	176
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	264		252
Allowance for equity funds	(13)		(21)
Changes in regulatory assets and liabilities	(4)		(16)
Deferred income taxes and amortization of investment tax credits	13		(30)
Other, net	(2)		6
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	61		85
Inventories	7		(26)
Derivative collateral, net	7		(1)
Prepaid expenses	6		(3)
Accrued property, income and other taxes, net	12		18
Accounts payable and other liabilities	(51)		(3)
Net cash flows from operating activities	469		437

Cash flows from investing activities:
Capital expenditures	(439)		(366)
Other, net	(1)		27
Net cash flows from investing activities	(440)		(339)

Cash flows from financing activities:


Net proceeds from (repayments of) short-term debt	2		(74)


Other, net	(1)		0
Net cash flows from financing activities	1		(74)

Net change in cash and cash equivalents and restricted cash and cash equivalents	30		24
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	19		36
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	49	$	60

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

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a ~~change~~United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a ~~parent company’s ownership interest~~number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated ~~subsidiary. Because Dominion Energy controls Dominion Energy Midstream both before and after the merger, the changes~~subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in ~~Dominion Energy’s ownership interest in Dominion Energy Midstream were accounted for as an equity transaction and 0 gain or loss was recognized. In connection~~accordance with the merger, Dominion Energy recognized $40 million of income taxes in equity primarily attributable to establishing additional regulatory liabilities related to excess deferred income taxes and changes in state income taxes.

~~2019 Corporate Units~~

~~In June 2019, Dominion Energy issued $1.6 billion of 2019 Equity Units, initially~~accounting principles generally accepted in the ~~form~~United States of ~~2019 Series A Corporate Units. The Corporate Units are listed on~~America ("GAAP") for interim financial information and the ~~NYSE under the symbol DCUE. The net proceeds were used~~United States Securities and Exchange Commission's rules and regulations for ~~general corporate purposes~~Form 10-Q and ~~to repay short-term debt, including commercial paper.~~

~~Each 2019 Series A Corporate Unit consists~~Article 10 of a stock purchase contract and a 1/10, or 10%, undivided beneficial ownership interest in one share of Series A Preferred Stock. Beginning in June 2022, the Series A Preferred Stock is convertible at the optionRegulation S-X. Accordingly, they do not include all of the ~~holder into Dominion Energy common stock under a formula based upon~~disclosures required by GAAP for annual financial statements. Management believes the ~~average closing price~~unaudited Consolidated Financial Statements contain all adjustments (consisting only of ~~Dominion Energy common stock prior to~~normal recurring adjustments) considered necessary for the conversion date. The Series A Preferred Stock is redeemable in cash by Dominion Energy beginning September 2022 at the liquidation preference. Settlement of any conversion is payable in cash, common stock or a combination thereof, at Dominion Energy’s election.

The stock purchase contracts obligate the holders to purchase shares of Dominion Energy common stock in June 2022. The purchase price to be paid under the stock purchase contracts is $100 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The Series A Preferred Stock was pledged upon issuance as collateral to secure the purchase of common stock under the related stock purchase contracts.

Dominion Energy pays cumulative dividends on the Series A Preferred Stock and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion Energy may elect to pay such dividends and/or payments in cash, shares of Dominion Energy common stock or a combination of cash and shares of Dominion Energy common stock. Dominion Energy may defer the contract adjustment payments for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion Energy may not make any distributions related to its capital stock, including dividends, redemptions, repurchases or liquidation payments. Also, during the deferral period, Dominion Energy may not make any payments on or redeem, repay or repurchase any debt securities that are equal in right of payment with, or subordinated to, the contract adjustment payments or make any payment on any guarantee of a security of a subsidiary if the guarantee ranks equal or junior to the contract adjustment payments. Unless all accumulated and unpaid dividends on the Series A Preferred Stock have been declared and paid, Dominion Energy may not make any distributions on any of its capital stock ranking equal or junior to the Series A Preferred Stock as to dividends or upon liquidation, as applicable, including dividends, redemptions, repurchases or liquidation payments. In such circumstances, Dominion Energy also may not make any contract adjustment payments or other similar types of payments, subject to certain exceptions.

~~Dominion Energy has recorded the present value~~fair presentation of the ~~stock purchase contract payments~~unaudited Consolidated Financial Statements as ~~a liability offset to common stock. Stock purchase contract payments are recorded against this liability. Accretion~~ of ~~the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion Energy applies the treasury stock method to the stock purchase contracts~~March 31, 2021 and the if-converted method to the Series A Preferred Stock. Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, the maximum number of shares of common stock Dominion Energy will issue in June 2022 is 21.8 million.

~~Selected information about Dominion Energy’s 2019 Equity Units is presented below:~~

Issuance Date

Units Issued

Total Net
Proceeds⁽¹⁾

Total
Preferred
Stock⁽²⁾

Cumulative
Dividend
Rate

Stock
Purchase
Contract
Annual Rate

Stock
Purchase
Contract
Liability⁽³⁾

Stock Purchase
Contract
Settlement Date
(millions except interest rates)

6/14/2019

16

$
1,582

$
1,610

1.75
%

5.5
%

$
250

6/1/2022

~~(1)~~

~~Issuance costs of $28 million were recorded as a reduction to preferred stock ($14 million) and common stock ($14 million) in the Consolidated Balance Sheets.~~

~~(2)~~

~~Dominion Energy recorded dividends of $7 million ($4.375 per share) for the three months ended March 31, 2020.~~

~~(3)~~

~~Payments of $20 million were made during the first quarter of 2020. The stock purchase contract liability was $192 million and $212 million at March 31, 2020 and December 31, 2019, respectively.~~

~~Series B Preferred Stock~~

In December 2019, Dominion Energy issued 800,000 shares of Series B Preferred Stock for $791 million, net of $9 million of issuance costs. The preferred stock has a liquidation preference of $1,000 per share and currently pays a 4.65% dividend per share on the liquidation preference. Dividends are paid cumulatively on a semi-annual basis, commencing June 15, 2020. Dominion Energy recorded dividends of $9 million ($11.625 per share) for the ~~three months~~three-month periods ended March 31, 2021 and 2020. The ~~dividend rate~~Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the ~~Series B Preferred Stock will be reset every five years beginning on December 15, 2024 to equal~~three-month periods ended March 31, 2021 and 2020. The results of operations for the ~~then-current five-year U.S. Treasury rate plus a spread of 2.993%. Unless all accumulated~~three-month periods ended March 31, 2021 and ~~unpaid dividends on the Series B Preferred Stock have been declared and paid, Dominion Energy may~~2020 are not make any distributions on any of its capital stock ranking equal or junior to the Series B Preferred Stock as to dividends or upon liquidation, including through dividends, redemptions, repurchases or otherwise.

Dominion Energy may, at its option, redeem the Series B Preferred Stock in whole or in part on December 15, 2024 or on any subsequent fifth anniversary of such date at a price equal to $1,000 per share plus any accumulated and unpaid dividends. Dominion Energy may also, at its option, redeem the Series B Preferred Stock in whole but not in part at a price equal to $1,020 per share plus any accumulated and unpaid dividends at any time within a certain period of time following any change in the criteria ratings agencies use to assign equity credit to securities such as the Series B Preferred Stock that has certain adverse effects on the equity credit actually received by the Series B Preferred Stock.

~~Holders~~necessarily indicative of the ~~Series B Preferred Stock have no voting rights except in~~results to be expected for the ~~limited circumstances provided for in the terms~~full year.

The preparation of the Series B Preferred Stock or as otherwise required by applicable law. The Series B Preferred Stock is not subject to any sinking fund or other obligation of ours to redeem, repurchase or retire the Series B Preferred Stock. The preferred stock contains no conversion rights.

~~Issuance of Common Stock~~

See Note 3 to the Consolidated Financial Statements for information on the issuance of Dominion Energy common stock in January 2019 in connection with the SCANA Combination. Also in January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of common stock as noted above.

~~At-the-Market Program~~

In June 2017, Dominion Energy filed an SEC shelf registration statement for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program as discussed in Note 20 to theunaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the ~~Companies’~~reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, ~~2019. In March~~ 2020 Dominion Energy entered into four separate sales agency agreements to effect sales under a new at-the-market program and pursuant to which it may offer from time to time up to $500 million aggregate amountdescribes the most significant accounting policies used in the preparation of ~~its common stock. Dominion Energy has 0t issued any shares under this new program.~~

~~Dividend Restrictions~~

~~At March 31, 2020, DESC’s retained earnings are below~~ the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is prohibited from the payment of dividends without regulatory approval until the balance of its retained earnings increases.unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2021		2020
Cash and cash equivalents	$	43	$	13
Restricted cash included in other current assets	3		4
Restricted cash included in other assets	3		2
Total cash and cash equivalents and restricted cash and cash equivalents	$	49	$	19

(3) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):


		As of
		March 31,		December 31,
	Depreciable Life	2021		2020
Utility Plant:
Generation	15 - 59 years	$	13,355	$	12,861
Transmission	60 - 90 years	7,686		7,632
Distribution	20 - 75 years	7,725		7,660
Intangible plant(1)	5 - 75 years	1,069		1,054
Other	5 - 60 years	1,513		1,510
Utility plant in service		31,348		30,717
Accumulated depreciation and amortization		(9,980)		(9,838)
Utility plant in service, net		21,368		20,879
Other non-regulated, net of accumulated depreciation and amortization	14 - 95 years	9		9
Plant, net		21,377		20,888
Construction work-in-progress		1,158		1,542
Property, plant and equipment, net		$	22,535	$	22,430

(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to ~~dividend restrictions affecting~~10 years.

Effective January 1, 2021, PacifiCorp revised its depreciation rates based on its recent depreciation study that was approved by its state regulatory commissions, other than in California. The approved depreciation rates resulted in an increase in depreciation expense of approximately $37 million for the ~~Companies described~~three-month period ended March 31, 2021 compared to the three-month period ended March 31, 2020 based on historical property, plant and equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.

(4) Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:


	Three-Month Periods
	Ended March 31,
		2021		2020

Federal statutory income tax rate		21	%	21	%
State income tax, net of federal income tax benefit		3		3
Federal income tax credits		(20)		(11)
Effects of ratemaking		(13)		(22)

Other		2		0
Effective income tax rate		(7)	%	(9)	%

Income tax credits relate primarily to production tax credits ("PTCs") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

Effects of ratemaking for the three-month periods ended March 31, 2021 and 2020 is primarily attributable to the amortization of excess deferred income taxes, including the use of excess deferred income taxes of $3 million and $30 million, respectively, to accelerate depreciation of certain retired wind equipment and to amortize certain regulatory asset balances in accordance with regulatory orders issued in Oregon and Wyoming.

Berkshire Hathaway includes BHE and its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the three-month periods ended March 31, 2021 and 2020, PacifiCorp made net cash payments for federal and state income tax to BHE totaling $1 million and $26 million, respectively.

(5) Employee Benefit Plans

Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020
Pension:
Service cost		$	0	$	0
Interest cost		7		9
Expected return on plan assets		(13)		(14)
Net amortization		5		5
Net periodic benefit credit		$	(1)	$	0

Other postretirement:
Service cost		$	0	$	0
Interest cost		2		3
Expected return on plan assets		(2)		(4)
Net amortization		0		0
Net periodic benefit credit		$	0	$	(1)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $1 million, respectively, during 2021. As of March 31, 2021, $1 million of contributions had been made to the pension plans.

(6) Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, manage and report each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Note 217 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):


	Other				Other		Other
	Current		Other		Current		Long-term
	Assets		Assets		Liabilities		Liabilities		Total
As of March 31, 2021
Not designated as hedging contracts(1):
Commodity assets	$	45	$	6	$	2	$	0	$	53
Commodity liabilities	(2)		0		(27)		(24)		(53)
Total	43		6		(25)		(24)		0

Total derivatives	43		6		(25)		(24)		0
Cash collateral receivable	0		0		13		4��		17
Total derivatives - net basis	$	43	$	6	$	(12)	$	(20)	$	17

As of December 31, 2020
Not designated as hedging contracts(1):
Commodity assets	$	29	$	6	$	1	$	0	$	36
Commodity liabilities	(2)		0		(23)		(28)		(53)
Total	27		6		(22)		(28)		(17)

Total derivatives	27		6		(22)		(28)		(17)
Cash collateral receivable	0		0		15		9		24
Total derivatives - net basis	$	27	$	6	$	(7)	$	(19)	$	7

(1)PacifiCorp's commodity derivatives are generally included in rates and as of March 31, 2021 and December 31, 2020, a regulatory asset of $— million and $17 million, respectively, was recorded related to the net derivative liability of $— million and $17 million, respectively.

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


	Three-Month Periods
	Ended March 31,
		2021		2020

Beginning balance		$	17	$	62
Changes in fair value		(17)		34
Net gains reclassified to operating revenue		0		8
Net losses reclassified to cost of fuel and energy		0		(20)
Ending balance		$	0	$	84

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	March 31,	December 31,
	Measure	2021	2020

Electricity sales, net	Megawatt hours	0	(1)
Natural gas purchases	Decatherms	114	100

Credit Risk

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

Collateral and Contingent Features

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $52 million and $51 million as of March 31, 2021 and December 31, 2020, respectively, for which PacifiCorp had posted collateral of $17 million and $24 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 March 31, 2021 and December 31, 2020, PacifiCorp would have been required to post $30 million and $25 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) 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 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 March 31, 2021
Assets:
Commodity derivatives	$	0	$	53	$	0	$	(4)	$	49
Money market mutual funds(2)	36		0		0		—		36
Investment funds	30		0		0		—		30
	$	66	$	53	$	0	$	(4)	$	115

Liabilities - Commodity derivatives	$	0	$	(53)	$	0	$	21	$	(32)

As of December 31, 2020
Assets:
Commodity derivatives	$	0	$	36	$	0	$	(3)	$	33
Money market mutual funds(2)	6		0		0		—		6
Investment funds	25		0		0		—		25
	$	31	$	36	$	0	$	(3)	$	64

Liabilities - Commodity derivatives	$	0	$	(53)	$	0	$	27	$	(26)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $17 million and $24 million as of March 31, 2021 and December 31, 2020, 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. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the ~~Companies’~~market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 6 for further discussion regarding PacifiCorp's risk management and hedging activities.

PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

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 March 31, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	8,613	$	10,198	$	8,612	$	10,995

(8) Commitments and Contingencies

Legal Matters

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

California and Oregon 2020 Wildfires

Several lawsuits have been filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.

Environmental Laws and Regulations

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

Hydroelectric Relicensing

PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.

Guarantees

PacifiCorp has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.

(9) Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):




	Three-Month Periods
	Ended March 31,
		2021		2020
Customer Revenue:
Retail:
Residential		$	483	$	460
Commercial		359		358
Industrial		271		277
Other retail		32		27
Total retail		1,145		1,122
Wholesale (1)		36		0
Transmission		25		22
Other Customer Revenue		23		26
Total Customer Revenue		1,229		1,170
Other revenue		13		36
Total operating revenue		$	1,242	$	1,206

(1)Includes net payments to counterparties for the financial settlement of certain non-derivative forward contracts for energy sales.

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

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

Results of Operations for the First Quarter of 2021 and 2020

Overview

Net income for the first three months of 2021 was $169 million, a decrease of $7 million compared to 2020. Net income decreased primarily due to lower allowances for equity and borrowed funds used during construction of $12 million, higher property taxes of $12 million, higher depreciation and amortization expense of $12 million, including the impacts of the depreciation study that was effective January 1, 2021, higher operations and maintenance expense of $5 million and higher interest expense of $5 million, partially offset by higher utility margin of $29 million and increased cash surrender value of corporate-owned life insurance policies. Utility margin increased primarily due to higher retail and wholesale revenue and lower purchased electricity costs, partially offset by higher natural gas-fueled generation costs, higher net amortization of deferred net power costs in accordance with established adjustment mechanisms, and higher coal-fueled generation costs. Retail customer volumes increased 0.3%, primarily due to an increase in the average number of customers across the service territory and favorable impact of weather, partially offset by lower customer usage. Energy generated increased 8% for the first three months of 2021 compared to 2020 primarily due to higher wind-powered, coal-fueled and natural gas-fueled generation, partially offset by lower hydroelectric generation. Wholesale electricity sales volumes increased 24% and purchased electricity volumes decreased 11%.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

PacifiCorp's cost of fuel and energy is generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):


	First Quarter
	2021		2020		Change
Utility margin:
Operating revenue	$	1,242	$	1,206	$	36	3	%
Cost of fuel and energy	424		417		7		2
Utility margin	818		789		29		4
Operations and maintenance	259		254		5		2
Depreciation and amortization	264		252		12		5
Property and other taxes	61		49		12		24
Operating income	$	234	$	234	$	—	—	%

Utility Margin

A comparison of key operating results related to utility margin is as follows for the quarters ended March 31:


	First Quarter
	2021		2020		Change
Utility margin (in millions):
Operating revenue	$	1,242	$	1,206	$	36	3	%
Cost of fuel and energy	424		417		7		2
Utility margin	$	818	$	789	$	29	4	%

Sales (GWhs):
Residential	4,632		4,421		211		5	%
Commercial	4,470		4,410		60		1
Industrial, irrigation and other	4,474		4,702		(228)		(5)
Total retail	13,576		13,533		43		—
Wholesale	1,591		1,281		310		24
Total sales	15,167		14,814		353		2	%


Average number of retail customers (in thousands)	1,989		1,955		34		2	%

Average revenue per MWh:
Retail	$	84.15	$	82.97	$	1.18	1	%
Wholesale	$	30.89	$	26.35	$	4.54	17	%

Heating degree days	4,687		4,605		82		2	%


Sources of energy (GWhs)(1):
Coal	7,644		7,228		416		6	%
Natural gas	3,065		3,041		24		1
Hydroelectric(2)	923		1,046		(123)		(12)
Wind and other(2)	1,803		1,112		691		62
Total energy generated	13,435		12,427		1,008		8
Energy purchased	3,028		3,391		(363)		(11)
Total	16,463		15,818		645		4	%

Average cost of energy per MWh:
Energy generated(3)	$	17.66	$	17.80	$	(0.14)	(1)	%
Energy purchased	$	47.13	$	47.41	$	(0.28)	(1)	%

(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 RECs 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 March 31, 2021 Compared to Quarter Ended March 31, 2020

Utility margin increased $29 million, or 4%, for the first quarter of 2021 compared to 2020 primarily due to:

•$20 million increase in retail revenue primarily due to higher customer volumes and higher average rates from sales mix, partially offset by lower prices due to certain general rate case orders. Retail customer volumes increased 0.3%, primarily due to an increase in the average number of customers across the service territory and favorable impact of weather, partially offset by lower customer usage;

•$18 million of lower purchased electricity costs from lower market prices and lower purchased volumes, partially due to higher wind generation from new Energy Vision 2020 ("EV 2020") generation and repowered facilities; and

•$15 million of higher wholesale revenue due to higher wholesale volumes and higher average wholesale market prices.

The increases above were partially offset by:

•$12 million of higher natural gas-fueled generation costs primarily due to higher average prices;

•$8 million primarily from higher net amortization of deferred net power costs in accordance with established adjustment mechanisms; and

•$6 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.

Operations and maintenance increased $5 million, or 2%, for the first quarter of 2021 compared to 2020 primarily due to higher vegetation management costs of $14 million, partially offset by cost savings from the retirement of Cholla unit 4 in December 2020 and decreased bad debt expense.

Depreciation and amortization increased $12 million, or 5%, for the first quarter of 2021 compared to 2020 primarily due to the impacts of a new depreciation study effective January 1, 2021 of approximately $37 million, including accelerated depreciation on coal-fueled units in Washington and an increase in assets placed in service, partially offset by a $44 million decrease resulting from lower accelerated depreciation for Oregon's share of certain retired wind equipment due to repowering ($3 million in the current quarter (fully offset in other revenue) compared to $47 million in the first quarter of 2020 ($7 million offset in other revenue and $40 million offset in income tax expense)).

Property and other taxes increased$12 million, or 24%, for the first quarter of 2021 compared to 2020 primarily due to higher property taxes from higher assessed property values.

Interest expense increased$5 million, or 5%, for the first quarter of 2021 compared to 2020 primarily due to a higher average long-term debt balance.

Allowance for borrowed and equity funds decreased $12 million, or 39%, for the first quarter of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances due to large EV 2020 projects being placed in service.

Other, net increased $10 million from a loss of $4 million for the first quarter of 2020 to income of $6 million for the first quarter of 2021, primarily due to market movements related to corporate-owned life insurance policies.

Income tax benefit decreased $3 million, or 21%, for the first quarter of 2021 compared to the first quarter of 2020. The effective tax rate was (7)% for 2021 and (9)% for 2020. The effective tax rate increased primarily as a result of lower amortization of excess deferred income taxes in the current year, partially offset by increased PTCs from PacifiCorp's new wind-powered generating facilities. For the first quarter of 2021, $3 million of excess deferred income taxes was amortized pursuant to regulatory orders for Wyoming, whereby portions of excess deferred income taxes were used to offset certain regulatory balances for Wyoming. For the first quarter of 2020, $30 million of excess deferred income taxes was amortized pursuant to the Oregon RAC settlement, whereby a portion of excess deferred income taxes was used to accelerate depreciation for Oregon's share of certain retired wind equipment.

Liquidity and Capital Resources

As of March 31, 2021, PacifiCorp's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	43

Credit facilities	1,200
Less:
Short-term debt	(95)
Tax-exempt bond support	(218)
Net credit facilities	887

Total net liquidity	$	930

Credit facilities:
Maturity dates	2022

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $469 million and $437 million, respectively. The change was primarily due to lower cash paid for income taxes, lower purchased power prices and volumes and lower fuel expense payments due to timing, partially offset by higher operating expense payments due to timing and higher cash paid for interest.

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

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(440) million and $(339) million, respectively. The change is primarily due to an increase in capital expenditures of $73 million and prior year proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2021 was $1 million. Sources of cash consisted of $2 million from the borrowing of short-term debt.

Net cash flows from financing activities for the three-month period ended March 31, 2020 was $(74) million. Uses of cash consisted of $74 million for the repayment of short-term debt.

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of March 31, 2021, PacifiCorp had $95 million of short-term debt outstanding at a weighted average interest rate of 0.16%. As of December 31, 2020, PacifiCorp had $93 million of short-term debt outstanding at a weighted average interest rate of 0.16%.

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $3 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.

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 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 customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2020		2021		2021

Wind generation	$	106	$	33	$	193
Electric distribution	99		195		730
Electric transmission	92		60		426
Other	69		151		548
Total	$	366	$	439	$	1,897

PacifiCorp's 2019 IRP identified a significant increase in renewable resource generation and associated transmission. PacifiCorp has included an estimate of the 2019 IRP resources in its forecast capital expenditures for 2021 through 2023. These estimates are likely to change as a result of the RFP process. PacifiCorp's historical and forecast capital expenditures include the following:

•Wind generation includes both growth projects and operating expenditures. Growth projects include:

◦Construction of wind-powered generating facilities at PacifiCorp totaling $27 million and $89 million for the three-month periods ended March 31, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs expected to be placed in-service in 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $100 million for 2021.

◦Repowering existing wind-powered generating facilities at PacifiCorp totaling $5 million and $16 million for the three-month periods ended March 31, 2021 and 2020, respectively. Certain repowering projects were placed in service in 2019 and 2020 with the remaining repowering projects expected to be placed in-service in 2021. The energy production from such repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned additional spending for certain existing wind-powered generating facilities totals $6 million for 2021.

◦Acquisition and repowering of wind-powered generating facilities totals $1 million for the three-month period ended March 31, 2021. Planned additional spending for these wind-powered generating facilities totals $44 million for 2021.

•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes planned spend on wildfire mitigation, wildfire damage restoration and storm damage repairs. Expenditures for these items totaled $83 million and $4 million for the three-month periods ended March 31, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with these activities will total an additional $145 million in 2021. Remaining investments relate to expenditures for new connections and distribution.

•Electric transmission includes both growth projects and operating expenditures. Transmission investment through 2020 primarily reflects costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020. Planned spending for the additional Energy Gateway Transmission segments totals $182 million in 2021 and are expected to be placed in service in 2023 - 2024.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $13 million and $10 million for the three-month periods ended March 31, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with information technology will total an additional $118 million for 2021. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.

Requests for Proposals

PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load or state-specific compliance obligations. Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.

PacifiCorp issued the 2020 All Source RFP to the market in July 2020. The 2020 All Source RFP sought bids for resources capable of coming online by the end of 2024 up to the level of resources identified in PacifiCorp's 2019 IRP. An initial shortlist was identified in October 2020. The final shortlist of winning bids will be identified by June 2021.

Contractual Obligations

As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, ~~2019.~~

~~Note 17. Commitments and Contingencies~~

~~As a result of issues generated in the ordinary course of business, the Companies are involved in legal proceedings before various courts and are periodically~~2020.

Regulatory Matters

PacifiCorp is subject to ~~governmental examinations (including by~~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 ~~authorities), inquiries~~matters.

Environmental Laws and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that itRegulations

PacifiCorp is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is

recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the Companies’ financial position, liquidity or results of operations.

~~Environmental Matters~~

~~The Companies are~~ subject to ~~costs resulting from a number of~~ federal, state and local laws and regulations ~~designed~~regarding climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to ~~protect human health~~impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the ~~environment.~~authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations ~~affect future planning~~are administered by various federal, state and ~~existing operations. They can result~~local agencies. PacifiCorp believes it is in ~~increased capital, operating~~material compliance with all applicable laws and ~~other costs as a result of compliance, remediation, containment and monitoring obligations.~~

~~Air~~

~~CAA~~

The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation's air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilitiesregulations, although many are subject to interpretation that may ultimately be resolved by the ~~CAA’s permitting~~courts. Environmental laws and ~~other requirements.~~

~~MATS~~

~~In February 2019, the EPA published a proposed rule~~regulations continue to ~~reverse its previous finding that it~~evolve, and PacifiCorp is ~~appropriate and necessary to regulate hazardous air pollutant emissions from~~ ~~coal- and oil-fired electric generating units~~. In April 2020, the EPA finalized its reconsideration and issued a final rule. The final rule is consistent with the EPA’s February 2019 proposal, and determines that it is not appropriate and necessary to regulate mercury and hazardous air pollutant emissions from coal- and oil-fired electric generating units. The final rule also states that the MATS rule remains in place and the emissions standards for affected coal- and oil-fired electric generating units will not change. The effective date of the action will be 60 days after publication in the Federal Register. ~~Dominion Energy and Virginia Power are complying with the applicable requirements of the rule and do not expect any impacts to their operations.~~

~~Ozone Standards~~

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, the Companies are unable to predict ~~whether or~~the impact of the changing laws and regulations on its operations and financial results.

Refer to ~~what extent~~"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 ~~new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact~~future. Amounts recognized on the ~~Companies’ results~~Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of ~~operations~~judgment and ~~cash flows.~~

~~Oil~~uncertainty and ~~Gas NSPS~~

~~In August 2012, the EPA issued an NSPS impacting new and modified facilities~~will likely change in the ~~natural gas production and gathering sectors and made revisions to the NSPS~~future as additional information becomes available. Estimates are used for, natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued another NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. The amended portions of the 2016 rule were effective immediately upon publication. Until the proposed rule regarding reconsideration is final, Dominion Energy and Dominion Energy Gas are implementing the 2016 regulation. Dominion Energy and Dominion Energy Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

~~ACE Rule~~

~~In July 2019, the EPA published the final rule informally referred to as the ACE Rule, as a replacement~~accounting for the ~~Clean Power Plan.~~ ACE Rule applies to existing coal-fired power plants. The final rule includes unit-specific performance standards based on the degree of emission reduction levels achievable from unit efficiency improvements to be determined by the permitting agency. The ACE Rule requires states to develop plans by July 2022, to implement these performance standards. These state plans must be approved by the EPA by January 2024. While the impacts of this rule could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.

