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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

☒

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2020

2021

or

☐

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

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

State or other jurisdiction of incorporation or organization of the registrants: Virginia

Securities registered pursuant______ to Section 12(b) of the Act:

_______

Exact name of registrant as specified in its charter
State or other jurisdiction of incorporation or organization
CommissionAddress of principal executive officesIRS Employer
File NumberRegistrant's telephone number, including area codeIdentification No.
001-14881BERKSHIRE HATHAWAY ENERGY COMPANY94-2213782
(An Iowa Corporation)
666 Grand Avenue, Suite 500
Des Moines, Iowa 50309-2580
515-242-4300
001-05152PACIFICORP93-0246090
(An Oregon Corporation)
825 N.E. Multnomah Street
Portland, Oregon 97232
888-221-7070
333-90553MIDAMERICAN FUNDING, LLC47-0819200
(An Iowa Limited Liability Company)
666 Grand Avenue, Suite 500
Des Moines, Iowa 50309-2580
515-242-4300
333-15387MIDAMERICAN ENERGY COMPANY42-1425214
(An Iowa Corporation)
666 Grand Avenue, Suite 500
Des Moines, Iowa 50309-2580
515-242-4300
000-52378NEVADA POWER COMPANY88-0420104
(A Nevada Corporation)
6226 West Sahara Avenue
Las Vegas, Nevada 89146
702-402-5000
000-00508SIERRA PACIFIC POWER COMPANY88-0044418
(A Nevada Corporation)
6100 Neil Road
Reno, Nevada 89511
775-834-4011
001-37591EASTERN ENERGY GAS HOLDINGS, LLC46-3639580
(A Virginia Limited Liability Company)
6603 West Broad Street
Richmond, Virginia 23230
804-613-5100
N/A
(Former name or former address, if changed from last report)


Registrant

Trading SymbolSecurities registered pursuant to Section 12(b) of the Act:

BERKSHIRE HATHAWAY ENERGY COMPANY

Title of Each ClassNone

PACIFICORP

None

MIDAMERICAN FUNDING, LLCNone
MIDAMERICAN ENERGY COMPANYNone
NEVADA POWER COMPANYNone
SIERRA PACIFIC POWER COMPANYNone
EASTERN ENERGY GAS HOLDINGS, LLCNone
RegistrantName of Each Exchange

exchange on Which Registeredwhich registered:

DOMINIONBERKSHIRE 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

MIDAMERICAN FUNDING, LLC

DCUE

2019 Series A Corporate Units

New York Stock Exchange

None

DOMINIONMIDAMERICAN ENERGY COMPANY

None
NEVADA POWER COMPANYNone
SIERRA PACIFIC POWER COMPANYNone
EASTERN ENERGY GAS

HOLDINGS, LLC

2014 Series C 4.6% Senior Notes

New York Stock Exchange

None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Dominion Energy, Inc.    Yes  

RegistrantYesNo
BERKSHIRE HATHAWAY ENERGY COMPANY☒
PACIFICORP☒
MIDAMERICAN FUNDING, LLC☒
MIDAMERICAN ENERGY COMPANY☒
NEVADA POWER COMPANY☒
SIERRA PACIFIC POWER COMPANY☒
EASTERN ENERGY GAS HOLDINGS, LLC☒
☒    No  ☐             Virginia Electric and Power Company    Yes  ☒    No  ☐

Dominion Energy Gas Holdings, LLC    Yes  ☒    No  ☐

Indicate by check mark whether the registrant hasregistrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant wasregistrants were required to submit such files).

Dominion Energy, Inc. Yes  ☒x  No  ☐o             Virginia Electric and Power Company    Yes  ☒    No  ☐

Dominion Energy Gas Holdings, LLC    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large"large accelerated filer,” “accelerated" "accelerated filer,” “non-accelerated filer,” “smaller" "smaller reporting company,”" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Dominion Energy, Inc.

RegistrantLarge accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

Smaller reporting company

Emerging growth company

☐

Non-accelerated filer

BERKSHIRE HATHAWAY ENERGY COMPANY

☐

☐

Smaller reporting company

☒

☐

☐
PACIFICORP

☐		☐☒☐☐
MIDAMERICAN FUNDING, LLC☐☐☒☐☐
MIDAMERICAN ENERGY COMPANY☐☐☒☐☐
NEVADA POWER COMPANY☐☐☒☐☐
SIERRA PACIFIC POWER COMPANY☐☐☒☐☐
EASTERN ENERGY GAS HOLDINGS, LLC☐☐☒☐☐

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

Virginia Electric and Power Company

Large accelerated filer

☐

Accelerated filer

☐

Emerging growth company

☐

Non-accelerated filer

☒

Smaller reporting company

☐


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.  

☐

Dominion Energy Gas Holdings, LLC

Large accelerated filer

☐

Accelerated filer

☐

Emerging growth company

☐

Non-accelerated filer

☒

Smaller reporting company

☐

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 isregistrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).

Dominion

Yes  ☐  No  x
All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of August 5, 2021, 76,368,874 shares of common stock, no par value, were outstanding.
All shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of August 5, 2021, 357,060,915 shares of common stock, no par value, were outstanding.
All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of August 5, 2021.
All shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of August 5, 2021, 70,980,203 shares of common stock, no par value, were outstanding.
All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of August 5, 2021, 1,000 shares of common stock, $1.00 stated value, were outstanding.
All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. Yes  ☐    No  ☒             Virginia Electric and Power Company    Yes  ☐    No  ☒

DominionAs of August 5, 2021, 1,000 shares of common stock, $3.75 par value, were outstanding.

All of the member's equity of Eastern Energy Gas Holdings, LLC Yes  ☐    No  ☒

At July 17, 2020, the latest practicable date for determination, Dominionis held indirectly by its parent company, Berkshire Hathaway Energy Inc. had 840,135,854 sharesCompany, as of common stock outstanding and Virginia Electric and Power Company had 274,723 shares of common stock outstanding. Dominion Energy, Inc. is the sole holder of Virginia Electric and Power Company’s common stock. Dominion Energy, Inc. holds all of the membership interests of Dominion Energy Gas Holdings, LLC.

August 5, 2021.

This combined Form 10-Q represents separate filingsis separately filed by DominionBerkshire Hathaway Energy Inc., Virginia Electric andCompany, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company and DominionEastern Energy Gas Holdings, LLC. Information contained herein relating to anany individual registrantcompany is filed by that registrantsuch company on its own behalf. Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC makeEach company makes no representationsrepresentation as to the information relating to Dominion Energy, Inc.’sthe other operations.

VIRGINIA ELECTRIC AND POWER COMPANY AND DOMINION ENERGY GAS HOLDINGS, LLC MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b)companies.




TABLE OF FORM 10-Q AND ARE FILING THIS FORM 10-Q UNDER THE REDUCED DISCLOSURE FORMAT.

COMBINED INDEX

CONTENTS
PART I

Page

Number

3

1

9

Item 1.

Financial Statements

9

Item 2.

105

2

124

180

125

180
PART II

181

126

181

Item 1.

126

Item 1A.

Risk Factors

126

Item 2.

126

181

128

181

182
182
182
186



GLOSSARY OF TERMS

The following abbreviations or acronyms

i

Definition of Abbreviations and Industry Terms

When used in this Form 10-Q are defined below:

Forward-Looking Statements, Part I - Items 2 through 3, and Part II - Items 1 through 6, the following terms have the definitions indicated.

Abbreviation or Acronym

Definition

2016 Equity Units

Dominion Energy’s 2016 Series A Equity Units issued in August 2016, initially in the form of 2016 Series A Corporate Units, consisting of a stock purchase contract and a 1/40 interest in RSNs issued by Dominion Energy

2019 Equity Units

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

2017 Tax Reform Act

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

ACE Rule

Affordable Clean Energy Rule

AFUDC

Allowance for funds used during construction

Align RNG

Align RNG, LLC, a joint venture between Dominion Energy and Smithfield Foods, Inc.

Altavista

Altavista biomass power station

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 Energy

Atlantic Coast Pipeline Project

A previously proposed approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which would have been owned by Dominion Energy and Duke Energy and constructed and operated by DETI

BACT

Best available control technology

bcf

Billion cubic feet

Bear Garden

A 590 MW combined-cycle, natural gas-fired power station in Buckingham County, Virginia

BHE

Berkshire Hathaway Energy Company

and Related Entities

Blue Racer

BHE

Blue Racer Midstream, LLC, a joint venture between CaimanBerkshire Hathaway Energy II, LLC and FR BR Holdings, LLC

Company

BP

Berkshire Hathaway

BP Wind Energy North AmericaBerkshire Hathaway Inc.

Brookfield

Berkshire Hathaway Energy or the Company

Brookfield Super-Core Infrastructure Partners, an infrastructure fund managed by Brookfield Asset Management Inc.

Berkshire Hathaway Energy Company and its subsidiaries

Brunswick County

PacifiCorp

A 1,376 MW combined-cycle, natural gas-fired power station in Brunswick County, Virginia

PacifiCorp and its subsidiaries

CAA

MidAmerican Funding

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

CWA

Clean Water Act

DCP

The legal entity, Dominion Cove Point, LLC, one or more of its consolidated subsidiaries, or the entirety of Dominion Cove Point,MidAmerican Funding, LLC and its consolidated subsidiaries

DECG

MidAmerican Energy

DominionMidAmerican 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 DominionNV Energy, Inc. and its consolidated subsidiaries

DominionNevada Power

Nevada Power Company and its subsidiaries
Sierra PacificSierra Pacific Power Company and its subsidiaries
Nevada UtilitiesNevada 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 DominionEastern Energy Gas Holdings, LLC and its consolidated subsidiaries

DominionRegistrants

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 GroupBHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE GT&SBHE GT&S, LLC
Northern Natural GasNorthern Natural Gas Company
Kern RiverKern River Gas Transmission Company
BHE TransmissionBHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE CanadaBHE Canada Holdings Corporation
AltaLinkAltaLink, L.P.
BHE U.S. TransmissionBHE U.S. Transmission, LLC
BHE RenewablesBHE Renewables, LLC and CalEnergy Philippines
HomeServicesHomeServices of America, Inc. and its subsidiaries
UtilitiesPacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Domestic Regulated BusinessesPacifiCorp 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
EGTSEastern Gas Transmission and Storage, Inc.
GT&S TransactionThe acquisition of DCPsubstantially 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 entiretystorage 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, or the entirety of Group

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 Energy

The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries, or the entirety of Duke Energy Corporation and its consolidated subsidiaries


ii

East Ohio

The East Ohio Gas Company, doing business as Dominion Energy Ohio

EPA

Certain Industry Terms

U.S.

2017 Tax ReformThe Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018
AFUDCAllowance for Funds Used During Construction
AUCAlberta Utilities Commission
BARTBest Available Retrofit Technology
COVID-19Coronavirus Disease 2019
CSAPRCross-State Air Pollution Rule
CPSTCustomer Price Stability Tariff
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
DthDecatherm
ECAMEnergy Cost Adjustment Mechanism
EPAUnited 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

FIP

Fee in lieu of taxes

Federal Implementation Plan

Four Brothers

Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy and Four Brothers Holdings, LLC, a subsidiary of GIP

Fowler Ridge

GAAP

Fowler I Holdings LLC, a wind-turbine facility joint venture with BPAccounting principles generally accepted in Benton County, Indiana

the United States of America

FTRs

GEMA

Financial transmission rights

Gas and Electricity Markets Authority

GAAP

GHG

U.S. generally accepted accounting principles

Greenhouse Gases

Gal

GWh

Gallon

Gigawatt Hour

Gas Distribution

GTA

Gas Distribution operating segment

General Tariff Application

Gas Transmission &   Storage

IPUC

Gas Transmission & Storage operating segment

Idaho Public Utilities Commission

GENCO

South Carolina Generating Company, Inc.

GHG

IRP

Greenhouse gas

Integrated Resource Plan

GIP

IUB

The legal entity, Global Infrastructure Partners, one or more of its consolidated subsidiaries, or the entirety of Global Infrastructure Partners and its consolidated subsidiaries

Iowa Utilities Board

Granite Mountain

kV

Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy and Granite Mountain Renewables, LLC, a subsidiary of GIP

Kilovolt

Grassfield Solar

A proposed 20 MW utility-scale solar power station located in Chesapeake, Virginia

Greensville County

A 1,588 MW combined-cycle, natural gas-fired power station in Greensville County, Virginia

GTSA

MW

Virginia Grid Transformation and Security Act of 2018

Megawatt

GW

MWh

Gigawatt

Megawatt Hour

Heating degree days

NAAQS

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

National Ambient Air Quality Standards

Hope

NOx

Hope Gas, Inc., doing business as Dominion Energy West Virginia

Nitrogen Oxides

Hopewell

Polyester biomass power station

Iron Springs

Ofgem

Iron Springs Holdings, LLC, a limited liability company owned by Dominion EnergyOffice of Gas and Iron Springs Renewables, LLC, a subsidiary of GIP

Electric Markets

Iroquois

OPUC

Iroquois Gas Transmission System, L.P.

Oregon Public Utility Commission

ISO

PTC

Independent system operator

Production Tax Credit

JAX LNG

PUCN

JAX LNG, LLC, an LNG supplier in Florida serving the marine and LNG markets

June 2006 hybrids

Dominion Energy’s 2006 Series A Enhanced Junior Subordinated Notes due 2066

Kewaunee

Kewaunee nuclear power station

kV

Kilovolt

Liquefaction Facility

A natural gas export/liquefaction facility at the Cove Point LNG Facility

LNG

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

Norge Solar

A proposed 20 MW utility-scale solar power station located in James City County, Virginia

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 Corps 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

Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development

Overthrust

REC

DominionRenewable Energy Overthrust Pipeline, L.L.C.

Credit

PIR

RFP

Pipeline Infrastructure Replacement program deployed by East Ohio

Request for Proposal

PJM

RPS

PJM Interconnection, L.L.C.

Renewable Portfolio Standards

Predecessor

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

PREP

SCR

Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure deployed by Hope

Selective Catalytic Reduction

PSD

SEC

Prevention of significant deterioration

PSNC

Public Service Company of North Carolina, Incorporated, doing business as Dominion Energy North Carolina

Questar Gas

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 B

A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass

Rider BW

A rate adjustment clause associated with the recovery of costs related to Brunswick County

Rider GV

A rate adjustment clause associated with the recovery of costs related to Greensville County


Rider R

A rate adjustment clause associated with the recovery of costs related to Bear Garden

Rider S

A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center

Rider T1

A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates and the new total revenue requirement developed annually for the rate years effective September 1

Rider U

A rate adjustment clause associated with the recovery of costs of new underground distribution facilities

Rider US-2

A rate adjustment clause associated with the recovery of costs related to Woodland Solar, Scott Solar and Whitehouse Solar 

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

Rider W

A rate adjustment clause associated with the recovery of costs related to Warren County

Riders C1A, C2A and C3A

Rate adjustment clauses associated with the recovery of cost related to certain DSM programs approved in DSM cases

ROE

Return on equity

RSN

Remarketable subordinated note

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

Scott Solar

A 17 MW utility-scale solar power station in Powhatan County, Virginia

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 SCANAState Implementation Plan through December 2019, and effective December 2019, a subsidiary of Wrangler

September 2006 hybrids

SO2

Dominion Energy’s 2006 Series B Enhanced Junior Subordinated Notes due 2066

Sulfur Dioxide

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

UPSC

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

Utah Public Service Commission of South Carolina

Southampton

WPSC

Southampton biomass power station

Wyoming Public Service Commission

Southern

WUTC

The legal entity, The Southern Company, one or more of its consolidated subsidiaries, or the entirety of The SouthernWashington 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;
iv

•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;
•unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;
•the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
•the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and
•other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.

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

v

Item 1.Financial Statements
Berkshire Hathaway Energy Company and its consolidated subsidiaries


Spring Grove 1

An approximately 98 MW proposed utility-scale solar power station located in Surry County, Virginia

Standard & Poor’s

Report of Independent Registered Public Accounting Firm

Standard & Poor’s Ratings Services, a division of S&P Global Inc.

4

Summer

Consolidated Balance Sheets

V.C. Summer nuclear power station

5

Supply Header Project

Consolidated Statements of Operations

A project previously intended for DETI to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline Project

7

Surry

Consolidated Statements of Comprehensive Income

Surry nuclear power station

8

Sycamore Solar

Consolidated Statements of Changes in Equity

A proposed 42 MW utility-scale solar power station located in Pittsylvania County, Virginia

9

Terra Nova Renewable Partners

Consolidated Statements of Cash Flows

A partnership comprised primarily of institutional investors advised by J.P. Morgan Asset Management-Global Real Assets

10

Three Cedars

Notes to Consolidated Financial Statements

Granite Mountain and Iron Springs, collectively

11

Utah Commission

PacifiCorp and its subsidiaries

Utah Public Service Commission

VCEA

Report of Independent Registered Public Accounting Firm

Virginia Clean Economy Act, passed by the Virginia General Assembly in March 2020 and enacted on April 11, 2020

56

VDEQ

Consolidated Balance Sheets

Virginia Department of Environmental Quality

57

VEBA

Consolidated Statements of Operations

Voluntary Employees’ Beneficiary Association

59

VIE

Consolidated Statements of Changes in Shareholders' Equity

Variable interest entity

60

Virginia City Hybrid Energy Center

Consolidated Statements of Cash Flows

A 610 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia

61

Virginia Commission

Notes to Consolidated Financial Statements

Virginia State Corporation Commission

62

Virginia Power

MidAmerican Energy Company

The legal entity, Virginia Electric

Report of Independent Registered Public Accounting Firm
81
Balance Sheets
82
Statements of Operations
84
Statements of Changes in Shareholder's Equity
85
Statements of Cash Flows
86
Notes to Financial Statements
87
MidAmerican Funding, LLC and Power Company, one or moreits subsidiaries
Report of its consolidated subsidiaries or operating segment, or the entiretyIndependent Registered Public Accounting Firm
96
Consolidated Balance Sheets
97
Consolidated Statements of Virginia Electric andOperations
99
Consolidated Statements of Changes in Member's Equity
100
Consolidated Statements of Cash Flows
101
Notes to Consolidated Financial Statements
102
Nevada Power Company and its consolidated subsidiaries

VOC

Report of Independent Registered Public Accounting Firm

Volatile organic compounds

118

Warren County

Consolidated Balance Sheets

A 1,350 MW combined-cycle, natural gas-fired power station in Warren County, Virginia

119

WECTEC

Consolidated Statements of Operations

WECTEC Global Project Services, Inc., a wholly-owned subsidiary of Westinghouse

120

West Virginia Commission

Consolidated Statements of Changes in Shareholder's Equity

Public Service Commission of West Virginia

121

Westinghouse

Consolidated Statements of Cash Flows

Westinghouse Electric Company LLC

122

Wexpro

Notes to Consolidated Financial Statements

The legal entity, Wexpro Company, one or more of its consolidated subsidiaries, or the entirety of Wexpro

123
Sierra Pacific Power Company and its consolidated subsidiaries

Whitehouse Solar

Report of Independent Registered Public Accounting Firm

A 20 MW utility-scale solar power station in Louisa County, Virginia

137

White River Hub

Consolidated Balance Sheets

White River Hub, LLC

138

Woodland Solar

Consolidated Statements of Operations

A 19 MW utility-scale solar power station in Isle of Wight County, Virginia

139

Wrangler

Consolidated Statements of Changes in Shareholder's Equity

Wrangler Retail

140
Consolidated Statements of Cash Flows
141
Notes to Consolidated Financial Statements
142
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

157

Consolidated Balance Sheets

158

Consolidated Statements of Operations

160

Consolidated Statements of Comprehensive Income

161

Consolidated Statements of Changes in Equity

162

Consolidated Statements of Cash Flows

163

Notes to Consolidated Financial Statements

164



PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOMINION ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenue(1)

 

$

3,585

 

 

$

3,970

 

 

$

8,081

 

 

$

7,828

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric fuel and other energy-related purchases

 

 

505

 

 

 

718

 

 

 

1,173

 

 

 

1,509

 

Purchased electric capacity

 

 

11

 

 

 

24

 

 

 

13

 

 

 

63

 

Purchased gas

 

 

74

 

 

 

227

 

 

 

501

 

 

 

957

 

Other operations and maintenance

 

 

995

 

 

 

1,283

 

 

 

2,038

 

 

 

2,285

 

Depreciation, depletion and amortization

 

 

673

 

 

 

661

 

 

 

1,346

 

 

 

1,312

 

Other taxes

 

 

256

 

 

 

284

 

 

 

540

 

 

 

576

 

Impairment of assets and other charges

 

 

531

 

 

 

312

 

 

 

1,299

 

 

 

1,147

 

Total operating expenses

 

 

3,045

 

 

 

3,509

 

 

 

6,910

 

 

 

7,849

 

Income (loss) from operations

 

 

540

 

 

 

461

 

 

 

1,171

 

 

 

(21

)

Earnings (loss) from equity method investees

 

 

(2,281

)

 

 

39

 

 

 

(2,228

)

 

 

80

 

Other income

 

 

502

 

 

 

53

 

 

 

50

 

 

 

400

 

Interest and related charges

 

 

449

 

 

 

452

 

 

 

939

 

 

 

921

 

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

 

 

(1,688

)

 

 

101

 

 

 

(1,946

)

 

 

(462

)

Income tax expense (benefit)

 

 

(556

)

 

 

43

 

 

 

(575

)

 

 

157

 

Net Income (Loss) Including Noncontrolling Interests

 

 

(1,132

)

 

 

58

 

 

 

(1,371

)

 

 

(619

)

Noncontrolling Interests

 

 

37

 

 

 

4

 

 

 

68

 

 

 

7

 

Net Income (Loss) Attributable to Dominion Energy

 

$

(1,169

)

 

$

54

 

 

$

(1,439

)

 

$

(626

)

Earnings Per Common Share

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) attributable to Dominion Energy - Basic

 

$

(1.41

)

 

$

0.07

 

 

$

(1.75

)

 

$

(0.78

)

Net Income (Loss) attributable to Dominion Energy - Diluted

 

 

(1.41

)

 

 

0.05

 

 

 

(1.75

)

 

 

(0.78

)


1

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

(1)

See Note 10 for amounts attributable to related parties.