~~Carbon Regulations~~

In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of CO₂ equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their results of operations, financial condition and/or cash flows.

In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices.

~~State Regulations~~

In May 2019, VDEQ issued a final rule establishing a state carbon regulation program with a 28.0 million ton initial state-wide carbon cap in 2020. The cap is reduced by approximately 3 percent per year through 2030, resulting in an ultimate cap of 19.6 million tons. The final rule includes a provision for VDEQ to delay implementation of the rule and possible adjustments to the baseline cap pending authorization from the General Assembly and Governor of Virginia. In April 2020, Virginia legislation was enacted authorizing VDEQ to implement the final rule. The Virginia legislation also authorizes Virginia to participate in RGGI or another market-based carbon trading program. The existing regulatory framework in Virginia provides rate recovery mechanisms that are expected to substantially mitigate any such impact.

This legislation is considered related legislation to the VCEA as discussed in Note 13. The VCEA institutes a mandatory renewable portfolio standard, enhances renewable generation and energy storage development, requires the retirementeffects of certain ~~generation facilities, establishes energy efficiency targets, expands net metering and directs Virginia’s participation in a market-based carbon trading program through 2050.~~

~~Water~~

~~The CWA, as amended, is a comprehensive program requiring a broad range~~types of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.

~~Regulation 316(b)~~

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of 5 mandatory facility-specific factors, including a social cost-benefit test, and 6 optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above ~~two~~ MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion Energy and Virginia Power currently have 13 and 7 facilities, respectively, that may be subject to the final regulations. Dominion Energy is also working with the EPA and state regulatory agencies to assess the applicability of Section 316(b) to six hydroelectric facilities, including one Virginia Power facility. Dominion Energy anticipates that it may have to install impingement control technologies at certain of these stations that have once-through cooling systems. Dominion Energy and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.

~~Effluent Limitations Guidelines~~

In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted 2 separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the EPA’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the Effluent Limitations Guidelines final rule from November 2018 to November 2020; however, the latest date for compliance for these regulations remains December 2023. While the impacts of this rule could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities.

~~Waste Management and Remediation~~

The operations of the Companies are subject to a variety of state and federal laws and regulations governing the management and disposal of solid and hazardous waste, and release of hazardous substances associated with current and/or historical operations. The CERCLA, as amended, and similar state laws, may impose joint, several and strict liability for cleanup on potentially responsible parties who owned, operated or arranged for disposal at facilities affected by a release of hazardous substances. In addition, many states have created programs to incentivize voluntary remediation of sites where historical releases of hazardous substances are identified and property owners or responsible parties decide to initiate cleanups.

From time to time, Dominion Energy, Virginia Power or Dominion Energy Gas may be identified as a potentially responsible party in connection with the alleged release of hazardous substances or wastes at a site. Under applicable federal and state laws, the Companies could be responsible for costs associated with the investigation or remediation of impacted sites, or subject to contribution claims by other responsible parties for their costs incurred at such sites. The Companies also may identify, evaluate and remediate other potentially impacted sites under voluntary state programs. Remediation costs may be subject to reimbursement under the Companies’ insurance policies, rate recovery mechanisms, or both. Except as described below, the Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.

Dominion Energy has determined that it is associated with former manufactured gas plant sites, including certain sites associated with Virginia Power. At 11 sites associated with Dominion Energy, including certain sites acquired in the SCANA Combination, remediation work has been substantially completed under federal or state oversight. Where required, the sites are following state-approved groundwater monitoring programs. Dominion Energy has proposed or expects to propose remediation plans associated with 3 sites, including 1 at Virginia Power, and expects to conduct remediation activities primarily in 2020. At both March 31, 2020 and December 31, 2019, Dominion Energy and Virginia Power have $34 million and $16 million, respectively, of reserves recorded. In addition, for 1 site associated with Dominion Energy, an updated work plan submitted to SCDHEC in September 2018, would increase costs by approximately $8 million if approved by federal and state agencies. Dominion Energy is associated with 13 additional sites, including 2 associated with Virginia Power, which are not under investigation by any state or federal environmental agency nor the subject of any current or proposed plans to perform remediation activities. Due to the uncertainty surrounding such sites, Dominion Energy and Virginia Power are unable to make an estimate of the potential financial statement impacts.

~~Other Legal Matters~~

The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.

~~SCANA Legal Proceedings~~

The following describes certain legal proceedings involving Dominion Energy, SCANA or DESC relating to events occurring before closing of the SCANA Combination. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. For certain of these matters, and unless otherwise noted therein, Dominion Energy is unable to estimate a reasonable range of possible loss and the related financial statement impacts, but for any such matter there could be a material impact to its results of operations, financial condition and/or cash flows. For the matters for which Dominion Energy is able to reasonably estimate a probable loss, Dominion Energy’s Consolidated Balance Sheets at March 31, 2020 and December 31, 2019 include reserves of $560 million and $696 million, respectively, and insurance receivables of $6 million and $111 million, respectively, included within other receivables. During the three months ended March 31, 2020, Dominion Energy’s Consolidated Statements of Income include charges of $25 million ($25 million after-tax) included within other income (expense). During the three months ended March 31, 2019, Dominion Energy’s Consolidated Statements of Income include charges of $178 million ($133 million after-tax) included within impairment of assetsregulation, derivatives, pension and other ~~charges.~~

~~Ratepayer Class Actions~~

~~In May 2018, a consolidated complaint against DESC, SCANA~~postretirement benefits, income taxes and ~~the State~~revenue recognition-unbilled revenue. For additional discussion of ~~South Carolina was filed in the State Court~~PacifiCorp's critical accounting estimates, see Item 7 of Common Pleas in Hampton County, South Carolina (the DESC Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that DESC was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that DESC committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that DESC may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and DESC’s assets frozen and all monies recovered from Toshiba Corporation and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.

In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the DESC Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC would establish an escrow account and proceeds from the escrow account would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain DESC-owned real estate or sales proceeds from the sale of such properties, which counsel for the DESC Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and DESC funded the cash payment portion of the escrow account. The court held a fairness hearing on the settlement in May 2019. In June 2019, the court entered an order granting final approval of the settlement, which order became effective July 2019. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. In addition, property, plant and equipment with a net recorded value of $54 million is in the process of being transferred to the plaintiffs in coordination with the court-appointed real estate trustee to satisfy the settlement agreement.

In September 2017, a purported class action was filed by Santee Cooper ratepayers against Santee Cooper, DESC, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the DESC Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants, including certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against DESC, which was denied. In October 2019, Santee Cooper voluntarily consented to stay its cross claims against DESC pending the outcome of the trial of the underlying case. In November 2019, DESC removed the case to the U.S. District Court for the District of South Carolina. In December 2019, the plaintiffs and Santee Cooper filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. In March 2020, the parties executed a settlement agreement relating to this matter as well as the Luquire Case and the Glibowski Case described below. The settlement agreement provides that Dominion Energy and Santee Cooper will establish a fund for the benefit of class members in the amount of $520 million, of which Dominion Energy’s portion is $320 million of shares of Dominion Energy common stock. Also in March 2020, the court granted preliminary approval for the settlement agreement. This case is pending.

In July 2019, a similar purported class action was filed by certain Santee Cooper ratepayers against DESC, SCANA, Dominion Energy and former directors and officers of SCANA in the State Court of Common Pleas in Orangeburg, South Carolina (the Luquire Case). In August 2019, DESC, SCANA and Dominion Energy were voluntarily dismissed from the case. The claims are similar to the Santee Cooper Ratepayer Case. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case is pending.

~~RICO Class Action~~

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, DESC and certain former executive officers in the U.S. District Court for the District of South Carolina (the Glibowski Case). The plaintiff alleges, among other things, that SCANA, DESC and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The DESC Ratepayer Class Action settlement described previously contemplates dismissal of claims by DESC ratepayers in this case against DESC, SCANA and their officers. In August 2019, the individual defendants filed motions to dismiss. In March 2020, the parties executed a settlement agreement as described above relating to this matter as well as the Santee Cooper Ratepayer Case and the Luquire Case. This case is pending.

~~SCANA Shareholder Litigation~~

In September 2017, a purported class action was filed against SCANA and certain former executive officers and directors in the U.S. District Court for the District of South Carolina. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants (collectively the SCANA Securities Class Action). In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Securities Exchange Act of 1934, as amended, and Rule ~~10b-5~~ promulgated thereunder, and that the individually named defendants are liable under §20(a) of the same act. In June 2018, the defendants filed motions to dismiss. In March 2019, the U.S. District Court for the District of South Carolina granted in part and denied in part the defendants’ motions to dismiss. In December 2019, the parties executed a settlement agreement pursuant to which SCANA will pay $192.5 million, up to $32.5 million of which can be satisfied through the issuance of shares of Dominion Energy common stock, subject to approval by the U.S. District Court for the District of South Carolina. In February 2020, the U.S. District Court for the District of South Carolina granted preliminary approval of the settlement agreement, pending a fairness hearing. In March 2020, SCANA funded an escrow account with $160 million in cash and the balance of the settlement will be paid upon final approval of the settlement by the court.

In September 2017, a shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina. In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the NND Project, and that the defendants were unjustly enriched by bonuses they were paid in connection with the project. In January 2019, the defendants filed a motion to dismiss the consolidated action. In February 2019, one action was voluntarily dismissed. In March 2020, the court denied the defendants’ motion to dismiss. In April 2020, the defendants filed a notice of appeal with the South Carolina Court of Appeals and a petition with the Supreme Court of South Carolina seeking appellate review of the denial of the motion to dismiss. This case is pending.

In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors of SCANA in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with a similar appeal in the Metzler Lawsuit discussed below. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court.

In February 2018, a purported class action was filed against Dominion Energy and certain former directors of SCANA and DESC in the State Court of Common Pleas in Richland County, South Carolina (the Metzler Lawsuit). The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal was consolidated with the City of Warren Lawsuit. In June 2019, the U.S. Court of Appeals for the Fourth Circuit reversed the order remanding the case to state court.

In September 2019, the U.S. District Court for the District of South Carolina granted the plaintiffs’ motion to consolidate the City of Warren Lawsuit and the Metzler Lawsuit. In October 2019, the plaintiffs filed an amended complaint against certain former directors and executive officers of SCANA and DESC, which stated substantially similar allegations to those in the City of Warren Lawsuit and the Metzler Lawsuit as well as an inseparable fraud claim. In November 2019, the defendants filed a motion to dismiss. In April 2020, ~~the U.S. District Court for the District of South Carolina denied the motion to dismiss. This case is pending.~~

In May 2019, a case was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the NND Project, were unjustly enriched by the bonuses they were paid in connection with the project and breached their fiduciary duties to secure and obtain the best price for the sale of SCANA. Also in May 2019, the case was removed to the U.S. District Court of South Carolina by the non-South Carolina defendants. In June 2019, the plaintiffs filed a motion to remand the case to state court. In January 2020, the case was remanded to state court. In February 2020, the defendants filed a motion to dismiss. This case is pending.

~~Employment Class Actions and Indemnification~~

In August 2017, a case was filed in the U.S. District Court for the District of South Carolina on behalf of persons who were formerly employed at the NND Project. In July 2018, the court certified this case as a class action. In February 2019, certain of these plaintiffs filed an additional case, which case has been dismissed and the plaintiffs have joined the case filed August 2017. The plaintiffs allege, among other things, that SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment and are seeking damages, which could be as much as $100 million for 100% of the NND Project.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against DESC and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. These cases are pending.

~~FILOT Litigation and Related Matters~~

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against DESC in the State Court of Common Pleas in Fairfield County, South Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to DESC’s termination of the FILOT agreement between DESC and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent DESC from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending.

~~Governmental Proceedings and Investigations~~

In June 2018, DESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of DESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that DESC’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. DESC has protested the proposed assessment, which remains pending.

In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In February 2020, the SEC filed a complaint against SCANA, two of its former executive officers and DESC in the U.S. District Court for the District of South Carolina alleging that the defendants violated federal securities laws by making false and misleading statements about the NND Project. In April 2020, SCANA and DESC reached an agreement in principle with the Staff of the SEC’s Division of Enforcement to settle, without admitting or denying the allegations in the complaint. The Staff of the SEC’s Division of Enforcement has not yet presented the proposed settlement to the SEC. The agreement in principle would, among other things, require SCANA to pay a civil monetary penalty totaling $25 million, and SCANA and DESC to pay disgorgement and prejudgment interest totaling $112.5 million, which disgorgement and prejudgment interest amount will be deemed satisfied by the settlements in the SCANA Securities Class Action and the DESC Ratepayer Case. The proposed settlement is contingent on the review and approval of final documentation by SCANA, DESC and the Staff of the SEC’s Division of Enforcement and is subject to approval by the SEC and the U.S. District Court for the District of South Carolina. This matter is pending.

In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. Dominion Energy is cooperating fully with the investigations by the U.S. Attorney’s Office and the South Carolina Law Enforcement Division, including responding to additional subpoenas and document requests. Dominion Energy has also entered into a cooperation agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office. The cooperation agreement provides that in consideration of its full cooperation with these investigations to the satisfaction of both agencies, neither such agency will criminally prosecute or bring any civil action against Dominion Energy or any of its current, previous, or future direct or indirect subsidiaries related to the NND Project. These matters are pending.

~~Other Litigation~~

In December 2018, arbitration proceedings commenced between DESC and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which DESC agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that DESC violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for the 2017 and 2018 delivery years. DESC denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. This matter is pending.

~~Abandoned NND Project~~

DESC, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which DESC’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper.

Based on the results of SCANA’s analysis, and in light of Santee Cooper's decision to suspend construction on the NND Project, in July 2017, SCANA determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings remain unresolved and are described above.

In September 2017, DESC, for itself and as agent for Santee Cooper, filed with the U.S. Bankruptcy Court for the Southern District of New York Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto.

Westinghouse’s reorganization plan was confirmed by the U.S. Bankruptcy Court for the Southern District of New York and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. DESC is contesting approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens are claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them are claims arising from work performed after the Westinghouse bankruptcy.

Westinghouse has indicated that some unsecured creditors have sought or may seek amounts beyond what Westinghouse allocated when it submitted its reorganization plan to the U.S. Bankruptcy Court for the Southern District of New York. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the bankruptcy reorganization plan allocated by Westinghouse, it is possible that the reorganization plan will not provide for payment in full or nearly in full to its ~~pre-petition~~ ~~trade creditors. The shortfall could be significant.~~

DESC and Santee Cooper were responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the interim assessment agreement.

Further, some Westinghouse subcontractors who have made claims against Westinghouse in the bankruptcy proceeding also filed against DESC and Santee Cooper in South Carolina state court for damages. Many of these claimants have also asserted construction liens against the NND Project site. DESC also intends to oppose these claims and liens. With respect to claims of Westinghouse subcontractors, DESC believes there were sufficient amounts previously funded during the interim assessment agreement period to pay such validly asserted claims. With respect to the Westinghouse subcontractor claims which relate to other periods, DESC understands that such claims will be paid pursuant to Westinghouse’s confirmed bankruptcy reorganization plan. DESC further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, DESC believes that the Westinghouse subcontractors may be paid substantially (and potentially in full) by Westinghouse. While Dominion Energy cannot be assured that it will not have any exposure on account of unpaid Westinghouse subcontractor claims, which DESC is presently disputing, Dominion Energy believes it is unlikely that it will be required to make payments on account of such claims.

~~Nuclear Matters~~

In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events resulted in significant nuclear safety reviews by the NRC and industry groups such as the Institute of Nuclear Power Operations. Like other U.S. nuclear operators, Dominion Energy has gathered supporting data and participated in industry initiatives focused on the ability to respond to and mitigate the consequences of, design-basis and beyond-design-basis events at its stations.

In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3. Tier 1 recommendations consisted of actions which the NRC staff determined should be started without unnecessary delay. Tier 2 and 3 items consisted of items which could not be initiated in the near term because of resource restraints, the need for further technical assessment, or were dependent on activities related to the higher priority Tier 1 issues. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.

Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactor licensees, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion Energy requiring implementation of safety enhancements related to mitigation strategies for responding to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC requested each reactor licensee to reevaluate the seismic and external flooding hazards at their facility using ~~present-day~~ methods and information, conduct walkdowns of their facility to ensure protection against these hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevaluation of the seismic hazards is complete and final with NRC acceptance received for all Dominion Energy facilities. Reevaluation of the external flooding hazards is complete for all Dominion Energy facilities. However, NRC acceptance of the external flooding hazards reevaluations for Millstone and Surry have not yet been received. NRC is expected to accept these external flooding hazards analyses in 2020. Dominion Energy and Virginia Power do not currently expect that compliance with the NRC’s information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff has resolved the Tier 2 and Tier 3 recommendations and no additional future actions on the part of Dominion Energy are anticipated with respect to these recommendations. Therefore, Dominion Energy and Virginia Power do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

~~Nuclear Operations~~

~~Spent Nuclear Fuel~~

~~As discussed in Note 23 to the Consolidated Financial Statements in the Companies’~~PacifiCorp's Annual Report on Form 10-K for the year ended December 31, ~~2019, Dominion Energy and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982.~~

~~In June 2018, a lawsuit for Kewaunee was filed~~2020. There have been no significant changes in the U.S. Court of Federal Claims for recovery of spent nuclear fuel storage costs incurred after 2013. In March 2019, Dominion Energy amended its filing for recovery of spent nuclear fuel storage to include costs incurred for the year endedPacifiCorp's assumptions regarding critical accounting estimates since December 31, ~~2018. This matter is pending.~~

~~Guarantees, Surety Bonds~~2020.

MidAmerican Funding, LLC and ~~Letters~~its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of ~~Credit~~

~~Dominion~~Directors and Shareholder of

MidAmerican Energy ~~entered into a guarantee agreement to support a portion~~Company

Results of ~~Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility with a stated maturity date~~Review of ~~October 2021. In March 2020, Dominion~~Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy acquired Southern’s 5% membership interest in Atlantic Coast Pipeline. As a result, Dominion Energy’s maximum potential loss exposure under the terms of the guarantee has increased from 48% to 53% of the outstanding borrowings under the revolving credit facility, an equal percentage to Dominion Energy’s ownership in Atlantic Coast Pipeline. As of March 31, 2020, Atlantic Coast Pipeline had borrowed $1.8 billion against the revolving credit facility and borrowed an additional $32 million in the second quarter of 2020. Dominion Energy’s Consolidated Balance Sheets include a liability of $60 million and $14 million associated with this guarantee agreement at March 31, 2020 and December 31, 2019, respectively. The liabilityCompany ("MidAmerican Energy") as of March 31, 2021, the related statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2021 and 2020, ~~includes~~and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2020, 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 26, 2021, 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, 2020, 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 ~~$48 million adjustment reflected within equity~~public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a ~~cumulative-effect~~whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

April 30, 2021

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	March 31,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	37	$	38
Trade receivables, net	521		234
Income tax receivable	293		0
Inventories	231		278
Other current assets	103		73
Total current assets	1,185		623

Property, plant and equipment, net	19,223		19,279
Regulatory assets	439		392
Investments and restricted investments	938		911
Other assets	215		232

Total assets	$	22,000	$	21,437

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

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	March 31,		December 31,
	2021		2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	292	$	408
Accrued interest	86		78
Accrued property, income and other taxes	124		161
Short-term debt	387		0

Other current liabilities	186		183
Total current liabilities	1,075		830

Long-term debt	7,224		7,210
Regulatory liabilities	1,257		1,111
Deferred income taxes	3,107		3,054
Asset retirement obligations	711		709
Other long-term liabilities	414		458
Total liabilities	13,788		13,372

Commitments and contingencies (Note 8)	0		0

Shareholder's equity:
Common stock - 350 shares authorized, 0 par value, 71 shares issued and outstanding	0		0
Additional paid-in capital	561		561
Retained earnings	7,651		7,504

Total shareholder's equity	8,212		8,065

Total liabilities and shareholder's equity	$	22,000	$	21,437

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue:
Regulated electric		$	545	$	471
Regulated natural gas and other		522		210
Total operating revenue		1,067		681

Operating expenses:
Cost of fuel and energy		151		80
Cost of natural gas purchased for resale and other		432		128
Operations and maintenance		193		165
Depreciation and amortization		207		176
Property and other taxes		36		34
Total operating expenses		1,019		583

Operating income		48		98

Other income (expense):
Interest expense		(74)		(76)
Allowance for borrowed funds		2		3
Allowance for equity funds		6		8
Other, net		11		(5)
Total other income (expense)		(55)		(70)

(Loss) income before income tax benefit		(7)		28
Income tax benefit		(154)		(123)

Net income		$	147	$	151

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, December 31, 2019	$	0	$	561	$	6,679	$	7,240
Net income	—		—		151		151

Balance, March 31, 2020	$	0	$	561	$	6,830	$	7,391






Balance, December 31, 2020	$	0	$	561	$	7,504	$	8,065
Net income	—		—		147		147

Balance, March 31, 2021	$	0	$	561	$	7,651	$	8,212

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income	$	147	$	151
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	207		176
Amortization of utility plant to other operating expenses	8		9
Allowance for equity funds	(6)		(8)
Deferred income taxes and amortization of investment tax credits	154		91
Settlements of asset retirement obligations	(4)		(2)
Other, net	(4)		14
Changes in other operating assets and liabilities:
Trade receivables and other assets	(299)		15
Inventories	46		(6)
Derivative collateral, net	(14)		1
Pension and other postretirement benefit plans	1		(6)
Accrued property, income and other taxes, net	(331)		(286)
Accounts payable and other liabilities	10		70
Net cash flows from operating activities	(85)		219

Cash flows from investing activities:
Capital expenditures	(298)		(472)
Purchases of marketable securities	(52)		(127)
Proceeds from sales of marketable securities	47		124
Other, net	0		5
Net cash flows from investing activities	(303)		(470)

Cash flows from financing activities:



Net proceeds from short-term debt	387		50
Other, net	0		(1)
Net cash flows from financing activities	387		49

Net change in cash and cash equivalents and restricted cash and cash equivalents	(1)		(202)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	45		330
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	44	$	128

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

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1) General

MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct, wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for ~~current expected credit loss associated with this guarantee agreement.~~

~~In addition, at~~interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of March 31, ~~2020, Dominion Energy had issued an additional $27 million~~2021, and for the three-month periods ended March 31, 2021 and 2020. The Statements of ~~guarantees, primarily to support other equity method investees. No amounts related to the other guarantees~~Comprehensive Income have been ~~recorded.~~

~~Dominion Energy also enters into guarantee arrangements on behalf~~omitted as net income equals comprehensive income for the three-month period ended March 31, 2021 and 2020. The results of ~~its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. If any of these subsidiaries fail to perform or pay under~~operations for the contracts and the counterparties seek performance or payment, Dominion Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion Energy isthree-month periods ended March 31, 2021, are not ~~required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms~~necessarily indicative of the ~~guarantees typically end once obligations have been paid. Dominion Energy currently believes it is unlikely that it would~~results to be ~~required to perform or otherwise incur any losses associated with guarantees~~expected for the full year.

The preparation of ~~its subsidiaries’ obligations.~~

~~At March 31, 2020, Dominion Energy had issued~~ the ~~following subsidiary guarantees:~~

Maximum
Exposure

(millions)

Commodity transactions⁽¹⁾

$
2,226

Nuclear obligations⁽²⁾

204

Cove Point⁽³⁾

1,900

Solar⁽⁴⁾

434

Other⁽⁵⁾

448

Total⁽⁶⁾

$
5,212

~~(1)~~

Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction related commodities and services.

~~(2)~~

~~Guarantees primarily related to certain DGI subsidiaries regarding all aspects of running a nuclear facility.~~

~~(3)~~

Guarantees related to Cove Point, in support of terminal services, transportation and construction. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount.

~~(4)~~

Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.

~~(5)~~

Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of workers’ compensation claims, the parental guarantee has no stated limit.

~~(6)~~

Excludes Dominion Energy's guarantees for the new corporate office properties discussed in Note 15 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

Additionally, at March 31, 2020, Dominion Energy had purchased $164 million of surety bonds, including $79 million at Virginia Power and $27 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $86 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

~~Note 18. Credit Risk~~

~~The Companies’ accounting policies for credit risk are discussed in Note 24 to the Consolidated~~unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the ~~Companies’~~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, ~~2019.~~

~~At March 31,~~ 2020, ~~Dominion Energy’s gross credit exposure related to energy marketing~~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 assumptions regarding significant accounting estimates and price risk management activities totaled $172 million. Of this amount, investment grade counterparties, including those internally rated, represented 95%. NaN single counterparty, whether investment grade or non-investment grade, exceeded $55 million of exposure. At March 31, 2020, Virginia Power’s exposure related to wholesale customers totaled $65 million. Of this amount, investment grade counterparties, including those internally rated, represented 100%. NaN single counterparty, whether investment grade or non-investment grade, exceeded $55 million of exposure. At March 31, 2020, Dominion Energy Gas’ exposure primarily related to wholesale customers totaled $45 million. Of this amount, investment grade counterparties, including those internally rated, represented 92%. NaN single counterparty, whether investment grade or non-investment grade, exceeded $12 million of exposure.

~~For~~policies during the ~~three months~~three-month period ended March 31, ~~2020~~2021.

(2) Cash and ~~2019, the Export Customers comprised approximately 33%~~Cash Equivalents and ~~32%, respectively,~~Restricted Cash and Cash Equivalents

Cash equivalents consist of ~~Dominion Energy Gas’ total operating revenue,~~funds invested in money market mutual funds, United States Treasury Bills and other investments with ~~Dominion Energy Gas’ largest customer representing approximately 17%~~a maturity of ~~such amount during both periods~~.

~~Credit-Related Contingent Provisions~~

~~The majority of Dominion Energy��s derivative instruments contain credit-related contingent~~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. These provisions require Dominion Energy to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability positionRestricted cash and ~~not fully collateralized with~~ cash ~~were fully triggered~~equivalents as of March 31, ~~2020~~2021 and December 31, ~~2019, Dominion Energy would have been required to post $14 million~~2020, consist substantially of funds restricted for wildlife preservation and, ~~$10 million, respectively,~~as of additional collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion Energy had posted $4 million of collateral at MarchDecember 31, 2020, ~~related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with~~the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and ~~had posted 0 collateral at December 31, 2019. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position~~cash equivalents and ~~not fully collateralized with~~restricted cash ~~was $18 million~~ and ~~$10 million at March 31, 2020 and December 31, 2019, respectively, which does not include the impact of any offsetting asset positions.~~

~~If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with~~ cash ~~were fully triggered~~equivalents as of March 31, ~~2020~~2021 and December 31, ~~2019, Virginia Power would have~~2020, as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2021		2020

Cash and cash equivalents	$	37	$	38
Restricted cash and cash equivalents in other current assets	7		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	44	$	45

(3) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):


		As of
		March 31,		December 31,
	Depreciable Life	2021		2020
Utility plant in service, net:
Generation	20-70 years	$	17,083	$	16,980
Transmission	52-75 years	2,372		2,365
Electric distribution	20-75 years	4,433		4,369
Natural gas distribution	29-75 years	1,970		1,955
Utility plant in service		25,858		25,669
Accumulated depreciation and amortization		(7,061)		(6,902)
Utility plant in service, net		18,797		18,767
Nonregulated property, net:
Nonregulated property gross	20-50 years	7		7
Accumulated depreciation and amortization		(1)		(1)
Nonregulated property, net		6		6
		18,803		18,773
Construction work-in-progress		420		506
Property, plant and equipment, net		$	19,223	$	19,279

(4) Regulatory Matters

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. These increased costs are reflected in cost of natural gas purchased for resale and other on the Statement of Operations and their recovery through the Purchased Gas Adjustment Clause is reflected in regulated natural gas and other revenue.

To mitigate the impact to customers, the Iowa Utilities Board ordered the recovery of these higher costs to be applied to natural gas sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during three-month period ended March 31, 2021.

(5) Income Taxes

The effective income tax rate for the three-month period ended March 31, 2021, is 2,200% and results from a $154 million income tax benefit associated with a $7 million pre-tax loss. The $154 million income tax benefit is primarily comprised of a $2 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss and a $168 million benefit (2,400%) from income tax credits, partially offset by a $13 million expense (186%) from the effects of ratemaking.

A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:


	Three-Month Periods
	Ended March 31,
		2021		2020

Federal statutory income tax rate		21	%	21	%
Income tax credits		2,400		(430)
State income tax, net of federal income tax impacts		(29)		(28)
Effects of ratemaking		(186)		(3)
Other, net		(6)		1
Effective income tax rate		2,200	%	(439)	%

Income tax credits relate primarily to production tax credits ("PTCs") from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. 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-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods ended March 31, 2021 and 2020 totaled $151 million and $120 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been ~~required~~computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to ~~post an additional~~or received from BHE. The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date. MidAmerican Energy made 0 cash payments for income tax to BHE for the three-month period ended March 31, 2021, and made net cash payments for income tax to BHE totaling $46 million for the three-month period ended March 31, 2020.

(6) Employee Benefit Plans

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.

Net periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020
Pension:
Service cost		$	5	$	1
Interest cost		6		6
Expected return on plan assets		(9)		(10)

Net periodic benefit cost (credit)		$	2	$	(3)

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

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and $12 million, respectively, during 2021. As of March 31, 2021, $2 million and $8$3 million ~~respectively,~~ of contributions had been made to the pension and other postretirement benefit plans, respectively.

(7) 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 March 31, 2021:
Assets:
Commodity derivatives	$	—	$	3	$	2	$	(2)	$	3
Money market mutual funds(2)	38		0		0		—		38
Debt securities:
United States government obligations	210		0		0		—		210
International government obligations	0		5		0		—		5
Corporate obligations	0		71		0		—		71
Municipal obligations	0		2		0		—		2
Agency, asset and mortgage-backed obligations	0		5		0		—		5
Equity securities:
United States companies	395		0		0		—		395
International companies	8		0		0		—		8
Investment funds	24		0		0		—		24
	$	675	$	86	$	2	$	(2)	$	761

Liabilities - commodity derivatives	$	0	$	(1)	$	(1)	$	2	$	0


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2020:
Assets:
Commodity derivatives	$	0	$	4	$	5	$	(5)	$	4
Money market mutual funds(2)	41		0		0		—		41
Debt securities:
United States government obligations	200		0		0		—		200
International government obligations	0		5		0		—		5
Corporate obligations	0		73		0		—		73
Municipal obligations	0		2		0		—		2
Agency, asset and mortgage-backed obligations	0		6		0		—		6
Equity securities:
United States companies	381		0		0		—		381
International companies	9		0		0		—		9
Investment funds	17		0		0		—		17
	$	648	$	90	$	5	$	(5)	$	738

Liabilities - commodity derivatives	$	0	$	(4)	$	(3)	$	5	$	(2)

(1)Represents netting under master netting arrangements and a net cash collateral ~~to its counterparties.~~

~~Credit-related contingent provisions for Dominion Energy Gas were not material~~receivable of $— million as of March 31, ~~2020~~2021 and December 31, ~~2019. See~~2020, respectively.

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

MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

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 March 31, 2021				As of December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,224	$	8,305	$	7,210	$	9,130

(8) Commitments and Contingencies

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

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

Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using Federal Energy Regulatory Commission ("FERC")-approved formula rates subject to true-up for actual cost of service. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the approved base return on equity ("ROE") effective January 2015. Prior to September 2016, the rates in effect were based on a 12.38% ROE. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the 12.38% ROE no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively. In September 2016, the FERC issued an order for the first complaint, which reduces the base ROE to 10.32% and required refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. In November 2019, the FERC issued an order addressing the second complaint and issues on appeal in the first complaint. The order established a ROE of 9.88% (10.38% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 forward. In May 2020, the FERC issued an order on rehearing of the November 2019 order. The May 2020 order affirmed the FERC's prior decision to dismiss the second complaint and established an ROE of 10.02% (10.52% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 to the date of the May 2020 order. These orders continue to be subject to judicial appeal. MidAmerican Energy cannot predict the ultimate outcome of these matters and, as of March 31, 2021, has accrued a $10 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.

(9) Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 10, (in millions):


	For the Three-Month Period Ended March 31, 2021
		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential		$	161	$	308	$	—	$	469
Commercial		71		129		—		200
Industrial		190		12		—		202
Natural gas transportation services		—		10		—		10
Other retail(1)		30		1		—		31
Total retail		452		460		—		912
Wholesale		74		51		—		125
Multi-value transmission projects		15		—		—		15
Other Customer Revenue		—		—		10		10
Total Customer Revenue		541		511		10		1,062
Other revenue		4		1		0		5
Total operating revenue		$	545	$	512	$	10	$	1,067


	For the Three-Month Period Ended March 31, 2020
		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential		$	148	$	128	$	—	$	276
Commercial		70		43		—		113
Industrial		163		4		—		167
Natural gas transportation services		—		11		—		11
Other retail(1)		29		0		—		29
Total retail		410		186		—		596
Wholesale		42		22		—		64
Multi-value transmission projects		16		—		—		16
Other Customer Revenue		—		—		1		1
Total Customer Revenue		468		208		1		677
Other revenue		3		1		0		4
Total operating revenue		$	471	$	209	$	1	$	681

(1) Other retail includes provisions for rate refunds, for which any actual refunds will be reflected in the applicable customer classes upon resolution of the related regulatory proceeding.

(10) Segment Information

MidAmerican Energy has identified 2 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
	Ended March 31,
		2021		2020
Operating revenue:
Regulated electric		$	545	$	471
Regulated natural gas		512		209
Other		10		1
Total operating revenue		$	1,067	$	681

Operating income:
Regulated electric		$	9	$	59
Regulated natural gas		39		39

Total operating income		48		98
Interest expense		(74)		(76)
Allowance for borrowed funds		2		3
Allowance for equity funds		6		8
Other, net		11		(5)
(Loss) income before income tax benefit		$	(7)	$	28


	As of
	March 31, 2021		December 31, 2020
Assets:
Regulated electric	$	20,272	$	19,892
Regulated natural gas	1,725		1,544
Other	3		1
Total assets	$	22,000	$	21,437

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of March 31, 2021, the related consolidated statements of operations, changes in member's equity, and cash flows for the three-month periods ended March 31, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2020, 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 26, 2021, 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, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB and with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

April 30, 2021

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	March 31,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	38	$	39
Trade receivables, net	521		234
Income tax receivable	295		0
Inventories	231		278
Other current assets	102		74
Total current assets	1,187		625

Property, plant and equipment, net	19,223		19,279
Goodwill	1,270		1,270
Regulatory assets	439		392
Investments and restricted investments	940		913
Other assets	215		232

Total assets	$	23,274	$	22,711

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
	March 31,		December 31,
	2021		2020
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	292	$	408
Accrued interest	87		83
Accrued property, income and other taxes	124		161
Note payable to affiliate	184		177
Short-term debt	387		—

Other current liabilities	187		183
Total current liabilities	1,261		1,012

Long-term debt	7,464		7,450
Regulatory liabilities	1,257		1,111
Deferred income taxes	3,104		3,052
Asset retirement obligations	711		709
Other long-term liabilities	414		458
Total liabilities	14,211		13,792

Commitments and contingencies (Note 8)	0		0

Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	7,384		7,240

Total member's equity	9,063		8,919

Total liabilities and member's equity	$	23,274	$	22,711

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue:
Regulated electric		$	545	$	471
Regulated natural gas and other		522		215
Total operating revenue		1,067		686

Operating expenses:
Cost of fuel and energy		151		80
Cost of natural gas purchased for resale and other		432		129
Operations and maintenance		193		165
Depreciation and amortization		207		176
Property and other taxes		36		34
Total operating expenses		1,019		584

Operating income		48		102

Other income (expense):
Interest expense		(78)		(81)
Allowance for borrowed funds		2		3
Allowance for equity funds		6		8
Other, net		10		(6)
Total other income (expense)		(60)		(76)

(Loss) income before income tax benefit		(12)		26
Income tax benefit		(156)		(124)

Net income		$	144	$	150

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

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, December 31, 2019	$	1,679	$	6,422	$	8,101
Net income	—		150		150

Balance, March 31, 2020	$	1,679	$	6,572	$	8,251






Balance, December 31, 2020	$	1,679	$	7,240	$	8,919
Net income	—		144		144

Balance, March 31, 2021	$	1,679	$	7,384	$	9,063

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income	$	144	$	150
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	207		176
Amortization of utility plant to other operating expenses	8		9
Allowance for equity funds	(6)		(8)
Deferred income taxes and amortization of investment tax credits	153		93

Settlements of asset retirement obligations	(4)		(2)
Other, net	(3)		15
Changes in other operating assets and liabilities:
Trade receivables and other assets	(298)		16
Inventories	46		(6)
Derivative collateral, net	(14)		1
Pension and other postretirement benefit plans	1		(6)
Accrued property, income and other taxes, net	(332)		(290)
Accounts payable and other liabilities	6		66
Net cash flows from operating activities	(92)		214

Cash flows from investing activities:
Capital expenditures	(298)		(472)
Purchases of marketable securities	(52)		(127)
Proceeds from sales of marketable securities	47		124

Other, net	0		6
Net cash flows from investing activities	(303)		(469)

Cash flows from financing activities:



Net change in note payable to affiliate	7		3
Net proceeds from short-term debt	387		50
Other, net	0		(1)
Net cash flows from financing activities	394		52

Net change in cash and cash equivalents and restricted cash and cash equivalents	(1)		(203)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	46		331
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	45	$	128

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct, wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct, wholly owned nonregulated subsidiary is Midwest Capital Group, Inc.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2021, and for the three-month periods ended March 31, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three-month period ended March 31, 2021 and 2020. The results of operations for the three-month periods ended March 31, 2021, 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, 2020, 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 assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States 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 as of March 31, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation and, as of December 31, 2020, the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2021		2020

Cash and cash equivalents	$	38	$	39
Restricted cash and cash equivalents in other current assets	7		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	45	$	46

(3) Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.

(4) Regulatory Matters

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

(5) Income Taxes

The effective income tax rate for the three-month period ended March 31, 2021, is 1,300% and results from a $156 million income tax benefit associated with a $12 million pre-tax loss. The $156 million income tax benefit is primarily comprised of a $3 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss and a $168 million benefit (1,400%) from income tax credits, partially offset by a $13 million expense (108%) from the effects of ratemaking.

A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit is as follows:


	Three-Month Periods
	Ended March 31,
		2021		2020

Federal statutory income tax rate		21	%	21	%
Income tax credits		1,400		(463)
State income tax, net of federal income tax impacts		(8)		(31)
Effects of ratemaking		(108)		(3)
Other, net		(5)		(1)
Effective income tax rate		1,300	%	(477)	%

Income tax credits relate primarily to production tax credits ("PTCs") from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. 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-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods ended March 31, 2021 and 2020 totaled $151 million and $120 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or received from BHE. The timing of MidAmerican Funding's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date. MidAmerican Funding made 0 cash payments for income tax to BHE for the three-month period ended March 31, 2021, and made net cash payments for income tax to BHE totaling $47 million for the three-month period ended March 31, 2020.

(6) Employee Benefit Plans

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

(7) Fair Value Measurements

Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):


	As of March 31, 2021				As of December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,464	$	8,622	$	7,450	$	9,466

(8) 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) Revenue from Contracts with Customers

Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $— million and $5 million for the three-month periods ended March 31, 2021 and 2020, respectively.

(10) Segment Information

MidAmerican Funding has identified 2 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
	Ended March 31,
		2021		2020
Operating revenue:
Regulated electric		$	545	$	471
Regulated natural gas		512		209
Other		10		6
Total operating revenue		$	1,067	$	686

Operating income:
Regulated electric		$	9	$	59
Regulated natural gas		39		39
Other		0		4
Total operating income		48		102
Interest expense		(78)		(81)
Allowance for borrowed funds		2		3
Allowance for equity funds		6		8
Other, net		10		(6)
(Loss) income before income tax benefit		$	(12)	$	26


	As of
	March 31, 2021		December 31, 2020
Assets(1):
Regulated electric	$	21,463	$	21,083
Regulated natural gas	1,804		1,623
Other	7		5
Total assets	$	23,274	$	22,711


(1)			Assets by reportable segment reflect the assignment of goodwill to applicable reporting units.

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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with MidAmerican Funding's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.

Results of Operations for the First Quarter of 2021 and 2020

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the first quarter of 2021 was $147 million, a decrease of $4 million, or 3%, compared to 2020 primarily due to higher depreciation and amortization expense of $31 million from additional assets placed in-service and the expiration of a regulatory mechanism deferring certain depreciation expense, and higher operations and maintenance expenses of $28 million, partially offset by a greater income tax benefit of $31 million from higher PTCs recognized, higher investment earnings of $19 million and higher company-retained margins of $9 million on natural gas wholesale sales. PTCs recognized increased due to higher wind-powered generation driven primarily by new wind projects placed in-service.

MidAmerican Funding -

MidAmerican Funding's net income for the first quarter of 2021 was $144 million, a decrease of $6 million, or 4%, compared to 2020. The decrease was primarily due to the changes in MidAmerican Energy's earnings discussed above.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.

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):


	First Quarter
		2021			2020			Change
Electric utility margin:
Operating revenue			$	545		$	471		$	74	16	%
Cost of fuel and energy			151			80			71		89
Electric utility margin			394			391			3		1	%

Natural gas utility margin:
Operating revenue			512			209			303		145	%
Natural gas purchased for resale			432			128			304		238
Natural gas utility margin			80			81			(1)		(1)	%

Utility margin			474			472			2		—	%

Other operating revenue			10			1			9		*

Operations and maintenance			193			165			28		17
Depreciation and amortization			207			176			31		18
Property and other taxes			36			34			2		6

Operating income			$	48		$	98		$	(50)	(51)	%

Electric Utility Margin

A comparison of key operating results related to electric utility margin is as follows for the quarters ended March 31:


	First Quarter
		2021	2020		Change
Utility margin (in millions):
Operating revenue			$	545	$	471	$	74	16	%
Cost of fuel and energy			151		80		71		89
Utility margin			$	394	$	391	$	3	1	%

Sales (GWhs):
Residential			1,738		1,668		70		4	%
Commercial			938		969		(31)		(3)
Industrial			3,819		3,524		295		8
Other			370		385		(15)		(4)
Total retail			6,865		6,546		319		5
Wholesale			4,051		2,434		1,617		66
Total sales			10,916		8,980		1,936		22	%

Average number of retail customers (in thousands)			801		792		9		1	%

Average revenue per MWh:
Retail			$	65.82	$	62.75	$	3.07	5	%
Wholesale			$	16.64	$	15.71	$	0.93	6	%

Heating degree days			3,211		2,952		259		9	%


Sources of energy (GWhs)(1):
Wind and other(2)			6,122		4,846		1,276		26	%
Coal			2,902		1,573		1,329		84
Nuclear			895		993		(98)		(10)
Natural gas			143		116		27		23
Total energy generated			10,062		7,528		2,534		34
Energy purchased			1,018		1,643		(625)		(38)
Total			11,080		9,171		1,909		21	%

Average cost of energy per MWh:
Energy generated(3)			$	6.15	$	5.00	$	1.15	23	%
Energy purchased			$	87.45	$	25.59	$	61.86	*

* Not meaningful.

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

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

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

Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows for the quarters ended March 31:


	First Quarter
		2021	2020		Change
Utility margin (in millions):
Operating revenue			$	512	$	209	$	303	*
Natural gas purchased for resale			432		128		304		*
Utility margin			$	80	$	81	$	(1)	(1)	%

Throughput (000's Dths):
Residential			25,282		23,910		1,372		6	%
Commercial			11,733		10,951		782		7
Industrial			1,437		1,512		(75)		(5)
Other			37		35		2		6
Total retail sales			38,489		36,408		2,081		6
Wholesale sales			10,773		12,910		(2,137)		(17)
Total sales			49,262		49,318		(56)		—
Natural gas transportation service			29,640		34,954		(5,314)		(15)
Total throughput			78,902		84,272		(5,370)		(6)	%

Average number of retail customers (in thousands)			777		770		7		1	%

Average revenue per retail Dth sold			$	11.70	$	4.85	$	6.85	*

Heating degree days			3,301		3,067		234		8	%

Average cost of natural gas per retail Dth sold			$	9.87	$	2.91	$	6.96	*

Combined retail and wholesale average cost of natural gas per Dth sold			$	8.76	$	2.60	$	6.16	*

* Not meaningful.

Quarter Ended March 31, 2021 Compared to Quarter Ended March 31, 2020

MidAmerican Energy -

Electric utility margin increased $3 million for the first quarter of 2021 compared to 2020, due to:

•a $15 million increase in retail utility margin due to an increase of $6 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); an increase of $6 million from the favorable impact of weather; and an increase of $4 million due to price impacts from changes in sales mix and other rate and usage variances, including increased usage for certain industrial customers; partially offset by

•a $12 million decrease in wholesale utility margin due to lower margins per unit, reflecting higher energy costs, partially offset by higher sales volumes of 66.4%.

Natural gas utility margin decreased $1 million for the first quarter of 2021 compared to 2020 primarily due to:

•a $7 million decrease from higher rider refunds related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit); partially offset by

•$3 million from higher natural gas energy efficiency program revenue (offset in operations and maintenance expense); and

•$2 million from the favorable impact of weather.

Operations and maintenance increased $28 million for the first quarter of 2021 compared to 2020 primarily due to higher generation operations and maintenance expenses of $6 million due to additional wind turbines and easements, higher electric and natural gas distribution costs of $6 million, higher energy efficiency program expense of $5 million (offset in operating revenue) and higher employee-related expenses of $5 million.

Depreciation and amortization for the first quarter of 2021 increased $31 million compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service and $13 million from the expiration of a regulatory mechanism deferring certain depreciation expense.

Interest expense decreased $2 million for the first quarter of 2021 compared to 2020 due to lower average interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds decreased $3 million for the first quarter of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net increased $16 million for the first quarter of 2021 compared to 2020 primarily due to higher cash surrender values of corporate-owned life insurance policies.

Income tax benefit increased $31 million for the first quarter of 2021 compared to 2020, and the effective tax rate was 2,200% for 2021 and (439)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was due to the higher PTCs and a lower pretax income, partially offset by the effects of ratemaking and state income tax impacts.

Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the first quarter of 2021 and 2020 totaled $151 million and $120 million, respectively.

MidAmerican Funding -

Income tax benefit increased $32 million for the first quarter of 2021 compared to 2020, and the effective tax rate was 1,300% for 2021 and (477)% for 2020. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.

Liquidity and Capital Resources

As of March 31, 2021, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):


MidAmerican Energy:
Cash and cash equivalents	$	37

Credit facilities, maturing 2021 and 2022	1,505
Less:
Short-term debt outstanding	(387)
Tax-exempt bond support	(370)
Net credit facilities	748

MidAmerican Energy total net liquidity	$	785

MidAmerican Funding:
MidAmerican Energy total net liquidity	$	785
Cash and cash equivalents	1
MHC, Inc. credit facility, maturing 2021	4
MidAmerican Funding total net liquidity	$	790

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020, were $(85) million and $219 million, respectively. MidAmerican Funding's net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020, were $(92) million and $214 million, respectively. Cash flows from operating activities reflect lower cash margins for MidAmerican Energy's regulated electric and natural gas businesses, including delayed recovery of higher natural gas costs in February 2021, discussed below, and higher payments to vendors.

In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to MidAmerican Energy's customers, the IUB ordered the recovery of these higher costs to be applied to sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during three-month period ended March 31, 2021.

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

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020, were $(303) million and $(470) million, respectively. MidAmerican Funding's net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020, were $(303) million and $(469) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures, which decreased primarily due to lower wind-powered generating facility construction expenditures. Purchases and proceeds related to marketable securities substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments.

100

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the three-month periods ended March 31, 2021 and 2020 were $387 million and $49 million, respectively. MidAmerican Funding's net cash flows from financing activities for the three-month periods ended March 31, 2021 and 2020, were $394 million and $52 million, respectively. Through its commercial paper program, MidAmerican Energy received $387 million in 2021 and $50 million in 2020. MidAmerican Funding received $7 million and $3 million in 2021 and 2020, respectively, through its note payable with BHE.

Debt Authorizations and Related Matters

MidAmerican Energy has authority from the FERC to issue, through April 2, 2022, commercial paper and bank notes aggregating $1.5 billion at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of 400 basis points. MidAmerican Energy has a $900 million unsecured credit facility expiring in June 2022. 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. MidAmerican Energy has a $600 million unsecured credit facility, which, following MidAmerican Energy's exercise of an option to extend the facility, expires in August 2021, and has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.

MidAmerican Energy currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities through June 26, 2021. Additionally, MidAmerican Energy has authorization from the FERC to issue, through June 30, 2021, long-term debt securities up to an aggregate of $850 million at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points and preferred stock up to an aggregate of $500 million and from the ICC to issue long-term debt securities up to an aggregate of $850 million through August 20, 2022.

Future Uses of Cash

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

Capital Expenditures

MidAmerican Energy has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

101

MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2020		2021		2021

Wind generation	$	166	$	32	$	865
Electric distribution	51		46		298
Electric transmission	38		23		197
Solar generation	—		3		245
Other	217		194		595
Total	$	472	$	298	$	2,200

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

•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.

◦Construction and acquisition of wind-powered generating facilities totaled $154 million for 2020. MidAmerican Energy's forecast expenditures in 2021 for the construction of additional wind-powered generating facilities total $391 million and include 202 MWs of wind-powered generating facilities expected to be placed in-service in 2021.

◦Repowering of wind-powered generating facilities totaled $24 million for 2021 and $6 million for 2020. Planned spending for repowering generating facilities totals $379 million for the remainder of 2021. 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. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of March 31, 2021, 80 MWs are currently expected to qualify for 100% of the PTCs available for 10 years following each facility's return to service, 591 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.

•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.

•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.

•Solar reflects MidAmerican Energy's current plan for the construction of 117 MWs of small- and utility-scale solar generation during 2021, of which 37 MWs are expected to be placed in-service in 2021.

•Remaining expenditures primarily relate to routine expenditures for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.

Contractual Obligations

As of March 31, 2021, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's contractual obligations from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2020.

102

Quad Cities Generating Station Operating Status

On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding. In November 2020, the PJM announced that the next capacity auction will be conducted in May 2021.

On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.

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.

103

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its 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 state and local agencies. All such laws and regulations are subject to a range of interpretation, which 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 "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2020. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2020.

104

Nevada Power Company and its subsidiaries

Consolidated Financial Section

105

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of March 31, 2021, the related consolidated statements of operations, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2020, 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 26, 2021, 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, 2020, 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.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

April 30, 2021

106

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of
	March 31,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	92	$	25
Trade receivables, net	180		234
Inventories	65		69
Derivative contracts	48		26
Regulatory assets	22		48
Prepayments	45		38

Other current assets	37		26
Total current assets	489		466

Property, plant and equipment, net	6,751		6,701
Finance lease right of use assets, net	348		351
Regulatory assets	741		746
Other assets	71		72

Total assets	$	8,400	$	8,336

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	189	$	181
Accrued interest	38		32
Accrued property, income and other taxes	38		25


Current portion of finance lease obligations	30		27
Regulatory liabilities	63		50
Customer deposits	42		47
Asset retirement obligation	18		25

Other current liabilities	38		22
Total current liabilities	456		409

Long-term debt	2,497		2,496
Finance lease obligations	328		334
Regulatory liabilities	1,171		1,163
Deferred income taxes	740		738
Other long-term liabilities	267		257
Total liabilities	5,459		5,397

Commitments and contingencies (Note 6)	0		0

Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	0		0
Additional paid-in capital	2,308		2,308
Retained earnings	636		634
Accumulated other comprehensive loss, net	(3)		(3)
Total shareholder's equity	2,941		2,939

Total liabilities and shareholder's equity	$	8,400	$	8,336

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

107

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2021		2020

Operating revenue		$	370	$	389

Operating expenses:
Cost of fuel and energy		165		170
Operations and maintenance		63		82
Depreciation and amortization		101		90
Property and other taxes		12		12
Total operating expenses		341		354

Operating income		29		35

Other income (expense):
Interest expense		(38)		(42)
Allowance for borrowed funds		1		1
Allowance for equity funds		1		2
Other, net		9		(1)
Total other income (expense)		(27)		(40)

Income (loss) before income tax benefit		2		(5)
Income tax benefit		0		(1)
Net income (loss)		$	2	$	(4)

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

108

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, December 31, 2019	1,000	$	0	$	2,308	$	493	$	(4)	$	2,797
Net loss	—	—		—		(4)		—		(4)

Other equity transactions	—	—		—		1		—		1
Balance, March 31, 2020	1,000	$	0	$	2,308	$	490	$	(4)	$	2,794







Balance, December 31, 2020	1,000	$	0	$	2,308	$	634	$	(3)	$	2,939
Net income	—	—		—		2		—		2


Balance, March 31, 2021	1,000	$	0	$	2,308	$	636	$	(3)	$	2,941

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

109

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income (loss)	$	2	$	(4)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:


Depreciation and amortization	101		90
Allowance for equity funds	(1)		(2)
Changes in regulatory assets and liabilities	(15)		3
Deferred income taxes and amortization of investment tax credits	(10)		(4)
Deferred energy	41		4

Other, net	(1)		8
Changes in other operating assets and liabilities:
Trade receivables and other assets	41		32
Inventories	4		(1)
Accrued property, income and other taxes	3		(6)
Accounts payable and other liabilities	14		(41)
Net cash flows from operating activities	179		79

Cash flows from investing activities:
Capital expenditures	(106)		(111)



Net cash flows from investing activities	(106)		(111)

Cash flows from financing activities:
Proceeds from long-term debt	0		719
Repayments of long-term debt	0		(575)




Other, net	(5)		(4)
Net cash flows from financing activities	(5)		140

Net change in cash and cash equivalents and restricted cash and cash equivalents	68		108
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	36		25
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	104	$	133

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

110

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United States 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 March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month period ended March 31, 2021 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, 2020 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 assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.