31
72
106
129
149
176



2

Berkshire Hathaway Energy Company and its subsidiaries
Consolidated Financial Section

3

PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of June 30, 2021, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 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
August 6, 2021
4

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)

 As of
 June 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$1,331 $1,290 
Restricted cash and cash equivalents154 140 
Trade receivables, net2,479 2,107 
Inventories1,113 1,168 
Mortgage loans held for sale2,082 2,001 
Amounts held in trust587 318 
Other current assets2,496 2,423 
Total current assets10,242 9,447 
   
Property, plant and equipment, net87,622 86,128 
Goodwill11,570 11,506 
Regulatory assets3,344 3,157 
Investments and restricted cash and cash equivalents and investments14,960 14,320 
Other assets2,823 2,758 
  
Total assets$130,561 $127,316 

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

these consolidated financial statements.


5
DOMINION
BERKSHIRE HATHAWAY ENERGY INC.

COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

BALANCE SHEETS (Unaudited)

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) including noncontrolling interests

 

$

(1,132

)

 

$

58

 

 

$

(1,371

)

 

$

(619

)

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net deferred gains (losses) on derivatives-hedging activities(1)

 

 

2

 

 

 

(78

)

 

 

(264

)

 

 

(102

)

Changes in unrealized net gains (losses) on investment

   securities(2)

 

 

19

 

 

 

13

 

 

 

28

 

 

 

29

 

Changes in net unrecognized pension and other postretirement

   benefit costs(3)

 

 

(1

)

 

 

113

 

 

 

(1

)

 

 

113

 

Amounts reclassified to net income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net derivative (gains) losses-hedging activities(4)

 

 

5

 

 

 

(21

)

 

 

27

 

 

 

(52

)

Net realized (gains) losses on investment securities(5)

 

 

(5

)

 

 

(1

)

 

 

(14

)

 

 

(1

)

Net pension and other postretirement benefit costs(6)

 

 

18

 

 

 

22

 

 

 

37

 

 

 

30

 

Total other comprehensive income (loss)

 

 

38

 

 

 

48

 

 

 

(187

)

 

 

17

 

Comprehensive income (loss) including noncontrolling interests

 

 

(1,094

)

 

 

106

 

 

 

(1,558

)

 

 

(602

)

Comprehensive income attributable to noncontrolling interests

 

 

37

 

 

 

4

 

 

 

68

 

 

 

7

 

Comprehensive income (loss) attributable to Dominion Energy

 

$

(1,131

)

 

$

102

 

 

$

(1,626

)

 

$

(609

)

(1)

Net of $(4) million and $27 million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $89 million and $32 million tax for the six months ended June 30, 2020 and 2019, respectively.

(continued)

(2)

Net of $(6) million and $(5) million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $(10) million and $(11) million tax for the six months ended June 30, 2020 and 2019, respectively.

(Amounts in millions)

(3)


Net of $3 million and $(49) million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $3 million and $(49) million tax for the six months ended June 30, 2020 and 2019 respectively
 As of
 June 30,December 31,
20212020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$1,802 $1,867 
Accrued interest549 555 
Accrued property, income and other taxes711 582 
Accrued employee expenses457 383 
Short-term debt2,536 2,286 
Current portion of long-term debt918 1,839 
Other current liabilities2,107 1,626 
Total current liabilities9,080 9,138 
  
BHE senior debt13,000 12,997 
BHE junior subordinated debentures100 100 
Subsidiary debt34,855 34,930 
Regulatory liabilities7,344 7,221 
Deferred income taxes12,464 11,775 
Other long-term liabilities4,353 4,178 
Total liabilities81,196 80,339 
   
Commitments and contingencies (Note 9)00
   
Equity:  
BHE shareholders' equity:  
Preferred stock - 100 shares authorized, $0.01 par value, 4 shares issued and outstanding3,750 3,750 
Common stock - 115 shares authorized, 0 par value, 76 shares issued and outstanding0 0 
Additional paid-in capital6,377 6,377 
Long-term income tax receivable(658)(658)
Retained earnings37,303 35,093 
Accumulated other comprehensive loss, net(1,360)(1,552)
Total BHE shareholders' equity45,412 43,010 
Noncontrolling interests3,953 3,967 
Total equity49,365 46,977 
  
Total liabilities and equity$130,561 $127,316 
.

(4)Net of $(2) million and $8 million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $(9) million and $18 million tax for the six months ended June 30, 2020 and 2019, respectively.

(5)Net of $— million and $— million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $4 million and $— million tax for the six months ended June 30, 2020 and 2019, respectively.

(6)Net of $(8) million and $3 million tax for the three months ended June 30, 2020 and 2019 respectively, and net of $(13) million and $(11) million tax for the six months ended June 30, 2020 and 2019, respectively.

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

these consolidated financial statements.


6
DOMINION
BERKSHIRE HATHAWAY ENERGY INC.

COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

STATEMENTS OF OPERATIONS (Unaudited)

 

 

June 30, 2020

 

 

December 31, 2019(1)

 

(millions)

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

675

 

 

$

166

 

Customer receivables (less allowance for doubtful accounts of $44 and $20)

 

 

2,040

 

 

 

2,278

 

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

 

 

233

 

 

 

367

 

Inventories

 

 

1,735

 

 

 

1,742

 

Prepayments

 

 

589

 

 

 

328

 

Regulatory assets

 

 

616

 

 

 

879

 

Other

 

 

236

 

 

 

328

 

Total current assets

 

 

6,124

 

 

 

6,088

 

Investments

 

 

 

 

 

 

 

 

Nuclear decommissioning trust funds

 

 

6,018

 

 

 

6,192

 

Investment in equity method affiliates

 

 

584

 

 

 

1,646

 

Other

 

 

382

 

 

 

379

 

Total investments

 

 

6,984

 

 

 

8,217

 

Property, Plant and Equipment

 

 

 

 

 

 

 

 

Property, plant and equipment

 

 

96,527

 

 

 

97,466

 

Accumulated depreciation, depletion and amortization

 

 

(28,547

)

 

 

(28,384

)

Total property, plant and equipment, net

 

 

67,980

 

 

 

69,082

 

Deferred Charges and Other Assets

 

 

 

 

 

 

 

 

Goodwill

 

 

8,946

 

 

 

8,946

 

Regulatory assets

 

 

9,438

 

 

 

7,687

 

Other

 

 

4,256

 

 

 

3,803

 

Total deferred charges and other assets

 

 

22,640

 

 

 

20,436

 

Total assets

 

$

103,728

 

 

$

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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
 2021202020212020
Operating revenue:
Energy$4,301 $3,419 $9,150 $7,053 
Real estate1,763 1,193 2,995 2,086 
Total operating revenue6,064 4,612 12,145 9,139 
    
Operating expenses:   
Energy:   
Cost of sales1,110 888 2,679 1,926 
Operations and maintenance1,037 794 1,971 1,531 
Depreciation and amortization936 725 1,851 1,534 
Property and other taxes189 153 399 304 
Real estate1,584 1,116 2,704 1,989 
Total operating expenses4,856 3,676 9,604 7,284 
     
Operating income1,208 936 2,541 1,855 
    
Other income (expense):   
Interest expense(532)(503)(1,062)(986)
Capitalized interest14 19 28 36 
Allowance for equity funds30 38 56 72 
Interest and dividend income26 20 47 40 
Gains on marketable securities, net1,966 583 848 610 
Other, net48 52 56 25 
Total other income (expense)1,552 209 (27)(203)
    
Income before income tax expense (benefit) and equity loss2,760 1,145 2,514 1,652 
Income tax expense (benefit)327 (7)(208)(191)
Equity loss(50)(32)(229)(50)
Net income2,383 1,120 2,493 1,793 
Net income attributable to noncontrolling interests102 4 208 7 
Net income attributable to BHE shareholders2,281 1,116 2,285 1,786 
Preferred dividends37 0 75 0 
Earnings on common shares$2,244 $1,116 $2,210 $1,786 

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

these consolidated financial statements.

7
DOMINION
BERKSHIRE HATHAWAY ENERGY INC.

COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS—(Continued)

STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

 

 

June 30, 2020

 

 

December 31, 2019(1)

 

(millions)

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

Securities due within one year

 

$

2,799

 

 

$

3,162

 

Supplemental 364-Day credit facility borrowings

 

 

225

 

 

 

—

 

Short-term debt

 

 

386

 

 

 

911

 

Accounts payable

 

 

797

 

 

 

1,115

 

Accrued interest, payroll and taxes

 

 

1,011

 

 

 

1,323

 

Regulatory liabilities

 

 

749

 

 

 

497

 

Reserves for SCANA legal proceedings

 

 

538

 

 

 

696

 

Derivative liabilities

 

 

586

 

 

 

408

 

Other(2)

 

 

2,446

 

 

 

1,827

 

Total current liabilities

 

 

9,537

 

 

 

9,939

 

Long-Term Debt

 

 

 

 

 

 

 

 

Long-term debt

 

 

33,844

 

 

 

30,313

 

Junior subordinated notes

 

 

2,858

 

 

 

3,406

 

Other

 

 

444

 

 

 

105

 

Total long-term debt

 

 

37,146

 

 

 

33,824

 

Deferred Credits and Other Liabilities

 

 

 

 

 

 

 

 

Deferred income taxes and investment tax credits

 

 

5,921

 

 

 

6,277

 

Regulatory liabilities

 

 

10,680

 

 

 

11,001

 

Derivative liabilities

 

 

748

 

 

 

332

 

Other(2)

 

 

8,812

 

 

 

8,417

 

Total deferred credits and other liabilities

 

 

26,161

 

 

 

26,027

 

Total liabilities

 

 

72,844

 

 

 

69,790

 

Commitments and Contingencies (see Note 17)

 

 

 

 

 

 

 

 

Equity

 

 

 

 

 

 

 

 

Preferred stock (See Note 16)

 

 

2,387

 

 

 

2,387

 

Common stock – no par(3)

 

 

23,984

 

 

 

23,824

 

Retained earnings

 

 

4,480

 

 

 

7,576

 

Accumulated other comprehensive loss

 

 

(1,980

)

 

 

(1,793

)

Total shareholders' equity

 

 

28,871

 

 

 

31,994

 

Noncontrolling interests

 

 

2,013

 

 

 

2,039

 

Total equity

 

 

30,884

 

 

 

34,033

 

Total liabilities and equity

 

$

103,728

 

 

$

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; 840 million shares and 838 million shares outstanding at June 30, 2020 and December 31, 2019, respectively.


 Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
 2021202020212020
 
Net income$2,383 $1,120 $2,493 $1,793 
 
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $1, $2, $5 and $1315 10 22 44 
Foreign currency translation adjustment68 109 159 (439)
Unrealized gains (losses) on cash flow hedges, net of tax of $(1), $3, $4 and $(7)1 9 15 (24)
Total other comprehensive income (loss), net of tax84 128 196 (419)
     
Comprehensive income2,467 1,248 2,689 1,374 
Comprehensive income attributable to noncontrolling interests106 4 212 7 
Comprehensive income attributable to BHE shareholders$2,361 $1,244 $2,477 $1,367 

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

these consolidated financial statements.


8
DOMINION
BERKSHIRE HATHAWAY ENERGY INC.

COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - QUARTER-TO-DATE

(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)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2019

 

 

—

 

 

$

—

 

 

 

802

 

 

$

20,834

 

 

$

7,806

 

 

$

(1,731

)

 

$

26,909

 

 

$

690

 

 

$

27,599

 

Net income including noncontrolling interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

54

 

 

 

 

 

 

 

54

 

 

 

4

 

 

 

58

 

Issuance of stock

 

 

2

 

 

 

1,596

 

 

 

1

 

 

 

78

 

 

 

 

 

 

 

 

 

 

 

1,674

 

 

 

 

 

 

 

1,674

 

Stock purchase contract component of 2019 Equity Units(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(264

)

 

 

 

 

 

 

 

 

 

 

(264

)

 

 

 

 

 

 

(264

)

Stock awards (net of change in unearned compensation)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12

 

 

 

 

 

 

 

 

 

 

 

12

 

 

 

 

 

 

 

12

 

Dividends ($0.9175 per common share) and distributions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(736

)

 

 

 

 

 

 

(736

)

 

 

(10

)

 

 

(746

)

Other comprehensive income, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

48

 

 

 

48

 

 

 

 

 

 

 

48

 

June 30, 2019

 

 

2

 

 

$

1,596

 

 

 

803

 

 

$

20,660

 

 

$

7,124

 

 

$

(1,683

)

 

$

27,697

 

 

$

684

 

 

$

28,381

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2020

 

 

2

 

 

$

2,387

 

 

 

839

 

 

$

23,902

 

 

$

6,455

 

 

$

(2,018

)

 

$

30,726

 

 

$

2,026

 

 

$

32,752

 

Net income (loss) including noncontrolling interests

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,169

)

 

 

 

 

 

 

(1,169

)

 

 

37

 

 

 

(1,132

)

Issuance of stock

 

 

 

 

 

 

 

 

 

 

1

 

 

 

70

 

 

 

 

 

 

 

 

 

 

 

70

 

 

 

 

 

 

 

70

 

Stock awards (net of change in unearned compensation)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13

 

 

 

 

 

 

 

 

 

 

 

13

 

 

 

 

 

 

 

13

 

Preferred stock dividends(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(16

)

 

 

 

 

 

 

(16

)

 

 

 

 

 

 

(16

)

Common stock dividends ($0.940 per share) and distributions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(789

)

 

 

 

 

 

 

(789

)

 

 

(50

)

 

 

(839

)

Other comprehensive income, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

38

 

 

 

38

 

 

 

 

 

 

 

38

 

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1

)

 

 

(1

)

 

 

 

 

 

 

(2

)

 

 

 

 

 

 

(2

)

June 30, 2020

 

 

2

 

 

$

2,387

 

 

 

840

 

 

$

23,984

 

 

$

4,480

 

 

$

(1,980

)

 

$

28,871

 

 

$

2,013

 

 

$

30,884

 

(Amounts in millions)

(1) See Note 16 for further information.

 BHE Shareholders' Equity
Long-termAccumulated
AdditionalIncomeOther
PreferredCommonPaid-inTaxRetainedComprehensiveNoncontrollingTotal
 StockStockCapitalReceivableEarningsLoss, NetInterestsEquity
Balance, March 31, 2020$0 $0 $6,382 $(530)$28,846 $(2,253)$127 $32,572 
Net income— — — — 1,116 — 4 1,120 
Other comprehensive income— — — — — 128 — 128 
Distributions— — — — — — (2)(2)
Purchase of noncontrolling interest— — (5)— — — (28)(33)
Balance, June 30, 2020$0 $0 $6,377 $(530)$29,962 $(2,125)$101 $33,785 
        
Balance, December 31, 2019$0 $0 $6,389 $(530)$28,296 $(1,706)$129 $32,578 
Net income— — — — 1,786 — 7 1,793 
Other comprehensive loss— — — — — (419)— (419)
Common stock purchases— — (6)— (120)— — (126)
Distributions— — — — — — (7)(7)
Purchase of noncontrolling interest— — (5)— — — (28)(33)
Other equity transactions— — (1)— — — — (1)
Balance, June 30, 2020$0 $0 $6,377 $(530)$29,962 $(2,125)$101 $33,785 
Balance, March 31, 2021$3,750 $0 $6,377 $(658)$35,060 $(1,440)$3,962 $47,051 
Net income— — — — 2,281 — 102 2,383 
Other comprehensive income— — — — — 80 4 84 
Preferred stock dividend— — — — (37)— — (37)
Distributions— — — — — — (121)(121)
Contributions— — — — — — 9 9 
Other equity transactions— — — — (1)— (3)(4)
Balance, June 30, 2021$3,750 $0 $6,377 $(658)$37,303 $(1,360)$3,953 $49,365 
        
Balance, December 31, 2020$3,750 $0 $6,377 $(658)$35,093 $(1,552)$3,967 $46,977 
Net income— — — — 2,285 — 208 2,493 
Other comprehensive income— — — — — 192 4 196 
Preferred stock dividend— — — — (75)— — (75)
Distributions— — — — — — (234)(234)
Contributions— — — — — — 9 9 
Other equity transactions— — — — — — (1)(1)
Balance, June 30, 2021$3,750 $0 $6,377 $(658)$37,303 $(1,360)$3,953 $49,365 

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

these consolidated financial statements.

9

DOMINION


BERKSHIRE HATHAWAY ENERGY INC.

COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY - YEAR-TO-DATE

CASH FLOWS (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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(626

)

 

 

 

 

 

 

(626

)

 

 

7

 

 

 

(619

)

Issuance of stock

 

 

2

 

 

 

1,596

 

 

 

4

 

 

 

325

 

 

 

 

 

 

 

 

 

 

 

1,921

 

 

 

 

 

 

 

1,921

 

Stock purchase contract component of 2019 Equity Units(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(264

)

 

 

 

 

 

 

 

 

 

 

(264

)

 

 

 

 

 

 

(264

)

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

)

Stock awards (net of change in unearned compensation)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12

 

 

 

 

 

 

 

 

 

 

 

12

 

 

 

 

 

 

 

12

 

Dividends ($1.835 per common share) and distributions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,469

)

 

 

 

 

 

 

(1,469

)

 

 

(43

)

 

 

(1,512

)

Other comprehensive income, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

17

 

 

 

17

 

 

 

 

 

 

 

17

 

June 30, 2019

 

 

2

 

 

$

1,596

 

 

 

803

 

 

$

20,660

 

 

$

7,124

 

 

$

(1,683

)

 

$

27,697

 

 

$

684

 

 

$

28,381

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,439

)

 

 

 

 

 

 

(1,439

)

 

 

68

 

 

 

(1,371

)

Issuance of stock

 

 

 

 

 

 

 

 

 

 

2

 

 

 

148

 

 

 

 

 

 

 

 

 

 

 

148

 

 

 

 

 

 

 

148

 

Stock awards (net of change in unearned compensation)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13

 

 

 

 

 

 

 

 

 

 

 

13

 

 

 

 

 

 

 

13

 

Preferred stock dividends(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(32

)

 

 

 

 

 

 

(32

)

 

 

 

 

 

 

(32

)

Common stock dividends ($1.880 per share) and distributions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,577

)

 

 

 

 

 

 

(1,577

)

 

 

(94

)

 

 

(1,671

)

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(187

)

 

 

(187

)

 

 

 

 

 

 

(187

)

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1

)

 

 

 

 

 

 

 

 

 

 

(1

)

 

 

 

 

 

 

(1

)

June 30, 2020

 

 

2

 

 

$

2,387

 

 

 

840

 

 

$

23,984

 

 

$

4,480

 

 

$

(1,980

)

 

$

28,871

 

 

$

2,013

 

 

$

30,884

 

(Amounts in millions)
 Six-Month Periods
Ended June 30,
 20212020
Cash flows from operating activities:
Net income$2,493 $1,793 
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net(848)(610)
Depreciation and amortization1,874 1,557 
Allowance for equity funds(56)(72)
Equity loss, net of distributions313 64 
Changes in regulatory assets and liabilities(199)(7)
Deferred income taxes and amortization of investment tax credits613 288 
Other, net(26)18 
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets(254)(783)
Derivative collateral, net92 16 
Pension and other postretirement benefit plans(33)(45)
Accrued property, income and other taxes, net76 (605)
Accounts payable and other liabilities187 240 
Net cash flows from operating activities4,232 1,854 
Cash flows from investing activities:  
Capital expenditures(2,848)(2,793)
Purchases of marketable securities(185)(272)
Proceeds from sales of marketable securities163 256 
Equity method investments(52)(1,087)
Other, net(53)58 
Net cash flows from investing activities(2,975)(3,838)
Cash flows from financing activities:  
Proceeds from BHE senior debt0 3,231 
Repayments of BHE senior debt(450)(350)
Preferred dividends(75)0 
Common stock purchases0 (126)
Proceeds from subsidiary debt539 2,448 
Repayments of subsidiary debt(1,210)(1,410)
Net proceeds from (repayments of) short-term debt245 (920)
Purchase of noncontrolling interest0 (33)
Distributions to noncontrolling interests(234)(8)
Contributions from noncontrolling interests9 5 
Other, net(28)(39)
Net cash flows from financing activities(1,204)2,798 
Effect of exchange rate changes2 (12)
Net change in cash and cash equivalents and restricted cash and cash equivalents55 802 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period1,445 1,268 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$1,500 $2,070 

1) See Note 16 for further information.


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

these consolidated financial statements.