(2)Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States 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 as of March 31, 2021 and December 31, 2020, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2021		2020
Cash and cash equivalents	$	92	$	25
Restricted cash and cash equivalents included in other current assets	12		11
Total cash and cash equivalents and restricted cash and cash equivalents	$	104	$	36

111

(3) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):


		As of
	Depreciable Life	March 31,		December 31,
		2021		2020
Utility plant:
Generation	30 - 55 years	$	3,691	$	3,690
Transmission	45 - 70 years	1,465		1,468
Distribution	20 - 65 years	3,803		3,771
General and intangible plant	5 - 65 years	798		791
Utility plant		9,757		9,720
Accumulated depreciation and amortization		(3,224)		(3,162)
Utility plant, net		6,533		6,558
Other non-regulated, net of accumulated depreciation and amortization	45 years	1		1
Plant, net		6,534		6,559
Construction work-in-progress		217		142
Property, plant and equipment, net		$	6,751	$	6,701

(4) Employee Benefit Plans

Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):


	As of
	March 31,		December 31,
	2021		2020
Qualified Pension Plan:
Other non-current assets	$	9	$	8



Non-Qualified Pension Plans:

Other current liabilities	(1)		(1)
Other long-term liabilities	(9)		(9)

Other Postretirement Plans:
Other non-current assets	4		4

112

(5) 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 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 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 March 31, 2021
Assets:
Commodity derivatives	$	0	$	0	$	48	$	48
Money market mutual funds(1)	86		0		0		86
Investment funds	2		0		0		2
	$	88	$	0	$	48	$	136

Liabilities - commodity derivatives	$	0	$	0	$	(21)	$	(21)

As of December 31, 2020
Assets:
Commodity derivatives	$	0	$	0	$	26	$	26
Money market mutual funds(1)	21		0		0		21
Investment funds	2		0		0		2
	$	23	$	0	$	26	$	49

Liabilities - commodity derivatives	$	0	$	0	$	(11)	$	(11)

(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.

113

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of March 31, 2021 and December 31, 2020, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.

Nevada Power's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

The following table reconciles the beginning and ending balances of Nevada Power's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):


	Three-Month Periods
	Ended March 31,
	2021		2020

Beginning balance	$	15	$	(8)
Changes in fair value recognized in regulatory assets	11		(31)

Settlements	1		1
Ending balance	$	27	$	(38)

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 March 31, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	2,497	$	2,991	$	2,496	$	3,245

114

(6) Commitments and Contingencies

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.

Environmental Laws and Regulations

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

(7) Revenue from Contracts with Customers

The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):


	Three-Month Periods
	Ended March 31,
	2021		2020
Customer Revenue:
Retail:
Residential	$	196	$	193
Commercial	84		94
Industrial	63		70
Other	3		3
Total fully bundled	346		360
Distribution only service	5		7
Total retail	351		367
Wholesale, transmission and other	14		16
Total Customer Revenue	365		383
Other revenue	5		6
Total revenue	$	370	$	389

115

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

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

Results of Operations for the First Quarter of 2021 and 2020

Overview

Net income for the first quarter of 2021 was $2 million, an increase of $6 million, compared to 2020 primarily due to $19 million of lower operations and maintenance expenses, primarily due to lower net regulatory instructed deferrals and amortizations of $11 million, lower plant operations and maintenance costs and a reduction to the accrual for earning sharing, $10 million of higher other, net, mainly due to higher cash surrender value of corporate-owned life insurance policies of $7 million and lower pension expense, and lower interest expense of $4 million. This increase is offset by $14 million of lower utility margin. primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, and $11 million of higher depreciation and amortization, mainly due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as electric operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

Nevada Power's cost of fuel and energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):


	First Quarter
	2021		2020		Change
Utility margin:
Operating revenue	$	370	$	389	$	(19)	(5)	%
Cost of fuel and energy	165		170		(5)		(3)
Utility margin	205		219		(14)		(6)
Operations and maintenance	63		82		(19)		(23)
Depreciation and amortization	101		90		11		12
Property and other taxes	12		12		—		—
Operating income	$	29	$	35	$	(6)	(17)	%

116

Utility Margin

A comparison of key operating results related to utility margin is as follows for the quarters ended March 31:


	First Quarter
	2021		2020		Change
Utility margin (in millions):
Operating revenue	$	370	$	389	$	(19)	(5)	%
Cost of fuel and energy	165		170		(5)		(3)
Utility margin	$	205	$	219	$	(14)	(6)	%

Sales (GWhs):
Residential	1,587		1,544		43		3	%
Commercial	954		1,011		(57)		(6)
Industrial	1,057		1,151		(94)		(8)
Other	47		48		(1)		(2)
Total fully bundled(1)	3,645		3,754		(109)		(3)
Distribution only service	516		611		(95)		(16)
Total retail	4,161		4,365		(204)		(5)
Wholesale	84		153		(69)		(45)
Total GWhs sold	4,245		4,518		(273)		(6)	%

Average number of retail customers (in thousands)	978		961		17		2	%





Average revenue per MWh:
Retail - fully bundled(1)	$	95.01	$	96.01	$	(1.00)	(1)	%

Wholesale	$	49.42	$	31.58	$	17.84	56	%

Heating degree days	994		942		52		6	%
Cooling degree days	6		2		4		*

Sources of energy (GWhs)(2)(3):
Natural gas	2,534		2,622		(88)		(3)	%

Renewables	16		16		—		—
Total energy generated	2,550		2,638		(88)		(3)
Energy purchased	1,355		1,240		115		9
Total	3,905		3,878		27		1	%

Average cost of energy per MWh(4):
Energy generated	$	14.96	$	21.95	$	(6.99)	(32)	%
Energy purchased	$	93.84	$	90.56	$	3.28	4	%

* 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 683 GWhs and 710 GWhs of gas generated energy that is purchased at cost by related parties for the first quarter of 2021 and 2020, respectively.

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

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

117

Quarter Ended March 31, 2021 Compared to Quarter Ended March 31, 2020

Utility margin decreased $14 million, or 6%, for the first quarter of 2021 compared to 2020 primarily due to:

•$9 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,

•$2 million due to lower energy efficiency program rates (offset in operations and maintenance expense),

•$1 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, decreased 4.7% primarily due to the impacts of COVID-19, which resulted in lower industrial, commercial and distribution only service customer usage and higher residential customer usage, offset by the favorable impacts of weather and

•$1 million of lower other revenue due to a regulatory amortization of impact fee that ended December 2020.

Operations and maintenance decreased $19 million, or 23%, for the first quarter of 2021 compared to 2020 primarily due to lower net regulatory instructed deferrals and amortizations of $11 million, mainly relating to deferrals in 2020 of the non-labor cost savings from the Navajo generating station retirement which was approved for amortization in the 2020 regulatory rate review with new rates effective January 2021, and timing of the regulatory impacts for the ON Line lease cost reallocation, lower plant operations and maintenance costs, a reduction to the accrual for earning sharing and lower energy efficiency program costs (offset in operating revenue).

Depreciation and amortization increased $11 million, or 12%, for the first quarter of 2021 compared to 2020 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.

Interest expense decreased $4 million, or 10%, for the first quarter of 2021 compared to 2020 primarily due to lower interest expense on long-term debt.

Other, net increased $10 million for the first quarter of 2021 compared to 2020 primarily due to higher cash surrender value of corporate-owned life insurance policies of $7 million, lower pension expense and higher interest income, mainly from carrying charges on regulatory items.

Income tax benefit decreased $1 million, for the first quarter of 2021 compared to 2020. Nevada Power did not incur tax expense in 2021 primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021. The effective tax rate was 20% in 2020.

Liquidity and Capital Resources

As of March 31, 2021, Nevada Power's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	92
Credit facility	400




Total net liquidity	$	492
Credit facility:
Maturity date	2022

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $179 million and $79 million, respectively. The change was primarily due to lower payments for fuel and energy costs, the timing of payments for operating costs and lower inventory purchases, partially offset by lower collections from customers.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(106) million and $(111) million, respectively. The change was primarily due to decreased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

118

Financing Activities

Net cash flows from financing activities for the three-month periods ended March 31, 2021 and 2020 were $(5) million and $140 million, respectively. The change was primarily due to lower proceeds from the issuance of long-term debt, partially offset by lower repayments of long-term debt.

Debt Authorizations

Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $3.2 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective automatic shelf registration statement with the SEC to issue an indeterminate amount of general and refunding mortgage securities through October 2022.

Future Uses of Cash

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

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to 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. 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.

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2020		2021		2021

Electric distribution	$	64	$	41	$	167
Electric transmission	8		13		77
Solar generation	—		1		32
Other	39		51		181
Total	$	111	$	106	$	457

Nevada Power's Fourth Amendment to the 2018 Joint IRP proposed an increase in solar generation and electric transmission. Nevada Power has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates are likely to change as a result of the RFP process and some are still pending PUCN approval. Nevada Power's historical and forecast capital expenditures include the following:

•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.

119

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has proposed to build a 350-mile, 525 kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation. Construction of the project has been approved by the PUCN with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

•Solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility, that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.

•Other investments include both growth projects and operating expenditures consisting of routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2020.

Regulatory Matters

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

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations 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 state and local agencies. All such laws and regulations are subject to a range of interpretation, which 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 "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2020. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2020.

120

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

121

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of March 31, 2021, the related consolidated statements of operations, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of Sierra Pacific as of December 31, 2020, 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 26, 2021, 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, 2020, 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 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.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

April 30, 2021

122

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of
	March 31,		December 31,
	2021		2020
ASSETS
Current assets:
Cash and cash equivalents	$	8	$	19
Trade receivables, net	93		97

Inventories	74		77
Derivative contracts	16		9
Regulatory assets	91		67

Other current assets	38		36
Total current assets	320		305

Property, plant and equipment, net	3,188		3,164

Regulatory assets	270		267
Other assets	185		183

Total assets	$	3,963	$	3,919

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	103	$	108
Accrued interest	11		14
Accrued property, income and other taxes	16		14
Short-term debt	55		45


Regulatory liabilities	28		34
Customer deposits	14		15
Other current liabilities	33		25
Total current liabilities	260		255

Long-term debt	1,164		1,164
Finance lease obligations	119		121
Regulatory liabilities	466		463
Deferred income taxes	382		374
Other long-term liabilities	133		131
Total liabilities	2,524		2,508

Commitments and contingencies (Note 7)	0		0

Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	0		0
Additional paid-in capital	1,111		1,111
Retained earnings	329		301
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	1,439		1,411

Total liabilities and shareholder's equity	$	3,963	$	3,919

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

123

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue:
Regulated electric		$	181	$	184
Regulated natural gas		39		48
Total operating revenue		220		232

Operating expenses:
Cost of fuel and energy		82		80
Cost of natural gas purchased for resale		21		30
Operations and maintenance		36		42
Depreciation and amortization		36		34
Property and other taxes		6		6
Total operating expenses		181		192

Operating income		39		40

Other income (expense):
Interest expense		(14)		(14)

Allowance for equity funds		1		1
Other, net		6		1
Total other income (expense)		(7)		(12)

Income before income tax expense		32		28
Income tax expense		4		3
Net income		$	28	$	25

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

124

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, December 31, 2019	1,000	$	0	$	1,111	$	210	$	(1)	$	1,320
Net income	—	—		—		25		—		25


Balance, March 31, 2020	1,000	$	0	$	1,111	$	235	$	(1)	$	1,345







Balance, December 31, 2020	1,000	$	0	$	1,111	$	301	$	(1)	$	1,411
Net income	—	—		—		28		—		28


Balance, March 31, 2021	1,000	$	0	$	1,111	$	329	$	(1)	$	1,439

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

125

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income	$	28	$	25
Adjustments to reconcile net income to net cash flows from operating activities:

Depreciation and amortization	36		34
Allowance for equity funds	(1)		(1)
Changes in regulatory assets and liabilities	(13)		(10)
Deferred income taxes and amortization of investment tax credits	4		(3)
Deferred energy	(18)		14
Amortization of deferred energy	(3)		4
Other, net	0		1
Changes in other operating assets and liabilities:
Trade receivables and other assets	8		1
Inventories	3		(3)
Accrued property, income and other taxes	(3)		4
Accounts payable and other liabilities	1		(12)
Net cash flows from operating activities	42		54

Cash flows from investing activities:
Capital expenditures	(61)		(52)


Net cash flows from investing activities	(61)		(52)

Cash flows from financing activities:

Net proceeds from short-term debt	10		0


Other, net	(2)		(1)
Net cash flows from financing activities	8		(1)

Net change in cash and cash equivalents and restricted cash and cash equivalents	(11)		1
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	26		32
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	15	$	33

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

126

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Sierra Pacific Power Company, together with its subsidiaries ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States 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 March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month period ended March 31, 2021 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, 2020 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 assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.

(2)Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States 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 as of March 31, 2021 and December 31, 2020, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2021		2020
Cash and cash equivalents	$	8	$	19
Restricted cash and cash equivalents included in other current assets	7		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	15	$	26

127

(3) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):


		As of
	Depreciable Life	March 31,		December 31,
		2021		2020
Utility plant:
Electric generation	25 - 60 years	$	1,131	$	1,130
Electric transmission	50 - 100 years	917		908
Electric distribution	20 - 100 years	1,763		1,754
Electric general and intangible plant	5 - 70 years	193		189
Natural gas distribution	35 - 70 years	431		429
Natural gas general and intangible plant	5 - 70 years	15		15
Common general	5 - 70 years	357		355
Utility plant		4,807		4,780
Accumulated depreciation and amortization		(1,783)		(1,755)
Utility plant, net		3,024		3,025
Other non-regulated, net of accumulated depreciation and amortization	70 years	2		2
Plant, net		3,026		3,027
Construction work-in-progress		162		137
Property, plant and equipment, net		$	3,188	$	3,164

(4)Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:


	Three-Month Periods
	Ended March 31,
	2021		2020

Federal statutory income tax rate	21	%	21	%


Effects of ratemaking	(10)		(8)


Other	2		(2)
Effective income tax rate	13	%	11	%

Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2020.

(5) 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. 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.

128

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):


	As of
	March 31,		December 31,
	2021		2020
Qualified Pension Plan:

Other non-current assets	$	27	$	26



Non-Qualified Pension Plans:


Other current liabilities	(1)		(1)
Other long-term liabilities	(8)		(8)

Other Postretirement Plans:



Other long-term liabilities	(14)		(13)

(6) 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 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 ~~derivative instruments.~~

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.

129

The following table presents Sierra Pacific's 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 March 31, 2021
Assets:
Commodity derivatives	$	0	$	0	$	16	$	16
Money market mutual funds(1)	5		0		0		5

	$	5	$	0	$	16	$	21

Liabilities - commodity derivatives	$	0	$	0	$	(4)	$	(4)

As of December 31, 2020
Assets:
Commodity derivatives	$	0	$	0	$	9	$	9
Money market mutual funds(1)	17		0		0		17

	$	17	$	0	$	9	$	26

Liabilities - commodity derivatives	$	0	$	0	$	(2)	$	(2)

(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 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.

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 March 31, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,164	$	1,312	$	1,164	$	1,358

130

(7) Commitments and Contingencies

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.

Environmental Laws and Regulations

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

(8) Revenue from Contracts with Customers

The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note ~~19. Related-Party Transactions~~

9 (in millions):


	Three-Month Periods
	Ended March 31,
	2021						2020
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	71	$	25	$	96	$	69	$	30	$	99
Commercial	54		10		64		57		13		70
Industrial	39		3		42		41		4		45
Other	1		0		1		1		0		1
Total fully bundled	165		38		203		168		47		215
Distribution only service	1		0		1		1		0		1
Total retail	166		38		204		169		47		216
Wholesale, transmission and other	15		0		15		14		0		14
Total Customer Revenue	181		38		219		183		47		230
Other revenue	0		1		1		1		1		2
Total revenue	$	181	$	39	$	220	$	184	$	48	$	232

131

(9)Segment Information

Sierra Pacific has identified 2 reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

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


	Three-Month Periods
	Ended March 31,
	2021		2020
Operating revenue:
Regulated electric	$	181	$	184
Regulated natural gas	39		48
Total operating revenue	$	220	$	232





















Operating income:
Regulated electric	$	31	$	33
Regulated natural gas	8		7
Total operating income	39		40
Interest expense	(14)		(14)

Allowance for equity funds	1		1
Other, net	6		1
Income before income tax expense	$	32	$	28










	As of
		March 31,		December 31,
		2021		2020
Assets:
Regulated electric		$	3,589	$	3,540
Regulated natural gas		348		342
Other(1)		26		37
Total assets		$	3,963	$	3,919

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

132

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

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

Results of Operations for the First Quarterof 2021 and 2020

Overview

Net income for the first quarter of 2021 was $28 million, an increase of $3 million, or 12%, compared to 2020 primarily due to $6 million of lower operations and maintenance expenses, mainly due to lower plant operations and maintenance expenses and a reduction to the accrual for earning sharing, and $5 million of higher other, net, mainly due to higher cash surrender value of corporate-owned life insurance policies and lower pension costs, partially offset by $5 million of lower electric utility margin, mainly from lower revenue recognized due to a favorable regulatory decision.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Consolidated Statements of Operations.

Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

133

Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):


	First Quarter
	2021		2020		Change
Electric utility margin:
Operating revenue	$	181	$	184	$	(3)	(2)	%
Cost of fuel and energy	82		80		2		3
Electric utility margin	99		104		(5)		(5)

Natural gas utility margin:
Operating revenue	39		48		(9)		(19)	%
Natural gas purchased for resale	21		30		(9)		(30)
Natural gas utility margin	18		18		—		—

Utility margin	117		122		(5)		(4)	%

Operations and maintenance	36		42		(6)		(14)	%
Depreciation and amortization	36		34		2		6
Property and other taxes	6		6		—		—
Operating income	$	39	$	40	$	(1)	(3)	%

134

Electric Utility Margin

A comparison of key operating results related to electric utility margin is as follows for the quarters ended March 31:


	First Quarter
	2021		2020		Change
Utility margin (in millions):
Operating revenue	$	181	$	184	$	(3)	(2)	%
Cost of fuel and energy	82		80		2		3
Utility margin	$	99	$	104	$	(5)	(5)	%

Sales (GWhs):
Residential	671		635		36		6	%
Commercial	677		701		(24)		(3)
Industrial	897		909		(12)		(1)
Other	4		4		—		—
Total fully bundled(1)	2,249		2,249		—		—
Distribution only service	397		412		(15)		(4)
Total retail	2,646		2,661		(15)		(1)
Wholesale	175		193		(18)		(9)
Total GWhs sold	2,821		2,854		(33)		(1)	%

Average number of retail customers (in thousands)	363		356		7		2	%





Average revenue per MWh:
Retail - fully bundled(1)	$	73.17	$	74.76	$	(1.59)	(2)	%

Wholesale	$	60.18	$	49.05	$	11.13	23	%

Heating degree days	2,198		2,066		132		6	%


Sources of energy (GWhs)(2):
Natural gas	1,082		1,215		(133)		(11)	%
Coal	29		66		(37)		(56)
Renewables(3)	6		6		—		—
Total energy generated	1,117		1,287		(170)		(13)
Energy purchased	1,373		1,325		48		4
Total	2,490		2,612		(122)		(5)	%

Average cost of energy per MWh(4):
Energy generated	$	25.23	$	26.53	$	(1.30)	(5)	%
Energy purchased	$	38.93	$	34.96	$	3.97	11	%

(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) Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.

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

135

Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows for the quarters ended March 31:


	First Quarter
	2021		2020		Change
Utility margin (in millions):
Operating revenue	$	39	$	48	$	(9)	(19)	%
Natural gas purchased for resale	21		30		(9)		(30)
Utility margin	$	18	$	18	$	—	—	%

Sold (000's Dths):
Residential	4,658		4,386		272		6	%
Commercial	2,304		2,167		137		6
Industrial	745		653		92		14
Total retail	7,707		7,206		501		7	%

Average number of retail customers (in thousands)	176		173		3		2	%

Average revenue per retail Dth sold	$	5.03	$	6.58	$	(1.55)	(24)	%

Heating degree days	2,198		2,066		132		6	%

Average cost of natural gas per retail Dth sold	$	2.73	$	4.22	$	(1.49)	(35)	%

Quarter Ended March 31, 2021 Compared to Quarter Ended March 31, 2020

Electric utility margin decreased$5 million, or 5%, for the first quarter of 2021 compared to 2020 primarily due to:

•$3 million in lower revenue recognized due to a favorable regulatory decision and

•$1 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, decreased 0.6% primarily due to the impacts of COVID-19, which resulted in lower distribution only service, commercial and industrial customer usage and higher residential customer usage, offset by the favorable impacts of weather.

Operations and maintenance decreased $6 million, or 14%, for the first quarter of 2021 compared to 2020 primarily due to lower plant operations and maintenance expenses, a reduction to the accrual for earning sharing and lower regulatory amortizations.

Depreciation and amortization increased $2 million, or 6%, for the first quarter of 2021 compared to 2020 primarily due to regulatory amortizations and higher plant in service.

Other, net increased $5 million for the first quarter of 2021 compared to 2020 primarily due to higher cash surrender value of corporate-owned life insurance policies and lower pension costs.

Income tax expense increased $1 million, or 33%, for the first quarter of 2021 compared to 2020. The effective tax rate was 13% in 2021 and 11% in 2020 and increased primarily due to higher pre-tax income.

136

Liquidity and Capital Resources

As of March 31, 2021, Sierra Pacific's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	8

Credit facility	250
Less -

Short-term debt	(55)
Net credit facility	195

Total net liquidity	$	203
Credit facility:
Maturity date	2022

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $42 million and $54 million, respectively. The change was primarily due to higher payments for fuel and energy costs and lower collections from customers partially offset by lower inventory purchases, the timing of payments for operating costs and increased collections of customer advances.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(61) million and $(52) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month periods ended March 31, 2021 and 2020 were $8 million and $(1) million, respectively. The change was primarily due to higher proceeds from short-term debt.

Debt Authorizations

Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $1.6 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.

Future Uses of Cash

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

137

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to 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. 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.

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2020		2021		2021


Electric distribution	$	37	$	20	$	126
Electric transmission	8		16		124
Solar generation	—		—		18
Other	7		25		129
Total	$	52	$	61	$	397

Sierra Pacific's Fourth Amendment to the 2018 Joint IRP proposed an increase in electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates are likely to change as a result of the RFP process and some are still pending PUCN approval. Sierra Pacific's historical and forecast capital expenditures include the following:

•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has proposed to build a 235-mile, 525 kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345 kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345 kV transmission line from the new Ft. Churchill substation to the Comstock Meadows substations. Construction of the project has been approved by the PUCN with the exception of the Ft. Churchill substation to the Robinson Summit substation segment for which conditional approval was limited to design, permitting and land acquisition only. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2020.

138

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 climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations 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 state and local agencies. All such laws and regulations are subject to a range of interpretation, which 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 "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2020. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2020.

139

Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

140

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Eastern Energy Gas Holdings, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of March 31, 2021, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for the three-month periods ended March 31, 2021 and 2020, 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, 2020, 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 26, 2021, 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, 2020, 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.

/s/ Deloitte & Touche LLP

Richmond, Virginia ~~Power~~

April 30, 2021

141

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	March 31, 2021		December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	106	$	35
Restricted cash and cash equivalents	9		13
Trade receivables, net	158		177
Receivables from affiliates	263		139
Other receivables	44		51
Inventories	120		119

Other current assets	145		122
Total current assets	845		656

Property, plant and equipment, net	10,099		10,144
Goodwill	1,286		1,286

Investments	262		244

Other assets	240		291

Total assets	$	12,732	$	12,621

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

142

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	March 31, 2021		December 31, 2020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	59	$	71
Accounts payable to affiliates	57		39
Accrued interest	54		19
Accrued property, income and other taxes	60		29

Notes payable	0		9


Current portion of long-term debt	500		500
Other current liabilities	127		147
Total current liabilities	857		814

Long-term debt	3,914		3,925


Regulatory liabilities	668		669

Other long-term liabilities	215		218
Total liabilities	5,654		5,626

Commitments and contingencies (Note 8)	0		0

Equity:
Member's equity:

Membership interests	3,035		2,957


Accumulated other comprehensive loss, net	(45)		(53)
Total member's equity	2,990		2,904
Noncontrolling interests	4,088		4,091
Total equity	7,078		6,995

Total liabilities and equity	$	12,732	$	12,621

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

143

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020




Operating revenue	$	486	$	556

Operating expenses:

Cost of gas	0		8
Operations and maintenance	124		168
Depreciation and amortization	80		93
Property and other taxes	39		39

Total operating expenses	243		308

Operating income	243		248

Other income (expense):
Interest expense	(44)		(58)

Allowance for equity funds	2		5
Interest and dividend income	0		30

Other, net	1		14
Total other income (expense)	(41)		(9)

Income before income tax expense and equity income	202		239
Income tax expense	27		52
Equity income	16		15


Net income	191		202
Net income attributable to noncontrolling interests	102		33
Net income attributable to Eastern Energy Gas	$	89	$	169

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

144

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020

Net income	$	191	$	202

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $0 and $1	2		1


Unrealized gains (losses) on cash flow hedges, net of tax of $3 and $(30)	10		(85)
Total other comprehensive income (loss), net of tax	12		(84)

Comprehensive income	203		118
Comprehensive income attributable to noncontrolling interests	106		33
Comprehensive income attributable to Eastern Energy Gas	$	97	$	85

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

145

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, December 31, 2019	$	9,031	$	(187)	$	1,385	$	10,229
Net income	169		—		33		202
Other comprehensive loss	—		(84)		—		(84)


Distributions	(232)		—		(37)		(269)





Balance, March 31, 2020	$	8,968	$	(271)	$	1,381	$	10,078

Balance, December 31, 2020	$	2,957	$	(53)	$	4,091	$	6,995
Net income	89		—		102		191
Other comprehensive income	—		8		4		12
Contributions	11		—		—		11
Distributions	(22)		—		(109)		(131)




Balance, March 31, 2021	$	3,035	$	(45)	$	4,088	$	7,078

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

146

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income	$	191	$	202
Adjustments to reconcile net income to net cash flows from operating activities:


Depreciation and amortization	80		93
Allowance for equity funds	(2)		(5)
Equity income, net of distributions	(5)		(1)
Changes in regulatory assets and liabilities	6		7
Deferred income taxes	30		15
Other, net	0		(1)
Changes in other operating assets and liabilities:
Trade receivables and other assets	(56)		357
Derivative collateral, net	2		9
Pension and other postretirement benefit plans	0		(18)
Accrued property, income and other taxes	(25)		(17)
Accounts payable and other liabilities	20		26
Net cash flows from operating activities	241		667

Cash flows from investing activities:
Capital expenditures	(55)		(76)



Loans to affiliates	0		(262)

Other, net	(1)		(4)
Net cash flows from investing activities	(56)		(342)

Cash flows from financing activities:


Net repayments of short-term debt	0		(32)
Repayment of notes payable, net	(9)		(5)



Distributions	(109)		(269)


Net cash flows from financing activities	(118)		(306)



Net change in cash and cash equivalents and restricted cash and cash equivalents	67		19
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	48		39
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	115	$	58

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

147

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) General

Eastern Energy Gas Holdings, LLC and its subsidiaries ("Eastern Energy Gas") is a holding company that conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transportation pipeline and underground storage operations in the eastern region of the United States 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 partnership interest 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 transportation pipeline.