10

DOMINION
BERKSHIRE HATHAWAY ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

Operating Activities

 

 

 

 

 

 

 

 

Net loss including noncontrolling interests

 

$

(1,371

)

 

$

(619

)

Adjustments to reconcile net loss including noncontrolling interests to net cash

   provided by operating activities:

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization (including nuclear fuel)

 

 

1,497

 

 

 

1,472

 

Deferred income taxes and investment tax credits

 

 

(231

)

 

 

107

 

Provision for refunds and rate credits to electric utility customers

 

 

—

 

 

 

953

 

Impairment of assets and other charges

 

 

1,297

 

 

 

1,012

 

Loss for equity method investee

 

 

2,315

 

 

 

—

 

Charge related to a voluntary retirement program

 

 

—

 

 

 

409

 

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

 

 

117

 

 

 

(371

)

Revision to future ash pond and landfill closure costs

 

 

—

 

 

 

(113

)

Other adjustments

 

 

4

 

 

 

4

 

Changes in:

 

 

 

 

 

 

 

 

Accounts receivable

 

 

396

 

 

 

492

 

Inventories

 

 

7

 

 

 

(14

)

Deferred fuel and purchased gas costs, net

 

 

237

 

 

 

120

 

Prepayments

 

 

(193

)

 

 

22

 

Accounts payable

 

 

(191

)

 

 

(446

)

Accrued interest, payroll and taxes

 

 

(313

)

 

 

(264

)

Customer deposits

 

 

(7

)

 

 

(85

)

Margin deposit assets and liabilities

 

 

19

 

 

 

113

 

Other operating assets and liabilities

 

 

(447

)

 

 

(479

)

Net cash provided by operating activities

 

 

3,136

 

 

 

2,313

 

Investing Activities

 

 

 

 

 

 

 

 

Plant construction and other property additions (including nuclear fuel)

 

 

(2,915

)

 

 

(2,112

)

Cash and restricted cash acquired in the SCANA Combination

 

 

—

 

 

 

389

 

Acquisition of solar development projects

 

 

(187

)

 

 

(152

)

Proceeds from sales of securities

 

 

1,660

 

 

 

882

 

Purchases of securities

 

 

(1,710

)

 

 

(888

)

Proceeds from sales of assets and equity method investments

 

 

—

 

 

 

196

 

Contributions to equity method affiliates

 

 

(39

)

 

 

(132

)

Acquisition of equity method investments

 

 

(178

)

 

 

—

 

Other

 

 

35

 

 

 

(16

)

Net cash used in investing activities

 

 

(3,334

)

 

 

(1,833

)

Financing Activities

 

 

 

 

 

 

 

 

Issuance (repayment) of short-term debt, net

 

 

(525

)

 

 

2,040

 

Issuance of short-term notes

 

 

1,125

 

 

 

—

 

Repayment of short-term notes

 

 

(625

)

 

 

—

 

Supplemental 364-Day credit facility borrowings

 

 

225

 

 

 

—

 

Repayment of credit facility borrowings

 

 

—

 

 

 

(113

)

Issuance of long-term debt

 

 

4,355

 

 

 

798

 

Repayment of long-term debt, including redemption premiums

 

 

(2,210

)

 

 

(3,378

)

Issuance of 2019 Equity Units

 

 

—

 

 

 

1,582

 

Issuance of common stock

 

 

148

 

 

 

325

 

Common dividend payments

 

 

(1,577

)

 

 

(1,469

)

Other

 

 

(245

)

 

 

(96

)

Net cash provided by (used in) financing activities

 

 

671

 

 

 

(311

)

Increase in cash, restricted cash and equivalents

 

 

473

 

 

 

169

 

Cash, restricted cash and equivalents at beginning of period

 

 

269

 

 

 

391

 

Cash, restricted cash and equivalents at end of period

 

$

742

 

 

$

560

 

Supplemental Cash Flow Information

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

Accrued capital expenditures

 

$

346

 

 

$

311

 

Leases(3)

 

 

35

 

 

 

24

 

COMPANY AND SUBSIDIARIES

(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 derivative restructuring, the acquisition of the public interest in Dominion Energy Midstream and the issuance of stock purchase contracts associated with the 2019 Equity Units. See Note 18 to the Consolidated Financial Statements in Dominion Energy’s Annual Report on Form 10-K for the year ended December 31, 2019 for non-cash financing activities related to the remarketing of RSNs.

(3)   Includes $32 million and $22 million of financing leases at June 30, 2020 and 2019, respectively, and $3 million and $2 million of operating leases at June 30, 2020 and 2019, respectively.


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


VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenue(1)

 

$

1,805

 

 

$

1,938

 

 

$

3,735

 

 

$

3,903

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric fuel and other energy-related purchases(1)

 

 

366

 

 

 

536

 

 

 

858

 

 

 

1,132

 

Purchased (excess) electric capacity

 

 

(8

)

 

 

13

 

 

 

(17

)

 

 

46

 

Other operations and maintenance:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Affiliated suppliers

 

 

80

 

 

 

127

 

 

 

167

 

 

 

213

 

Other

 

 

296

 

 

 

438

 

 

 

627

 

 

 

631

 

Depreciation and amortization

 

 

307

 

 

 

299

 

 

 

618

 

 

 

603

 

Other taxes

 

 

85

 

 

 

90

 

 

 

172

 

 

 

175

 

Impairment of assets and other charges

 

 

44

 

 

 

197

 

 

 

808

 

 

 

743

 

Total operating expenses

 

 

1,170

 

 

 

1,700

 

 

 

3,233

 

 

 

3,543

 

Income from operations

 

 

635

 

 

 

238

 

 

 

502

 

 

 

360

 

Other income

 

 

52

 

 

 

16

 

 

 

—

 

 

 

53

 

Interest and related charges(1)

 

 

137

 

 

 

135

 

 

 

263

 

 

 

270

 

Income before income tax expense

 

 

550

 

 

 

119

 

 

 

239

 

 

 

143

 

Income tax expense

 

 

60

 

 

 

19

 

 

 

29

 

 

 

23

 

Net Income

 

$

490

 

 

$

100

 

 

$

210

 

 

$

120

 

(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 June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

490

 

 

$

100

 

 

$

210

 

 

$

120

 

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net deferred gains (losses) on derivatives-hedging activities(1)

 

 

1

 

 

 

(11

)

 

 

(44

)

 

 

(18

)

Changes in unrealized net gains (losses) on nuclear

   decommissioning trust funds(2)

 

 

6

 

 

 

2

 

 

 

4

 

 

 

4

 

Amounts reclassified to net income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

—

 

 

 

1

 

 

 

—

 

 

 

1

 

Net realized (gains) losses on nuclear decommissioning

   trust funds(4)

 

 

(2

)

 

 

(1

)

 

 

(1

)

 

 

(1

)

Total other comprehensive income (loss)

 

 

5

 

 

 

(9

)

 

 

(41

)

 

 

(14

)

Comprehensive income

 

$

495

 

 

$

91

 

 

$

169

 

 

$

106

 

(1)

Net of $(1) million and $4 million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $15 million and $6 million tax for the six months ended June 30, 2020 and 2019, respectively.

(2)

Net of $(1) million and $— million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $(1) million and $(1) million tax for the six months ended June 30, 2020 and 2019, respectively.

(3)

Net of$(1) million and $ — million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $ (1) million and $ — million tax for the six months ended June 30, 2020 and 2019, respectively.

(4)

Net of $2 million and $ — million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $1 million and $ — million tax for the six months ended June 30, 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)

 

 

June 30, 2020

 

 

December 31, 2019(1)

 

(millions)

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

37

 

 

$

17

 

Customer receivables (less allowance for doubtful accounts of $20 and $9)

 

 

1,184

 

 

 

1,163

 

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

 

 

94

 

 

 

106

 

Affiliated receivables

 

 

2

 

 

 

27

 

Inventories (average cost method)

 

 

874

 

 

 

873

 

Regulatory assets

 

 

197

 

 

 

433

 

Other(2)

 

 

64

 

 

 

57

 

Total current assets

 

 

2,452

 

 

 

2,676

 

Investments

 

 

 

 

 

 

 

 

Nuclear decommissioning trust funds

 

 

2,782

 

 

 

2,881

 

Other

 

 

3

 

 

 

3

 

Total investments

 

 

2,785

 

 

 

2,884

 

Property, Plant and Equipment

 

 

 

 

 

 

 

 

Property, plant and equipment

 

 

45,273

 

 

 

47,038

 

Accumulated depreciation and amortization

 

 

(13,774

)

 

 

(14,156

)

Total property, plant and equipment, net

 

 

31,499

 

 

 

32,882

 

Deferred Charges and Other Assets

 

 

 

 

 

 

 

 

Regulatory assets

 

 

3,780

 

 

 

1,863

 

Other(2)

 

 

1,524

 

 

 

1,123

 

Total deferred charges and other assets

 

 

5,304

 

 

 

2,986

 

Total assets

 

$

42,040

 

 

$

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)

 

 

June 30, 2020

 

 

December 31, 2019(1)

 

(millions)

 

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDER’S EQUITY

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

Securities due within one year

 

$

7

 

 

$

4

 

Short-term debt

 

 

—

 

 

 

243

 

Accounts payable

 

 

305

 

 

 

334

 

Payables to affiliates

 

 

406

 

 

 

210

 

Affiliated current borrowings

 

 

340

 

 

 

107

 

Accrued interest, payroll and taxes

 

 

276

 

 

 

253

 

Asset retirement obligations

 

 

91

 

 

 

340

 

Regulatory liabilities

 

 

296

 

 

 

167

 

Derivative liabilities(2)

 

 

478

 

 

 

243

 

Other

 

 

598

 

 

 

571

 

Total current liabilities

 

 

2,797

 

 

 

2,472

 

Long-Term Debt

 

 

 

 

 

 

 

 

Long-term debt

 

 

12,328

 

 

 

12,325

 

Finance leases

 

 

30

 

 

 

16

 

Total long-term debt

 

 

12,358

 

 

 

12,341

 

Deferred Credits and Other Liabilities

 

 

 

 

 

 

 

 

Deferred income taxes and investment tax credits

 

 

2,739

 

 

 

2,962

 

Asset retirement obligations

 

 

3,548

 

 

 

3,241

 

Regulatory liabilities

 

 

4,954

 

 

 

5,074

 

Other(2)

 

 

1,700

 

 

 

1,349

 

Total deferred credits and other liabilities

 

 

12,941

 

 

 

12,626

 

Total liabilities

 

 

28,096

 

 

 

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

 

 

7,163

 

 

 

7,167

 

Accumulated other comprehensive loss

 

 

(70

)

 

 

(29

)

Total common shareholder’s equity

 

 

13,944

 

 

 

13,989

 

Total liabilities and shareholder’s equity

 

$

42,040

 

 

$

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 June 30, 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)

QUARTER-TO-DATE

 

 

Common Stock

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shares

 

 

Amount

 

 

Other Paid-In Capital

 

 

Retained Earnings

 

 

AOCI

 

 

Total

 

(millions, except for shares)

 

(thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2019

 

 

275

 

 

$

5,738

 

 

$

1,113

 

 

$

6,110

 

 

$

(17

)

 

$

12,944

 

Net income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

100

 

 

 

 

 

 

 

100

 

Dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(71

)

 

 

 

 

 

 

(71

)

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(9

)

 

 

(9

)

June 30, 2019

 

 

275

 

 

$

5,738

 

 

$

1,113

 

 

$

6,139

 

 

$

(26

)

 

$

12,964

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2020

 

 

275

 

 

$

5,738

 

 

$

1,113

 

 

$

6,780

 

 

$

(75

)

 

$

13,556

 

Net income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

490

 

 

 

 

 

 

 

490

 

Dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(107

)

 

 

 

 

 

 

(107

)

Other comprehensive income, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5

 

 

 

5

 

June 30, 2020

 

 

275

 

 

$

5,738

 

 

$

1,113

 

 

$

7,163

 

 

$

(70

)

 

$

13,944

 

YEAR-TO-DATE

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

120

 

 

 

 

 

 

 

120

 

Dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(189

)

 

 

 

 

 

 

(189

)

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(14

)

 

 

(14

)

June 30, 2019

 

 

275

 

 

$

5,738

 

 

$

1,113

 

 

$

6,139

 

 

$

(26

)

 

$

12,964

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2019

 

 

275

 

 

$

5,738

 

 

$

1,113

 

 

$

7,167

 

 

$

(29

)

 

$

13,989

 

Net income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

210

 

 

 

 

 

 

 

210

 

Dividends

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(215

)

 

 

 

 

 

 

(215

)

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(41

)

 

 

(41

)

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1

 

 

 

 

 

 

 

1

 

June 30, 2020

 

 

275

 

 

$

5,738

 

 

$

1,113

 

 

$

7,163

 

 

$

(70

)

 

$

13,944

 

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)

Six Months Ended June 30,

 

2020

 

 

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

Operating Activities

 

 

 

 

 

 

 

 

 

 

Net income

 

$

210

 

 

 

 

$

120

 

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

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization (including nuclear fuel)

 

 

702

 

 

 

 

 

690

 

Deferred income taxes and investment tax credits

 

 

(220

)

 

 

 

 

(43

)

Revision to future ash pond and landfill closure costs

 

 

—

 

 

 

 

 

(113

)

Impairment of assets and other charges

 

 

806

 

 

 

 

 

608

 

Charge related to a voluntary retirement program

 

 

—

 

 

 

 

 

190

 

Other adjustments

 

 

2

 

 

 

 

 

(51

)

Changes in:

 

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

1

 

 

 

 

 

68

 

Affiliated receivables and payables

 

 

220

 

 

 

 

 

(179

)

Inventories

 

 

(1

)

 

 

 

 

(30

)

Prepayments

 

 

—

 

 

 

 

 

(4

)

Deferred fuel expenses, net

 

 

136

 

 

 

 

 

153

 

Accounts payable

 

 

(9

)

 

 

 

 

(35

)

Accrued interest, payroll and taxes

 

 

18

 

 

 

 

 

14

 

Net realized and unrealized changes related to derivative activities

 

 

(20

)

 

 

 

 

17

 

Other operating assets and liabilities

 

 

47

 

 

 

 

 

(331

)

Net cash provided by operating activities

 

 

1,892

 

 

 

 

 

1,074

 

Investing Activities

 

 

 

 

 

 

 

 

 

 

Plant construction and other property additions

 

 

(1,474

)

 

 

 

 

(1,079

)

Purchases of nuclear fuel

 

 

(154

)

 

 

 

 

(67

)

Acquisition of solar development projects

 

 

(19

)

 

 

 

 

(150

)

Proceeds from sales of securities

 

 

530

 

 

 

 

 

447

 

Purchases of securities

 

 

(549

)

 

 

 

 

(478

)

Other

 

 

18

 

 

 

 

 

(11

)

Net cash used in investing activities

 

 

(1,648

)

 

 

 

 

(1,338

)

Financing Activities

 

 

 

 

 

 

 

 

 

 

(Repayment) issuance of short-term debt, net

 

 

(243

)

 

 

 

 

986

 

Issuance (repayment) of affiliated current borrowings, net

 

 

233

 

 

 

 

 

(153

)

Issuance of long-term debt

 

 

105

 

 

 

 

 

198

 

Repayment of long-term debt

 

 

(105

)

 

 

 

 

(589

)

Common dividend payments to parent

 

 

(215

)

 

 

 

 

(189

)

Other

 

 

(3

)

 

 

 

 

(2

)

Net cash provided by (used in) financing activities

 

 

(228

)

 

 

 

 

251

 

Increase (decrease) in cash, restricted cash and equivalents

 

 

16

 

 

 

 

 

(13

)

Cash, restricted cash and equivalents at beginning of period

 

 

24

 

 

 

 

 

38

 

Cash, restricted cash and equivalents at end of period

 

$

40

 

 

 

 

$

25

 

Supplemental Cash Flow Information

 

 

 

 

 

 

 

 

 

 

Significant noncash investing activities:

 

 

 

 

 

 

 

 

 

 

Accrued capital expenditures

 

$

239

 

 

 

 

$

193

 

Financing leases

 

 

20

 

 

 

 

 

9

 

 

 

 

 

 

 

 

 

 

 

 

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 June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenue(1)

 

$

510

 

 

$

530

 

 

$

1,066

 

 

$

1,096

 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchased (excess) gas(1)

 

 

—

 

 

 

(3

)

 

 

8

 

 

 

9

 

Other energy-related purchases

 

 

1

 

 

 

1

 

 

 

1

 

 

 

1

 

Other operations and maintenance:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Affiliated suppliers

 

 

39

 

 

 

54

 

 

 

79

 

 

 

93

 

Other

 

 

111

 

 

 

156

 

 

 

236

 

 

 

293

 

Depreciation and amortization

 

 

94

 

 

 

92

 

 

 

187

 

 

 

182

 

Other taxes

 

 

35

 

 

 

38

 

 

 

77

 

 

 

78

 

Impairment of assets and other charges

 

 

482

 

 

 

13

 

 

 

482

 

 

 

13

 

Total operating expenses

 

 

762

 

 

 

351

 

 

 

1,070

 

 

 

669

 

Income (loss) from continuing operations

 

 

(252

)

 

 

179

 

 

 

(4

)

 

 

427

 

Earnings from equity method investees

 

 

8

 

 

 

9

 

 

 

23

 

 

 

22

 

Other income(1)

 

 

46

 

 

 

44

 

 

 

95

 

 

 

85

 

Interest and related charges(1)

 

 

50

 

 

 

86

 

 

 

108

 

 

 

173

 

Income (loss) from continuing operations before income tax expense

 

 

(248

)

 

 

146

 

 

 

6

 

 

 

361

 

Income tax expense (benefit)

 

 

(82

)

 

 

23

 

 

 

(30

)

 

 

66

 

Net income (loss) from continuing operations

 

 

(166

)

 

 

123

 

 

 

36

 

 

 

295

 

Net income from discontinued operations

 

 

—

 

 

 

26

 

 

 

—

 

 

 

80

 

Net income (loss) including noncontrolling interests

 

 

(166

)

 

 

149

 

 

 

36

 

 

 

375

 

Noncontrolling interests

 

 

32

 

 

 

30

 

 

 

65

 

 

 

66

 

Net Income (Loss) attributable to Dominion Energy Gas

 

$

(198

)

 

$

119

 

 

$

(29

)

 

$

309

 

(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 June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) including noncontrolling interests

 

$

(166

)

 

$

149

 

 

$

36

 

 

$

375

 

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net deferred gains (losses) on derivatives-hedging activities(1)

 

 

—

 

 

 

(24

)

 

 

(91

)

 

 

(51

)

Changes in unrecognized pension and other postretirement benefits(2)

 

 

—

 

 

 

29

 

 

 

—

 

 

 

29

 

Amounts reclassified to net income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

(2

)

 

 

(2

)

 

 

4

 

 

 

1

 

Net pension and other postretirement benefit costs(4)

 

 

2

 

 

 

2

 

 

 

3

 

 

 

3

 

Total other comprehensive income (loss)

 

 

—

 

 

 

5

 

 

 

(84

)

 

 

(18

)

Comprehensive income (loss) including noncontrolling interests

 

 

(166

)

 

 

154

 

 

 

(48

)

 

 

357

 

Comprehensive income attributable to noncontrolling interests

 

 

32

 

 

 

30

 

 

 

65

 

 

 

65

 

Comprehensive income (loss) attributable to Dominion Energy Gas

 

$

(198

)

 

$

124

 

 

$

(113

)

 

$

292

 

(1)

Net of $(1) million and $8 million tax for the three months ended June 30, 2020 and 2019, respectively, and $31 million and $17 million tax for the six months ended June 30, 2020 and 2019, respectively.

(2)

Net of $ — million and $(11) million tax for the three months ended June 30, 2020 and 2019, respectively, and $ — million and $(11) million tax for the six months ended June 30, 2020 and 2019, respectively.

(3)

Net of $ — million and $— million tax for the three months ended June 30, 2020 and 2019, respectively, and $(2) million and $ — million tax for the six months ended June 30, 2020 and 2019, respectively.

(4)

Net of $ — million and $ — million tax for the three months ended June 30, 2020 and 2019, respectively, and $(1) million and $(1) million tax for the six months ended June 30, 2020 and 2019, respectively.

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


DOMINION ENERGY GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

June 30, 2020

 

 

December 31, 2019(1)

 

(millions)

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

53

 

 

$

27

 

Customer receivables (less allowance for doubtful accounts of $5 and $2)

 

 

151

 

 

 

173

 

Other receivables(2)

 

 

12

 

 

 

26

 

Affiliated receivables

 

 

77

 

 

 

362

 

Affiliated notes receivable

 

 

263

 

 

 

—

 

Inventories

 

 

130

 

 

 

122

 

Prepayments

 

 

43

 

 

 

73

 

Gas imbalances(2)

 

 

25

 

 

 

52

 

Other

 

 

23

 

 

 

23

 

Total current assets

 

 

777

 

 

 

858

 

Investments

 

 

 

 

 

 

 

 

Affiliated notes receivable

 

 

2,272

 

 

 

3,437

 

Investment in equity method affiliates

 

 

310

 

 

 

312

 

Total investments

 

 

2,582

 

 

 

3,749

 

Property, Plant and Equipment

 

 

 

 

 

 

 

 

Property, plant and equipment

 

 

14,899

 

 

 

15,166

 

Accumulated depreciation and amortization

 

 

(3,695

)

 

 

(3,538

)

Total property, plant and equipment, net

 

 

11,204

 

 

 

11,628

 

Deferred Charges and Other Assets

 

 

 

 

 

 

 

 

Goodwill

 

 

1,471

 

 

 

1,471

 

Other(2)

 

 

1,107

 

 

 

1,078

 

Total deferred charges and other assets

 

 

2,578

 

 

 

2,549

 

Total assets

 

$

17,141

 

 

$

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)

 

 

June 30, 2020

 

 

December 31, 2019(1)

 

(millions)

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

Securities due within one year

 

$

1,200

 

 

$

700

 

Short-term debt

 

 

—

 

 

 

62

 

Accounts payable

 

 

52

 

 

 

59

 

Payables to affiliates

 

 

159

 

 

 

82

 

Affiliated current borrowings

 

 

314

 

 

 

260

 

Other(2)

 

 

382

 

 

 

289

 

Total current liabilities

 

 

2,107

 

 

 

1,452

 

Long-Term Debt

 

 

 

 

 

 

 

 

Long-term debt

 

 

4,324

 

 

 

4,821

 

Finance leases

 

 

5

 

 

 

5

 

Total long-term debt

 

 

4,329

 

 

 

4,826

 

Deferred Credits and Other Liabilities

 

 

 

 

 

 

 

 

Deferred income taxes and investment tax credits

 

 

1,156

 

 

 

1,288

 

Other

 

 

1,093

 

 

 

989

 

Total deferred credits and other liabilities

 

 

2,249

 

 

 

2,277

 

Total liabilities

 

 

8,685

 

 

 

8,555

 

Commitments and Contingencies (see Note 17)

 

 

 

 

 

 

 

 

Equity

 

 

 

 

 

 

 

 

Membership interests

 

 

7,352

 

 

 

9,031

 

Accumulated other comprehensive loss

 

 

(271

)

 

 

(187

)

Total members' equity

 

 

7,081

 

 

 

8,844

 

Noncontrolling interests

 

 

1,375

 

 

 

1,385

 

Total equity

 

 

8,456

 

 

 

10,229

 

Total liabilities and equity

 

$

17,141

 

 

$

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)

QUARTER-TO-DATE

 

 

Predecessor Equity

 

 

Membership Interests

 

 

AOCI

 

 

Total Members' Equity

 

 

Noncontrolling Interests

 

 

Total

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2019

 

$

2,938

 

 

$

4,682

 

 

$

(191

)

 

$

7,429

 

 

$

1,432

 

 

$

8,861

 

Net income

 

 

72

 

 

 

47

 

 

 

 

 

 

 

119

 

 

 

30

 

 

 

149

 

Dividends and distributions

 

 

(153

)

 

 

 

 

 

 

 

 

 

 

(153

)

 

 

(36

)

 

 

(189

)

Other comprehensive income, net of tax

 

 

 

 

 

 

 

 

 

 

5

 

 

 

5

 

 

 

 

 

 

 

5

 

Other

 

 

2

 

 

 

 

 

 

 

 

 

 

 

2

 

 

 

 

 

 

 

2

 

June 30, 2019

 

$

2,859

 

 

$

4,729

 

 

$

(186

)

 

$

7,402

 

 

$

1,426

 

 

$

8,828

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2020

 

$

—

 

 

$

8,968

 

 

$

(271

)

 

$

8,697

 

 

$

1,381

 

 

$

10,078

 

Net income (loss)

 

 

 

 

 

 

(198

)

 

 

 

 

 

 

(198

)

 

 

32

 

 

 

(166

)

Dividends and distributions

 

 

 

 

 

 

(1,418

)

 

 

 

 

 

 

(1,418

)

 

 

(38

)

 

 

(1,456

)

June 30, 2020

 

$

—

 

 

$

7,352

 

 

$

(271

)

 

$

7,081

 

 

$

1,375

 

 

$

8,456

 

YEAR-TO-DATE

 

 

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

 

 

146

 

 

 

163

 

 

 

 

 

 

 

309

 

 

 

66

 

 

 

375

 

Acquisition of public interest in Dominion Energy Midstream

 

 

1,181

 

 

 

 

 

 

 

 

 

 

 

1,181

 

 

 

(1,221

)

 

 

(40

)

Dividends and distributions

 

 

(266

)

 

 

 

 

 

 

 

 

 

 

(266

)

 

 

(82

)

 

 

(348

)

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

 

 

(17

)

 

 

(17

)

 

 

(1

)

 

 

(18

)

Other

 

 

(6

)

 

 

 

 

 

 

 

 

 

 

(6

)

 

 

 

 

 

 

(6

)

June 30, 2019

 

$

2,859

 

 

$

4,729

 

 

$

(186

)

 

$

7,402

 

 

$

1,426

 

 

$

8,828

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2019

 

$

—

 

 

$

9,031

 

 

$

(187

)

 

$

8,844

 

 

$

1,385

 

 

$

10,229

 

Net income (loss)

 

 

 

 

 

 

(29

)

 

 

 

 

 

 

(29

)

 

 

65

 

 

 

36

 

Dividends and distributions

 

 

 

 

 

 

(1,650

)

 

 

 

 

 

 

(1,650

)

 

 

(75

)

 

 

(1,725

)

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

 

 

(84

)

 

 

(84

)

 

 

 

 

 

 

(84

)

June 30, 2020

 

$

—

 

 

$

7,352

 

 

$

(271

)

 

$

7,081

 

 

$

1,375

 

 

$

8,456

 

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)

Six Months Ended June 30,

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

Operating Activities

 

 

 

 

 

 

 

 

Net income including noncontrolling interests

 

$

36

 

 

$

375

 

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

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

187

 

 

 

227

 

Deferred income taxes and investment tax credits

 

 

(97

)

 

 

39

 

Charge related to a voluntary retirement program

 

 

—

 

 

 

73

 

Impairment of assets and other charges

 

 

482

 

 

 

13

 

Other adjustments

 

 

(1

)

 

 

15

 

Changes in:

 

 

 

 

 

 

 

 

Accounts receivable

 

 

37

 

 

 

88

 

Affiliated receivables and payables

 

 

362

 

 

 

(48

)

Inventories

 

 

(8

)

 

 

(31

)

Prepayments

 

 

30

 

 

 

59

 

Accounts payable

 

 

6

 

 

 

(105

)

Accrued interest, payroll and taxes

 

 

(16

)

 

 

(55

)

Customer deposits

 

 

(1

)

 

 

(81

)

Pension and other postretirement benefits

 

 

(35

)

 

 

(64

)

Other operating assets and liabilities

 

 

26

 

 

 

(45

)

Net cash provided by operating activities

 

 

1,008

 

 

 

460

 

Investing Activities

 

 

 

 

 

 

 

 

Plant construction and other property additions

 

 

(147

)

 

 

(341

)

Repayment of loans by affiliates

 

 

1,165

 

 

 

—

 

Advances to affiliates

 

 

(263

)

 

 

—

 

Other

 

 

(4

)

 

 

(12

)

Net cash provided by (used in) investing activities

 

 

751

 

 

 

(353

)

Financing Activities

 

 

 

 

 

 

 

 

Issuance (repayment) of short-term debt, net

 

 

(62

)

 

 

240

 

Issuance (repayment) of affiliated current borrowings, net

 

 

54

 

 

 

(11

)

Repayment of long-term debt

 

 

—

 

 

 

(300

)

Issuance of affiliated long-term debt

 

 

—

 

 

 

395

 

Repayment of credit facility borrowings

 

 

—

 

 

 

(73

)

Dividends and distributions

 

 

(1,725

)

 

 

(348

)

Other

 

 

(1

)

 

 

(1

)

Net cash used in financing activities

 

 

(1,734

)

 

 

(98

)

Increase in cash, restricted cash and equivalents

 

 

25

 

 

 

9

 

Cash, restricted cash and equivalents at beginning of period

 

 

39

 

 

 

198

 

Cash, restricted cash and equivalents at end of period

 

$

64

 

 

$

207

 

Supplemental Cash Flow Information

 

 

 

 

 

 

 

 

Significant noncash investing activities:

 

 

 

 

 

 

 

 

Accrued capital expenditures

 

$

24

 

 

$

43

 

Financing leases

 

 

1

 

 

 

6

 

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 conductsowns 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 activitiessegments: 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-regulatedthese 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 undergroundinterests in a liquefied natural gas ("LNG") export, import and storage systemsfacility in the easternUnited 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 regionshydroelectric projects, the largest residential real estate brokerage firm in the United States and 1 of the U.S., as well aslargest residential real estate brokerage franchise networks in the Cove Point LNG Facility. In addition, Dominion Energy Gas owns a 50% noncontrolling interestUnited States.

The unaudited Consolidated Financial Statements have been prepared in both Iroquoisaccordance 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. In July 2020, Dominion Energy entered an agreement to sell substantially all of its gas transmissionUnited States Securities and storage operations, including Dominion Energy Gas, to BHE. See Note 3 for additional information.

Note 2. Significant Accounting Policies

As permitted by theExchange 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. Theseall adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements shouldas of June 30, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 2021 are not necessarily indicative of the results to be readexpected for the full year.


The preparation of the unaudited Consolidated Financial Statements in conjunctionconformity 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 accompanyingpreparation of the unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position at June 30, 2020, their results of operations and changes in equity for the three and six months ended June 30, 2020 and 2019 and their cash flows for the six months ended June 30, 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 June 30, 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 forCompany's assumptions regarding significant accounting estimates and policies during the yearsix-month period ended December 31, 2019, with the exceptionJune 30, 2021.



11

(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 CashConsideration"), and Equivalents

The following table providesassumed 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 reconciliation25% 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.


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 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 for a cash restrictedpurchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and equivalents reportedindebtedness 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 June 30, 2021 and December 31, 2020, to Dominion Questar on November 2, 2020. Pursuant to the Q-Pipe Purchase Agreement, Dominion Questar agreed that, if the Q-Pipe Transaction did not close, it would repay all or (depending upon 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.

On July 9, 2021, Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Purchase Agreement. On July 14, 2021, BHE received the Purchase Price Repayment Amount of approximately $1.3 billion in cash.

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 FlowsBHE Pipeline Group reportable segment for the six monthsthree- and six-month periods ended June 30, 20202021, is operating revenue of $487 million and 2019:

 

 

Cash, Restricted Cash and Equivalents

at End of Period

 

 

Cash, Restricted Cash and Equivalents

at Beginning of Period

 

 

 

June 30, 2020

 

 

June 30, 2019

 

 

December 31, 2019

 

 

December 31, 2018

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dominion Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

675

 

 

$

382

 

 

$

166

 

 

$

268

 

Restricted cash and equivalents(1)

 

 

67

 

 

 

178

 

 

 

103

 

 

 

123

 

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

 

$

742

 

 

$

560

 

 

$

269

 

 

$

391

 

Virginia Power

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

37

 

 

$

17

 

 

$

17

 

 

$

29

 

Restricted cash and equivalents(1)

 

 

3

 

 

 

8

 

 

 

7

 

 

 

9

 

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

 

$

40

 

 

$

25

 

 

$

24

 

 

$

38

 

Dominion Energy Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents(2)

 

$

53

 

 

$

195

 

 

$

27

 

 

$

108

 

Restricted cash and equivalents (1)

 

 

11

 

 

 

12

 

 

 

12

 

 

 

90

 

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

 

$

64

 

 

$

207

 

 

$

39

 

 

$

198

 

(1)

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

(2)

At June 30, 2019 and December 31, 2018, Dominion Energy Gas had $12 million and $9 million of cash and cash equivalents included in current assets of discontinued operations, respectively.

Property, Plant$1,047 million, respectively and Equipment

In January 2019, Virginia Power committednet income attributable to a plan to retire certain automated metering reading infrastructure associated with its electric operations before the endBHE shareholders of its estimated useful life$66 million and replace such equipment with more current AMI technology. As a result, Virginia Power recorded a charge of $160$173 million, ($119 million after-tax) in the first quarter of 2019, 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) in the first quarter of 2019, 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 May 2019, Virginia Power abandoned a coal rail project at its Mt. Storm generating facility. As a result, Virginia Power recorded a charge of $62 million ($46 million after-tax) in the second quarter of 2019, included in impairment of assets and other charges in its Consolidated Statements of Income.

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) in the first quarter of 2020, 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 second quarter of 2020, Virginia Power recorded charges of $30 million ($22 million after-tax) associated with dismantling certain of these electric generation facilities, recorded in impairment of assets and other charges in its Consolidated Statements of Income.

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

12

Preliminary Allocation of license extensions from the NRC. This adjustment resulted in a decrease in depreciation expense of $8 million ($6 million after-tax) and $16 million ($12 million after-tax) for the three and six months ended June 30, 2020, respectively, in Virginia Power’s Consolidated Statements of Income and a $0.01 increase in Dominion Energy’s EPS, for both the three and six months ended June 30, 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.

In the second quarter of 2020, DESC completed a nuclear decommissioning cost study related to Summer. As a result of the study, Dominion Energy recorded an $89 million increase to its nuclear decommissioning ARO, with a corresponding increase to property, plant and equipment.

In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header Project. As a result of the cancellation of the Atlantic Coast Pipeline Project, Dominion Energy and Dominion Energy Gas recorded a charge of $482 million ($359 million after-tax) in impairment of assets and other charges in their Consolidated Statements of Income for the three and six months ended June 30, 2020 associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million ARO.  As DETI evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.

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 purchase price allocation. In addition, see Note 17are 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 discussionreturn 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 legal proceedings involving Dominion Energy, SCANAcontracts 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 DESC relatingliabilities, to events occurring before closingthe extent recoverable in rates, or goodwill provided additional information is obtained about the facts and circumstances that existed as of the SCANA Combination.

In accordance withacquisition date. Such information includes, but is not limited to, the SCANA Merger Approval Order, Dominion Energy incurred certain chargesreceipt of further information regarding the fair value of the contracts and property, plant and equipment related to its Consolidated Statementsnon-regulated operations, the equity method investment and any associated deferred income tax amounts as well as the evolution of Incomethe rate-making process for regulated operations.


The following table summarizes the following:

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

•

In the first quarterFair Value
Current assets, including cash and cash equivalents of 2019, DESC recorded a reduction in operating revenue$104$582 
Property, plant and a corresponding regulatory liabilityequipment9,264 
Goodwill1,741 
Regulatory assets108 
Deferred income taxes284 
Other long-term assets1,424 
Total assets13,403 
Current liabilities, including current portion of $1.0 billion representing a refundlong-term debt 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 six months ended June 30, 2019 includes a $756 million after-tax charge.$1,2001,616 

Long-term debt, less current portion4,415 
Regulatory liabilities650 
Other long-term liabilities292 
Total liabilities6,973 
Noncontrolling interest3,916 
Net assets acquired$2,514 

•

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 Statement of Income for the six months ended June 30, 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 six months ended June 30, 2019 includes a charge of $198 million included in income tax expense.

Results of Operations and Unaudited Pro Forma Information

The impact ofDuring the SCANA Combination on Dominion Energy’s operating revenue was an increase of $701 million and $909 million for the three monthssix-month period ended June 30, 20202021, the Company made revisions to certain contracts and 2019, respectively,property, plant and an increaseequipment related to non-regulated operations, the equity method investment and associated deferred income tax amounts based upon the receipt of $1.6additional information about the facts and circumstances that existed as of the acquisition date. Provisional amounts are subject to further revision for up to 12 months following the acquisition date until the related valuations are completed.

13

Goodwill

The excess of the purchase price paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1.7 billion and $1.1 billionis reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily for the six months ended June 30, 2020long-term opportunity to improve operating results through the efficient management of operating expenses and 2019, respectively, in the Consolidated Statementsdeployment of Income.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 deemed asset acquisition resulting from tax elections being made, therefore all tax goodwill is deductible. Due to book and tax basis differences of certain items, book and tax goodwill will differ. The impactamount of the SCANA Combination on net income attributable to Dominion Energy was an increase of $58 milliontax goodwill is approximately $0.9 billion and a decrease of $102 million for the three months ended June 30, 2020 and 2019, respectively, and an increase of $112 million and a decrease of $1.2 billion for the six months ended June 30, 2020 and 2019, respectively, in the Consolidated Statements of Income.

Dominion Energy incurred merger and integration-related costs of $23 million and $42 million for the three and six months ended June 30, 2020, respectively, of which $20 million and $39 million are recorded in other operations and maintenance expense in the Consolidated Statements of Income. Dominion Energy incurred merger and integration-related costs of $443 million and $567 million in the Consolidated Statements of Income for the three and six months ended June 30, 2019, respectively. These amounts for both the three and six months ended June 30, 2019 include $423 million for a charge related to a voluntary retirement program. See Note 20 for additional information. Of the remaining merger and integration-related costs, $20 million and $135 million was recorded in other operations and maintenance expense in the Consolidated Statements of Income for the three and six months ended June 30, 2019, respectively, and $9 million was recorded in interest and related charges in the Consolidated Statement of Income for the six months ended June 30, 2019. There were 0 such charges recorded in interest and related charges for the three months ended June 30, 2019. These costs consist of professional fees, charitable contribution commitments, employee-related expenses, certain financing costs and other miscellaneous costs.

will be amortized over 15 years.


Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion EnergyBHE and the amortization of the purchase price adjustments assuming the SCANA Combinationacquisition had taken place on January 1, 2018. 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):
Six-Month Period
Ended June 30, 2020
Operating revenue$10,120 
Net income attributable to BHE shareholders$1,616 

(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
   As of
 Depreciable June 30, December 31,
Life20212020
Regulated assets:   
Utility generation, transmission and distribution systems5-80 years $88,748  $86,730 
Interstate natural gas pipeline assets3-80 years 16,772  16,667 
   105,520 103,397 
Accumulated depreciation and amortization  (31,935) (30,662)
Regulated assets, net  73,585 72,735 
      
Nonregulated assets:     
Independent power plants5-30 years 7,058  7,012 
Other assets3-40 years 5,911  5,659 
   12,969 12,671 
Accumulated depreciation and amortization  (2,819) (2,586)
Nonregulated assets, net  10,150 10,085 
      
Net operating assets  83,735 82,820 
Construction work-in-progress  3,887  3,308 
Property, plant and equipment, net  $87,622 $86,128 

Construction work-in-progress includes $3.5 billion as of June 30, 2021 and $3.2 billion as of December 31, 2020, related to the construction of regulated assets.

14

(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
 June 30,December 31,
20212020
Investments:
BYD Company Limited common stock$6,727 $5,897 
Rabbi trusts472 440 
Other299 263 
Total investments7,498 6,600 
   
Equity method investments:
BHE Renewables tax equity investments5,302 5,626 
Iroquois Gas Transmission System, L.P.584 580 
Electric Transmission Texas, LLC571 594 
JAX LNG, LLC86 75 
Bridger Coal Company71 74 
Other145 118 
Total equity method investments6,759 7,067 
Restricted cash and cash equivalents and investments:  
Quad Cities Station nuclear decommissioning trust funds728 676 
Other restricted cash and cash equivalents169 155 
Total restricted cash and cash equivalents and investments897 831 
   
Total investments and restricted cash and cash equivalents and investments$15,154 $14,498 
Reflected as:
Current assets$194 $178 
Noncurrent assets14,960 14,320 
Total investments and restricted cash and cash equivalents and investments$15,154 $14,498 

Investments

Gains on marketable securities, net recognized during the period consists of the following (in millions):
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Unrealized gains recognized on marketable securities still held at the reporting date$1,966 $584 $847 $609 
Net (losses) gains recognized on marketable securities sold during the period0 (1)1 1 
Gains on marketable securities, net$1,966 $583 $848 $610 


15

Equity Method Investments

The unaudited pro forma financial informationCompany 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 $305 million, or after-tax income of $70 million inclusive of production tax credits ("PTCs") of $306 million and other income tax benefits of $67 million, during the six-month period ended June 30, 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 June 30, 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 June 30, 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 June 30, 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
June 30,December 31,
20212020
Cash and cash equivalents$1,331 $1,290 
Restricted cash and cash equivalents154 140 
Investments and restricted cash and cash equivalents and investments15 15 
Total cash and cash equivalents and restricted cash and cash equivalents$1,500 $1,445 

(5)    Recent Financing Transactions

Long-Term Debt

In July 2021, MidAmerican Energy issued $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Energy used the net proceeds to finance a portion of the capital expenditures, disbursed during the period from July 22, 2019 to September 27, 2019, with respect to investments in its 2,000-megawatt Wind XI project, its 592-megawatt Wind XII project, its 207-megawatt Wind XII Expansion project and the repowering of certain of its existing wind-powered generating facilities, which were previously financed with MidAmerican Energy's general funds.

In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.

On June 30, 2021, as part of an intercompany transaction with its wholly owned subsidiary EGTS, Eastern Energy Gas exchanged a total of $1.6 billion of its issued and outstanding third party notes, making EGTS the primary obligor of the exchanged notes. The intercompany debt exchange was a common control transaction accounted for as a debt modification with no gain or loss recognized in the Consolidated Financial Statements.

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.

16

Credit Facilities

In June 2021, BHE amended and restated its existing $3.5 billion unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2022. In June 2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

In June 2021, MidAmerican Energy amended and restated its existing $900 million unsecured credit facility expiring in June 2022. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to consent of the lenders. Additionally, in June 2021, MidAmerican Energy terminated its existing $600 million unsecured credit facility expiring in August 2021.

In June 2021, Nevada Power and Sierra Pacific each amended and restated its existing $400 million and $250 million secured credit facilities, respectively, expiring in June 2022 with no remaining one-year extension options. The amendments extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

In May 2021, AltaLink, L.P. extended, with lender consent, the expiration date for its existing C$75 million and C$500 million secured credit facilities to December 2025 by exercising an available one-year extension option.

In May 2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$300 million unsecured credit facility to December 2025 by exercising an available one-year extension option.

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

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense (benefit) is as follows:
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
 2021202020212020
 
Federal statutory income tax rate21 %21 %21 %21 %
Income tax credits(13)(20)(27)(28)
State income tax, net of federal income tax impacts4 2 2 1 
Income tax effect of foreign income3 (2)3 (2)
Effects of ratemaking(2)(1)(4)(3)
Equity income0 (1)(2)(1)
Noncontrolling interest(1)0 (2)0 
Other, net0 0 1 0 
Effective income tax rate12 %(1)%(8)%(12)%


17

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 six-month periods ended June 30, 2021 and 2020 totaled $678 million and $454 million, respectively.

Income tax effect on foreign income includes, among other items, a deferred income tax charge of $109 million recognized in June 2021 upon the enactment of an increase in the United Kingdom's corporate income tax rate from 19% to 25% effective April 1, 2023.

The Company's provision for income taxes has been presented for illustrative purposes onlycomputed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and is not necessarily indicativeIowa 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 received net cash payments for federal income taxes from Berkshire Hathaway totaling $943 million for the six-month period ended June 30, 2021 and made payments for federal income taxes to Berkshire Hathaway totaling $100 million for the six-month period ended June 30, 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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
 2021202020212020
Pension:
Service cost$8 $4 $15 $7 
Interest cost18 23 38 46 
Expected return on plan assets(36)(35)(69)(70)
Net amortization7 8 13 17 
Net periodic benefit credit$(3)$0 $(3)$0 
Other postretirement:
Service cost$4 $3 $6 $4 
Interest cost5 4 10 10 
Expected return on plan assets(6)(7)(11)(16)
Net amortization(1)(3)(2)(4)
Net periodic benefit cost (credit)$2 $(3)$3 $(6)

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 June 30, 2021, $7 million and $6 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

18

Foreign Operations

Net periodic benefit credit for the United Kingdom pension plan included the following components (in millions):
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
 2021202020212020
 
Service cost$4 $4 $8 $8 
Interest cost7 10 15 20 
Expected return on plan assets(28)(25)(56)(50)
Net amortization14 11 28 21 
Net periodic benefit credit$(3)$0 $(5)$(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 June 30, 2021, £14 million, or $19 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.