In July 2020, Dominion Energy, Inc. ("DEI") entered into an agreement to sell substantially all of its gas transmission and storage operations, including Eastern Energy Gas and a 25% limited partnership interest in Cove Point, to Berkshire Hathaway Energy Company ("BHE"). Approval of the transaction under the Hart-Scott-Rodino Act was not obtained within 75 days and DEI and BHE mutually agreed to a dual-phase closing consisting of two separate disposal groups identified as the acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Energy Questar Corporation, exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction") and the proposed sale of the Questar Pipeline Group by DEI to BHE pursuant to a purchase and sale agreement entered into on October 5, 2020 ("Q-Pipe Transaction"). The Q-Pipe Transaction is currently anticipated to close in the first half of 2021, contingent on clearance or approval under the Hart-Scott-Rodino Act, and other customary closing and regulatory conditions. Prior to the completion of the GT&S Transaction, Eastern Energy Gas ~~engage~~finalized a restructuring whereby Eastern Energy Gas distributed the Questar Pipeline Group and a 50% noncontrolling interest in ~~related-party~~Cove Point to DEI. This restructuring was accounted for by Eastern Energy Gas as a reorganization of entities under common control and the disposition was reflected as an equity transaction. The disposition was not reported as a discontinued operation as the disposal did not represent a strategic shift in the way management had intended to run the business. On November 1, 2020, BHE completed the GT&S Transaction. As a result of the GT&S Transaction, Eastern Energy Gas became an indirect wholly owned subsidiary of BHE. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

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 March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month periods ended March 31, 2021 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, 2020 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' assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.

148

(2) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):


		As of
		March 31,		December 31,
	Depreciable Life	2021		2020
Utility Plant:

Interstate natural gas pipeline assets	24 - 43 years	$	8,385	$	8,382
Intangible plant	5 - 10 years	114		115
Utility plant in service		8,499		8,497
Accumulated depreciation and amortization		(2,792)		(2,759)
Utility plant in service, net		5,707		5,738

Nonutility Plant:

LNG facility	40 years	4,460		4,454
Intangible plant	14 years	25		25
Nonutility plant in service		4,485		4,479
Accumulated depreciation and amortization		(320)		(283)
Nonutility plant in service, net		4,165		4,196

Plant, net		9,872		9,934
Construction work- in-progress		227		210
Property, plant and equipment, net		$	10,099	$	10,144

Construction work-in-progress includes $211 million and $196 million as of March 31, 2021 and December 31, 2020, respectively, related to the construction of utility plant.

149

(3) Investments and Restricted Cash and Cash Equivalents

Investments and restricted cash and cash equivalents consists of the following (in millions):


	As of
	March 31,		December 31,
	2021		2020
Investments:
Investment funds	$	12	$	0


Equity method investments:
Iroquois	250		244



Total investments	262		244

Restricted cash and cash equivalents:
Customer deposits	9		13
Total restricted cash and cash equivalents	9		13

Total investments and restricted cash and cash equivalents	$	271	$	257

Reflected as:
Current assets	$	9	$	13
Noncurrent assets	262		244
Total investments and restricted cash and cash equivalents	$	271	$	257

Equity Method Investments

Eastern Energy Gas, through a subsidiary, owns 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut. Prior to the GT&S Transaction, Eastern Energy Gas, through the Questar Pipeline Group, owned 50% of White River Hub, which owns and operates a natural gas pipeline in northwest Colorado.

As of March 31, 2021 and December 31, 2020, 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 $10 million and $15 million for the three-month periods ended March 31, 2021 and 2020, respectively.

150

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States 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 as of March 31, 2021 and December 31, 2020 consist substantially of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2021		2020

Cash and cash equivalents	$	106	$	35
Restricted cash and cash equivalents	9		13
Total cash and cash equivalents and restricted cash and cash equivalents	$	115	$	48

(4) Regulatory Matters

Eastern Gas Transmission and Storage, Inc.

In July 2017, the FERC audit staff communicated to Eastern Gas Transmission and Storage, Inc. ("EGTS") that it had substantially completed an audit of EGTS' compliance with the accounting and reporting requirements of the FERC's Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report. In December 2017, EGTS provided its response to the audit report. EGTS requested FERC review of the contested findings and submitted its plan for compliance with the uncontested portions of the report. EGTS reached resolution of certain matters with the FERC in the fourth quarter of 2018. EGTS recognized a charge of $129 million ($94 million after-tax) for the year ended December 31, 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with the FERC. In December 2020, the FERC issued a final ruling on the remaining matter, which resulted in a $43 million ($31 million after-tax) charge for disallowance of capitalized allowance for funds used during construction. As a condition of the December 2020 ruling, EGTS will file its proposed accounting entries and supporting documentation with the FERC by the second quarter of 2021; however, EGTS does not expect a material change from the charge recognized.

Cove Point

In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April 2021.

151

(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 is as follows:


	Three-Month Periods
	Ended March 31,
	2021		2020

Federal statutory income tax rate	21	%	21	%
State income tax, net of federal income tax benefit	3		3



Equity interest	2		1
Effects of ratemaking	(1)		(1)





Absence of noncontrolling interest	(11)		(3)

Other, net	(1)		1
Effective income tax rate	13	%	22	%

Absence of tax on noncontrolling interest is attributable to Eastern Energy Gas' ownership in Cove Point. The GT&S Transaction resulted in a change of noncontrolling interest to 75% as of March 31, 2021 from 25% as of March 31, 2020.

Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. All affiliate payables or receivables were settled with DEI prior to the closing date of the GT&S Transaction. Subsequent to the GT&S Transaction, Eastern Energy Gas, as a subsidiary of BHE, is included in Berkshire Hathaway's United States federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provisions for income tax have been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. Eastern Energy Gas made 0 cash payments for income tax to BHE for the three-month period ended March 31, 2021.

(6) Employee Benefit Plans

Prior to the GT&S Transaction, certain Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by DEI that provides benefits to multiple DEI subsidiaries. As participating employers, Eastern Energy Gas was subject to DEI's funding policy, which was to contribute annually an amount that is in accordance with the Employee Retirement Income Security Act of 1974. Also prior to the GT&S Transaction, pension benefits for Eastern Energy Gas employees represented by collective bargaining units were provided by a separate plan that provides benefits to employees of both EGTS and Hope Gas, Inc. ("Hope"). Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Company ("MidAmerican Energy") Pension Plan, similar to the DEI plan.

Prior to the GT&S Transaction, certain retiree healthcare and life insurance benefits for Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by DEI that provides certain retiree healthcare and life insurance benefits to multiple DEI subsidiaries. Also prior to the GT&S Transaction, retiree health and life insurance benefits for Eastern Energy Gas employees represented by collective bargaining units were covered by a separate other postretirement benefit plan that provides benefits to both EGTS and Hope. Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Retiree Health and Welfare plan, similar to the DEI plan.

152

Net periodic benefit cost (credit) for the pension and other postretirement benefit plans included the following components (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020
Pension:
Service cost		$	0	$	1
Interest cost		0		3
Expected return on plan assets		0		(14)
Net amortization		0		2
Net periodic benefit cost (credit)		$	0	$	(8)

Other Postretirement:
Service cost		$	0	$	1
Interest cost		0		1
Expected return on plan assets		0		(5)
Net amortization		0		(1)
Net periodic benefit cost (credit)		$	0	$	(4)

(7) 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.

153

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 March 31, 2021
Assets:

Foreign currency exchange rate derivatives	$	0	$	12	$	0	$	12
Money market mutual funds(1)	71		0		0		71
Investment funds	12		0		0		12
	$	83	$	12	$	0	$	95

Liabilities:

Foreign currency exchange rate derivatives	$	0	$	(1)	$	0	$	(1)
Interest rate derivatives	0		(3)		0		(3)
	$	0	$	(4)	$	0	$	(4)

As of December 31, 2020
Assets:

Foreign currency exchange rate derivatives	$	0	$	20	$	0	$	20

	$	0	$	20	$	0	$	20

Liabilities:
Commodity derivatives	$	0	$	(1)	$	0	$	(1)
Foreign currency exchange rate derivatives	0		(2)		0		(2)
Interest rate derivatives	0		(6)		0		(6)
	$	0	$	(9)	$	0	$	(9)

(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 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.

154

Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. 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 March 31, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	4,414	$	4,744	$	4,425	$	5,012

(8) Commitments and Contingencies

Legal Matters

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

Environmental Laws and Regulations

Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.

(9) Revenue from Contracts with Customers

The following table summarizes Eastern Energy Gas' energy products and services revenue by regulated and nonregulated (in millions):


	Three-Month Periods
	Ended March 31,
	2021		2020
Customer Revenue:
Regulated:
Gas transportation and storage	$	279	$	344
Wholesale	17		2
Other	0		1
Total regulated	296		347




Nonregulated	190		208
Total Customer Revenue	486		555
Other revenue	0		1
Total operating revenue	$	486	$	556

155

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 March 31, 2021 (in millions):


	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total
Eastern Energy Gas	$	1,564	$	16,115	$	17,679

(10) 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, 2019	$	(106)	$	(81)	$	0	$	(187)
Other comprehensive income (loss)	1		(85)		0		(84)
Balance, March 31, 2020	$	(105)	$	(166)	$	0	$	(271)

Balance, December 31, 2020	$	(12)	$	(51)	$	10	$	(53)
Other comprehensive income (loss)	2		10		(4)		8
Balance, March 31, 2021	$	(10)	$	(41)	$	6	$	(45)

(11) Variable Interest Entities

The primary beneficiary of a variable interest entity ("VIE") is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity's economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

In November 2019, DEI contributed to Eastern Energy Gas a 75% controlling limited partner interest in Cove Point. In December 2019, DEI sold its retained 25% noncontrolling limited partner interest in Cove Point. As part of the GT&S Transaction, Eastern Energy Gas finalized a restructuring which included the disposition of a 50% noncontrolling interest in Cove Point to DEI, which resulted in Eastern Energy Gas owning 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. Eastern Energy Gas concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Eastern Energy Gas is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.

Eastern Energy Gas purchased shared services from Carolina Gas Services, Inc. ("Carolina Gas Services") an affiliated VIE, of $3 million and $4 million for the three-month periods ended March 31, 2021 and 2020, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $26 million and $22 million as of March 31, 2021 and December 31, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities is the primary beneficiary of Carolina Gas Services as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Carolina Gas Services provides marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities has any obligation to absorb more than its allocated share of Carolina Gas Services costs.

156

Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Questar Pipeline Services, Inc. ("DEQPS"), an affiliated VIE, of $7 million for the three-month period ended March 31, 2020. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DEQPS, as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DEQPS provided marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DEQPS costs.

Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Services, Inc. ("DES"), an affiliated VIE, of $31 million for the three-month period ended March 31, 2020. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DES as neither it nor any of its consolidated entities had both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DES provided accounting, legal, finance and certain administrative and technical services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DES costs.

(12) Related Party Transactions

Transactions Prior to the GT&S Transaction

Prior to the GT&S Transaction, Eastern Energy Gas engaged in related party transactions primarily with other ~~Dominion Energy~~DEI subsidiaries (affiliates). ~~Virginia Power and Dominion~~Eastern Energy ~~Gas’~~Gas' receivable and payable balances with affiliates ~~are~~were settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. ~~Virginia Power and Dominion~~Through October 31, 2020, Eastern Energy Gas ~~are~~was included in ~~Dominion Energy's~~DEI's consolidated federal income tax return and, where applicable, combined state income tax ~~returns for Dominion~~returns. All affiliate payables or receivables were settled with DEI prior to the closing of the GT&S Transaction.

Eastern Energy ~~are filed in various states. Dominion Energy’s transactions with equity method investments are described in Note 10. A discussion of significant related-party transactions follows.~~

~~Virginia Power~~

~~Transactions with Affiliates~~

~~Virginia Power transacts~~Gas transacted with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. ~~Virginia Power~~Additionally, Eastern Energy Gas provided transportation and storage services to affiliates. Eastern Energy Gas also ~~enters~~entered into certain ~~commodity derivative~~other contracts with ~~affiliates. Virginia Power uses these~~affiliates, and related parties, including construction services, which were presented separately from contracts which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. At March 31, 2020, Virginia Power’s derivative assets and liabilities with affiliates were $2 million and $20 million, respectively. At December 31, 2019, Virginia Power’s derivative assets and liabilities with affiliates were $3 million and $53 million, respectively. See Note 9 for more information.

~~Virginia Power participates~~involving commodities or services. Eastern Energy Gas participated in certain ~~Dominion Energy~~DEI benefit plans as described in Note 22 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019. At March 31, 2020 and December 31, 2019, amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and included in other deferred credits and other liabilities in the Consolidated Balance Sheets were $810 million and $782 million, respectively. At March 31, 2020 and December 31, 2019, Virginia Power's amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and included in other deferred charges and other assets in the Consolidated Balance Sheets were $303 million and $287 million, respectively.

DES, Carolina Gas Services, DEQPS and other affiliates ~~provide~~provided accounting, legal, finance and certain administrative and technical services to ~~Virginia Power. In addition, Virginia Power provides~~Eastern Energy Gas. Eastern Energy Gas provided certain services to ~~affiliates,~~related parties, including ~~charges for facilities and equipment usage.~~

technical services.

The financial statements for ~~all years presented~~the three-month period ended March 31, 2020 include costs for certain general, administrative and corporate expenses assigned by DES, Carolina Gas Services and DEQPS to ~~Virginia Power~~Eastern Energy Gas on the basis of direct and allocated methods in accordance with ~~Virginia Power’s~~Eastern Energy Gas' services agreements with ~~DES.~~DES, Carolina Gas Services and DEQPS. Where costs incurred cannot be determined by specific identification, the costs ~~are~~were allocated based on the proportional level of effort devoted by DES, Carolina Gas Services and DEQPS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.

Subsequent to the GT&S Transaction, and with the exception of Cove Point, Eastern Energy Gas' transactions with other DEI subsidiaries are no longer related-party transactions.

Presented below are ~~Virginia Power’s~~Eastern Energy Gas' significant transactions with DES, Carolina Gas Services, DEQPS and other ~~affiliates:~~

affiliated and related parties for the three-month period ended March 31, 2020 (in millions):

Three Months Ended March 31,

2020

2019

(millions)

Commodity purchases from affiliates

$
211

$
272

Services provided by affiliates⁽¹⁾

121

119

Services provided to affiliates

5

6


Sales of natural gas and transportation and storage services	$	64
Purchases of natural gas and transportation and storage services	3
Services provided by related parties(1)	~~Includes capitalized expenditures of~~43 ~~$34 million and $33 million for the three months ended March 31, 2020 and 2019, respectively.~~
Services provided to related parties(2)	32

~~Virginia Power has borrowed funds~~

(1) Includes capitalized expenditures of $3 million.

(2) Amount primarily attributable to Atlantic Coast Pipeline, LLC, a related-party VIE prior to the GT&S Transaction.

157

Interest income related to Eastern Energy Gas' affiliated notes receivable from ~~Dominion~~DEI was $11 million for the three-month period ended March 31, 2020.

Interest income related to Eastern Energy ~~under short-term borrowing arrangements. There were 0 short-term demand note borrowings~~Gas' affiliated notes receivable from ~~Dominion~~East Ohio Gas Company was $18 million for the three-month period ended March 31, 2020.

For the three-month period ended March 31, 2020, Eastern Energy Gas distributed $37 million to DEI.

Transactions Subsequent to the GT&S Transaction

Eastern Energy Gas is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $21 million and $20 million as of March 31, 2020 and $107 million in short-term demand note borrowings from Dominion Energy as of December 31, 2019. Virginia Power had 0 outstanding borrowings, net of repayments, under the Dominion Energy money pool for its nonregulated subsidiaries as of March 31, 20202021 and December 31, ~~2019. Interest charges~~2020, respectively.

DEI, BHE, MidAmerican Energy, Northern Natural Gas Company and other related parties provided accounting, human resources, information technology and certain other administrative and technical services to ~~Virginia Power’s borrowings from Dominion~~Eastern Energy ~~were immaterial~~Gas, which totaled $7 million for the ~~three months~~three-month period ended March 31, ~~2020~~2021. Eastern Energy Gas provided certain services to affiliates, including administrative and ~~2019.~~

~~There were 0 issuances of Virginia Power’s common stock to Dominion Energy~~technical services, which totaled $9 million for the ~~three months~~three-month period ended March 31, ~~2020 and 2019.~~

~~Dominion~~2021. Eastern Energy Gas

~~Transactions with Related Parties~~

Dominion Energy Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Energy Gas provides also provided transportation and storage services to ~~affiliates. Dominion~~affiliates, which totaled $7 million for the three-month period ended March 31, 2021. Other assets included amounts due from an affiliate of $6 million and $7 million as of March 31, 2021 and December 31, 2020, respectively.

Eastern Energy Gas ~~also enters into certain other contracts with affiliates~~has a $400 million intercompany revolving credit agreement from its parent, BHE GT&S, LLC ("BHE GT&S") expiring in November 2021. The credit facility, which is for general corporate purposes and ~~related parties, including construction services, which are presented separately from contracts involving commodities or services.~~provide for the issuance of letters of credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") plus a fixed spread. As of March 31, ~~2020~~2021 and December 31, ~~2019, Dominion~~2020, $— million and $9 million, respectively, was outstanding under the credit agreement.

BHE GT&S has an intercompany revolving credit agreement from Eastern Energy Gas ~~did 0t have any commodity derivative assets or liabilities with affiliates. See Notes 7~~expiring in December 2021. In March 2021, BHE GT&S increased its credit facility limit from $200 million to $400 million. The credit agreement has a variable interest rate based on LIBOR plus a fixed spread. As of March 31, 2021 and ~~9 for more information. See Note 10 for information regarding transactions with Atlantic Coast Pipeline. See Note 3 for information regarding~~December 31, 2020, $234 million and $124 million, respectively, was outstanding under the ~~Dominion Energy Gas Restructuring, an affiliated transaction.~~

~~Dominion~~credit agreement.

Eastern Energy Gas participates in certain ~~Dominion~~MidAmerican Energy benefit plans as described in Note 216. As of March 31, 2021 and December 31, 2020, 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 $110 million and $115 million, respectively.

158

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 ~~Companies’~~future could differ significantly from the historical results.

Results of Operations for the First Quarter of 2021 and 2020

Overview

Net income for the first three months of 2021 was $89 million, a decrease of $80 million compared to 2020. Net income decreased primarily a result of the GT&S Transaction consisting of an increase in net income attributable to noncontrolling interests due to DEI's 50% noncontrolling interest in Cove Point LNG, LP ("Cove Point") of $69 million and the absence of Questar Pipeline Group operations of $23 million.

Quarter Ended March 31, 2021 Compared to Quarter Ended March 31, 2020

Operating revenue decreased $70 million, or 13%, for the first quarter of 2021 compared to 2020, primarily due to the absence of Questar Pipeline Group operations of $64 million and a decrease in services performed for Atlantic Coast Pipeline, LLC of $17 million, which is offset in operations and maintenance expense. The decrease in operating revenue was partially offset by an increase in regulated gas sales primarily due to increased volumes of $17 million.

Cost of gas decreased $8 million, or 100%, for the first quarter of 2021 compared to 2020, primarily due to favorable prices of $19 million and the absence of Questar Pipeline Group operations of $2 million, partially offset by an increase in volumes sold of $14 million.

Operations and maintenance decreased $44 million, or 26%, for the first quarter of 2021 compared to 2020, primarily due to a decrease in services performed for Atlantic Coast Pipeline, LLC of $17 million and the absence of Questar Pipeline Group operations of $15 million.

Depreciation and amortization decreased $13 million, or 14%, for the first quarter of 2021 compared to 2020, primarily due to the absence of Questar Pipeline Group.

Interest expense decreased$14 million, or 24%, for the first quarter of 2021 compared to 2020, primarily due to lower interest expense of $7 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and the absence of interest expense related to Questar Pipeline Group of $5 million.

Interest and dividend income decreased $30 million, or 100%, for the first quarter of 2021 compared to 2020, primarily due to the absence of interest income from the East Ohio Gas Company of $18 million and DEI of $11 million.

Other, net decreased $13 million, or 93%, for the first quarter of 2021 compared to 2020, primarily due to a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI as a result of the GT&S Transaction.

Income tax expense decreased $25 million for the first quarter of 2021 compared to 2020 and the effective tax rate was 13% for the first quarter of 2021 and 22% for the first quarter of 2020. The effective tax rate decreased primarily due to the change in the noncontrolling interest of Cove Point and lower pre-tax income as a result of the GT&S Transaction.

Net income attributable to noncontrolling interests increased $69 million, or 209%, for the first quarter of 2021 compared to 2020 primarily due to DEI's 50% interest in Cove Point effective with the GT&S Transaction.

159

Liquidity and Capital Resources

As of March 31, 2021, Eastern Energy Gas' total net liquidity was $506 million as follows (in millions):


Cash and cash equivalents	$	106

Intercompany credit agreement(1)	400
Less:
Notes payable	—

Net intercompany credit agreement	400

Total net liquidity	$	506

Intercompany credit agreement:
Maturity date	2021

(1)Refer to Note 12 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for further discussion regarding Eastern Energy Gas' intercompany credit agreement.

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $241 million and $667 million. respectively. The change was primarily due to decreased repayments of affiliated receivables by DEI subsidiaries in 2021 and the absence of the Questar Pipeline Group.

The timing of Eastern Energy Gas' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods elected and assumptions for each payment date.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(56) million and $(342) million. respectively. The change was primarily due to the absence of loans to affiliates of $262 million.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2021 were $(118) million. Uses of cash totaled $(118) million and consisted mainly of distributions to noncontrolling interests from Cove Point of $109 million.

Net cash flows from financing activities for the three-month period ended March 31, 2020 were $(306) million. Uses of cash totaled $306 million and consisted mainly of distributions of $269 million and repayments of short-term debt of $32 million.

Future Uses of Cash

Eastern Energy Gas has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which 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 utility industry.

160

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' 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. Expenditures for certain assets may ultimately include acquisition of existing assets.

Eastern Energy Gas' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2020		2021		2021

Natural gas transmission and storage	$	23	$	8	$	30
Other	53		47		432
Total	$	76	$	55	$	462

Eastern Energy Gas' natural gas transmission and storage capital expenditures primarily include growth capital expenditures related to planned regulated projects. Eastern Energy Gas' other capital expenditures consist primarily of non-regulated and routine capital expenditures for natural gas transmission, storage and liquefied natural gas terminalling infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, ~~2019. At March 31, 2020~~2020.

161

Regulatory Matters

Eastern Energy Gas is subject to comprehensive regulation. Refer to Note 4 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for discussion regarding Eastern Energy Gas' current regulatory matters.

Environmental Laws and ~~December 31, 2019, amounts due from Dominion~~Regulations

Eastern Energy ~~associated~~Gas is subject to federal, state and local laws and regulations regarding climate change, air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the ~~Dominion Energy Pension Plan included in other deferred charges~~authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other ~~assets~~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 laws and regulations are subject to interpretation that may ultimately be resolved by the courts.

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 ~~Balance Sheets were $331 million~~Financial Statements based on such estimates involve numerous assumptions subject to varying and ~~$326 million, respectively. At March 31, 2020~~potentially significant degrees of judgment and ~~December 31, 2019, Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Retiree Health~~uncertainty and ~~Welfare Plan included in other deferred charges and other assets~~will likely change in the ~~Consolidated Balance Sheets were $19 million and $17 million, respectively.~~

DES, DECGS, DEQPS and other affiliates provide accounting, legal, finance, marketing and certain administrative and technical services to Dominion Energy Gas. Dominion Energy Gas provides certain services to related parties, including technical services.

~~The financial statements~~future as additional information becomes available. Estimates are used for, all years presented include costs for certain general, administrative and corporate expenses assigned by DES, DECGS and DEQPS to Dominion Energy Gas on the basis of direct and allocated methods in accordance with Dominion Energy Gas’ services agreements with DES, DECGS and DEQPS. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES, DECGS and DEQPS resources that are attributablebut not limited to, the ~~entity, determined by reference to number of employees, salaries and wages and other similar measures~~accounting for the ~~relevant DES, DECGS~~effects of certain types of regulation, impairment of goodwill and ~~DEQPS service. Management believes the assumptions~~long-lived assets and ~~methodologies underlying the allocation~~income taxes. For additional discussion of ~~general corporate overhead expenses are reasonable.~~

~~Presented below are Dominion~~Eastern Energy ~~Gas’ significant transactions with DES, DECGS, DEQPS and other affiliates and related parties:~~

Three Months Ended March 31,

2020

2019

(millions)

Sales of natural gas and transportation and storage services

$
64

$
67

Purchases of natural gas and transportation storage services

3

—

Services provided by related parties⁽¹⁾

43

45

Services provided to related parties⁽²⁾

32

45

~~(1)~~

~~Includes capitalized expenditures of $3 million and $6 million for the three months ended March 31, 2020 and 2019, respectively.~~

~~(2)~~

~~Amounts primarily attributable to Atlantic Coast Pipeline, a related-party VIE.~~

~~The following table presents affiliated and related party balances reflected in Dominion~~Gas' critical accounting estimates, see Item 7 of Eastern Energy ~~Gas’ Consolidated Balance Sheets:~~

March 31, 2020

December 31, 2019

(millions)

Other receivables⁽¹⁾

$
8

$
7

Imbalances receivable from affiliates

—

8

Imbalances payable to affiliates⁽²⁾

2

1

Other deferred charges and other assets

11

12

~~(1)~~

~~Represents amounts due from Atlantic Coast Pipeline, a related-party VIE.~~

~~(2)~~

~~Amounts are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

Affiliated receivables at March 31, 2020 and December 31, 2019 included $21 million and $22 million, respectively, of accrued unbilled revenue. This revenue is based on estimated amounts of services provided but not yet billed to various affiliates.

~~Dominion Energy Gas’ affiliated borrowings and investments are discussed in Note 25 to the Companies’~~Gas' Annual Report on Form 10-K for the year ended December 31, ~~2019.~~

~~Dominion~~2020. There have been no significant changes in Eastern Energy ~~Gas had $262 million in affiliated notes receivable under the Dominion Energy money pool as of March 31, 2020 and 0 outstanding receivables as of~~Gas' assumptions regarding critical accounting estimates since December 31, ~~2019. Interest income related to~~2020.

162

Item 3.Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the ~~affiliated notes receivable was immaterial for the three months ended March 31, 2020.~~

Interest income on affiliated notes receivable from East Ohio and DGP for borrowings under intercompany revolving credit agreements with Dominion Energy Gas was $5 million for the three months ended March 31, 2019.

~~Interest income earned on DMLPHCII’s promissory note to Dominion Energy was immaterial for the three months ended March 31, 2020 and 2019.~~

~~Interest income related to Dominion Energy’s promissory note borrowings with Cove Point was $27 million for the three months ended March 31, 2019.~~

At March 31, 2020 and December 31, 2019, Dominion Energy Gas’ affiliated notes receivable from Dominion Energy totaled $1.8 billion. Interest income on these promissory notes was $11 million for the three months ended March 31, 2020.

At March 31, 2020 and December 31, 2019, Dominion Energy Gas’ affiliated notes receivable from East Ohio totaled $1.7 billion. Interest income on these promissory notes were $18 million for the three months ended March 31, 2020.

~~Dominion Energy Gas’ borrowings under the intercompany revolving credit agreement with Dominion Energy totaled $256 million and $251 million as~~Registrants, see Item 7A of March 31, 2020 and December 31, 2019. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were less than $1 million for the three months ended March 31, 2020 and 2019.

~~Interest charges related to DCP’s total borrowings from Dominion Energy under an intercompany revolving credit agreement totaled $29 million for the three months ended March 31, 2019.~~

DCP had borrowings of $9 million with DES as of December 31, 2019. Interest related to DCP’s total borrowings from DES totaled less than $1 million for the three months ended March 31, 2020 and 2019.

In the first quarter of 2019, Dominion Energy Midstream borrowed $395 million from Dominion Energy under a $400 million promissory note with Dominion Energy that was scheduled to mature in 2022. Interest charges of $2 million were incurred for the three months ended March 31, 2019.

For the three months ended March 31, 2020 and 2019, Dominion Energy Gas, including entities acquired in the Dominion Energy Gas Restructuring, distributed $37 million and $46 million to Dominion Energy, respectively.

~~Note 20. Employee Benefit Plans~~

~~Dominion Energy~~

~~The components of Dominion Energy’s provision for net periodic benefit cost (credit) were as follows:~~

Pension Benefits

Other Postretirement Benefits

2020

2019

2020

2019

(millions)

Three Months Ended March 31,

Service cost

$
43

$
40

$
7

$
7

Interest cost

91

101

15

17

Expected return on plan assets

(193
)

(177
)

(39
)

(33
)
Amortization of prior service credit

—

—

(12
)

(13
)
Amortization of net actuarial loss

49

39

1

4

Settlements

—

2

—

—

Net periodic benefit cost (credit)

$
(10
)

$
5

$
(28
)

$
(18
)

~~Employer Contributions~~

During the three months ended March 31, 2020, Dominion Energy made 0 contributions to its qualified defined benefit pension plans or other postretirement benefit plans. Dominion Energy does 0t expect to make contributions to its defined benefit pension plans and expects to contribute $12 million to other postretirement benefit plans through VEBAs, respectively, during the remainder of 2020.

~~Dominion Energy Gas~~

~~Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 22 to the Consolidated Financial Statements in the Companies’~~each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2019. See~~2020. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2020. Refer to Note 196 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for ~~more information.~~

~~The components~~disclosure of ~~Dominion~~the respective Registrant's derivative positions as of March 31, 2021.

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 ~~Gas’ provision~~Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC 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 ~~net periodic benefit cost (credit) for employees represented~~such entity were effective to ensure that information required to be disclosed by ~~collective bargaining units were~~such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as ~~follows:~~

Pension Benefits

Other Postretirement Benefits

2020

2019

2020

2019

(millions)

Three Months Ended March 31,

Service cost

$
1

$
4

$
1

$
1

Interest cost

3

8

1

3

Expected return on plan assets

(14
)

(39
)

(5
)

(7
)
Amortization of prior service credit

—

—

(1
)

(1
)
Amortization of net actuarial loss

2

5

—

1

Net periodic benefit credit

$
(8
)

$
(22
)

$
(4
)

$
(3
)

~~Employer Contributions~~

~~During~~amended, is recorded, processed, summarized and reported within the ~~three months~~time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended March 31, 2021 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

163

PART II

Item 1.Legal Proceedings

Berkshire Hathaway Energy and PacifiCorp

On September 30, 2020, ~~Dominion Energy Gas made 0 contributions~~a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20cv33885, Circuit Court, Multnomah County, Oregon. The complaint was filed by Oregon residents and businesses who seek to ~~its qualified defined benefit pension plan~~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. The complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp acted with gross negligence, among other ~~postretirement benefit plans. Dominion Energy Gas does 0t expect~~things. The complaint was amended November 2, 2020, and seeks the following damages: (i) damages for real and personal property and other economic losses in excess of $600 million; (ii) double the amount of property and economic damages based on alleged gross negligence; (iii) treble damages for specific costs associated with loss of timber, trees and shrubbery; (iv) double the damages for the costs of litigation and reforestation; and (v) prejudgment interest. The plaintiffs demand a trial by jury and have reserved their right to ~~make contributions~~amend the complaint to ~~its qualified defined benefit pension plan~~allege claims for punitive damages.

On March 12, 2021, a complaint against PacifiCorp was filed, captioned Shyla Zeober et al. v. PacifiCorp, Case No. 21cv09339, Circuit Court, Marion County, Oregon. The complaint was filed by Oregon residents and ~~expects~~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 ~~contribute approximately $12 million~~the Beachie Creek Fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages for real and personal property and other economic losses in an amount determined by the jury to ~~its other postretirement benefit plans through VEBAs during the remainder of 2020.~~

~~Note 21. Operating Segments~~

~~The Companies are organized primarily on the basis of products~~be fair and ~~services sold~~reasonable, but not to exceed $150 million; and (ii) noneconomic damages in the ~~U.S. A description of~~amount determined by the ~~operations included~~jury to be fair and reasonable, but not to exceed $500 million. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint.

On March 15, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21cv09520, Circuit Court, Marion County, Oregon. The 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 for real and personal property and other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $150 million; and (ii) noneconomic damages in the ~~Companies’ primary operating segments is as follows:~~

~~Primary Operating Segment~~	~~Description of Operations~~	~~Dominion~~ ~~Energy~~	~~Virginia~~ ~~Power~~	~~Dominion~~ ~~Energy~~ ~~Gas~~
~~Dominion Energy Virginia~~	~~Regulated electric distribution~~	X	X
	~~Regulated electric transmission~~	X	X
	~~Regulated electric generation fleet~~⁽¹⁾	X	X
~~Gas Transmission & Storage~~	~~Regulated gas transmission and storage~~⁽²⁾	X		X
	~~LNG terminalling and storage~~	X		X
	~~Nonregulated retail energy marketing~~	X
~~Gas Distribution~~	~~Regulated gas distribution and storage~~⁽³⁾	X
~~Dominion Energy South~~ ~~Carolina~~	~~Regulated electric distribution~~	X
	~~Regulated electric transmission~~	X
	~~Regulated electric generation fleet~~	X
	~~Regulated gas distribution and storage~~	X
~~Contracted Generation~~	~~Merchant electric generation fleet~~	X

~~(1)~~amount determined by the jury to be fair and reasonable, but not to exceed $500 million. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint.

I~~ncludes Virginia Power’s nonjurisdictional generation operations.~~

~~(2)~~

~~Includes gathering and processing activities.~~

~~(3)~~

~~Includes Wexpro’s gas development and production operations.~~

~~In addition to the operating segments above, the Companies also report a Corporate~~Other individual lawsuits alleging similar claims have been filed in Oregon and ~~Other segment.~~

~~Dominion Energy~~

~~The Corporate and Other Segment of Dominion Energy~~ includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. As discussed in Note 1 in the Companies’ Annual Report on Form 10-K, in December 2019, Dominion Energy realigned its segments which resulted in the formation of five primary operating segments. The information for the three months ended March 31, 2019 presented herein has been recast to reflect the current segment presentation.

In the three months ended March 31, 2020, Dominion Energy reported after-tax net expenses of $1.2 billion for specific items in the Corporate and Other segment, with $1.0 billion of net expenses attributable to its operating segments. In the three months ended March 31, 2019, Dominion Energy reported after-tax net expenses of $1.6 billion for specific items in the Corporate and Other segment, with $1.3 billion of net expenses attributable to its operating segments.

~~The net expense for specific items attributable to Dominion Energy’s operating segments in 2020 primarily~~California related to the ~~impact~~2020 Wildfires. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 9 of the ~~following items:~~

•	~~A $754 million ($566 million after-tax) charge primarily related to the early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia;~~

•	~~A $538 million ($410 million after-tax) loss related to investments in nuclear decommissioning trust funds, attributable to:~~

•

~~Contracted Generation ($364 million after-tax) and;~~

•

~~Dominion Energy Virginia ($46 million after-tax).~~

~~The net expense for specific items attributable~~Notes to ~~Dominion Energy’s operating segments~~Consolidated Financial Statements of Berkshire Hathaway Energy in ~~2019 primarily related~~Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to ~~the impact~~Note 8 of the ~~following items:~~

•	~~A $1.0 billion ($756~~ ~~million after-tax) charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, attributable to Dominion Energy South Carolina;~~

•	~~A $369 million ($275 million after-tax) charge related to the early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia;~~

•	A $198 million tax charge for $264 million of income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina;

•	~~$178 million ($133 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina;~~

•	~~A $160 million ($119 million after-tax) charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure, attributable to Dominion Energy Virginia;~~

•	~~$106 million ($81 million after-tax) of merger and integration-related costs associated with the SCANA Combination, attributable to Dominion Energy South Carolina;~~

•	A $105 million ($79 million after-tax) charge for property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forego recovery, attributable to Dominion Energy South Carolina;

•	~~A $253 million ($197 million after-tax) net gain related to investments in nuclear decommissioning trust funds, attributable to:~~

•

~~Contracted Generation ($175 million after-tax) and;~~

Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

•

~~Dominion Energy Virginia ($22 million after-tax).~~

•	A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019, attributable to Dominion Energy Virginia.

~~The following table presents segment information pertaining to Dominion Energy’s operations:~~

Dominion
Energy
Virginia

Gas
Transmission
& Storage

Gas
Distribution

Dominion
Energy
South
Carolina

Contracted
Generation

Corporate
and Other

Adjustments
& Eliminations

Consolidated
Total

(millions)

Three Months Ended March 31, 2020

Total revenue from external customers

$
1,938

$
644

$
887

$
713

$
286

$
28

$
—

$
4,496

Intersegment revenue

(3
)

57

3

1

4

279

(341
)

—

Total operating revenue

1,935

701

890

714

290

307

(341
)

4,496

Net income (loss) attributable to Dominion
Energy

429

221

225

94

59

(1,298
)

-

(270
)
Three Months Ended March 31, 2019

Total revenue from external customers

$
2,001

$
984

$
917

$
689

$
352

$
(1,052
)

$
(33
)

$
3,858

Intersegment revenue

(4
)

54

4

—

3

277

(334
)

—

Total operating revenue

1,997

1,038

921

689

355

(775
)

(367
)

3,858

Net income (loss) attributable to Dominion
Energy

361

222

205

71

102

(1,641
)

-

(680
)
Item 1A.Risk Factors

~~Intersegment sales and transfers for Dominion Energy are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.~~

~~Virginia Power~~

~~The Corporate and Other Segment of Virginia Power~~ primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources. As discussed in Note 1 in the Companies’ Annual Report on Form 10-K, in December 2019, Virginia Power realigned its segments which resulted in the formation of one primary operating segment. The information for the three months ended March 31, 2019 presented herein

There has been ~~recast~~no material change to ~~reflect the current segment presentation.~~

In the three months ended March 31, 2020, Virginia Power reported after-tax net expenses of $700 million for specific items in the Corporate and Other segment with $634 million of the net expenses attributable to its operating segment. In the three months ended March 31, 2019 Virginia Power reported after-tax expense of $344 million for specific items in the Corporate and Other segment, with $324 million of net expenses attributable to its operating segment.

~~The net expenses for specific items in 2020 primarily related to the impact of the following items:~~

•	~~A $754 million ($561 million after-tax) charge related to the early retirement of certain Virginia Power electric generation facilities;~~

•	~~A $62 million ($46 million after-tax) loss related to investments in nuclear decommissioning trust funds.~~

~~The net expenses for specific items in 2019 primarily related to the impact of the following items:~~

•	~~A $369 million ($275 million after-tax) charge related to the early retirement of certain electric generation facilities;~~

•	~~A $160 million ($119 million after-tax) charge related to the planned early retirement of certain automated meter reading infrastructure; and~~

•	~~A $29 million ($22 million after-tax) charge related to a portion of rate adjustment clauses for excess deferred taxes which are probable of being returned to customers, partially offset by~~

•	~~A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019.~~

~~The following table presents segment information pertaining to Virginia Power’s operations:~~

Dominion
Energy
Virginia

Corporate
and Other

Consolidated
Total

(millions)

Three Months Ended March 31, 2020

Operating revenue

$
1,930

$
—

$
1,930

Net income (loss)

427

(707
)

(280
)
Three Months Ended March 31, 2019

Operating revenue

$
1,994

$
(29
)

$
1,965

Net income (loss)

358

(338
)

20

~~Dominion Energy Gas~~

~~The Corporate and Other Segment of Dominion Energy Gas~~ primarily includes specific items attributable to Dominion Energy Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed. In addition, Corporate and Other includes the net impact of discontinued operations, which are discussed in Note 3. As discussed in Note 1 in the Companies’ Annual Report on Form 10-K, in December 2019, Dominion Energy Gas realigned its segments which resulted in the formation of one primary operating segment. The information for the three months ended March 31, 2019 presented herein has been recast to reflect the current segment presentation.

~~In both the three months ended March 31, 2020 and 2019, Dominion Energy Gas reported an immaterial amount of specific items in the Corporate and Other segment.~~

~~The following table presents segment information pertaining to Dominion Energy Gas’ operations:~~

Gas
Transmission
& Storage

Corporate
and Other

Consolidated
Total

(millions)

Three Months Ended March 31, 2020

Operating revenue

$
556

$
—

$
556

Net income (loss) attributable to Dominion Energy Gas

174

(5
)

169

Three Months Ended March 31, 2019

Operating revenue

$
566

$
—

$
566

Net income from discontinued operations

—

54

54

Net income (loss) attributable to Dominion Energy Gas

138

52

190

~~ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS~~

~~OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

MD&A discusses Dominion Energy’s results of operations and general financial condition and Virginia Power’s and Dominion Energy Gas’ results of operations. MD&A should be read in conjunction with the Companies’ Consolidated Financial Statements. Virginia Power and Dominion Energy Gas meet the conditions to file under the reduced disclosure format, and therefore have omitted certain sections of MD&A.

~~Contents of MD&A~~

~~MD&A consists of the following information:~~

•	~~Forward-Looking Statements~~

•	~~Accounting Matters – Dominion Energy~~

•	~~Dominion Energy~~

•

~~Results of Operations~~

•

~~Segment Results of Operations~~

•	~~Virginia Power~~

•

~~Results of Operations~~

•	~~Dominion Energy Gas~~

•

~~Results of Operations~~

•	~~Liquidity and Capital Resources – Dominion Energy~~

•	~~Future Issues and Other Matters – Dominion Energy~~

~~Forward-Looking Statements~~

This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.

The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, othereach Registrant's risk factors ~~may cause actual results to differ materially~~ from those ~~indicated in any forward-looking statement. These factors include but are not limited to:~~

•	~~Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;~~

•	Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities;

•	The impact of extraordinary external events, such as the current pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in our markets;

•	~~Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;~~

•	~~Risks of operating businesses in regulated industries that are subject to changing regulatory structures;~~

•	Changes to regulated electric rates collected by Dominion Energy and Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;

•	Changes in rules for RTOs and ISOs in which Dominion Energy and Virginia Power join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;

•	~~Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;~~

•

Risks associated with entities in which Dominion Energy and Dominion Energy Gas share ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy and Dominion Energy Gas and third party participants and difficulties in exiting these arrangements;

•	~~Changes in future levels of domestic and international natural gas production, supply or consumption;~~

•	~~Fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG;~~

•	~~Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;~~

•	The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects;

•	Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;

•	~~Cost of environmental compliance, including those costs related to climate change;~~

•	~~Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;~~

•	~~Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;~~

•	~~Unplanned outages at facilities in which the Companies have an ownership interest;~~

•	The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events;

•	Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;

•	~~Changes in operating, maintenance and construction costs;~~

•	~~Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;~~

•

Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;

•	~~Competition in the development, construction and ownership of certain electric transmission facilities in Dominion Energy and Virginia Power’s service territory in connection with Order 1000;~~

•	~~Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;~~

•

Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas’ pipeline systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;

•	~~Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;~~

•	~~Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews;~~

•	~~Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination;~~

•	~~Counterparty credit and performance risk;~~

•	~~Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas;~~

•	~~Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets;~~

•	~~Fluctuations in interest rates or foreign currency exchange rates;~~

•	~~Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;~~

•	~~Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;~~

•	~~Political and economic conditions, including inflation and deflation;~~

•	~~Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and~~

•	~~Changes in financial or regulatory accounting principles or policies imposed by governing bodies.~~

~~Additionally, other risks that could cause actual results to differ from predicted results are set forth~~disclosed in Item ~~1A. Risk Factors in the Companies’~~1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020.

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

Not applicable.

Item ~~1A. Risk Factors~~3.Defaults Upon Senior Securities

Not applicable.

164

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 ~~report.~~

Form 10-Q.

Item 5.Other Information

Not applicable.

Item 6.Exhibits

The ~~Companies’ forward-looking statements are based on beliefs~~following is a list of exhibits filed as part of this Quarterly Report.

165

Exhibit No.Description

BERKSHIRE HATHAWAY ENERGY

4.1Fiscal Agency Agreement, dated as of April 9 , 20 21 , by and ~~assumptions using information available at the time the statements are made.~~between Northern Natural Gas Company and The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

~~Accounting Matters~~

~~Critical Accounting Policies and Estimates~~

As Bank of ~~March 31, 2020, there have been no significant changes with regard~~New York Mellon Trust Company, N.A., Fiscal Agent, relating to the ~~critical accounting policies~~$55 0,000,000 in principal amount of the 3.40 % Senior Notes due 20 5 1 .

15.1Awareness Letter of Independent Registered Public Accounting Firm.

31.1Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

PACIFICORP

15.2Awareness Letter of Independent Registered Public Accounting Firm.

31.3Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.3Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

95Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and ~~estimates disclosed in MD&A in~~Consumer Protection Act .

MIDAMERICAN ENERGY

15.3Awareness Letter of Independent Registered Public Accounting Firm.

31.5Principal Executive Officer Certification Pursuant to Section 302 of the ~~Companies’ Annual~~Sarbanes-Oxley Act of 2002.

31.6Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.5Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

MIDAMERICAN FUNDING

31.7Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.8Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.7Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.8Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

NEVADA POWER

15.4Awareness Letter of Independent Registered Public Accounting Firm.

31.9Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.10Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 .

32.9Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.10Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 .

166

SIERRA PACIFIC

31.11Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.12Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.11Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.12Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

EASTERN ENERGY GAS

31.13P rincipal Executive Officer Certif ication Pursuant to Section 302 of the Sarbanes -Oxley Act of 2002.

31.14Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.13Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.14Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

ALL REGISTRANTS

101The following financial information from each respective Registrant's Quarterly Report on Form ~~10-K~~10-Q for the ~~year~~quarter ended ~~December~~March 31, ~~2019. The policies disclosed~~2021, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the accounting for regulated operations, AROs, income taxes, derivative contracts and financial instruments at fair value, impairment testing of goodwill, long-lived assets and equity method investments and employee benefit plans.

~~Dominion Energy~~

~~Results~~Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations,

~~Presented below is a summary~~ (iii) the Consolidated Statements of ~~Dominion Energy’s consolidated results:~~

2020

2019

$ Change

(millions, except EPS)

First Quarter

Net loss attributable to Dominion Energy

$
(270
)

$
(680
)

$
410

Diluted EPS

(0.34
)

(0.86
)

0.52

~~Overview~~

~~First Quarter 2020 vs. 2019~~

~~Net loss attributable~~Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Dominion Energy decreased 60%, primarily due to the absence of charges for refunds of amounts previously collected from retail electric customers of DESC for the NND Project and for certain regulatory assets and property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, a decrease in charges associated with litigation acquired in the SCANA Combination and the absence of charges for the planned early retirement of certain Virginia Power automated meter reading infrastructure. These decreases were partially offset by a decrease in net investment earnings on nuclear decommissioning trust funds and an increase in charges associated with the planned early retirements of certain electric generation facilities in Virginia.

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Dominion Energy’s results of operations:~~

First Quarter

2020

2019

$ Change

(millions)

Operating revenue

$
4,496

$
3,858

$
638

Electric fuel and other energy-related purchases

668

791

(123
)
Purchased electric capacity

2

39

(37
)
Purchased gas

427

730

(303
)
Net revenue

3,399

2,298

1,101

Other operations and maintenance

1,043

1,002

41

Depreciation, depletion and amortization

673

651

22

Other taxes

284

292

(8
)
Impairment of assets and other charges

768

835

(67
)
Other income (expense)

(399
)

388

(787
)
Interest and related charges

490

469

21

Income tax expense (benefit)

(19
)

114

(133
)
Noncontrolling interests

31

3

28

~~An analysis of Dominion Energy’s results of operations follows:~~

~~First Quarter 2020 vs. 2019~~

~~Net revenue~~ ~~increased 48%, primarily reflecting:~~

•	~~The absence of a~~ ~~$1.0 billion charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project;~~

•	~~A $128 million increase from Virginia Power rate adjustment clauses;~~

•

~~A $32 million decrease in Virginia Power electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($30 million) and a~~ ~~contract termination with a non-utility generator ($13 million) partially offset by the expiration of various contracts ($11 million); and~~

•	A ~~$25 million net unrealized gain on freestanding commodity derivatives.~~

~~These increases were partially offset by:~~

•	~~A $46 million decrease from the contribution of SEMI to Wrangler;~~

•	~~A $41 million decrease due to unfavorable pricing at Millstone, including the effects of the Millstone 2019 power purchase agreements; and~~

•	~~A $23 million net decrease in sales to electric retail customers from a net decrease in heating degree days.~~

~~Other operations and maintenance~~ ~~increased 4%, primarily reflecting:~~

•	~~The absence of a benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019 ($113 million); and~~

•	~~A $39 million increase in certain Virginia Power expenditures, which are primarily recovered through state and FERC rates and do not impact net income; partially offset by~~

•	~~A decrease in merger and integration-related costs associated with the SCANA Combination ($96 million); and~~

•	~~An $18 million decrease in salaries, wages and benefits.~~

~~Impairment of assets and other charges~~ ~~decreased~~ 8%, primarily due to the absence of charges associated with litigation acquired in the SCANA Combination ($178 million), the absence of a charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure ($160 million) and a decrease in charges for property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($103 million), partially offset by an increase in charges associated with the planned early retirements of certain electric generation facilities in Virginia ($382 million).

~~Other income (expense)decreased $787 million, primarily reflecting~~ ~~net investment losses in 2020 compared to net investment gains in 2019~~ ~~on nuclear decommissioning trust funds ($792 million) and charges associated with litigation acquired in the SCANA Combination ($25 million).~~

~~Interest and related charges~~ ~~increased 4%, primarily related to increases~~ for unrealized losses associated with freestanding derivatives ($58 million) and charges associated with the early redemption of certain securities in the first quarter of 2020 ($25 million), partially offset by lower interest expense from early redemptions of certain securities in 2019 ($57 million).

~~Income tax expense (benefit)~~ ~~decreased~~ ~~$133 million, primarily due to~~ the absence of a charge for certain income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($198 million), partially offset by a lower pre-tax loss ($60 million).

~~Noncontrolling interests~~ ~~increased~~ ~~$28 million, primarily due to the sale of a 25% noncontrolling limited partnership interest in Cove Point to Brookfield in December 2019.~~

~~Segment Results of Operations~~

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. In December 2019, Dominion Energy realigned its segments which resulted in the formation of five primary operating segments. The historical information presented herein has been recast to reflect the current segment presentation. Presented below is a summary of contributions by Dominion Energy’s operating segments to net loss attributable to Dominion Energy:

Net Income (Loss) Attributable to
Dominion Energy

Diluted EPS

2020

2019

$ Change

2020

2019

$ Change

(millions, except EPS)

First Quarter

Dominion Energy Virginia

$
429

$
361

$
68

$
0.51

$
0.45

$
0.06

Gas Transmission & Storage

221

222

(1
)

0.26

0.28

(0.02
)
Gas Distribution

225

205

20

0.27

0.26

0.01

Dominion Energy South Carolina

94

71

23

0.11

0.09

0.02

Contracted Generation

59

102

(43
)

0.07

0.13

(0.06
)
Corporate and Other

(1,298
)

(1,641
)

343

(1.56
)

(2.07
)

0.51

Consolidated

$
(270
)

$
(680
)

$
410

$
(0.34
)

$
(0.86
)

$
0.52

~~Dominion Energy Virginia~~

~~Presented below are selected operating statistics related to Dominion Energy Virginia’s operations:~~

First Quarter

2020

2019

% Change

Electricity delivered (million MWh)

20.8

21.8

(5
)%
Electricity supplied (million MWh):

Utility

22.4

21.9

2

Degree days (electric distribution and utility service area):

Cooling

14

5

180

Heating

1,518

1,892

(20
)
Average electric distribution customer accounts
(thousands)

2,647

2,617

1

~~Presented below, on an after-tax basis, are the key factors impacting Dominion Energy Virginia’s net income contribution:~~

First Quarter
2020 vs. 2019
Increase (Decrease)

Amount

EPS

(millions, except EPS)

Regulated electric sales:

Weather

$
(26
)

$
(0.03
)
Other

4

—

Rate adjustment clause equity return

23

0.03

Electric capacity

24

0.03

Depreciation and amortization

12

0.02

Renewable energy investment tax credits

29

0.04

Other

2

—

Share dilution

—

(0.03
)
Change in net income contribution

$
68

$
0.06

~~Gas Transmission & Storage~~

~~Presented below are selected operating statistics related to Gas Transmission & Storage’s operations:~~

First Quarter

2020

2019

% Change

Average retail energy marketing customer accounts⁽¹⁾
(thousands)

398

799

(50
)%

~~(1)~~

~~Excludes accounts held by equity method investees.~~

~~Presented below, on an after-tax basis, are the key factors impacting Gas Transmission & Storage’s net income contribution:~~

First Quarter
2020 vs. 2019
Increase (Decrease)

Amount

EPS

(millions, except EPS)

Noncontrolling interest

$
(20
)

$
(0.02
)
Contribution to Wrangler

(17
)

(0.02
)
Atlantic Coast Pipeline equity earnings

8

0.01

Interest expense, net

26

0.03

Other

2

—

Share dilution

—

(0.02
)
Change in net income contribution

$
(1
)

$
(0.02
)

~~Gas Distribution~~

~~Presented below are selected operating statistics related to Gas Distribution’s operations:~~

First Quarter

2020

2019

% Change

Gas distribution throughput (bcf):

Sales

80

88

(9
%)
Transportation

250

240

4

Heating degree days (gas distribution service area):

North Carolina

1,334

1,656

(19
)
Ohio and West Virginia

2,442

2,915

(16
)
Utah, Wyoming and Idaho

2,332

2,570

(9
)
Average gas distribution customer accounts
(thousands):

Sales

1,891

1,853

2

Transportation

1,115

1,111

—

~~Presented below, on an after-tax basis, are the key factors impacting Gas Distribution’s net income contribution:~~

First Quarter
2020 vs. 2019
Increase (Decrease)

Amount

EPS

(millions, except EPS)

Regulated gas sales:

Weather

$
(5
)

$
—

Other

11

0.01

Rate adjustment clause equity return

2

—

Interest expense, net

6

0.01

Other

6

0.01

Share dilution

—

(0.02
)
Change in net income contribution

$
20

$
0.01

~~Dominion Energy South Carolina~~

~~Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations:~~

First Quarter

2020

2019

% Change

Electricity delivered (million MWh)

5.1

5.1

—
%
Electricity supplied (million MWh)

5.3

5.2

2

Degree days (electric distribution service areas):

Cooling

5

—

100

Heating

578

660

(12
)
Average electric distribution customer accounts
(thousands)

746

734

2

Gas distribution throughput (bcf):

Sales

19

18

6

Average gas distribution customer accounts
(thousands)

394

382

3

~~Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution:~~

First Quarter
2020 vs. 2019
Increase (Decrease)

Amount

EPS

(millions, except EPS)

Regulated electric sales:

Weather

$
9

$
0.01

Other

5

—

Regulated gas sales

4

—

Interest expense, net

8

0.01

Other

(3
)

—

Share dilution

—

—

Change in net income contribution

$
23

$
0.02

~~Contracted Generation~~

~~Presented below are selected operating statistics related to Contracted Generation’s operations:~~

First Quarter

2020

2019

% Change

Electricity supplied (million MWh)

5.3

5.2

2
%

~~Presented below, on an after-tax basis, are the key factors impacting Contracted Generation’s net income contribution:~~

First Quarter
2020 vs. 2019
Increase (Decrease)

Amount

EPS

(millions, except EPS)

Margin

$
(44
)

$
(0.06
)
Interest expense, net

4

—

Other

(3
)

—

Share dilution

—

—

Change in net income contribution

$
(43
)

$
(0.06
)

~~Corporate and Other~~

~~Presented below are the Corporate and Other segment’s after-tax results:~~

First Quarter

2020

2019

$ Change

(millions, except EPS)

Specific items attributable to operating segments

$
(1,031
)

$
(1,335
)

$
304

Specific items attributable to Corporate and Other
segment

(170
)

(218
)

48

Total specific items

(1,201
)

(1,553
)

352

Other corporate operations⁽¹⁾

(97
)

(88
)

(9
)
Total net income (expense)

$
(1,298
)

$
(1,641
)

$
343

EPS impact

$
(1.56
)

$
(2.07
)

$
0.51

~~(1)~~

~~Primarily consists of net interest expense.~~

~~Total Specific Items~~

Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or in allocating resources. See Note 21 to the Consolidated Financial Statements, tagged in ~~this report for discussion of these items~~summary and detail.