19

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 1Level 2Level 3
Other(1)
Total
As of June 30, 2021
Assets:
Commodity derivatives$5 $232 $158 $(40)$355 
Foreign currency exchange rate derivatives0 16 0 — 16 
Interest rate derivatives0 1 42 — 43 
Mortgage loans held for sale0 2,082 0 — 2,082 
Money market mutual funds(2)
795 0 0 — 795 
Debt securities:
United States government obligations222 0 0 — 222 
International government obligations0 5 0 — 5 
Corporate obligations0 78 0 — 78 
Municipal obligations0 2 0 — 2 
Agency, asset and mortgage-backed obligations0 1 0 — 1 
Equity securities:
United States companies412 0 0 — 412 
International companies6,735 0 0 — 6,735 
Investment funds266 0 0 — 266 
 $8,435 $2,417 $200 $(40)$11,012 
Liabilities:     
Commodity derivatives$(1)$(100)$(53)$34 $(120)
Foreign currency exchange rate derivatives0 (5)0 — (5)
Interest rate derivatives(3)(16)(1)4 (16)
$(4)$(121)$(54)$38 $(141)
20

Input Levels for Fair Value Measurements
Level 1Level 2Level 3
Other(1)
Total
As of December 31, 2020
Assets:
Commodity derivatives$1 $73 $135 $(21)$188 
Foreign currency exchange rate derivatives0 20 0 — 20 
Interest rate derivatives0 0 62 — 62 
Mortgage loans held for sale0 2,001 0 — 2,001 
Money market mutual funds(2)
873 0 0 — 873 
Debt securities:
United States government obligations200 0 0 — 200 
International government obligations0 5 0 — 5 
Corporate obligations0 73 0 — 73 
Municipal obligations0 2 0 — 2 
Agency, asset and mortgage-backed obligations0 6 0 — 6 
Equity securities:
United States companies381 0 0 — 381 
International companies5,906 0 0 — 5,906 
Investment funds201 0 0 — 201 
 $7,562 $2,180 $197 $(21)$9,918 
Liabilities:
Commodity derivatives$(1)$(90)$(19)$56 $(54)
Foreign currency exchange rate derivatives0 (2)0 — (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 payable of $2 million as of June 30, 2021 and a net cash collateral receivable of $35 million as of December 31, 2020.
(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.


21

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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
InterestInterest
 CommodityRateCommodityRate
DerivativesDerivativesDerivativesDerivatives
2021:
Beginning balance$124 $41 $116 $62 
Changes included in earnings(1)
(10)0 (16)(21)
Changes in fair value recognized in OCI(6)0 (7)0 
Changes in fair value recognized in net regulatory assets(7)0 9 0 
Purchases1 0 1 0 
Settlements3 0 2 0 
Ending balance$105 $41 $105 $41 

Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
InterestInterest
CommodityRateCommodityRate
DerivativesDerivativesDerivativesDerivatives
2020:
Beginning balance$52 $45 $97 $14 
Changes included in earnings(1)
(1)33 (4)64 
Changes in fair value recognized in net regulatory assets(16)0 (56)0 
Purchases1 0 3 0 
Settlements8 0 4 0 
Ending balance$44 $78 $44 $78 

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


22

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 June 30, 2021As of December 31, 2020
 CarryingFairCarryingFair
ValueValueValueValue
 
Long-term debt$48,873 $57,059 $49,866 $60,633 

(9)    Commitments and Contingencies

Construction Commitments

During the six-month period ended June 30, 2021, MidAmerican Energy entered into firm construction commitments totaling $558 million through the remainder of 2021 and 2022 related to the repowering and construction of wind-powered generating facilities and the construction of solar-powered generating facilities.

Easements

During the six-month period ended June 30, 2021, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $87 million through 2061 for land in Iowa on which some of its wind- and solar-powered generating facilities will be located.

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 resultsfinancial results. The Company is also involved in other kinds of operations that wouldlegal 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 achievedfiled 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.


23

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 June 30, 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. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC, the Karuk Tribe, the Yurok Tribe and the States as co-licensees. The transfer will be effective after PacifiCorp secures property transfer approvals from its state public utility commissions and 30 days following the issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions approved the property transfer.

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.


24

(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 and nonregulated, with further disaggregation of regulated 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 June 30, 2021
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$1,188 $516 $708 $0 $0 $0 $0 $(1)$2,411 
Retail gas0 89 20 0 0 0 0 0 109 
Wholesale30 69 10 0 0 0 0 (1)108 
Transmission and
   distribution		37 15 22 243 0 178 0 0 495 
Interstate pipeline0 0 0 0 458 0 0 (25)433 
Other31 0 1 0 (1)0 0 0 31 
Total Regulated1,286 689 761 243 457 178 0 (27)3,587 
Nonregulated0 1 1 8 232 7 239 124 612 
Total Customer Revenue1,286 690 762 251 689 185 239 97 4,199 
Other revenue12 3 5 29 17 (3)28 11 102 
Total$1,298 $693 $767 $280 $706 $182 $267 $108 $4,301 
For the Six-Month Period Ended June 30, 2021
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$2,333 $968 $1,219 $0 $0 $0 $0 $(1)$4,519 
Retail gas0 549 58 0 0 0 0 0 607 
Wholesale66 194 25 0 17 0 0 (1)301 
Transmission and
   distribution		62 30 43 506 0 350 0 0 991 
Interstate pipeline0 0 0 0 1,273 0 0 (66)1,207 
Other54 0 1 0 1 0 0 0 56 
Total Regulated2,515 1,741 1,346 506 1,291 350 0 (68)7,681 
Nonregulated0 11 1 18 469 15 405 311 1,230 
Total Customer Revenue2,515 1,752 1,347 524 1,760 365 405 243 8,911 
Other revenue25 8 11 56 39 (3)52 51 239 
Total$2,540 $1,760 $1,358 $580 $1,799 $362 $457 $294 $9,150 
25

For the Three-Month Period Ended June 30, 2020
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$1,066 $468 $638 $0 $0 $0 $0 $0 $2,172 
Retail gas0 84 20 0 0 0 0 0 104 
Wholesale17 37 6 0 0 0 0 (1)59 
Transmission and
   distribution		24 18 22 191 0 164 0 0 419 
Interstate pipeline0 0 0 0 221 0 0 (26)195 
Other20 0 0 0 0 0 0 0 20 
Total Regulated1,127 607 686 191 221 164 0 (27)2,969 
Nonregulated0 3 1 5 0 5 212 122 348 
Total Customer Revenue1,127 610 687 196 221 169 212 95 3,317 
Other revenue17 6 8 25 4 0 32 10 102 
Total$1,144 $616 $695 $221 $225 $169 $244 $105 $3,419 
For the Six-Month Period Ended June 30, 2020
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$2,188 $878 $1,167 $0 $0 $0 $0 $0 $4,233 
Retail gas0 271 67 0 0 0 0 0 338 
Wholesale17 101 20 0 0 0 0 (2)136 
Transmission and
   distribution		46 33 45 424 0 333 0 0 881 
Interstate pipeline0 0 0 0 621 0 0 (74)547 
Other46 0 1 0 0 0 0 0 47 
Total Regulated2,297 1,283 1,300 424 621 333 0 (76)6,182 
Nonregulated0 9 2 12 0 8 371 249 651 
Total Customer Revenue2,297 1,292 1,302 436 621 341 371 173 6,833 
Other revenue53 10 15 51 5 0 51 35 220 
Total$2,350 $1,302 $1,317 $487 $626 $341 $422 $208 $7,053 

(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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Customer Revenue:
Brokerage$1,569 $957 $2,591 $1,734 
Franchise24 15 42 31 
Total Customer Revenue1,593 972 2,633 1,765 
Mortgage and other revenue170 221 362 321 
Total$1,763 $1,193 $2,995 $2,086 
26

Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2021, by reportable segment (in millions):
Performance obligations expected to be satisfied:
Less than 12 monthsMore than 12 monthsTotal
BHE Pipeline Group$2,562 $21,728 $24,290 
BHE Transmission350 0 350 
Total$2,912 $21,728 $24,640 

(11)    BHE Shareholders' Equity

On July 22, 2021, BHE redeemed at par 1,450,003 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $1.45 billion, plus an additional amount equal to the accrued dividends on the pro rata shares redeemed.

For the six-month period ended June 30, 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) by each component of other comprehensive income (loss), net of applicable income tax (in millions):
UnrecognizedForeignUnrealizedAOCI
Amounts onCurrency(Losses) GainsAttributable
RetirementTranslationon CashNoncontrollingTo BHE
BenefitsAdjustmentFlow HedgesInterestsShareholders, Net
Balance, December 31, 2019$(417)$(1,296)$7 $0 $(1,706)
Other comprehensive income (loss)44 (439)(24)0 (419)
Balance, June 30, 2020$(373)$(1,735)$(17)$0 $(2,125)
Balance, December 31, 2020$(492)$(1,062)$(8)$10 $(1,552)
Other comprehensive income (loss)22 159 15 (4)192 
Balance, June 30, 2021$(470)$(903)$7 $6 $(1,360)

27

(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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
 2021202020212020
Operating revenue:
PacifiCorp$1,298 $1,144 $2,540 $2,350 
MidAmerican Funding693 616 1,760 1,302 
NV Energy767 695 1,358 1,317 
Northern Powergrid280 221 580 487 
BHE Pipeline Group706 225 1,799 626 
BHE Transmission182 169 362 341 
BHE Renewables267 244 457 422 
HomeServices1,763 1,193 2,995 2,086 
BHE and Other(1)
108 105 294 208 
Total operating revenue$6,064 $4,612 $12,145 $9,139 
Depreciation and amortization:
PacifiCorp$275 $210 $539 $462 
MidAmerican Funding209 175 416 351 
NV Energy137 125 273 249 
Northern Powergrid73 63 144 126 
BHE Pipeline Group121 25 239 89 
BHE Transmission60 55 118 115 
BHE Renewables61 71 121 142 
HomeServices12 12 23 23 
BHE and Other(1)
(1)0 1 0 
Total depreciation and amortization$947 $736 $1,874 $1,557 

28

 Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
 2021202020212020
Operating income:  
PacifiCorp$283 $256 $517 $490 
MidAmerican Funding103 110 151 212 
NV Energy145 161 215 240 
Northern Powergrid126 89 277 221 
BHE Pipeline Group245 92 863 341 
BHE Transmission85 81 166 157 
BHE Renewables97 84 130 101 
HomeServices179 77 291 97 
BHE and Other(1)
(55)(14)(69)(4)
Total operating income1,208 936 2,541 1,855 
Interest expense(532)(503)(1,062)(986)
Capitalized interest14 19 28 36 
Allowance for equity funds30 38 56 72 
Interest and dividend income26 20 47 40 
Gains on marketable securities, net1,966 583 848 610 
Other, net48 52 56 25 
Total income before income tax expense (benefit) and equity loss$2,760 $1,145 $2,514 $1,652 
Interest expense:
PacifiCorp$105 $110 $212 $212 
MidAmerican Funding78 78 156 159 
NV Energy51 57 103 115 
Northern Powergrid32 31 65 63 
BHE Pipeline Group40 15 78 29 
BHE Transmission40 35 78 73 
BHE Renewables40 42 80 84 
HomeServices1 3 2 8 
BHE and Other(1)
145 132 288 243 
Total interest expense$532 $503 $1,062 $986 
Earnings on common shares:
PacifiCorp$226 $167 $395 $343 
MidAmerican Funding211 208 355 358 
NV Energy100 98 134 118 
Northern Powergrid(25)59 79 146 
BHE Pipeline Group100 64 483 243 
BHE Transmission60 60 119 115 
BHE Renewables181 138 197 233 
HomeServices135 59 219 69 
BHE and Other1,256 263 229 161 
Earnings on common shares$2,244 $1,116 $2,210 $1,786 

29

 As of
 June 30,December 31,
20212020
Assets:
PacifiCorp$27,235 $26,862 
MidAmerican Funding24,156 23,530 
NV Energy14,839 14,501 
Northern Powergrid9,071 8,782 
BHE Pipeline Group19,739 19,541 
BHE Transmission9,516 9,208 
BHE Renewables11,754 12,004 
HomeServices5,410 4,955 
BHE and Other(1)
8,841 7,933 
Total assets$130,561 $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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
 2021202020212020
Operating revenue by country:
United States$5,604 $4,224 $11,201 $8,313 
United Kingdom280 221 580 487 
Canada180 167 357 338 
Philippines and other0 0 7 1 
Total operating revenue by country$6,064 $4,612 $12,145 $9,139 
Income before income tax expense (benefit) and equity loss by country:
United States$2,611 $1,027 $2,188 $1,381 
United Kingdom104 59 236 168 
Canada46 46 85 86 
Philippines and other(1)13 5 17 
Total income before income tax expense (benefit) and equity loss by country$2,760 $1,145 $2,514 $1,652 

The following table shows the change in the carrying amount of goodwill by reportable segment for the six-month period ended June 30, 2021 (in millions):
BHE Pipeline Group
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE TransmissionBHE RenewablesHomeServices
Total
 
December 31, 2020$1,129 $2,102 $2,369 $1,000 $1,803 $1,551 $95 $1,457 $11,506 
Acquisitions0 0 0 0 11 0 0 2 13 
Foreign currency translation0 0 0 9 0 42 0 0 51 
June 30, 2021$1,129 $2,102 $2,369 $1,009 $1,814 $1,593 $95 $1,459 $11,570 

30

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

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

 

 

Three Months Ended

June 30, 2019(1)

 

 

Six Months Ended

June 30, 2019(1)

 

(millions, except EPS)

 

 

 

 

 

 

 

 

Operating Revenue

 

$

3,970

 

 

$

8,835

 

Net income attributable to Dominion Energy

 

 

392

 

 

 

962

 

Earnings Per Common Share – Basic

 

$

0.49

 

 

$

1.21

 

Earnings Per Common Share – Diluted

 

$

0.47

 

 

$

1.19

 


(1)

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

Disposition of Gas Transmission & Storage Operations to BHE

In July 2020, Dominion Energy entered into an agreement with BHE with a total value of approximately $10 billion, comprised of approximately $4.0 billion of cash consideration (subject to customary closing adjustments) plusCompany during the assumption of Dominion Energy Gas’ long-term debt, to sell substantially all of its  gas transmission and storage operations, including processing assets, as well as noncontrolling partnership interests in Iroquois, JAX LNG and White River Hub and a controlling interest in Cove Point (consisting of 100%periods included herein. Explanations include management's best estimate of the general partner interest and 25%impact of the total limited partner interests). Upon closing, Dominion Energy Gas will become a wholly-owned subsidiary of BHE. Dominion Energy will retain a 50% noncontrolling interest in Cove Point, which will be accounted for as an equity method investment following completion of the sale, as well as the assets and obligations of the pensionweather, customer growth, usage trends and other postretirement employee benefit plans associatedfactors. This discussion should be read in conjunction with the operations to be sold and relating to services provided through closing. The sale will be treated as an asset sale for tax purposes and is expected to close in the fourth quarter of 2020, contingent on clearance or approval under the Hart-Scott-Rodino Act and from the DOE, and other customary closing and regulatory conditions. Based on the recorded balances at June 30, 2020, Dominion Energy expects to recognize a pre-tax gain of approximately $1 billion upon closing, excluding the effects of any closing adjustments.  If approval under the Hart-Scott-Rodino Act is not obtained by mid-September 2020, Dominion Energy may elect to exclude from this transaction Dominion Energy Questar Pipeline and certain other affiliated entities pursuant to a provision in the agreement with BHE, with an associated reduction in the cash consideration to $2.7 billion, subject to customary closing adjustments.

Dominion Energy will reclassify the assets and liabilities to be disposed of, currently reflected within Gas Transmission & Storage, as held for sale and will report the associated results of operations as discontinued operations starting in the third quarter of 2020. In addition, in the third quarter of 2020, Dominion Energy and Dominion Energy Gas expect to record pre-tax losses of approximately $225 million and $140 million, respectively, for cash flow hedges of debt-related items that are probable of not occurring.

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 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 completion of the Dominion Energy Gas Restructuring, DCP and DMLPHCII are wholly-owned subsidiaries of Dominion Energy Gas and therefore are consolidated by Dominion Energy Gas. The accompanyingCompany'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 represented 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

June 30, 2019

 

 

Six Months Ended

June 30, 2019

 

(millions)

 

 

 

 

 

 

 

 

Operating revenue

 

$

154

 

 

$

383

 

Depreciation and amortization

 

 

22

 

 

 

43

 

Other operating expenses

 

 

128

 

 

 

277

 

Other income

 

 

18

 

 

 

37

 

Interest and related charges

 

 

8

 

 

 

18

 

Income tax expense

 

 

3

 

 

 

17

 

Net income from discontinued operations

 

$

11

 

 

$

65

 


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

 

 

Six Months Ended

June 30, 2019

 

(millions)

 

 

 

 

Capital expenditures

 

$

168

 

Significant noncash items

 

 

 

 

Charge related to a voluntary retirement program

 

 

32

 

Accrued capital expenditures

 

 

8

 

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

June 30, 2019

 

 

Six Months Ended

June 30, 2019

 

(millions)

 

 

 

 

 

 

 

 

Operating revenue

 

$

34

 

 

$

79

 

Depreciation and amortization

 

 

1

 

 

 

2

 

Other operating expenses

 

 

12

 

 

 

56

 

Income tax expense

 

 

6

 

 

 

6

 

Net income from discontinued operations

 

$

15

 

 

$

15

 

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

 

 

Six Months Ended

June 30, 2019

 

(millions)

 

 

 

 

Capital Expenditures

 

$

8

 


Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dominion Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated electric sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

1,091

 

 

$

1,094

 

 

$

2,249

 

 

$

1,740

 

Commercial

 

 

728

 

 

 

889

 

 

 

1,526

 

 

 

1,385

 

Industrial

 

 

176

 

 

 

217

 

 

 

358

 

 

 

247

 

Government and other retail

 

 

193

 

 

 

214

 

 

 

412

 

 

 

414

 

Wholesale

 

 

29

 

 

 

41

 

 

 

62

 

 

 

89

 

Nonregulated electric sales

 

 

177

 

 

 

175

 

 

 

409

 

 

 

491

 

Regulated gas sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

 

182

 

 

 

177

 

 

 

730

 

 

 

779

 

Commercial

 

 

63

 

 

 

73

 

 

 

254

 

 

 

264

 

Other

 

 

16

 

 

 

25

 

 

 

44

 

 

 

63

 

Nonregulated gas sales

 

 

33

 

 

 

71

 

 

 

116

 

 

 

318

 

Regulated gas transportation and storage:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

FERC-regulated

 

 

247

 

 

 

247

 

 

 

528

 

 

 

524

 

State-regulated

 

 

182

 

 

 

166

 

 

 

414

 

 

 

379

 

Nonregulated gas transportation and storage

 

 

176

 

 

 

174

 

 

 

351

 

 

 

348

 

Other regulated revenues(1)

 

 

98

 

 

 

82

 

 

 

173

 

 

 

126

 

Other nonregulated revenues(1)(2)

 

 

79

 

 

 

101

 

 

 

167

 

 

 

209

 

Total operating revenue from contracts

   with customers

 

 

3,470

 

 

 

3,746

 

 

 

7,793

 

 

 

7,376

 

Other revenues(3)

 

 

115

 

 

 

224

 

 

 

288

 

 

 

452

 

Total operating revenue

 

$

3,585

 

 

$

3,970

 

 

$

8,081

 

 

$

7,828

 

Virginia Power

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated electric sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

818

 

 

$

808

 

 

$

1,714

 

 

$

1,731

 

Commercial

 

 

546

 

 

 

681

 

 

 

1,160

 

 

 

1,317

 

Industrial

 

 

89

 

 

 

118

 

 

 

186

 

 

 

230

 

Government and other retail

 

 

177

 

 

 

197

 

 

 

380

 

 

 

401

 

Wholesale

 

 

21

 

 

 

29

 

 

 

45

 

 

 

66

 

Other regulated revenues

 

 

94

 

 

 

62

 

 

 

156

 

 

 

88

 

Other nonregulated revenues(1)(2)

 

 

20

 

 

 

19

 

 

 

33

 

 

 

33

 

Total operating revenue from contracts

   with customers

 

 

1,765

 

 

 

1,914

 

 

 

3,674

 

 

 

3,866

 

Other revenues(2)(3)

 

 

40

 

 

 

24

 

 

 

61

 

 

 

37

 

Total operating revenue

 

$

1,805

 

 

$

1,938

 

 

$

3,735

 

 

$

3,903

 

Dominion Energy Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated gas sales - wholesale

 

$

—

 

 

$

—

 

 

$

2

 

 

$

2

 

Nonregulated gas sales(2)

 

 

—

 

 

 

1

 

 

 

1

 

 

 

3

 

Regulated gas transportation and storage(2)

 

 

302

 

 

 

306

 

 

 

646

 

 

 

646

 

Nonregulated gas transportation and storage

 

 

175

 

 

 

173

 

 

 

350

 

 

 

348

 

Management service revenue(2)

 

 

29

 

 

 

45

 

 

 

60

 

 

 

88

 

Other regulated revenues(1)

 

 

2

 

 

 

3

 

 

 

3

 

 

 

6

 

Other nonregulated revenues(1)(2)

 

 

1

 

 

 

1

 

 

 

2

 

 

 

1

 

Total operating revenue from contracts

   with customers

 

 

509

 

 

 

529

 

 

 

1,064

 

 

 

1,094

 

Other revenues(2)

 

 

1

 

 

 

1

 

 

 

2

 

 

 

2

 

Total operating revenue

 

$

510

 

 

$

530

 

 

$

1,066

 

 

$

1,096

 

1)

Amounts above include sales which are considered to be goods transferred at a point in time. Such amounts included $19 million and $— million for the three months ended June 30, 2020, $42 million and $2 million for the three months ended June 30, 2019, $58 million and $1 million for the six months ended June 30, 2020 and $93 and $3 million for the six months ended June 30, 2019, primarily consisting of NGL sales at Dominion Energy and Dominion Energy Gas, respectively. Additionally, amounts above include sales of renewable energy credits. Such amounts included $7 million and $5 million for the three months ended June 30, 2020, $4 million and $2 million for the three months ended June 30, 2019, $11 million and $8 million for the six months ended June 30, 2020 and $7 million and $3 million for the six months ended June 30, 2019, at Dominion Energy and Virginia Power, respectively.


2)

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

3)

Amounts above include alternative revenue of $39 million and $21 million at Dominion Energy and $34 million and $18 million at Virginia Power for the three months ended June 30, 2020 and 2019, respectively, and $75 million and $35 million at Dominion Energy and $51 million and $26 million at Virginia Power for the six months ended June 30, 2020 and 2019, respectively.