104Cover Page Interactive Data File formatted in ~~more detail. Corporate~~iXBRL (Inline eXtensible Business Reporting Language) and ~~Other also includes items attributable to the Corporate and Other segment.~~

~~Virginia Power~~

~~Results of Operations~~

~~Presented below is a summary of Virginia Power’s consolidated results:~~

First Quarter

2020

2019

$ Change

(millions)

Net income (loss)

$
(280
)

$
20

$
(300
)

~~Overview~~

~~First Quarter 2020 vs. 2019~~

Net income decreased $300 million, primarily due to an increase in charges related to the planned early retirements of certain electric generation facilities. This decrease was partially offset by the absence of a charge related to the planned early retirement of certain automated meter reading infrastructure.

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Virginia Power’s results of operations:~~

First Quarter

2020

2019

$ Change

(millions)

Operating revenue

$
1,930

$
1,965

$
(35
)
Electric fuel and other energy-related purchases

492

596

(104
)
Purchased (excess) electric capacity

(9
)

33

(42
)
Net revenue

1,447

1,336

111

Other operations and maintenance

418

279

139

Depreciation and amortization

311

304

7

Other taxes

87

85

2

Impairment of assets and other charges

764

546

218

Other income (expense)

(52
)

37

(89
)
Interest and related charges

126

135

(9
)
Income tax expense (benefit)

(31
)

4

(35
)

~~An analysis of Virginia Power’s results of operations follows:~~

~~First Quarter 2020 vs. 2019~~

~~Net revenue~~ ~~increased 8%, primarily reflecting:~~

•	~~A $128 million increase from rate adjustment clauses; and~~

•

~~A $~~32 million decrease in electric capacity expense related to the annual PJM capacity performance market effective June 2019; ($30 million) and a contract termination with a non-utility generator ($13 million) partially offset by the expiration of various contracts ($11 million); partially offset by

•	~~A $35 million decrease in sales to retail customers, primarily due to a decrease in heating degree days.~~

~~Other operations and maintenance~~ increased 50%, primarily reflecting the absence of a benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019 ($113 million) and a $39 million increase in certain expenses, which are primarily recovered through state and FERC rates and do not impact net income.

~~Depreciation and amortization~~ ~~increased 2%, primarily~~ ~~due to various projects being placed into service ($14 million), partially offset by an $8 million decrease~~ ~~reflectingthe expected approval of the nuclear plant life extensions from the NRC.~~

~~Impairment of assets and other charges~~ increased 40%, primarily due to an increase in charges associated with the planned early retirements of certain electric generation facilities ($382 million), partially offset by the absence of a charge related to the planned early retirement of certain automated meter reading infrastructure ($160 million).

~~Other income (expense)~~ ~~decreased $89 million, primarily reflecting net investment losses in 2020 compared to net investment gains in 2019 on nuclear decommissioning trust funds.~~

~~Income tax expense (benefit)~~ ~~decreased $35 million, primarily due to lower pre-tax income.~~

~~Dominion Energy Gas~~

~~Results of Operations~~

~~Presented below is a summary of Dominion Energy Gas’ consolidated results:~~

First Quarter

2020

2019

$ Change

(millions)

Net income attributable to Dominion Energy Gas

$
169

$
190

$
(21
)

~~Overview~~

~~First Quarter 2020 vs. 2019~~

Net income attributable to Dominion Energy Gas decreased 11%, primarily due to the absence of net income from discontinued operations related to the Dominion Energy Gas Restructuring, partially offset by a decrease in interest and related charges from lower outstanding debt balances.

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Dominion Energy Gas’ results of operations:~~

First Quarter

2020

2019

$ Change

(millions)

Operating revenue

$
556

$
566

$
(10
)
Purchased gas

8

12

(4
)
Other energy-related purchases

—

1

(1
)
Net revenue

548

553

(5
)
Other operations and maintenance

165

176

(11
)
Depreciation and amortization

93

91

2

Other taxes

42

39

3

Earnings from equity method investees

15

13

2

Other income

49

42

7

Interest and related charges

58

87

(29
)
Income tax expense

52

43

9

Net income from discontinued operations

—

54

(54
)
Noncontrolling interests

33

36

(3
)

~~An analysis of Dominion Energy Gas’ results of operations follows:~~

~~First Quarter 2020 vs. 2019~~

~~Net revenue~~ ~~decreased 1%, primarily reflecting:~~

•	~~An $11 million decrease in services performed for Atlantic Coast Pipeline; partially offset by~~

•	~~A $3 million increase due to DETI contract changes.~~

~~Other operations and maintenance~~ ~~decreased 6% primarily due to a decrease in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.~~

~~Other income~~ increased 17%, primarily due to a $3 million increase in non-service components of pension and other postretirement employee benefit credits and a $2 million net increase in interest income from affiliated promissory note receivables.

~~Interest and related charges~~ ~~decreased 33%,~~primarily due to the absence of interest expense from Cove Point’s term loan borrowings ($36 million), partially offset by interest expense on Dominion Energy Gas’ November 2019 senior note issuance ($7 million).

~~Income tax expense~~ ~~increased 21%, primarily due to higher pre-tax income.~~

~~Liquidity and Capital Resources~~

Dominion Energy depends on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.

At March 31, 2020, Dominion Energy had $3.8 billion of unused capacity under its joint revolving credit facility. In addition, Dominion Energy had $900 million available under a 364-Day Revolving Credit Agreement entered into March 2020.

As part of its strategic response to COVID-19, Dominion Energy undertook certain measures in March and April 2020 to buttress its liquidity position. This includes entering the $900 million 364-Day Revolving Credit Agreement, which has the potential for an additional $300 million of capacity upon certain events, and under which Dominion Energy has borrowed $225 million. In addition, Dominion Energy borrowed $1.1 billion under two 364-Day Term Loan Credit Agreements and issued $2.3 billion of senior notes. See Note 16 to the Consolidated Financial Statements for more information.

~~A summary of Dominion Energy’s cash flows is presented below:~~

2020

2019

(millions)

Cash, restricted cash and equivalents at January 1

$
269

$
391

Cash flows provided by (used in):

Operating activities

1,633

1,171

Investing activities

(1,641
)

(552
)
Financing activities

1,006

(383
)
Net increase in cash, restricted cash and equivalents

998

236

Cash, restricted cash and equivalents at March 31

$
1,267

$
627

~~Operating Cash Flows~~

Net cash provided by Dominion Energy’s operating activities increased $462 million, primarily due to higher deferred fuel cost recoveries, lower payments for property taxes and net changes in working capital items.

~~Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares.~~

Dominion Energy’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, which are discussed in Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 and Part II. Item 1A. Risk Factors in this report.

~~Credit Risk~~

Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of March 31, 2020 for these activities. Gross credit exposure for each counterparty is calculated prior to the application of collateral and represents outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

Gross Credit
Exposure

Credit
Collateral

Net Credit
Exposure

(millions)

Investment grade⁽¹⁾

$
91

$
—

$
91

Non-investment grade⁽²⁾

3

—

3

No external ratings:

Internally rated—investment grade⁽³⁾

71

—

71

Internally rated—non-investment grade⁽⁴⁾

7

—

7

Total⁽⁵⁾

$
172

$
—

$
172

~~(1)~~

Designations as investment grade are based upon minimum credit ratings assigned by Moody’s Investors Service and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 34% of the total net credit exposure.

~~(2)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 2% of the total net credit exposure.~~

~~(3)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 40% of the total net credit exposure.~~

~~(4)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 2% of the total net credit exposure.~~

~~(5)~~

~~Excludes the Millstone 2019 power purchase agreements.~~

~~Investing Cash Flows~~

Net cash used in Dominion Energy’s investing activities increased $1.1 billion, primarily due to an increase in plant construction and other property additions, the absence of cash acquired in the SCANA Combination and the acquisitions of Pivotal LNG, Inc. and an additional interest in Atlantic Coast Pipeline.

~~Financing Cash Flows and Liquidity~~

~~Dominion Energy relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed further in~~ ~~Credit Ratings~~ ~~and~~ ~~Debt Covenants~~ in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, the ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

Dominion Energy currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933, as amended. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion Energy to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.

Net cash provided by Dominion Energy's financing activities was $1.0 billion for the three months ended March 31, 2020, compared to net cash used by financing activities of $383 million for the three months ended March 31, 2019, primarily due to lower repayments of long-term debt.

In November 2017, Dominion Energy filed an SEC shelf registration statement for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability Investment^SM. The registration limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. The balance as of March 31, 2020 was $119 million. The notes are short-term debt obligations on Dominion Energy’s Consolidated Balance Sheets. The proceeds will be used for general corporate purposes and to repay debt.

~~See Note 16 to the Consolidated Financial Statements in this report for further information regarding Dominion Energy’s credit facilities, liquidity and significant financing transactions.~~

~~Credit Ratings~~

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the ~~Credit Ratings~~ section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, there is a discussion on the use of capital markets by Dominion Energy as well as the impact of credit ratings on the accessibility and costs of using these markets. As of March 31, 2020, there have been no changes in Dominion Energy’s credit ratings.

~~Debt Covenants~~

~~In the~~ ~~Debt Covenants~~ section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, there is a discussion on the various covenants present in the enabling agreements underlying Dominion Energy’s debt. In addition, see Note 16 to the Consolidated Financial Statements in this report for a description of certain financial covenants associated with term loan and revolving credit agreements entered into in the first quarter of 2020. As of March 31, 2020, there have been no material changes to debt covenants, nor any events of default under Dominion Energy’s debt covenants.

~~Future Cash Payments for Contractual Obligations and Planned Capital Expenditures~~

As of March 31, 2020, there have been no material changes outside the ordinary course of business to Dominion Energy’s contractual obligations nor any material changes to planned capital expenditures as disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~Use of Off-Balance Sheet Arrangements~~

~~As of March 31, 2020, there have been no material changes to the off-balance sheet arrangements disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.~~

~~Future Issues and Other Matters~~

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by, and subsequent to, the dates of Dominion Energy’s Consolidated Financial Statements that may impact future results of operations, financial condition and/or cash flows. This section should be read in conjunction with ~~Item 1. Business~~ ~~and~~ ~~Future Issues and Other Matters~~ ~~in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 and Note 17 to the Consolidated Financial Statements in this report.~~

~~Environmental Matters~~

Dominion Energy is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, and Note 17 to the Consolidated Financial Statements in this report for additional information on various environmental matters.

~~Legal Matters~~

~~See~~Notes 13 and 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 and Notes 13 and 17 to the Consolidated Financial Statements and ~~Item 1. Legal Proceedings~~ ~~in this report for additional information on various legal matters.~~

~~Regulatory Matters~~

See Notes 3 and 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 and Note 13 to the Consolidated Financial Statements in this report for additional information on various regulatory matters.

~~Atlantic Coast Pipeline~~

In September 2014, Dominion Energy, along with Duke and Southern, announced the formation of Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Atlantic Coast Pipeline has continued to experience delays in obtaining and/or maintaining permits necessary for construction along with construction delays due to judicial actions. In February 2020, the Supreme Court of the U.S. heard oral arguments in Atlantic Coast Pipeline’s case regarding the Appalachian Trail crossing and is expected to issue a ruling by June 2020. If a favorable ruling is not received, Atlantic Coast Pipeline is also evaluating possible legislative and administrative remedies to this issue. Given the legal challenges, the project is expected to enter full in-service in early 2022, with project costs estimated to be approximately $8 billion, excluding financing costs. Atlantic Coast Pipeline has reached agreements in principle with major customers to amend the contracted rate to share in certain delay cost increases, pending certain regulatory~~approvals. Project construction activities, schedules andcosts are~~subject to uncertainty due to permitting and/or work delays (including due to judicial or regulatory action), abnormal weather and other conditions that could result in cost or schedule modifications in the future, a suspension of AFUDC for Atlantic Coast Pipeline and/or impairment charges potentially material to Dominion Energy’s cash flows, financial position and/or results of operations. See Note 10 to the Consolidated Financial Statements in this report for more information.

~~NWP 12 Permitting~~

In April 2020, the U.S. District Court for the District of Montana issued an order vacating an NWP 12 issued by the Army Corps of Engineers and remanding the permit back to the Army Corps of Engineers for consultation under the Endangered Species Act. In 2017, the Army Corps of Engineers issued an NWP 12 authorizing discharges related to construction projects into waters of the U.S. The court concluded that the issuance of the NWP 12 was unlawful because the Army Corps of Engineers did not consult under the Endangered Species Act with the U.S Fish and Wildlife Service and/or National Marine Fisheries Service. The court also enjoined the Army Corps of Engineers from authorizing any dredge or fill activities under NWP 12. Following the court’s ruling, the Army Corps of Engineers suspended the NWP 12. Also in April 2020, the U.S. Department of Justice, along with other defendants, filed a motion to stay the portions of the court’s order that vacated NWP 12 and enjoined the Army Corps of Engineers from authorizing any dredge or fill activities under NWP 12. Defendants also filed a motion to expedite briefing and consideration of such request for stay to no later than May 2020 and indicated that they intended to file an appeal in the U.S. Court of Appeals for the Ninth Circuit immediately following the court’s determination.

The court’s order has significant near-term implications for all U.S. utilities, including electric, gas, water and communications, that are constructing projects requiring discharges into waters of the U.S. Because NWP 12 has been suspended, the Army Corps of Engineers may decline to verify future construction activities submitted under NWP 12 pending further court action. As Dominion Energy relies on NWP 12 for many of its energy infrastructure projects, as well as the Atlantic Coast Pipeline Project, the court’s ruling has the potential for causing a significant delay in construction schedules. While Dominion Energy expects that the court’s decision will be challenged by the federal defendants in that case, at this time Dominion Energy cannot predict the timing or outcome of such proceedings.

~~Significant Contracted Generation Investment~~

In May 2020, Dominion Energy announced it is leading a consortium of offshore wind energy industry participants in pursuing the development of a Jones Act compliant offshore wind installation vessel. This vessel will be designed to handle current turbine technologies as well as next generation turbine sizes of 12 MW or larger. The vessel will be funded by the consortium participants including Dominion Energy, based on its proportional share of equity interest in the project which is still to be finalized, and is expected to enter service in 2023 and operate for several years under contracts with multiple major U.S. offshore wind developers.

~~COVID-19~~

Dominion Energy is monitoring the global outbreak of COVID-19 and taking steps to mitigate the potential risks to Dominion Energy posed by the spread of the virus. Dominion Energy provides a critical service to its customers which means that it is paramount that Dominion Energy keeps its employees who operate its businesses safe and informed. For example, Dominion Energy has taken precautions with regard to employee and facility hygiene, imposed travel limitations on employees, directed employees to work remotely whenever possible and expanded health and paid time off benefits for employees. Additional protocols are being implemented for required work within customer premises to protect Dominion Energy’s employees, such customers and the public. In addition, Dominion Energy has assessed and updated its existing business continuity plans for its business units in the context of this pandemic. Dominion Energy is also working with suppliers to understand the potential impacts to its supply chain; however, at this time, no material risks to Dominion Energy’s supply chain have been identified. This is a rapidly evolving situation, and Dominion Energy will continue to monitor developments affecting its workforce, suppliers and other aspects of its business, such as construction projects, and will take additional precautions as Dominion Energy believes are warranted. In addition, Dominion Energy continues to monitor both customer demand and its ability to collect customer receivables. . While Dominion Energy currently does not expect a material impact to its results of operations from the impacts of the COVID-19 pandemic on its operations, the ultimate impacts on its results of operations, financial position and/or cash flows could be material based on the ultimate duration of the pandemic and the related economic recovery.

~~ITEM 3.~~

~~QUANTITATIVE AND QUALITATIVE~~

~~DISCLOSURES ABOUT MARKET RISK~~

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. MD&A in this report. The reader’s attention is directed to those paragraphs for discussion of various risks and uncertainties that may impact the Companies.

~~Market Risk Sensitive Instruments and Risk Management~~

The Companies’ financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion Energy and Virginia Power’s electric operations and Dominion Energy and Dominion Energy Gas’ natural gas procurement and marketing operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, the Companies are exposed to investment price risk through various portfolios of equity and debt securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices or interest rates.

~~Commodity Price Risk~~

To manage price risk, Dominion Energy and Virginia Power hold commodity-based derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products. Dominion Energy Gas’ operations are contracted primarily under long-term fixed reservation agreements. Accordingly, management believes that Dominion Energy Gas is not subject to material commodity price risk.

The derivatives used to manage commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease in fair value of $46 million and $50 million of Dominion Energy’s commodity-based derivative instruments as of March 31, 2020 and December 31, 2019, respectively.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease in fair value of $44 million and $54 million of Virginia Power’s commodity-based derivative instruments as of March 31, 2020 and December 31, 2019, respectively.

The impact of a change in energy commodity prices on the Companies' commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity-based financial derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.

~~Interest Rate Risk~~

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt outstanding for Dominion Energy, Virginia Power and Dominion Energy Gas, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at March 31, 2020 or December 31, 2019.

The Companies also use interest rate derivatives, including forward-starting swaps, as hedges of forecasted interest payments. As of March 31, 2020, Dominion Energy, Virginia Power and Dominion Energy Gas had $8.0 billion, $2.1 billion and $1.3 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $84 million, $49 million and $8 million, respectively, in the fair value of Dominion Energy, Virginia Power and Dominion Energy Gas’ interest rate derivatives at March 31, 2020. As of December 31, 2019, Dominion Energy, Virginia Power and Dominion Energy Gas had $6.4 billion, $1.9 billion and $1.3 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $135 million, $88 million and $17 million, respectively, in the fair value of Dominion Energy, Virginia Power and Dominion Energy Gas’ interest rate derivatives at December 31, 2019.

Dominion Energy Gas holds foreign currency swaps for the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. At both March 31, 2020 and December 31, 2019, Dominion Energy and Dominion Energy Gas had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $5 million in the fair value of Dominion Energy Gas' foreign currency swaps at March 31, 2020 and would not have resulted in a material decrease in the fair value of Dominion Energy Gas’ foreign currency swaps at December 31, 2019.

The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

~~Investment Price Risk~~

Dominion Energy and Virginia Power are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in Dominion Energy and Virginia Power’s Consolidated Balance Sheets at fair value.

Dominion Energy recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $876 million for the three months ended March 31, 2020, and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $448 million for the three months ended March 31, 2019 and $1.0 billion for the year ended December 31, 2019. Net realized gains and losses include gains and losses from the sale of investments in both 2020 and 2019 as well as any other-than-temporary declines in fair value in 2019 only. Dominion Energy recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $39 million for the three months ended March 31, 2019 and $74 million for the year ended December 31, 2019.

Virginia Power recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $412 million for the three months ended March 31, 2020, and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $202 million for the three months ended March 31, 2019 and $481 million for the year ended December 31, 2019. Net realized gains and losses include gains and losses from the sale of investments in both 2020 and 2019 as well as any other-than-temporary declines in fair value in 2019 only. Virginia Power recorded in AOCI and regulatory liabilities, a net decrease in unrealized gains on debt investments of $1 million for the three months ended March 31, 2020 and recorded increase in unrealized gains on debt investments of $20 million for the three months ended March 31, 2019 and $30 million for the year ended December 31, 2019.

Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Energy Gas employees participate in these plans. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

~~ITEM 4. CONTROLS AND PROCEDURES~~

Senior management of each of Dominion Energy, Virginia Power and Dominion Energy Gas, including Dominion Energy, Virginia Power and Dominion Energy Gas’ CEO and CFO, evaluated the effectiveness of each of their respective company’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, each of Dominion Energy, Virginia Power and Dominion Energy Gas’ CEO and CFO have concluded that each of their respective company’s disclosure controls and procedures are effective.

There were no changes that occurred during the last fiscal quarter that materially affected, or are reasonably likely to materially affect Dominion Energy, Virginia Power or Dominion Energy Gas’ internal control over financial reporting.

~~PART II. OTHER INFORMATION~~

~~ITEM 1. LEGAL PROCEEDINGS~~

From time to time, the Companies are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings.

In March 2018, Virginia Power received a proposed consent order from the VDEQ in connection with alleged CWA permit violations at the Chesterfield power station in 2017. Virginia Power began working cooperatively with both the VDEQ and the EPA to resolve those and certain other alleged violations collectively. In March 2020, Virginia Power finalized a consent decree with the VDEQ and the EPA that would require Virginia Power to pay a $1.4 million civil penalty in connection with various alleged CWA permit and other violations. The consent decree is subject to a 30-day public comment period and is expected to become final and effective in the second or third quarter of 2020.

~~See the following for discussions on various legal, environmental and other regulatory proceedings to which the Companies are a party, which information is incorporated herein by reference:~~

•	~~Notes 13 and 23 to the Consolidated Financial Statements and~~ ~~Future Issues and Other Matters~~ ~~in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.~~

•	~~Notes 13 and 17 to the Consolidated Financial Statements in this report.~~

~~ITEM 1A. RISK FACTORS~~

The Companies’ businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the Companies’ control. A number of these risk factors have been identified in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, which should be taken into consideration when reviewing the information contained in this report Other than the risk factor discussed below, there have been no material changes with regard to the risk factors previously disclosed in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see ~~Forward-Looking Statements~~Exhibit 101. ~~in MD&A in this report.~~

~~Public health crises and epidemics or pandemics, such as COVID-19, could adversely affect the Companies’ business, results of operations, financial condition, liquidity and/or cash flows.~~

The effects of the continued outbreak of the COVID-19 pandemic and related government responses could include extended disruptions to supply chains and capital markets, reduced labor availability and productivity and a prolonged reduction in economic activity. The effects could also have a variety of adverse impacts on the Companies, including reduced demand for energy, particularly from commercial and industrial customers, impairment of goodwill or long-lived assets and diminished ~~ability of the Companies to access funds from financial institutions and capital markets.~~ There is considerable uncertainty regarding the extent to which COVID-19 will spread and the extent and duration of measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter-in-place orders and shutdowns. Such restrictions may cause operational interruptions and delays in construction projects, which, in the case of renewable energy projects, could delay the expected in-service dates of these projects and financial statement impact of the investment tax credits associated with these projects beyond 2020. For the duration of the outbreak of COVID-19, voluntary suspension, or potential legislative or government action, is expected to limit the Companies’ ability to collect on overdue accounts or disconnect services for non-payment, which may cause a decrease in the Companies’ results of operations and cash flows. To the extent the COVID-19 pandemic adversely affects the Companies’ business, results of operations, financial condition, liquidity and/or cash flows, it may also have the effect of heightening many of the other risks described in Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~

~~Dominion Energy~~

~~ISSUER PURCHASES OF EQUITY SECURITIES~~

Period

Total
Number of
Shares
(or Units)
Purchased⁽¹⁾

Average
Price Paid
per Share
(or Unit)⁽²⁾

Total Number
of Shares (or Units)
Purchased as Part
of Publicly
Announced Plans or
Programs

Maximum Number (or
Approximate Dollar
Value) of Shares (or Units)
that May Yet Be
Purchased under the Plans
or Programs⁽³⁾
1/1/20-1/31/20

1,945

$
82.82

—

19,629,059 shares/
$1.18 billion
2/1/20-2/29/20

79,716

85.81

—

19,629,059 shares/
$1.18 billion
3/1/20-3/31/20

—

—

—

19,629,059 shares/
$1.18 billion
Total

81,661

$
85.74

—

19,629,059 shares/
$1.18 billion

~~(1)~~

~~Represents shares that were tendered by employees to satisfy tax withholding obligations on vested restricted stock.~~

~~(2)~~

~~Represents the weighted-average price paid per share.~~

167

~~(3)~~

The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Energy Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Energy Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.