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 June 30, 2020

 

2020

 

 

2021

 

 

2022

 

 

2023

 

 

2024

 

 

Thereafter

 

 

Total

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dominion Energy

 

$

823

 

 

$

1,567

 

 

$

1,475

 

 

$

1,315

 

 

$

1,190

 

 

$

13,095

 

 

$

19,465

 

Virginia Power

 

 

2

 

 

 

1

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

3

 

Dominion Energy Gas

 

 

899

 

 

 

1,719

 

 

 

1,585

 

 

 

1,402

 

 

 

1,248

 

 

 

13,280

 

 

 

20,133

 

Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. At June 30, 2020 and December 31, 2019, Dominion Energy’s contract asset balances were $25 million and $28 million, respectively. Dominion Energy Gas’ contract asset balances were $35 million and $40 million at June 30, 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 June 30, 2020 and December 31, 2019, Dominion Energy’s contract liability balances were $109 million and $123 million, respectively. At June 30, 2020 and December 31, 2019, Virginia Power’s contract liability balances were $37 million and $24 million, respectively. At June 30, 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 six months ended June 30, 2020 and 2019 Dominion Energy recognized revenue of $106 million and $91 million, respectively, from the beginning contract liability balances. During the six months ended June 30, 2020 and 2019, Virginia Power recognized $24 million and $22 million, respectively, from the beginning contract liability balance. During the six months ended June 30, 2020 and 2019, Dominion Energy Gas recognized $1 million and $28 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

 

 

Six Months Ended June 30,

 

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

 

 

5.6

 

 

 

0.7

 

 

 

4.9

 

 

 

4.7

 

 

 

(255.3

)

 

 

3.0

 

 

Investment tax credits

 

 

3.9

 

 

 

(3.8

)

 

 

(11.3

)

 

 

(5.2

)

 

 

—

 

 

 

—

 

 

Production tax credits

 

 

0.3

 

 

 

(1.1

)

 

 

(2.0

)

 

 

(0.8

)

 

 

—

 

 

 

—

 

 

Reversal of excess deferred income

   taxes

 

 

1.5

 

 

 

(6.9

)

 

 

(0.8

)

 

 

(4.2

)

 

 

(68.4

)

 

 

(0.9

)

 

Write-off of regulatory assets

 

 

(4.2

)

 

 

(41.6

)

 

 

—

 

 

 

—

 

 

 

189.4

 

 

 

—

 

 

AFUDC - equity

 

 

0.5

 

 

 

(1.9

)

 

 

(0.6

)

 

 

(0.1

)

 

 

(36.8

)

 

 

(0.5

)

 

Other, net

 

 

0.9

 

 

 

(0.3

)

 

 

1.1

 

 

 

0.4

 

 

 

(467.1

)

(1)

 

(4.3

)

(1)

Effective tax rate

 

 

29.5

%

 

 

(33.9

)%

 

 

12.3

%

 

 

15.8

%

 

 

(617.2

)%

 

 

18.3

%

 

(1)

Includes (276.0)% and (4.0)% 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 a liquefied natural gas ("LNG") export, import 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.

31

Results of Operations for the Second Quarter and First Six Months of 2021 and 2020

Overview

Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):
Second QuarterFirst Six Months
20212020Change20212020Change
Operating revenue:
PacifiCorp$1,298 $1,144 $154 13 %$2,540 $2,350 $190 8 %
MidAmerican Funding693 616 77 13 1,760 1,302 458 35 
NV Energy767 695 72 10 1,358 1,317 41 3 
Northern Powergrid280 221 59 27 580 487 93 19 
BHE Pipeline Group706 225 481 *1,799 626 1,173 *
BHE Transmission182 169 13 8 362 341 21 6 
BHE Renewables267 244 23 9 457 422 35 8 
HomeServices1,763 1,193 570 48 2,995 2,086 909 44 
BHE and Other108 105 3 3 294 208 86 41 
Total operating revenue$6,064 $4,612 $1,452 31 %$12,145 $9,139 $3,006 33 %
Earnings on common shares:
PacifiCorp$226 $167 $59 35 %$395 $343 $52 15 %
MidAmerican Funding211 208 3 1 355 358 (3)(1)
NV Energy100 98 2 2 134 118 16 14 
Northern Powergrid(25)59 (84)*79 146 (67)(46)
BHE Pipeline Group100 64 36 56 483 243 240 99 
BHE Transmission60 60 — — 119 115 4 3 
BHE Renewables(1)
181 138 43 31 197 233 (36)(15)
HomeServices135 59 76 *219 69 150 *
BHE and Other1,256 263 993 *229 161 68 42
Earnings on common shares$2,244 $1,116 $1,128 *$2,210 $1,786 $424 24 %

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

*    Not meaningful

Earnings on common shares increased $1,128 million for the second quarter of 2021 compared to 2020. The second quarter of 2021 included a pre-tax unrealized gain of $1,954 million ($1,420 million after-tax) compared to a pre-tax unrealized gain in the second quarter of 2020 of $562 million ($408 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 second quarter of 2021 was $824 million, an increase of $116 million, or 16%, compared to adjusted earnings on common shares in the second quarter of 2020 of $708 million.
Earnings on common shares increased $424 million for the first six months of 2021 compared to 2020. The first six months of 2021 included a pre-tax unrealized gain of $830 million ($602 million after-tax) compared to a pre-tax unrealized gain in the first six months of 2020 of $615 million ($447 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 six months of 2021 was $1,608 million, an increase of $269 million, or 20%, compared to adjusted earnings on common shares in the first six months of 2020 of $1,339 million.


32

The increases in earnings on common shares for the second quarter and for the first six months of 2021 compared to 2020 were primarily due to the following:
•The Utilities' net income increased $64 million for the second quarter and $65 million for the first six months of 2021 compared to 2020, reflecting higher electric utility margin and favorable income tax expense from higher PTCs recognized and the impacts of ratemaking, partially offset by higher depreciation and amortization expense and higher operations and maintenance expense. Electric retail customer volumes increased 5.7% for the first six months of 2021 compared to 2020, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers;
•Northern Powergrid's net income decreased $84 million for the second quarter and $67 million for the first six months of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to the enactment in the second quarter of 2021 of an increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by higher distribution revenue;
•BHE Pipeline Group's net income increased $36 million for the second quarter and $240 million for the first six months of 2021 compared to 2020, largely due to $66 million and $173 million, respectively, of incremental net income from BHE GT&S, acquired in November 2020. In addition, net income for the first six months increased from the effects of higher margins on natural gas sales and higher transportation revenue at Northern Natural Gas, largely due to the favorable impacts of the February 2021 polar vortex weather event;
•BHE Renewables' net income increased $43 million for the second quarter and decreased $36 million for the first six months of 2021 compared to 2020. The changes were primarily due to earnings from tax equity investment projects reaching commercial operation and higher operating revenue from owned renewable energy projects, with the first six months being negatively impacted by lower tax equity investment earnings from the February 2021 polar vortex weather event;
•HomeServices' net income increased $76 million for the second quarter and $150 million for the first six months of 2021 compared to 2020, reflecting higher earnings from brokerage services due to comparative increases in closed transaction volumes and higher earnings from mortgage services from an unfavorable 2020 contingent earn-out remeasurement and higher funded mortgage volume for the first six months; and
•BHE and Other's net income increased $993 million for the second quarter and $68 million for the first six months of 2021 compared to 2020, mainly due to $1,012 million and $155 million, respectively, of favorable changes in the after-tax unrealized position of the Company's investment in BYD Company Limited, partially offset by dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020.

Reportable Segment Results

PacifiCorp

Operating revenue increased $154 million for the second quarter of 2021 compared to 2020, primarily due to higher retail revenue of $124 million and higher wholesale and other revenue of $30 million. Retail revenue increased due to higher customer volumes of $132 million, partially offset by price impacts of $8 million from lower rates due to certain general rate case orders. Retail customer volumes increased 11.6%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers. Wholesale and other revenue increased primarily due to higher wheeling revenue and wholesale volumes, partially offset by lower average wholesale market prices.

Net income increased $59 million for the second quarter of 2021 compared to 2020, primarily due to higher utility margin of $96 million, favorable income tax expense, from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and lower property taxes of $9 million, partially offset by higher depreciation and amortization expense of $65 million, including the impacts of a depreciation study effective January 1, 2021, lower allowances for equity and borrowed funds used during construction of $17 million and higher operations and maintenance expense of $12 million. Utility margin increased primarily due to the higher retail, wheeling and wholesale revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power costs and higher thermal generation costs.

Operating revenue increased $190 million for the first six months of 2021 compared to 2020, primarily due to higher retail revenue of $144 million and higher wholesale and other revenue of $46 million. Retail revenue increased due to higher customer volumes of $148 million, partially offset by price impacts of $4 million from lower rates due to certain general rate case orders. Retail customer volumes increased 5.7%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers. Wholesale and other revenue increased primarily due to higher wholesale volumes, higher wheeling revenue and higher average wholesale market prices.
33

Net income increased $52 million for the first six months of 2021 compared to 2020, primarily due to higher utility margin of $125 million and favorable income tax expense from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking, partially offset by higher depreciation and amortization expense of $77 million, including the impacts of a depreciation study effective January 1, 2021, lower allowances for equity and borrowed funds used during construction of $29 million and higher operations and maintenance expense of $17 million. Utility margin increased primarily due to the higher retail, wholesale and wheeling revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher thermal generation costs and higher purchased power costs.

MidAmerican Funding

Operating revenue increased $77 million for the second quarter of 2021 compared to 2020, primarily due to higher electric operating revenue of $68 million and higher natural gas operating revenue of $11 million. Electric operating revenue increased due to higher retail revenue of $48 million and higher wholesale and other revenue of $20 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to higher customer volumes of $30 million, higher recoveries through adjustment clauses of $16 million (largely offset in cost of sales), and price impacts of $2 million from changes in sales mix. Electric retail customer volumes increased 9.2% due to increased usage of certain industrial customers and the favorable impact of weather. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $17 million (offset in cost of sales), partially offset by a 4.8% decrease in customer volumes.

Net income increased $3 million for the second quarter of 2021 compared to 2020, primarily due to higher electric utility margin of $36 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $34 million, from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020, and unfavorable changes in the cash surrender value of corporate-owned life insurance policies. 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 primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs.

Operating revenue increased $458 million for the first six months of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $314 million and higher electric operating revenue of $142 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $321 million (offset in cost of sales), primarily due to the February 2021 polar vortex weather event, partially offset by a 1.3% decrease in customer volumes. Electric operating revenue increased due to higher retail revenue of $90 million and higher wholesale and other revenue of $52 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $48 million (largely offset in cost of sales), higher customer volumes of $35 million and price impacts of $7 million from changes in sales mix. Electric retail customer volumes increased 7.0% due to increased usage of certain industrial customers and the favorable impact of weather.

Net income decreased $3 million for the first six months of 2021 compared to 2020, primarily due to higher depreciation and amortization expense of $65 million, from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020, and $30 million higher operations and maintenance expenses, partially offset by higher electric utility margin of $39 million, 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 primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs.

NV Energy

Operating revenue increased $72 million for the second quarter of 2021 compared to 2020 due to higher electric operating revenue, which increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $77 million, higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers, partially offset by lower base tariff general rates of $15 million at Nevada Power. Electric retail customer volumes increased 11.2%, primarily due to the impacts from COVID-19 recovery and the favorable impact of weather.

34

Net income increased $2 million for the second quarter of 2021 compared to 2020, primarily due to lower income tax expense from the impacts of ratemaking and lower interest expense of $6 million, partially offset by higher depreciation and amortization expense of $12 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service, and lower electric utility margin of $4 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers.

Operating revenue increased $41 million for the first six months of 2021 compared to 2020, primarily due to higher electric operating revenue of $51 million, partially offset by lower natural gas operating revenue of $10 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $73 million, higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers, partially offset by lower base tariff general rates of $24 million at Nevada Power. Electric retail customer volumes increased 4.4%, primarily due to the impacts from COVID-19 recovery and the favorable impact of weather. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold (offset in cost of sales).

Net income increased $16 million for the first six months of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $21 million, primarily from lower regulatory instructed deferrals and amortizations, lower income tax expense from the impacts of ratemaking, lower interest expense of $12 million, lower pension costs and favorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by higher depreciation and amortization expense of $24 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service, and lower electric utility margin of $22 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers.

Northern Powergrid

Operating revenue increased $59 million for the second quarter of 2021 compared to 2020, primarily due to $31 million from the weaker United States dollar and higher distribution revenue of $26 million, mainly from 10.9% higher units distributed of $16 million and increased tariff rates of $9 million.

Net income decreased $84 million for the second quarter of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to an enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by the higher distribution revenue.

Operating revenue increased $93 million for the first six months of 2021 compared to 2020, primarily due to $52 million from the weaker United States dollar and higher distribution revenue of $39 million, mainly from increased tariff rates of $19 million and 4.7% higher units distributed of $16 million.

Net income decreased $67 million for the first six months of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to an enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by the higher distribution revenue and $6 million from the weaker United States dollar.

BHE Pipeline Group

Operating revenue increased $481 million for the second quarter of 2021 compared to 2020, primarily due to $487 million of incremental revenue at BHE GT&S, acquired in November 2020, and higher gas sales at Northern Natural Gas of $14 million (largely offset in cost of sales), partially offset by lower transportation revenue of $27 million at Northern Natural Gas, primarily due to lower volumes and rates.

Net income increased $36 million for the second quarter of 2021 compared to 2020, primarily due to $66 million of incremental net income at BHE GT&S, partially offset by lower earnings of $34 million at Northern Natural Gas, largely due to the lower transportation revenue and a favorable adjustment in 2020 from a rate case settlement.

Operating revenue increased $1,173 million for the first six months of 2021 compared to 2020, primarily due to $1,047 million of incremental revenue at BHE GT&S, higher gas sales of $77 million and higher transportation revenue of $49 million at Northern Natural Gas, each due to the favorable impacts of the February 2021 polar vortex weather event, and higher gas sales at Northern Natural Gas of $28 million (largely offset in cost of sales), partially offset by lower transportation revenue of $50 million at Northern Natural Gas, primarily due to lower volumes and rates.

35

Net income increased $240 million for the first six months of 2021 compared to 2020, primarily due to $173 million of incremental net income at BHE GT&S and higher earnings of $64 million at Northern Natural Gas. Northern Natural Gas' improved performance was primarily due to higher gross margin on gas sales and higher transportation revenue, each due to the favorable impacts of the February 2021 polar vortex weather event, partially offset by the lower transportation revenue due to lower volumes and rates.

BHE Transmission

Operating revenue increased $13 million for the second quarter of 2021 compared to 2020, primarily due to $20 million from the stronger United States dollar, partially offset by the impacts of favorable regulatory decisions received in April and November 2020 at AltaLink.

Operating revenue increased by $21 million for the first six months of 2021 compared to 2020, primarily due to $31 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 favorable regulatory decisions received in April and November 2020 at AltaLink.

Net income increased $4 million for the first six months of 2021 compared to 2020, primarily due to $8 million from the stronger United States dollar, higher earnings from the Montana-Alberta Tie-Line and lower non-regulated interest expense at BHE Canada, partially offset by the impacts of favorable regulatory decisions received in April and November 2020 at AltaLink.
BHE Renewables

Operating revenue increased $23 million for the second quarter of 2021 compared to 2020, primarily due to higher natural gas, solar, geothermal and wind revenues from higher generation as well as higher capacity payments at a natural gas facility, partially offset by an unfavorable change in the valuation of a power purchase agreement of $12 million.

Net income increased $43 million for the second quarter 2021 compared to 2020, primarily due to higher wind earnings of $32 million, largely from tax equity investment projects reaching commercial operation, and higher solar earnings of $9 million, mainly due to the higher operating revenue and lower depreciation expense.

Operating revenue increased $35 million for the first six months of 2021 compared to 2020, primarily due to higher natural gas, solar, geothermal, hydro and wind revenues from higher generation, as well higher capacity payments at a natural gas facility and favorable pricing at the geothermal facilities, partially offset by an unfavorable change in the valuation of a power purchase agreement of $14 million.

Net income decreased $36 million for the first six months of 2021 compared to 2020, primarily due to lower wind earnings of $62 million, largely from lower tax equity investment earnings of $58 million, partially offset by higher solar earnings of $16 million, mainly due to the higher operating revenue and lower depreciation expense, and higher geothermal earnings of $11 million. Tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $134 million, primarily due to the February 2021 polar vortex weather event, partially offset by $78 million of earnings from projects reaching commercial operation. Geothermal earnings increased primarily due to higher natural gas margins and the higher geothermal revenue, partially offset by higher operations and maintenance expense.

HomeServices

Operating revenue increased $570 million for the second quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $589 million from a 72% increase in closed transaction volume resulting from increases in closed units and average sales price, partially offset by lower mortgage revenue of $51 million due to a 62% decrease in refinance activity.

Net income increased $76 million for the second quarter of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $54 million, largely due to the increase in closed transaction volume, and mortgage services of $12 million, largely attributable to an unfavorable 2020 contingent earn-out remeasurement offset by the decrease in refinancing activity.

Operating revenue increased $909 million for the first six months of 2021 compared to 2020, primarily due to higher brokerage revenue of $816 million from a 56% increase in closed transaction volume, resulting from increases in closed units and average sales price, and higher mortgage revenue of $41 million from a 26% increase in funded mortgage volume.
36

Net income increased $150 million for the first six months of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $79 million, largely due to the increase in closed transaction volume, and mortgage services of $48 million, largely attributable to an unfavorable 2020 contingent earn-out remeasurement and the increase in funded mortgage volume.

BHE and Other

Operating revenue increased $3 million for the second quarter of 2021 compared to 2020, primarily due to higher electricity sales revenue at MidAmerican Energy Services, LLC, from higher volumes offset by unfavorable pricing.

Net income increased $993 million for the second quarter of 2021 compared to 2020, primarily due to the $1,012 million favorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $48 million of higher federal income tax credits recognized on a consolidated basis and higher net income of $8 million at MidAmerican Energy Services, LLC, partially offset by higher other corporate costs, $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 unfavorable changes in the cash surrender value of corporate-owned life insurance policies.

Operating revenue increased $86 million for the first six months 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 income increased $68 million for the first six months of 2021 compared to 2020, primarily due to the $155 million favorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $42 million of higher federal income tax credits recognized on a consolidated basis, favorable changes in the cash surrender value of corporate-owned life insurance policies and higher net income of $12 million at MidAmerican Energy Services, LLC, partially offset by $75 million of dividends on BHE's 4.00% Perpetual Preferred Stock, higher other corporate costs and higher BHE corporate interest expense.

37

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, 20192020 for more information.further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of June 30, 2021, the Company's total net liquidity was as follows (in millions):
MidAmericanNVNorthernBHE
BHEPacifiCorpFundingEnergyPowergridCanadaOtherTotal
Cash and cash equivalents$526 $44 $31 $79 $17 $57 $577 $1,331 
Credit facilities3,500 1,200 1,509 650 222 867 3,541 11,489 
Less:
Short-term debt— (301)— (74)(15)(262)(1,884)(2,536)
Tax-exempt bond support and letters of credit— (218)(370)— — (1)— (589)
Net credit facilities3,500 681 1,139 576 207 604 1,657 8,364 
Total net liquidity$4,026 $725 $1,170 $655 $224 $661 $2,234 $9,695 
Credit facilities:
Maturity dates202420242022, 2024202420232022, 20252021, 2022



38

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $4.2 billion and $1.9 billion, respectively. The increase was primarily due to favorable income tax cash flows, improved operating results and 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 six-month periods ended June 30, 2021 and 2020 were $(3.0) billion and $(3.8) billion, respectively. The change was primarily due to lower funding of tax equity investments, partially offset by higher capital expenditures of $55 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2021 was $(1.2) billion. Uses of cash totaled $2.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.2 billion, repayments of BHE senior debt totaling $450 million and distributions to noncontrolling interests of $234 million. Sources of cash totaled $793 million and consisted primarily of proceeds from subsidiary debt issuances totaling $539 million and net proceeds from short-term debt totaling $245 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 six monthssix-month period ended June 30, 2020 Dominion Energy’s effectivewas $2.8 billion. Sources of cash totaled $5.7 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.4 billion. Uses of cash totaled $2.9 billion and consisted mainly of repayments of subsidiary debt totaling $1.4 billion, net repayments of short-term debt totaling $920 million, 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 rate reflects a chargelaws; general business conditions; load projections; system reliability standards; the cost and efficiency of $81construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.

39

The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Six-Month PeriodsAnnual
Ended June 30,Forecast
202020212021
Capital expenditures by business:
PacifiCorp$973 $819 $1,782 
MidAmerican Funding824 720 2,170 
NV Energy366 365 842 
Northern Powergrid312 369 760 
BHE Pipeline Group196 308 1,225 
BHE Transmission222 156 269 
BHE Renewables26 80 181 
HomeServices14 18 37 
BHE and Other(1)
(140)13 78 
Total$2,793 $2,848 $7,344 
Capital expenditures by type:
Wind generation$718 $483 $1,156 
Electric distribution743 817 1,842 
Electric transmission527 339 919 
Natural gas transmission and storage178 308 1,099 
Solar generation1 67 288 
Other626 834 2,040 
Total$2,793 $2,848 $7,344 

(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 $172 million for 2021 and $388 million for 2020. Planned spending for the construction of additional wind-powered generating facilities totals $198 million for the write-offremainder of tax-related regulatory assets2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $82 million for 2021 and $19 million for 2020. Planned spending for repowering generating facilities totals $284 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 June 30, 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.
40

◦Construction of wind-powered generating facilities at PacifiCorp totaling $79 million and $395 million for the six-month periods ended June 30, 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 impactsconstruction of wind-powered generating facilities will total an additional $39 million for 2021.
◦Repowering of wind-powered generating facilities at PacifiCorp totaling $3 million and $46 million for the six-month periods ended June 30, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first six months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the cancellationfederal PTCs available for 10 years following each facility's return to service. Planned additional spending for repowering of wind-powered generating facilities totals $47 million for 2021.
◦Construction of wind-powered generating facilities at BHE Renewables totaling $55 million for the Atlantic Coast Pipeline Projectsix-month period ended June 30, 2021. In May 2021, BHE Renewables completed the asset acquisition of a 54 MW wind-powered generating facility located in Iowa. BHE Renewables anticipates costs to complete construction of this facility will total an additional $30 million in 2021.
•Electric distribution includes both growth and related portions ofoperating expenditures. Growth expenditures include new customer connections and enhancements to existing customer connections. Operating expenditures include ongoing distribution systems infrastructure needed at the Supply Header Project.  In addition, Dominion Energy Gas’ effective tax rateUtilities 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 functionmajor segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020, the nominal year-to-date pre-tax income drivenNevada 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 Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, asset modernization, pipeline integrity projects and natural gas transmission, storage and liquefied natural gas terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including MidAmerican Energy's current plan for the construction of 141 MWs of small- and utility-scale solar generation during 2021, of which 61 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 a charge associatedthe 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.
41

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 Supply Header Projectproject sponsors that require contributions. The Company has made no contributions for the six-month period ended June 30, 2021, and has commitments as discussed in Note 2.