~~ITEM 6. EXHIBITS~~

~~Exhibit~~ ~~Number~~	~~Description~~	~~Dominion Energy~~	~~Virginia Power~~	~~Dominion Energy Gas~~

~~3.1.a~~	~~Dominion Energy, Inc. Articles of Incorporation, as restated, effective December 13, 2019 (Exhibit 3.1, Form 8-K filed December 13, 2019, File No.1-8489).~~	X

~~3.1.b~~	~~Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).~~		X

~~3.1.c~~	~~Articles of Organization of Dominion Energy Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).~~			X

~~3.1.d~~	~~Articles of Amendment to the Articles of Organization of Dominion Energy Gas Holdings, LLC (Exhibit 3.1, Form 8-K filed May 16, 2017, File No. 1-37591).~~			X

~~3.2.a~~	~~Dominion Energy, Inc. Bylaws, as amended and restated, effective March 20, 2020 (Exhibit 3.1, Form 8-K filed March 25, 2020, File No. 1-8489).~~	X

~~3.2.b~~	~~Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).~~		X

~~3.2.c~~	~~Operating Agreement of Dominion Energy Gas Holdings, LLC, as amended and restated, effective November 5, 2019 (Exhibit 3.1, Form 8-K filed November 12, 2019, File No. 001-37591).~~			X

~~4.1~~	Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC agree to furnish to the U.S. Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of any of their total consolidated assets.	X	X	X

~~4.2~~	~~Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489)~~; ~~First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489)~~; ~~Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, File No. 1-8489)~~; ~~Third Supplemental Indenture, dated as of February 1, 2016 (Exhibit 4.7, Form 10-K for the fiscal year ended December 31, 2015 filed February 26, 2016, File No. 1-8489)~~; ~~Fourth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.2, Form 8-K filed August 9, 2016, File No. 1-8489)~~; ~~Fifth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.3, Form 8-K filed August 9, 2016, File No. 1-8489)~~; ~~Sixth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.4, Form 8-K filed August 9, 2016, File No. 1-8489)~~; ~~Seventh Supplemental Indenture, dated as of September 1, 2016 (Exhibit 4.1, Form 10-Q filed November 9, 2016, File No. 1-8489)~~; ~~Eighth Supplemental Indenture, dated as of December 1, 2016 (Exhibit 4.7, Form 10-K for the fiscal year ended December 31, 2016 filed February 28, 2017, File No. 1-8489)~~; ~~Ninth Supplemental Indenture, dated as of January 1, 2017 (Exhibit 4.2, Form 8-K filed January 12, 2017, File No. 1-8489)~~; ~~Tenth Supplemental Indenture, dated as of January 1, 2017 (Exhibit 4.3, Form 8-K filed January 12, 2017, File No. 1-8489)~~; ~~Eleventh Supplemental Indenture, dated as of March 1, 2017 (Exhibit 4.3, Form 10-Q filed May 4, 2017, File No. 1-8489)~~; ~~Twelfth Supplemental Indenture, dated as of June 1, 2017 (Exhibit 4.2, Form 10-Q filed August 3, 2017, File No. 1-8489)~~; ~~Thirteenth Supplemental Indenture, dated December 1, 2017 (Exhibit 4.8, Form 10-K for the fiscal year ended December 31, 2017 filed February 27, 2018, File No. 1-8489)~~; ~~Fourteenth Supplemental Indenture, dated May 1, 2018 (Exhibit 4.2, Form 10-Q filed August 2, 2018, File No. 1-8489)~~; ~~Fifteenth Supplemental Indenture, dated June 1, 2018 (Exhibit 4.2, Form 8-K, filed June 5, 2018, File No. 1-8489)~~; ~~Sixteenth Supplemental Indenture, dated March 1, 2019 (Exhibit 4.2, Form 8-K filed March 13, 2019, File No. 1-8489)~~; ~~Seventeenth Supplemental Indenture, dated as of August 1, 2019 (Exhibit 4.2, Form 10-Q filed November 1, 2019, File No. 1-8489)~~; ~~Eighteenth Supplemental Indenture, dated as of March 1, 2020 (Exhibit 4.2, Form 8-K, filed March 19, 2020, File No. 1-8489)~~; ~~Nineteenth Supplemental Indenture, dated as of March 1, 2020 (Exhibit 4.3, Form 8-K, filed March 19, 2020, File No. 1-8489)~~; ~~Twentieth Supplemental Indenture, dated as of April 1, 2020 (Exhibit 4.2, Form 8-K, filed April 3, 2020, File No. 1-8489)~~.	X

SIGNATURES

~~Exhibit~~ ~~Number~~	~~Description~~	~~Dominion Energy~~	~~Virginia Power~~	~~Dominion Energy Gas~~

~~31.a~~	~~Certification by Chief Executive Officer of Dominion Energy, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~	X

~~31.b~~	~~Certification by Chief Financial Officer of Dominion Energy, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~	X

~~31.c~~	~~Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~		X

~~31.d~~	~~Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~		X

~~31.e~~	~~Certification by Chief Executive Officer of Dominion Energy Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~			X

~~31.f~~	~~Certification by Chief Financial Officer of Dominion Energy Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~			X

~~32.a~~	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Energy, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).	X

~~32.b~~	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X

~~32.c~~	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Energy Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).			X

99	~~Condensed consolidated earnings statements (filed herewith).~~	X	X	X

~~101~~	The following financial statements from Dominion Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, filed on May 5, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia Electric and Power Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, filed on May 5, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Common Shareholder’s Equity (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Dominion Energy Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, filed on May 5, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.	X	X	X

~~104~~	~~Cover Page~~ ~~Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.~~	X	X	X

~~SIGNATURE~~

Pursuant to the requirements of the Securities Exchange Act of 1934, ~~the~~each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		BERKSHIRE HATHAWAY ENERGY COMPANY

Date: April 30, 2021		~~DOMINION ENERGY, INC.~~ ~~Registrant~~ /s/ Calvin D. Haack
		Calvin D. Haack
~~May 5, 2020~~		~~/s/ Michele L. Cardiff~~ Senior Vice President and Chief Financial Officer
		(principal financial and accounting officer)

		~~Michele L. Cardiff~~ ~~Vice President, Controller and~~ ~~Chief Accounting Officer~~ PACIFICORP

	~~VIRGINIA ELECTRIC AND POWER COMPANY~~ ~~Registrant~~

~~May 5, 2020~~	~~/s/ Michele L. Cardiff~~
Date: April 30, 2021		~~Michele~~/s/ Nikki L. ~~Cardiff~~ Kobliha
		Nikki L. Kobliha
		Vice President, ~~Controller~~Chief Financial Officer and ~~Chief Accounting Officer~~ Treasurer
		(principal financial and accounting officer)
		~~DOMINION~~
		MIDAMERICAN FUNDING, LLC
		MIDAMERICAN ENERGY COMPANY

Date: April 30, 2021		/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: April 30, 2021		/s/ Michael E. Cole
		Michael E. Cole
		Vice President, Chief Financial Officer and Treasurer
		(principal financial and accounting officer)

		SIERRA PACIFIC POWER COMPANY

Date: April 30, 2021		/s/ Michael E. Cole
		Michael E. Cole
		Vice President, Chief Financial Officer and Treasurer
		(principal financial and accounting officer)

		EASTERN ENERGY GAS HOLDINGS, LLC ~~Registrant~~

~~May 5, 2020~~	~~/s/ Michele L. Cardiff~~
Date: April 30, 2021		~~Michele L. Cardiff~~ /s/ Scott C. Miller
		Scott C. Miller
		Vice President, ~~Controller~~Chief Financial Officer and ~~Chief Accounting Officer~~ Treasurer
		(principal financial and accounting officer)

~~112~~

168

~~Commission File~~ ~~Number~~	~~Exact name of registrants as specified in their charters, address of~~ ~~principal executive offices and registrants’ telephone number~~	~~I.R.S. Employer~~ ~~Identification Number~~

~~001-08489~~	~~DOMINION ENERGY, INC.~~	~~54-1229715~~

~~000-55337~~	~~VIRGINIA ELECTRIC AND POWER COMPANY~~	~~54-0418825~~

~~001-37591~~	~~DOMINION ENERGY GAS HOLDINGS, LLC~~	~~46-3639580~~

	~~120 Tredegar Street~~ ~~Richmond, Virginia 23219~~ ~~(804) 819-2000~~


Registrant	Name of ~~Each Exchange~~ exchange on ~~Which Registered~~which registered:
~~DOMINION~~BERKSHIRE HATHAWAY ENERGY ~~INC.~~ COMPANY	D	~~Common Stock, no par value~~	~~New York Stock Exchange~~ None
PACIFICORP	~~DRUA~~	~~2016 Series A 5.25% Enhanced Junior Subordinated Notes~~	~~New York Stock Exchange~~ None
~~DOMINION~~MIDAMERICAN FUNDING, LLC	None
MIDAMERICAN ENERGY COMPANY	None
NEVADA POWER COMPANY	None
SIERRA PACIFIC POWER COMPANY	None
EASTERN ENERGY GAS HOLDINGS, LLC	~~DCUE~~	~~2019 Series A Corporate Units~~ ~~2014 Series C 4.6% Senior Notes~~	~~New York Stock Exchange~~ ~~New York Stock Exchange~~ None

~~Large accelerated filer~~	☐		~~Accelerated filer~~	☐	~~Emerging growth company~~	☐
~~Non-accelerated filer~~	☒		~~Smaller reporting company~~	☐

~~Large accelerated filer~~	☐		~~Accelerated filer~~	☐	~~Emerging growth company~~	☐
~~Non-accelerated filer~~	☒		~~Smaller reporting company~~	☐


Registrant			~~Trading~~ ~~Symbol~~Securities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY			~~Title of Each Class~~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

		~~Page~~ ~~Number~~
Item 1.			~~Glossary of Terms~~Financial Statements		3 1

	~~PART I. Financial Information~~	8

~~Item 1.~~	~~Financial Statements~~	8
Item 2.	~~Management’s~~Management's Discussion and Analysis of Financial Condition and Results of Operations			92 2
Item 3.			Quantitative and Qualitative Disclosures About Market Risk		~~106~~ 163
Item 4.			Controls and Procedures		~~107~~ 163

	Three Months Ended March 31,
	2020			2019
(millions, except per share amounts)
Operating Revenue⁽¹⁾	$	4,496		$	3,858
Operating Expenses
Electric fuel and other energy-related purchases		668			791
Purchased electric capacity		2			39
Purchased gas		427			730
Other operations and maintenance		1,043			1,002
Depreciation, depletion and amortization		673			651
Other taxes		284			292
Impairment of assets and other charges		768			835
Total operating expenses		3,865			4,340
Income (loss) from operations		631			(482	)
Other income (expense)		(399	)		388
Interest and related charges		490			469
Loss from operations including noncontrolling interests before income tax expense (benefit)		(258	)		(563	)
Income tax expense (benefit)		(19	)		114
Net Loss Including Noncontrolling Interests		(239	)		(677	)
Noncontrolling Interests		31			3
Net Loss Attributable to Dominion Energy	$	(270	)	$	(680	)
Earnings Per Common Share
Net loss attributable to Dominion Energy - Basic	$	(0.34	)	$	(0.86	)
Net loss attributable to Dominion Energy - Diluted		(0.34	)		(0.86	)

	March 31, 2020			December 31, 2019⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	1,192		$	166
Customer receivables (less allowance for doubtful accounts of $20 at both dates)		2,177			2,278
Other receivables (less allowance for doubtful accounts of $3 at both dates)⁽²⁾		248			367
Inventories		1,677			1,742
Regulatory assets		668			879
Other		574			656
Total current assets		6,536			6,088
Investments
Nuclear decommissioning trust funds		5,313			6,192
Investment in equity method affiliates		1,886			1,646
Other		376			379
Total investments		7,575			8,217
Property, Plant and Equipment
Property, plant and equipment		95,341			97,466
Accumulated depreciation, depletion and amortization		(27,945	)		(28,384	)
Total property, plant and equipment, net		67,396			69,082
Deferred Charges and Other Assets
Goodwill		8,946			8,946
Regulatory assets		9,564			7,687
Other		4,109			3,803
Total deferred charges and other assets		22,619			20,436
Total assets	$	104,126		$	103,823

	Preferred Stock				Common Stock				Dominion Energy Shareholders						Total
	Shares		Amount		Shares		Amount		Retained Earnings			AOCI			Shareholders' Equity			Noncontrolling Interests			Total Equity
(millions, except per share amounts)
December 31, 2018						681	$	12,588	$	9,219		$	(1,700	)	$	20,107		$	1,941		$	22,048
Net income (loss) including noncontrolling interests										(680	)					(680	)		3			(677	)
Issuance of common stock						3		247								247						247
Acquisition of SCANA						96		6,818								6,818						6,818
Acquisition of public interest in Dominion Energy Midstream						22		1,181								1,181			(1,221	)		(40	)
Dividends ($0.9175 per common share) and distributions										(733	)					(733	)		(33	)		(766	)
Other comprehensive loss, net of tax													(31	)		(31	)					(31	)
March 31, 2019		—	$	—		802	$	20,834	$	7,806		$	(1,731	)	$	26,909		$	690		$	27,599


December 31, 2019		2	$	2,387		838	$	23,824	$	7,576		$	(1,793	)	$	31,994		$	2,039		$	34,033
Cumulative-effect of changes in accounting principles										(48	)					(48	)					(48	)
Net income (loss) including noncontrolling interests										(270	)					(270	)		31			(239	)
Issuance of stock					1		78									78						78
Preferred stock dividends (See Note 16)										(16	)					(16	)					(16	)
Common stock dividends ($0.940 per share) and distributions										(788	)					(788	)		(44	)		(832	)
Other comprehensive loss, net of tax													(225	)		(225	)					(225	)
Other										1						1						1
March 31, 2020		2	$	2,387		839	$	23,902	$	6,455		$	(2,018	)	$	30,726		$	2,026		$	32,752

	Predecessor Equity			Membership Interests			AOCI			Total Members' Equity			Noncontrolling Interests			Total
(millions)
December 31, 2018	$	1,804		$	4,566		$	(169	)	$	6,201		$	2,664		$	8,865
Net income		74			116						190			36			226
Acquisition of public interest in Dominion Energy Midstream		1,181									1,181			(1,221	)		(40	)
Dividends and distributions		(113	)								(113	)		(46	)		(159	)
Other comprehensive loss, net of tax								(22	)		(22	)		(1	)		(23	)
Other		(8	)								(8	)					(8	)
March 31, 2019	$	2,938		$	4,682		$	(191	)	$	7,429		$	1,432		$	8,861

December 31, 2019	$	—		$	9,031		$	(187	)	$	8,844		$	1,385		$	10,229
Net income					169						169			33			202
Dividends and distributions					(232	)					(232	)		(37	)		(269	)
Other comprehensive loss, net of tax								(84	)		(84	)					(84	)
March 31, 2020	$	—		$	8,968		$	(271	)	$	8,697		$	1,381		$	10,078

	Three Months Ended March 31, 2019⁽¹⁾
(millions, except EPS)
Operating Revenue	$	4,887
Net income attributable to Dominion Energy		605
Earnings Per Common Share – Basic	$	0.76
Earnings Per Common Share – Diluted	$	0.76

	Three Months Ended March 31, 2019
(millions)
Operating revenue	$	229
Depreciation and amortization		21
Other operating expenses		148
Other income		18
Interest and related charges		10
Income tax expense		14
Net income from discontinued operations	$	54

	Dominion Energy						Virginia Power						Dominion Energy Gas
Three Months Ended March 31,	2020			2019			2020			2019			2020				2019
U.S. statutory rate		21.0	%		21.0	%		21.0	%		21.0	%		21.0	%			21.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		4.4			2.2			4.8			4.6			2.9				3.4
Investment tax credits		(4.1	)		(1.5	)		(6.4	)		(3.2	)		—				—
Production tax credits		(0.4	)		(0.8	)		(0.8	)		(1.0	)		—				—
Reversal of excess deferred income taxes		(9.5	)		(5.1	)		(8.1	)		(5.0	)		(0.7	)			(0.7	)
Write-off of regulatory assets		—			(34.1	)		—			—			—				—
AFUDC - equity		(1.6	)		(1.4	)		(0.7	)		—			(0.4	)			(0.5	)
Other, net		(2.5	)		(0.6	)		0.3			0.1			(2.4	)	⁽¹⁾		(3.3	)	⁽¹⁾
Effective tax rate		7.3	%		(20.3	)%		10.1	%		16.5	%		20.4	%			19.9	%

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Unrecognized pension and other postretirement benefit costs			Other comprehensive loss from equity method investees			Total
(millions)
Three Months Ended March 31, 2020
Beginning balance	$	(407	)	$	37		$	(1,421	)	$	(2	)	$	(1,793	)
Other comprehensive income before reclassifications: gains (losses)		(266	)		9			—			—			(257	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		22			(9	)		19			—			32
Net current period other comprehensive income (loss)		(244	)		—			19			—			(225	)
Ending balance	$	(651	)	$	37		$	(1,402	)	$	(2	)	$	(2,018	)
Three Months Ended March 31, 2019
Beginning balance	$	(235	)	$	2		$	(1,465	)	$	(2	)	$	(1,700	)
Other comprehensive income before reclassifications: gains (losses)		(24	)		16			—			—			(8	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		(31	)		—			8			—			(23	)
Net current period other comprehensive income (loss)		(55	)		16			8			—			(31	)
Ending balance	$	(290	)	$	18		$	(1,457	)	$	(2	)	$	(1,731	)

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Three Months Ended March 31, 2020
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(7	)	Operating revenue
		3		Purchased gas
Interest rate contracts		27		Interest and related charges
Foreign currency contracts		6		Other income (expense)
Total		29
Tax		(7	)	Income tax expense (benefit)
Total, net of tax	$	22
Unrealized (gains) and losses on investment securities:
Realized (gains) losses on sale of securities	$	(13	)	Other income (expense)
Total		(13	)
Tax		4		Income tax expense (benefit)
Total, net of tax	$	(9	)
Unrecognized pension and other postretirement benefit costs:
Amortization of prior-service costs (credits)	$	(6	)	Other income (expense)
Amortization of actuarial losses		30		Other income (expense)
Total		24
Tax		(5	)	Income tax expense (benefit)
Total, net of tax	$	19
Three Months Ended March 31, 2019
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(54	)	Operating revenue
		(3	)	Purchased gas
Interest rate contracts		10		Interest and related charges
Foreign currency contracts		6		Other income (expense)
Total		(41	)
Tax		10		Income tax expense (benefit)
Total, net of tax	$	(31	)
Unrecognized pension and other postretirement benefit costs:
Amortization of prior-service costs (credits)	$	(5	)	Other income (expense)
Amortization of actuarial losses		27		Other income (expense)
Total		22
Tax		(14	)	Income tax expense (benefit)
Total, net of tax	$	8

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Total
(millions)
Three Months Ended March 31, 2020
Beginning balance	$	(34	)	$	5		$	(29	)
Other comprehensive income before reclassifications: gains (losses)		(45	)		(2	)		(47	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		—			1			1
Net current period other comprehensive income (loss)		(45	)		(1	)		(46	)
Ending balance	$	(79	)	$	4		$	(75	)
Three Months Ended March 31, 2019
Beginning balance	$	(13	)	$	1		$	(12	)
Other comprehensive income before reclassifications: gains (losses)		(7	)		2			(5	)
Amounts reclassified from AOCI: (gains) losses		—			—			—
Net current period other comprehensive income (loss)		(7	)		2			(5	)
Ending balance	$	(20	)	$	3		$	(17	)

	Deferred gains and losses on derivatives- hedging activities			Unrecognized pension costs			Total
(millions)
Three Months Ended March 31, 2020
Beginning balance	$	(81	)	$	(106	)	$	(187	)
Other comprehensive income before reclassifications: gains (losses)		(91	)		—			(91	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		6			1			7
Net current period other comprehensive income (loss)		(85	)		1			(84	)
Ending balance	$	(166	)	$	(105	)	$	(271	)
Three Months Ended March 31, 2019
Beginning balance	$	(25	)	$	(144	)	$	(169	)
Other comprehensive income before reclassifications: gains (losses)		(27	)		—			(27	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		3			1			4
Net current period other comprehensive income (loss)		(24	)		1			(23	)
Less other comprehensive income (loss) attributable to noncontrolling interest		(1	)		—			(1	)
Ending balance	$	(48	)	$	(143	)	$	(191	)

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average⁽¹⁾
Assets
Physical and financial forwards:
Natural gas⁽²⁾	$	48	Discounted cash flow	Market price (per Dth)	⁽³⁾	(2) - 3		(1	)
FTRs		1	Discounted cash flow	Market price (per MWh)	⁽³⁾	(1) - 2		—
Total assets	$	49
Liabilities
Financial forwards:
FTRs	$	4	Discounted cash flow	Market price (per MWh)	⁽³⁾	(2) - 2		—
Physical options:
Natural gas		2	Option model	Market price (per Dth)	⁽³⁾	1 - 2		1
				Price volatility	⁽⁴⁾	45% - 83%		57	%
Total liabilities	$	6

	Three Months Ended
	March 31,
	2020			2019
(millions)
Beginning balance	$	(37	)	$	64
Total realized and unrealized gains (losses):
Included in earnings:
Operating revenue		—			(1	)
Electric fuel and other energy-related purchases		(22	)		(4	)
Included in regulatory assets/liabilities		80			7
Settlements		22			(1	)
Purchases		—			(10	)
Transfers out of Level 3		—			(2	)
Ending balance	$	43		$	53

	March 31, 2020				December 31, 2019
	Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾
(millions)
Dominion Energy
Long-term debt⁽²⁾	$	32,984	$	35,685	$	32,055	$	36,155
Junior subordinated notes⁽³⁾		4,407		4,381		4,797		4,953
Virginia Power
Long-term debt⁽³⁾	$	12,327	$	13,998	$	12,326	$	14,281
Dominion Energy Gas
Long-term debt⁽⁴⁾	$	5,516	$	5,479	$	5,520	$	5,738

	March 31, 2020								December 31, 2019
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet⁽¹⁾		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet⁽¹⁾		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	55	$	3	$	—	$	52	$	35	$	21	$	—	$	14
Exchange		64		16		34		14		37		21		—		16
Interest rate contracts:
Over-the-counter		29		21		—		8		11		3		—		8
Foreign currency contracts:
Over-the-counter		—		—		—		—		8		8		—		—
Total derivatives, subject to a master netting or similar arrangement	$	148	$	40	$	34	$	74	$	91	$	53	$	—	$	38

	Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		81		36
Basis		268		574
Electricity (MWh):
Fixed price		3,088,875		—
FTRs		18,836,472		—
Liquids (Gal)⁽²⁾		39,690,000		—
Interest rate⁽³⁾	$	2,450,000,000	$	5,582,850,761
Foreign currency⁽³⁾	€	-	€	250,000,000

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(2	)	$	(2	)	21 months
Electricity		14			14		9 months
NGL		1			1		9 months
Interest rate		(655	)		(50	)	381 months
Foreign currency		(9	)		(1	)	75 months
Total	$	(651	)	$	(38	)

	Carrying Amount of the Hedged Asset (Liability)⁽¹⁾						Cumulative Amount of Fair Value Hedging Adjustments Included in the Carrying Amount of the Hedged Assets (Liabilities)⁽²⁾
	March 31, 2020			December 31, 2019			March 31, 2020			December 31, 2019
(millions)
Long-term debt	$	(1,154	)	$	(1,154	)	$	(4	)	$	(4	)

	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
March 31, 2020
ASSETS
Current Assets
Commodity	$	—	$	80	$	80
Interest rate		—		11		11
Total current derivative assets⁽¹⁾		—		91		91
Noncurrent Assets
Commodity		—		41		41
Interest rate		—		18		18
Total noncurrent derivative assets⁽²⁾		—		59		59
Total derivative assets	$	—	$	150	$	150
LIABILITIES
Current Liabilities
Commodity	$	—	$	45	$	45
Interest rate		515		232		747
Foreign currency		1		—		1
Total current derivative liabilities		516		277		793
Noncurrent Liabilities
Commodity		—		4		4
Interest rate		722		111		833
Foreign currency		16		—		16
Total noncurrent derivative liabilities		738		115		853
Total derivative liabilities	$	1,254	$	392	$	1,646
December 31, 2019
ASSETS
Current Assets
Commodity	$	30	$	37	$	67
Interest rate		1		—		1
Total current derivative assets⁽¹⁾		31		37		68
Noncurrent Assets
Commodity		1		6		7
Interest rate		10		—		10
Foreign currency		8		—		8
Total noncurrent derivative assets⁽²⁾		19		6		25
Total derivative assets	$	50	$	43	$	93
LIABILITIES
Current Liabilities
Commodity	$	6	$	77	$	83
Interest rate		321		1		322
Foreign currency		3		—		3
Total current derivative liabilities		330		78		408
Noncurrent Liabilities
Commodity		1		47		48
Interest rate		267		17		284
Total noncurrent derivative liabilities		268		64		332
Total derivative liabilities	$	598	$	142	$	740

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives⁽¹⁾			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Three Months Ended March 31, 2020
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	7
Purchased gas					(3	)
Total commodity	$	—		$	4		$	—
Interest rate⁽³⁾		(336	)		(27	)		(563	)
Foreign currency⁽⁴⁾		(23	)		(6	)		—
Total	$	(359	)	$	(29	)	$	(563	)
Three Months Ended March 31, 2019
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	54
Purchased gas					3
Total commodity	$	66		$	57		$	—
Interest rate⁽³⁾		(84	)		(10	)		(84	)
Foreign currency⁽⁴⁾		(11	)		(6	)		—
Total	$	(29	)	$	41		$	(84	)

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾
	Three Months Ended
	March 31,
	2020			2019
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	65		$	3
Purchased gas		(14	)		3
Electric fuel and other energy-related purchases		(65	)		(9	)
Interest rate⁽²⁾		(61	)		—
Total	$	(75	)	$	(3	)

	Current		Noncurrent
Interest rate⁽¹⁾	$	250,000,000	$	1,050,000,000
Foreign currency⁽¹⁾	€	-	€	250,000,000

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(157	)	$	(11	)	297 months
Foreign currency		(9	)		(1	)	75 months
Total	$	(166	)	$	(12	)

	Fair Value- Derivatives Under Hedge Accounting		Fair Value-Derivatives Not Under Hedge Accounting		Total Fair Value
(millions)
March 31, 2020
LIABILITIES
Current Liabilities
Interest rate	$	57	$	11	$	68
Foreign currency		1		—		1
Total current derivative liabilities⁽²⁾		58		11		69
Noncurrent Liabilities
Interest rate		119		3		122
Foreign currency		16		—		16
Total noncurrent derivative liabilities⁽³⁾		135		3		138
Total derivative liabilities	$	193	$	14	$	207
December 31, 2019
ASSETS
Noncurrent Assets
Foreign currency	$	8	$	—	$	8
Total noncurrent derivative assets⁽¹⁾		8		—		8
Total derivative assets	$	8	$	—	$	8
LIABILITIES
Current Liabilities
Interest rate	$	30	$	—	$	30
Foreign currency		3		—		3
Total current derivative liabilities⁽²⁾		33		—		33
Noncurrent Liabilities
Interest rate		53		—		53
Total noncurrent derivative liabilities⁽³⁾		53		—		53
Total derivative liabilities	$	86	$	—	$	86

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives⁽¹⁾			Amount of Gain (Loss) Reclassified From AOCI to Income
(millions)
Three Months Ended March 31, 2020
Derivative Type and Location of Gains (Losses):
Interest rate⁽²⁾	$	(100	)	$	(2	)
Foreign currency⁽³⁾		(23	)		(6	)
Total	$	(123	)	$	(8	)
Three Months Ended March 31, 2019
Derivative Type and Location of Gains (Losses):
Commodity:
Net income from discontinued operations				$	2
Total commodity	$	(1	)	$	2
Interest rate⁽²⁾		(24	)		1
Foreign currency⁽³⁾		(11	)		(6	)
Total	$	(36	)	$	(3	)

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives
	Three Months Ended
	March 31,
	2020			2019
(millions)
Derivative type and location of gains (losses):
Interest rate⁽¹⁾	$	(8	)	$	—
Total	$	(8	)	$	—

	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses				Allowance for Credit Losses			Fair Value
(millions)
March 31, 2020
Equity securities:⁽¹⁾
U.S.	$	1,813	$	1,709	$	(161	)		$	—		$	3,361
Fixed income securities:⁽²⁾
Corporate debt instruments		491		18		—				(13	)		496
Government securities		1,084		55		—				(6	)		1,133
Common/collective trust funds		118		2		—				(2	)		118
Insurance contracts		209		—		—				—			209
Cash equivalents and other⁽³⁾		—		—		(4	)			—			(4	)
Total	$	3,715	$	1,784	$	(165	)	⁽⁴⁾	$	(21	)	$	5,313
December 31, 2019
Equity securities:⁽¹⁾
U.S.	$	1,807	$	2,451	$	(20	)		$	—		$	4,238
Fixed income securities:⁽²⁾
Corporate debt instruments		434		29		—				—			463
Government securities		1,108		39		(2	)			—			1,145
Common/collective trust funds		115		4		—				—			119
Insurance contracts		214		—		—				—			214
Cash equivalents and other⁽³⁾		13		—		—				—			13
Total	$	3,691	$	2,523	$	(22	)	⁽⁴⁾	$	—		$	6,192

	Amount
(millions)
Due in one year or less	$	178
Due after one year through five years		430
Due after five years through ten years		389
Due after ten years		750
Total	$	1,747