In March 2020, the CARES Act was enacted which includes several significant business tax provisions that modify or temporarily suspend certain provisions of the 2017 Tax Reform Act.  The CARES Act provisions are intendedJune 30, 2021, subject 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 recognitionsatisfaction of certain tax attributes, where applicable, they are not expectedspecified conditions, to provide equity contributions of $766 million for the remainder of 2021 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a material benefit.

In July 2020,project achieves commercial operation, the U.S. Department of Treasury issued final regulations providing guidance about the limitation on the deduction for business interest expenses and issued proposed regulations on the application of these rules to certain pass-through entities and partners in those entities under the 2017 Tax Reform Act as modified by the CARES Act.  Dominion Energy is currently assessing the impact of these regulations, but expects interest expense to be deductible in 2020.

In connectionCompany enters into a partnership agreement with the SCANA Combination, Dominion Energy committed to forgo, or limit,project sponsor that directs and allocates the recovery of certain income tax-related regulatory assets associated with the NND Project.  Dominion Energy’s 2019 effectiveoperating profits and 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 resultingbenefits from the SCANA Combination.

project.


Contractual Obligations

As of June 30, 2020,2021, 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 duringinformation 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.

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 discussioncompliance 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 these unrecognized tax benefits.

Note 6. Earnings Per Share

The following table presentsthe 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.


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 basicMOPR 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 diluted EPS:

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Dominion Energy

 

$

(1,169

)

 

$

54

 

 

$

(1,439

)

 

$

(626

)

Preferred stock dividends (see Note 16)

 

 

(16

)

 

 

—

 

 

 

(32

)

 

 

—

 

Net income (loss) attributable to Dominion Energy – Basic

 

 

(1,185

)

 

 

54

 

 

 

(1,471

)

 

 

(626

)

Dilutive effect of Series A Preferred Stock

 

 

—

 

 

 

(13

)

 

 

—

 

 

 

—

 

Net income (loss) attributable to Dominion Energy - Diluted

 

 

(1,185

)

 

 

41

 

 

 

(1,471

)

 

 

(626

)

Average shares of common stock outstanding – Basic &

    Diluted

 

 

839.4

 

 

 

802.5

 

 

 

838.8

 

 

 

797.8

 

Net effect of dilutive securities

 

 

—

 

 

 

0.1

 

 

 

—

 

 

 

—

 

Average shares of common stock outstanding – Diluted

 

 

839.4

 

 

 

802.6

 

 

 

838.8

 

 

 

797.8

 

Earnings Per Common Share – Basic

 

$

(1.41

)

 

$

0.07

 

 

$

(1.75

)

 

$

(0.78

)

Earnings Per Common Share – Diluted

 

$

(1.41

)

 

$

0.05

 

 

$

(1.75

)

 

$

(0.78

)

Asrelated services, which will then be used in calculating a resultnumber of a net lossparameters 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 three and six months ended June 30, 2020new revenue projection methodology, and the six months ended June 30, 2019, any adjustmentstiming for commencing the capacity auction schedule.


42

Exelon Generation is currently working with the PJM and other stakeholders to earningspursue 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 shareswhen such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station.

In May 2021, the PJM conducted its capacity auction as scheduled, and because Illinois has not implemented an FRR program, the MOPR applied to Quad Cities Station in the capacity auction. The MOPR prevented Quad Cities Station from clearing in the auction.

Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be considered antidilutive and are therefore excludedat heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism under which Quad Cities Station would be removed from the calculationPJM's capacity auction. At the direction of diluted EPS. The 2019 Equity Unitsthe PJM Board of Managers, the PJM and its stakeholders are potentially dilutive securities. The forward stock purchase contracts included withinconsidering MOPR reforms to ensure that the 2019 Equity Units were excluded from the calculation of diluted EPS for the three months ended June 30, 2019,capacity market rules respect and accommodate state resource preferences such as the dilutive stock price threshold was not met.ZEC programs, which the PJM filed at the FERC on July 30, 2021.

Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The Series A Preferred Stock included within the 2019 Equity Units is excluded from the effectdiscussion below contains material developments to those matters disclosed in Item 1 of dilutive securities within diluted EPS, but a fair value adjustment is reflected within net income attributable to Dominion Energy for the calculation of diluted EPS for the three months ended June 30, 2019, based upon the expectation that the conversion will be settled in cash rather than through the


issuance of Dominion Energy common stock. The 2016 Equity Units are potentially dilutive securities, but were excluded from the calculation of diluted EPS for the three months ended June 30, 2019 as the dilutive stock price threshold was not met.

Note 7. Accumulated Other Comprehensive Income

Dominion Energy

The following table presents Dominion Energy’s 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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(651

)

 

$

37

 

 

$

(1,402

)

 

$

(2

)

 

$

(2,018

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

2

 

 

 

19

 

 

 

(1

)

 

 

—

 

 

 

20

 

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

 

 

5

 

 

 

(5

)

 

 

18

 

 

 

—

 

 

 

18

 

Net current period other comprehensive income (loss)

 

 

7

 

 

 

14

 

 

 

17

 

 

 

—

 

 

 

38

 

Ending balance

 

$

(644

)

 

$

51

 

 

$

(1,385

)

 

$

(2

)

 

$

(1,980

)

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(290

)

 

$

18

 

 

$

(1,457

)

 

$

(2

)

 

$

(1,731

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(78

)

 

 

13

 

 

 

113

 

 

 

—

 

 

 

48

 

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

 

 

(21

)

 

 

(1

)

 

 

22

 

 

 

—

 

 

 

—

 

Net current period other comprehensive income (loss)

 

 

(99

)

 

 

12

 

 

 

135

 

 

 

—

 

 

 

48

 

Ending balance

 

$

(389

)

 

$

30

 

 

$

(1,322

)

 

$

(2

)

 

$

(1,683

)

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(407

)

 

$

37

 

 

$

(1,421

)

 

$

(2

)

 

$

(1,793

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(264

)

 

 

28

 

 

 

(1

)

 

 

—

 

 

 

(237

)

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

 

 

27

 

 

 

(14

)

 

 

37

 

 

 

—

 

 

 

50

 

Net current period other comprehensive income (loss)

 

 

(237

)

 

 

14

 

 

 

36

 

 

 

—

 

 

 

(187

)

Ending balance

 

$

(644

)

 

$

51

 

 

$

(1,385

)

 

$

(2

)

 

$

(1,980

)

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(235

)

 

$

2

 

 

$

(1,465

)

 

$

(2

)

 

$

(1,700

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(102

)

 

 

29

 

 

 

113

 

 

 

—

 

 

 

40

 

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

 

 

(52

)

 

 

(1

)

 

 

30

 

 

 

—

 

 

 

(23

)

Net current period other comprehensive income (loss)

 

 

(154

)

 

 

28

 

 

 

143

 

 

 

—

 

 

 

17

 

Ending balance

 

$

(389

)

 

$

30

 

 

$

(1,322

)

 

$

(2

)

 

$

(1,683

)

(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 June 30, 2020

 

 

 

 

 

 

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

 

 

 

 

 

 

Commodity contracts

 

$

(9

)

 

Operating revenue

Interest rate contracts

 

 

22

 

 

Interest and related charges

Foreign currency contracts

 

 

(6

)

 

Other income

Total

 

 

7

 

 

 

Tax

 

 

(2

)

 

Income tax expense (benefit)

Total, net of tax

 

$

5

 

 

 

Unrealized (gains) and losses on investment securities:

 

 

 

 

 

 

Realized (gains) losses on sale of securities

 

$

(5

)

 

Other income

Total

 

 

(5

)

 

 

Tax

 

 

—

 

 

Income tax expense (benefit)

Total, net of tax

 

$

(5

)

 

 

Unrecognized pension and other postretirement benefit costs:

 

 

 

 

 

 

Amortization of prior-service costs (credits)

 

$

(5

)

 

Other income

Amortization of actuarial losses

 

 

31

 

 

Other income

Total

 

 

26

 

 

 

Tax

 

 

(8

)

 

Income tax expense (benefit)

Total, net of tax

 

$

18

 

 

 

Three Months Ended June 30, 2019

 

 

 

 

 

 

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

 

 

 

 

 

 

Commodity contracts

 

$

(38

)

 

Operating revenue

Interest rate contracts

 

 

13

 

 

Interest and related charges

Foreign currency contracts

 

 

(4

)

 

Other income

Total

 

 

(29

)

 

 

Tax

 

 

8

 

 

Income tax expense (benefit)

Total, net of tax

 

$

(21

)

 

 

Unrealized (gains) and losses on investment securities:

 

 

 

 

 

 

Realized (gains) losses on sale of securities

 

$

(1

)

 

Other income

Total

 

 

(1

)

 

 

Tax

 

 

—

 

 

Income tax expense (benefit)

Total, net of tax

 

$

(1

)

 

 

Unrecognized pension and other postretirement benefit costs:

 

 

 

 

 

 

Amortization of prior-service costs (credits)

 

$

(8

)

 

Other income

Amortization of actuarial losses

 

 

27

 

 

Other income

Total

 

 

19

 

 

 

Tax

 

 

3

 

 

Income tax expense (benefit)

Total, net of tax

 

$

22

 

 

 


Details about AOCI components

 

Amounts

reclassified

from AOCI

 

 

Affected line item in the

Consolidated Statements of

Income

(millions)

 

 

 

 

 

 

Six Months Ended June 30, 2020

 

 

 

 

 

 

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

 

 

 

 

 

 

Commodity contracts

 

$

(16

)

 

Operating revenue

 

 

 

3

 

 

Purchased gas

Interest rate contracts

 

 

49

 

 

Interest and related charges

Total

 

 

36

 

 

 

Tax

 

 

(9

)

 

Income tax expense (benefit)

Total, net of tax

 

$

27

 

 

 

Unrealized (gains) and losses on investment securities:

 

 

 

 

 

 

Realized (gains) losses on sale of securities

 

$

(18

)

 

Other income

Total

 

 

(18

)

 

 

Tax

 

 

4

 

 

Income tax expense (benefit)

Total, net of tax

 

$

(14

)

 

 

Unrecognized pension and other postretirement benefit costs:

 

 

 

 

 

 

Amortization of prior-service costs (credits)

 

$

(11

)

 

Other income

Amortization of actuarial losses

 

 

61

 

 

Other income

Total

 

 

50

 

 

 

Tax

 

 

(13

)

 

Income tax expense (benefit)

Total, net of tax

 

$

37

 

 

 

Six Months Ended June 30, 2019

 

 

 

 

 

 

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

 

 

 

 

 

 

Commodity contracts

 

$

(92

)

 

Operating revenue

 

 

 

(3

)

 

Purchased gas

Interest rate contracts

 

 

23

 

 

Interest and related charges

Foreign currency contracts

 

 

2

 

 

Other income

Total

 

 

(70

)

 

 

Tax

 

 

18

 

 

Income tax expense (benefit)

Total, net of tax

 

$

(52

)

 

 

Unrealized (gains) and losses on investment securities:

 

 

 

 

 

 

Realized (gains) losses on sale of securities

 

$

(1

)

 

Other income

Total

 

 

(1

)

 

 

Tax

 

 

—

 

 

Income tax expense (benefit)

Total, net of tax

 

$

(1

)

 

 

Unrecognized pension and other postretirement benefit costs:

 

 

 

 

 

 

Amortization of prior-service costs (credits)

 

$

(13

)

 

Other income

Amortization of actuarial losses

 

 

54

 

 

Other income

Total

 

 

41

 

 

 

Tax

 

 

(11

)

 

Income tax expense (benefit)

Total, net of tax

 

$

30

 

 

 


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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(79

)

 

$

4

 

 

$

(75

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

1

 

 

 

6

 

 

 

7

 

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

 

 

—

 

 

 

(2

)

 

 

(2

)

Net current period other comprehensive income (loss)

 

 

1

 

 

 

4

 

 

 

5

 

Ending balance

 

$

(78

)

 

$

8

 

 

$

(70

)

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(20

)

 

$

3

 

 

$

(17

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(11

)

 

 

2

 

 

 

(9

)

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

 

 

1

 

 

 

(1

)

 

 

—

 

Net current period other comprehensive income (loss)

 

 

(10

)

 

 

1

 

 

 

(9

)

Ending balance

 

$

(30

)

 

$

4

 

 

$

(26

)

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(34

)

 

$

5

 

 

$

(29

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(44

)

 

 

4

 

 

 

(40

)

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

 

 

—

 

 

 

(1

)

 

 

(1

)

Net current period other comprehensive income (loss)

 

 

(44

)

 

 

3

 

 

 

(41

)

Ending balance

 

$

(78

)

 

$

8

 

 

$

(70

)

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(13

)

 

$

1

 

 

$

(12

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(18

)

 

 

4

 

 

 

(14

)

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

 

 

1

 

 

 

(1

)

 

 

—

 

Net current period other comprehensive income (loss)

 

 

(17

)

 

 

3

 

 

 

(14

)

Ending balance

 

$

(30

)

 

$

4

 

 

$

(26

)

(1)

See table below for details about these reclassifications. Virginia Power’s reclassifications out of AOCI were immaterial for both the three and six months ended June 30, 2019.


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 June 30, 2020

 

 

 

 

 

 

(Gains) losses on cash flow hedges:

 

 

 

 

 

 

Interest rate contracts

 

$

1

 

 

Interest and related charges

Total

 

 

1

 

 

 

Tax

 

 

(1

)

 

Income tax expense

Total, net of tax

 

$

—

 

 

 

Unrealized (gains) and losses on investment securities:

 

 

 

 

 

 

Realized (gains) losses on sale of securities

 

$

(4

)

 

Other income

Total

 

 

(4

)

 

 

Tax

 

 

2

 

 

Income tax expense

Total, net of tax

 

$

(2

)

 

 

Six Months Ended June 30, 2020

 

 

 

 

 

 

(Gains) losses on cash flow hedges:

 

 

 

 

 

 

Interest rate contracts

 

 

1

 

 

Interest and related charges

Total

 

 

1

 

 

 

Tax

 

 

(1

)

 

Income tax expense

Total, net of tax

 

$

—

 

 

 

Unrealized (gains) and losses on investment securities:

 

 

 

 

 

 

Realized (gains) losses on sale of securities

 

$

(2

)

 

Other income

Total

 

 

(2

)

 

 

Tax

 

 

1

 

 

Income tax expense

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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(166

)

 

$

(105

)

 

$

(271

)

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

 

 

(2

)

 

 

2

 

 

 

—

 

Net current period other comprehensive income (loss)

 

 

(2

)

 

 

2

 

 

 

—

 

Ending balance

 

$

(168

)

 

$

(103

)

 

$

(271

)

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(48

)

 

$

(143

)

 

$

(191

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(24

)

 

 

29

 

 

 

5

 

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

 

 

(2

)

 

 

2

 

 

 

—

 

Net current period other comprehensive income (loss)

 

 

(26

)

 

 

31

 

 

 

5

 

Ending balance

 

$

(74

)

 

$

(112

)

 

$

(186

)

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(81

)

 

$

(106

)

 

$

(187

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(91

)

 

 

—

 

 

 

(91

)

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

 

 

4

 

 

 

3

 

 

 

7

 

Net current period other comprehensive income (loss)

 

 

(87

)

 

 

3

 

 

 

(84

)

Ending balance

 

$

(168

)

 

$

(103

)

 

$

(271

)

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

(25

)

 

$

(144

)

 

$

(169

)

Other comprehensive income before reclassifications:

   gains (losses)

 

 

(51

)

 

 

29

 

 

 

(22

)

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

 

 

1

 

 

 

3

 

 

 

4

 

Net current period other comprehensive income (loss)

 

 

(50

)

 

 

32

 

 

 

(18

)

Less other comprehensive income (loss) attributable to noncontrolling interest

 

 

(1

)

 

 

—

 

 

 

(1

)

Ending balance

 

$

(74

)

 

$

(112

)

 

$

(186

)

(1)

See table below for details about these reclassifications.


The following table presents Dominion Energy Gas’ 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 June 30, 2020

 

 

 

 

 

 

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

 

 

 

 

 

 

Interest rate contracts

 

$

4

 

 

Interest and related charges

Foreign currency contracts

 

 

(6

)

 

Other income

Total

 

 

(2

)

 

 

Tax

 

 

—

 

 

Income tax expense (benefit)

Total, net of tax

 

$

(2

)

 

 

Unrecognized pension and other postretirement benefit costs:

 

 

 

 

 

 

Actuarial losses

 

$

2

 

 

Other income

Total

 

 

2

 

 

 

Tax

 

 

—

 

 

Income tax expense (benefit)

Total, net of tax

 

$

2

 

 

 

Three Months Ended June 30, 2019

 

 

 

 

 

 

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

 

 

 

 

 

 

Interest rate contracts

 

$

2

 

 

Interest and related charges

Foreign currency contracts

 

 

(4

)

 

Other income

Total

 

 

(2

)

 

 

Tax

 

 

—

 

 

Income tax expense (benefit)

Total, net of tax

 

$

(2

)

 

 

Unrecognized pension and other postretirement benefit costs:

 

 

 

 

 

 

Actuarial losses

 

$

2

 

 

Other income

Total

 

 

2

 

 

 

Tax

 

 

—

 

 

Income tax expense (benefit)

Total, net of tax

 

$

2

 

 

 

Six Months Ended June 30, 2020

 

 

 

 

 

 

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

 

 

 

 

 

 

Interest rate contracts

 

$

6

 

 

Interest and related charges

Total

 

 

6

 

 

 

Tax

 

 

(2

)

 

Income tax expense (benefit)

Total, net of tax

 

$

4

 

 

 

Unrecognized pension and other postretirement benefit costs:

 

 

 

 

 

 

Actuarial losses

 

$

4

 

 

Other income

Total

 

 

4

 

 

 

Tax

 

 

(1

)

 

Income tax expense (benefit)

Total, net of tax

 

$

3

 

 

 

Six Months Ended June 30, 2019

 

 

 

 

 

 

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

 

 

 

 

 

 

Commodity contracts

 

$

(2

)

 

Net income from discontinued operations

Interest rate contracts

 

 

1

 

 

Interest and related charges

Foreign currency contracts

 

 

2

 

 

Other income

Total

 

 

1

 

 

 

Tax

 

 

—

 

 

Income tax expense (benefit)

Total, net of tax

 

$

1

 

 

 

Unrecognized pension and other postretirement benefit costs:

 

 

 

 

 

 

Actuarial losses

 

$

4

 

 

Other income

Total

 

 

4

 

 

 

Tax

 

 

(1

)

 

Income tax expense (benefit)

Total, net of tax

 

$

3

 

 

 


Note 8. Fair Value Measurements

The Companies’ fair value measurements are made in accordance with the policies discussed in Note 6 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 Note 92020 and new regulatory matters occurring in this report2021.


PacifiCorp

Utah

In March 2020, PacifiCorp filed its annual Energy Balancing Account application with the UPSC requesting recovery of $37 million of deferred power costs from customers for further information about the Companies’ derivativesperiod January 1, 2019 through December 31, 2019, reflecting the difference between base and hedge accounting activities.

actual net power costs in the 2019 deferral period. This reflected a 1.0% increase compared to current rates. The Companies enter intoUPSC approved the request in February 2021 for rates effective March 1, 2021.


In March 2021, PacifiCorp filed its annual Energy Balancing Account application with the UPSC requesting recovery of $2 million of deferred net power costs from 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 reflected a $36 million reduction or 1.7% decrease compared to current rates. In June 2021, PacifiCorp updated the requested recovery to $7 million to correct certain physicalload related data reflected in the initial application. The updated recovery request reflects a $31 million reduction, or 1.5% decrease compared to current rates.

In August 2021, PacifiCorp filed an application with the UPSC for alternative cost recovery of a major plant addition to recover the incremental revenue requirement related to the delayed portions of the Pryor Mountain and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputsTB Flats wind-powered generating facilities that are not observablecurrently reflected in rates from the last general rate case. PacifiCorp's request results in a net decrease of $4 million, or 0.2%, in base rates effective January 1, 2022. Requested recovery of $7 million for the capital-related cost is offset by $7 million related to forecast PTCs and are significant$4 million in net power cost savings. Actual PTCs and net power cost will be trued-up in the Energy Balancing Account.

43

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 valuation.OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to the exclusion of the impacts of repowered wind-powered generating facilities, new wind-powered generating facilities and certain other new investments that had not been placed in service at the time of the filing. Additional compliance filings have been made to include these investments in rates concurrent with 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-powered generating 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-powered generating facility and the Pryor Mountain new wind-powered generating facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021.

In July 2021, in accordance with the OPUC's December 2020 general rate case order, PacifiCorp filed an application with the OPUC to initiate the review of PacifiCorp's estimated decommissioning and other closure costs per third-party studies associated with its coal-fueled generating facilities. The discounted cash flow method is usedapplication requested an initial rate increase of $35 million, or 2.8%, effective January 1, 2022, 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 modelrecover the incremental costs from those approved in the last general rate case.

Wyoming

In September 2018, PacifiCorp filed an application for forwards, futures and swaps calculates mark-to-market valuationsdepreciation rate changes with the WPSC based on forward market prices, original transaction prices, volumes, risk-freePacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Updates since September 2018 include the filing of returnPacifiCorp's 2020 decommissioning studies in which a third‑party consultant was engaged to estimate decommissioning costs associated with coal-fueled generating facilities and credit spreads.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 option model calculates mark-to-market valuations using variationsstipulation 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 Black-Scholes option model.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 was held in July 2021. Public deliberations are expected in August 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 inputs intoapplication also requested a revision to the models areECAM to eliminate the forward market prices, implied price volatilities, risk-freesharing 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 return, the option expiration dates,remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the option strike prices,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 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 sales pricesapplication 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 June 30,vacated the hearing that was scheduled for October 2020. The rangeWPSC re-noticed PacifiCorp's case and weighted average are presentedrescheduled the hearings. The hearings began February 2021 and were completed in dollars for market price inputsMarch 2021. In May 2021, the WPSC approved a $7 million base revenue requirement increase that includes the Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs and percentages for price volatility.

 

 

Fair Value

(millions)

 

 

Valuation Techniques

 

Unobservable Input

 

 

Range

 

Weighted

Average(1)

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Physical and financial forwards:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas(2)

 

$

112

 

 

Discounted cash flow

 

Market price (per Dth)

(3)

 

(2) - 3

 

 

(1

)

FTRs

 

 

18

 

 

Discounted cash flow

 

Market price (per MWh)

(3)

 

(1) - 5

 

 

1

 

Total assets

 

$

130

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial forwards:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

FTRs

 

$

5

 

 

Discounted cash flow

 

Market price (per MWh)

(3)

 

(5) - 5

 

 

—

 

Physical options:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

 

2

 

 

Option model

 

Market price (per Dth)

(3)

 

1 - 5

 

 

2

 

 

 

 

 

 

 

 

 

Price volatility

(4)

 

56% - 72%

 

 

66

%

Total liabilities

 

$

7

 

 

 

 

 

 

 

 

 

 

 

 

(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 measurementsrate design proposals 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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

$

—

 

 

$

52

 

 

$

130

 

 

$

182

 

Interest rate

 

 

—

 

 

 

34

 

 

 

—

 

 

 

34

 

Investments(1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

3,817

 

 

 

—

 

 

 

—

 

 

 

3,817

 

Fixed income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate debt instruments

 

 

—

 

 

 

624

 

 

 

—

 

 

 

624

 

Government securities

 

 

488

 

 

 

746

 

 

 

—

 

 

 

1,234

 

Cash equivalents and other

 

 

19

 

 

 

12

 

 

 

—

 

 

 

31

 

Total assets

 

$

4,324

 

 

$

1,468

 

 

$

130

 

 

$

5,922

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

$

—

 

 

$

43

 

 

$

7

 

 

$

50

 

Interest rate

 

 

—

 

 

 

1,272

 

 

 

—

 

 

 

1,272

 

Foreign currency

 

 

—

 

 

 

12

 

 

 

—

 

 

 

12

 

Total liabilities

 

$

—

 

 

$

1,327

 

 

$

7

 

 

$

1,334

 

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 $296 million and $274 million of assets at June 30, 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

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

43

 

 

$

53

 

 

$

(37

)

 

$

64

 

Total realized and unrealized gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Included in earnings:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

 

—

 

 

 

3

 

 

 

—

 

 

 

2

 

Purchased gas

 

 

—

 

 

 

1

 

 

 

—

 

 

 

1

 

Electric fuel and other energy-related purchases

 

 

(4

)

 

 

(3

)

 

 

(26

)

 

 

(7

)

Included in regulatory assets/liabilities

 

 

80

 

 

 

18

 

 

 

160

 

 

 

25

 

Settlements

 

 

4

 

 

 

3

 

 

 

26

 

 

 

2

 

Purchases

 

 

—

 

 

 

—

 

 

 

—

 

 

 

(10

)

Transfers out of Level 3

 

 

—

 

 

 

—

 

 

 

—

 

 

 

(2

)

Ending balance

 

$

123

 

 

$

75

 

 

$

123

 

 

$

75

 

The amount of total gains (losses) for the period included in

   earnings attributable to the change in unrealized gains

   (losses) relating to assets/liabilities still held at the

   reporting date:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

—

 

 

$

2

 

 

$

—

 

 

$

2

 

Purchased gas

 

 

—

 

 

 

1

 

 

 

—

 

 

 

1

 

Total

 

$

—

 

 

$

3

 

 

$

—

 

 

$

3

 

 There were no 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 and six months ended June 30, 2020 and 2019.

Virginia Power

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at June 30, 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)

 

$

112

 

 

Discounted cash flow

 

Market price (per Dth)

(3)

 

(2) - 2

 

 

(1

)

FTRs

 

 

18

 

 

Discounted cash flow

 

Market price (per MWh)

(3)

 

(1) - 5

 

 

1

 

Total assets

 

$

130

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial forwards:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

FTRs

 

$

5

 

 

Discounted cash flow

 

Market price (per MWh)

(3)

 

(5) - 5

 

 

—

 

Physical options:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas

 

 

2

 

 

Option model

 

Market price (per Dth)

(3)

 

1 - 5

 

 

2

 

 

 

 

 

 

 

 

 

Price volatility

(4)

 

56% - 72%

 

 

66

%

Total liabilities

 

$

7

 

 

 

 

 

 

 

 

 

 

 

 

(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)

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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

$

—

 

 

$

3

 

 

$

130

 

 

$

133

 

Investments(1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

1,787

 

 

 

—

 

 

 

—

 

 

 

1,787

 

Fixed income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate debt instruments

 

 

—

 

 

 

354

 

 

 

—

 

 

 

354

 

Government securities

 

 

184

 

 

 

306

 

 

 

—

 

 

 

490

 

Total assets

 

$

1,971

 

 

$

663

 

 

$

130

 

 

$

2,764

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

$

—

 

 

$

17

 

 

$

7

 

 

$

24

 

Interest rate

 

 

—

 

 

 

980

 

 

 

—

 

 

 

980

 

Total liabilities

 

$

—

 

 

$

997

 

 

$

7

 

 

$

1,004

 

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 $154 million and $159 million of assets at June 30, 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

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

43

 

 

$

59

 

 

$

(37

)

 

$

60

 

Total realized and unrealized gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Included in earnings:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric fuel and other energy-related purchases

 

 

(4

)

 

 

(3

)

 

 

(26

)

 

 

(7

)

Included in regulatory assets/liabilities

 

 

80

 

 

 

18

 

 

 

160

 

 

 

26

 

Settlements

 

 

4

 

 

 

3

 

 

 

26

 

 

 

(2

)

Ending balance

 

$

123

 

 

$

77

 

 

$

123

 

 

$

77

 

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 and six months ended June 30, 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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

$

—

 

 

$

192

 

 

$

—

 

 

$

192

 

Foreign currency

 

 

—

 

 

 

12

 

 

 

—

 

 

 

12

 

Total liabilities

 

$

—

 

 

$

204

 

 

$

—

 

 

$

204

 

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:

 

 

June 30, 2020

 

 

December 31, 2019

 

 

 

Carrying

Amount

 

 

Estimated

Fair

Value(1)

 

 

Carrying

Amount

 

 

Estimated

Fair

Value(1)

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dominion Energy

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt(2)

 

$

36,060

 

 

$

42,151

 

 

$

32,055

 

 

$

36,155

 

Supplemental 364-Day credit facility borrowings

 

 

225

 

 

 

225

 

 

 

—

 

 

 

—

 

Junior subordinated notes(3)

 

 

3,408

 

 

 

3,554

 

 

 

4,797

 

 

 

4,953

 

Virginia Power

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt(3)

 

$

12,328

 

 

$

15,189

 

 

$

12,326

 

 

$

14,281

 

Dominion Energy Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt(4)

 

$

5,523

 

 

$

5,891

 

 

$

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 June 30, 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)

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.

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:

 

 

June 30, 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

 

$

136

 

 

$

9

 

 

$

—

 

 

$

127

 

 

$

35

 

 

$

21

 

 

$

—

 

 

$

14

 

Exchange

 

 

45

 

 

 

20

 

 

 

7

 

 

 

18

 

 

 

37

 

 

 

21

 

 

 

—

 

 

 

16

 

Interest rate contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Over-the-counter

 

 

34

 

 

 

14

 

 

 

—

 

 

 

20

 

 

 

11

 

 

 

3

 

 

 

—

 

 

 

8

 

Foreign currency contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Over-the-counter

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

8

 

 

 

8

 

 

 

—

 

 

 

—

 

Total derivatives, subject to a

   master netting or similar

   arrangement

 

$

215

 

 

$

43

 

 

$

7

 

 

$

165

 

 

$

91

 

 

$

53

 

 

$

—

 

 

$

38

 

(1)

Excludes $1million and $2 million of derivative assets at June 30, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.

 

 

June 30, 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

 

$

30

 

 

$

9

 

 

$

—

 

 

$

21

 

 

$

105

 

 

$

21

 

 

$

—

 

 

$

84

 

Exchange

 

 

20

 

 

 

20

 

 

 

—

 

 

 

—

 

 

 

21

 

 

 

21

 

 

 

—

 

 

 

—

 

Interest rate contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Over-the-counter

 

 

1,272

 

 

 

14

 

 

 

22

 

 

 

1,236

 

 

 

606

 

 

 

8

 

 

 

35

 

 

 

563

 

Foreign currency contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Over-the-counter

 

 

12

 

 

 

—

 

 

 

—

 

 

 

12

 

 

 

3

 

 

 

3

 

 

 

—

 

 

 

—

 

Total derivatives, subject to a

   master netting or similar

   arrangement

 

$

1,334

 

 

$

43

 

 

$

22

 

 

$

1,269

 

 

$

735

 

 

$

53

 

 

$

35

 

 

$

647

 

(1)

Excludes $—million and $5 million of derivative liabilities at June 30, 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 June 30, 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)

 

 

69

 

 

 

32

 

Basis

 

 

236

 

 

 

538

 

Electricity (MWh):

 

 

 

 

 

 

 

 

Fixed price

 

 

4,964,045

 

 

 

2,775,850

 

FTRs

 

 

101,087,887

 

 

 

—

 

Liquids (Gal)(2)

 

 

26,460,000

 

 

 

—

 

Interest rate(3)

 

$

1,950,000,000

 

 

$

6,576,403,434

 

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 June 30, 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

)

 

18 months

Electricity

 

 

8

 

 

 

8

 

 

6 months

NGL

 

 

—

 

 

 

—

 

 

6 months

Interest rate

 

 

(640

)

 

 

(59

)

 

378 months

Foreign currency

 

 

(10

)

 

 

(4

)

 

72 months

Total

 

$

(644

)

 

$

(57

)

 

 

The amounts that will be reclassified from AOCI to earnings will generally be offset by returning the recognitionremaining 2017 Tax Reform benefits to customers over the next three years. The WPSC also approved revisions to the ECAM to adjust the sharing band from 70/30 to 80/20 and to include PTCs within the mechanism. PacifiCorp's proposals for extended recovery of the hedged transactions (e.g., anticipated sales)depreciation of certain coal-fueled generation units and use of remaining 2017 Tax Reform benefits to buy down certain plant balances were denied. The WPSC decision results in earnings, thereby achievingan overall net decrease of 3.5% with a rate effective date of July 1, 2021. A final written order was issued in July 2021.


In April 2021, PacifiCorp filed its annual ECAM and Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism application with the realizationWPSC requesting to refund $15 million of prices contemplateddeferred 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, which was approved by the underlying risk management strategies and will vary fromWPSC in June 2021. A hearing has been scheduled for November 2021.

44

Washington

In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. The proposed $13 million, or 3.7%, rate increase has a requested effective date of January 1, 2022.

Idaho

In March 2021, PacifiCorp filed its annual ECAM application with the expected amounts presented above asIPUC requesting recovery of $14 million for deferred costs in 2020, a result1.1% decrease compared to current rates. 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 market prices, interest ratesPTCs, RECs, and foreign currency exchange rates.

In connectiona resource tracking mechanism to match costs with the agreement Dominion Energy enteredbenefits of new wind and wind repowering projects until they are reflected in July 2020base rates. In May 2021, PacifiCorp updated the requested recovery to correct for the disposition of substantially all of its gas transmission and storage operations, certain cash flow hedges of debt-related items will become probable of not occurring.  See Note 3 for further information.

Fair Value Hedges

For derivative instruments that are designated and qualify as 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 to the hedged risk are recognized in current earnings and presentedload related data reflected in the same line item. There were 0 derivative instruments designatedinitial application, and the IPUC approved recovery of $10 million for deferred costs, a 2.5% decrease compared to current rates, effective June 1, 2021.


In May 2021, PacifiCorp filed a general rate case with the IPUC requesting a $19 million, or 7.0%, revenue requirement increase effective January 1, 2022. This is the first general rate case PacifiCorp has filed in fair value hedges during the threeIdaho since 2011. The rate case includes recovery of Energy Vision 2020 investments, Pryor Mountain wind-powered generating facilities, repowering Foote Creek, new investment in transmission, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and six months ended June 30, 2020. Gains and losses on derivatives in fair value hedge relationships were immaterial for the three and six months ended June 30, 2019.


rate design modernization proposals. The following table presents the amounts recorded on 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)

 

 

 

June 30, 2020

 

 

December 31, 2019

 

 

June 30, 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 June 30, 2020 and December 31, 2019, respectively.

(2)

Includes $(4) million and $3 million of hedging adjustments on discontinued hedging relationships at June 30, 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)

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

$

—

 

 

$

73

 

 

$

73

 

Interest rate

 

 

—

 

 

 

8

 

 

 

8

 

Total current derivative assets(1)

 

 

—

 

 

 

81

 

 

 

81

 

Noncurrent Assets

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

 

—

 

 

 

109

 

 

 

109

 

Interest rate

 

 

—

 

 

 

26

 

 

 

26

 

Total noncurrent derivative assets(2)

 

 

—

 

 

 

135

 

 

 

135

 

Total derivative assets

 

$

—

 

 

$

216

 

 

$

216

 

LIABILITIES

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

$

—

 

 

$

42

 

 

$

42

 

Interest rate

 

 

514

 

 

 

25

 

 

 

539

 

Foreign currency

 

 

5

 

 

 

—

 

 

 

5

 

Total current derivative liabilities

 

 

519

 

 

 

67

 

 

 

586

 

Noncurrent Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

 

—

 

 

 

8

 

 

 

8

 

Interest rate

 

 

655

 

 

 

78

 

 

 

733

 

Foreign currency

 

 

7

 

 

 

—

 

 

 

7

 

Total noncurrent derivative liabilities

 

 

662

 

 

 

86

 

 

 

748

 

Total derivative liabilities

 

$

1,181

 

 

$

153

 

 

$

1,334

 

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 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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

Commodity:

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

 

 

 

 

$

9

 

 

 

 

 

Purchased gas

 

 

 

 

 

 

—

 

 

 

 

 

Total commodity

 

$

—

 

 

$

9

 

 

$

—

 

Interest rate(3)

 

 

—

 

 

 

(22

)

 

 

14

 

Foreign currency(4)

 

 

6

 

 

 

6

 

 

 

—

 

Total

 

$

6

 

 

$

(7

)

 

$

14

 

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

Commodity:

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

 

 

 

 

$

38

 

 

 

 

 

Total commodity

 

$

35

 

 

$

38

 

 

$

—

 

Interest rate(3)

 

 

(142

)

 

 

(13

)

 

 

(131

)

Foreign currency(4)

 

 

2

 

 

 

4

 

 

 

—

 

Total

 

$

(105

)

 

$

29

 

 

$

(131

)

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

Commodity:

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

 

 

 

 

$

16

 

 

 

 

 

Purchased gas

 

 

 

 

 

 

(3

)

 

 

 

 

Electric fuel and other energy-related

   purchases

 

 

 

 

 

 

—

 

 

 

 

 

Total commodity

 

$

—

 

 

$

13

 

 

$

—

 

Interest rate(3)

 

 

(336

)

 

 

(49

)

 

 

(550

)

Foreign currency(4)

 

 

(17

)

 

 

—

 

 

 

—

 

Total

 

$

(353

)

 

$

(36

)

 

$

(550

)

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

Commodity:

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

 

 

 

 

$

92

 

 

 

 

 

Purchased gas

 

 

 

 

 

 

3

 

 

 

 

 

Total commodity

 

$

101

 

 

$

95

 

 

$

—

 

Interest rate(3)

 

 

(226

)

 

 

(23

)

 

 

(215

)

Foreign currency(4)

 

 

(9

)

 

 

(2

)

 

 

—

 

Total

 

$

(134

)

 

$

70

 

 

$

(215

)

(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

 

 

Six Months Ended

 

 

 

 

June 30,

 

 

June 30,

 

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

(10

)

 

$

27

 

 

$

55

 

 

$

30

 

 

Purchased gas

 

 

—

 

 

 

(11

)

 

 

(14

)

 

 

(8

)

 

Electric fuel and other energy-related

   purchases

 

 

(8

)

 

 

(3

)

 

 

(73

)

 

 

(12

)

 

Interest rate(2)

 

 

(25

)

 

 

—

 

 

 

(86

)

 

 

—

 

 

Total

 

$

(43

)

 

$

13

 

 

$

(118

)

 

$

10

 

 

(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:

 

 

June 30, 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

 

$

129

 

 

$

5

 

 

$

—

 

 

$

124

 

 

$

19

 

 

$

18

 

 

$

—

 

 

$

1

 

Interest rate contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Over-the-counter

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

2

 

 

 

—

 

 

 

—

 

 

 

2

 

Total derivatives, subject to a

   master netting or similar

   arrangement

 

$

129

 

 

$

5

 

 

$

—

 

 

$

124

 

 

$

21

 

 

$

18

 

 

$

—

 

 

$

3

 

(1)

Excludes $4million and $3 million of derivative assets at June 30, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.

 

 

June 30, 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

 

$

5

 

 

$

5

 

 

$

—

 

 

$

—

 

 

$

59

 

 

$

18

 

 

$

—

 

 

$

41

 

Interest rate contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Over-the-counter

 

 

980

 

 

 

—

 

 

 

—

 

 

 

980

 

 

 

363

 

 

 

—

 

 

 

—

 

 

 

363

 

Total derivatives, subject to a

   master netting or similar

   arrangement

 

$

985

 

 

$

5

 

 

$

—

 

 

$

980

 

 

$

422

 

 

$

18

 

 

$

—

 

 

$

404

 


(1)

Excludes $19million and $44 million of derivative liabilities at June 30, 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 June 30, 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 valueapplication also requested recovery of the net volume of its longdecommissioning and short positions.

 

 

Current

 

 

Noncurrent

 

Natural Gas (bcf):

 

 

 

 

 

 

 

 

Fixed price(1)

 

 

38

 

 

 

8

 

Basis

 

 

143

 

 

 

507

 

Electricity (MWh):

 

 

 

 

 

 

 

 

FTRs

 

 

101,087,887

 

 

 

—

 

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 June 30, 2020:

 

 

AOCI

After-Tax

 

 

Amounts Expected to be

Reclassified to Earnings

During the Next 12

Months After-Tax

 

 

Maximum Term

(millions)

 

 

 

 

 

 

 

 

 

 

Interest rate

 

$

(78

)

 

$

(1

)

 

378 months

Total

 

$

(78

)

 

$

(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)

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

Current Assets

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

$

—

 

 

$

31

 

 

$

31

 

Total current derivative assets(1)

 

 

—

 

 

 

31

 

 

 

31

 

Noncurrent Assets

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

 

—

 

 

 

102

 

 

 

102

 

Total noncurrent derivative assets(2)

 

 

—

 

 

 

102

 

 

 

102

 

Total derivative assets

 

$

—

 

 

$

133

 

 

$

133

 

LIABILITIES

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

$

—

 

 

$

23

 

 

$

23

 

Interest rate

 

 

455

 

 

 

—

 

 

 

455

 

Total current derivative liabilities

 

 

455

 

 

 

23

 

 

 

478

 

Noncurrent Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

 

—

 

 

1

 

 

 

1

 

Interest rate

 

 

525

 

 

 

—

 

 

 

525

 

Total noncurrent derivatives liabilities(3)

 

 

525

 

 

 

1

 

 

 

526

 

Total derivative liabilities

 

$

980

 

 

$

24

 

 

$

1,004

 

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 derivatives liabilities(4)

 

 

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.

(4)

Current derivative liabilities are presented in other current 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 theclosure costs 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

 

 

Increase (Decrease)

in Derivatives

Subject to

Regulatory

Treatment(2)

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate(3)

 

$

2

 

 

$

(1

)

 

$

13

 

Total

 

$

2

 

 

$

(1

)

 

$

13

 

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate(3)

 

$

(15

)

 

$

(1

)

 

$

(133

)

Total

 

$

(15

)

 

$

(1

)

 

$

(133

)

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate(3)

 

$

(59

)

 

$

(1

)

 

$

(552

)

Total

 

$

(59

)

 

$

(1

)

 

$

(552

)

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate(3)

 

$

(24

)

 

$

(1

)

 

$

(218

)

Total

 

$

(24

)

 

$

(1

)

 

$

(218

)

(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.

Derivatives not designated as hedging instruments

 

Amount of Gain (Loss) Recognized

in Income on Derivatives(1)

 

 

 

 

Three Months Ended

 

 

Six Months Ended

 

 

 

 

June 30,

 

 

June 30,

 

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity(2)

 

$

(8

)

 

$

(3

)

 

$

(73

)

 

$

(12

)

 

Total

 

$

(8

)

 

$

(3

)

 

$

(73

)

 

$

(12

)

 

(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:

 

 

June 30, 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

 

 

$

—

 

 

$

—

 

 

 

June 30, 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

 

$

192

 

 

$

—

 

 

$

—

 

 

$

192

 

 

$

83

 

 

$

5

 

 

$

—

 

 

$

78

 

Foreign currency contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Over-the-counter

 

 

12

 

 

 

—

 

 

 

—

 

 

 

12

 

 

 

3

 

 

 

3

 

 

 

—

 

 

 

—

 

Total derivatives, subject to a

   master netting or similar

   arrangement

 

$

204

 

 

$

—

 

 

$

—

 

 

$

204

 

 

$

86

 

 

$

8

 

 

$

—

 

 

$

78

 

Volumes

The following table presents the volume of Dominion Energy Gas’ derivative activity at June 30, 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)

 

$

750,000,000

 

 

$

550,000,000

 

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 June 30, 2020:

 

 

AOCI

After-Tax

 

 

Amounts Expected

to be Reclassified to

Earnings During the

Next 12 Months

After-Tax

 

 

Maximum Term

(millions)

 

 

 

 

 

 

 

 

 

 

Interest rate

 

$

(158

)

 

$

(11

)

 

294 months

Foreign currency

 

 

(10

)

 

 

(4

)

 

72 months

Total

 

$

(168

)

 

$

(15

)

 

 

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.

In connection with the agreement Dominion Energy enteredearly retirement of Cholla Unit 4.


California

California Senate Bill 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp submitted its 2021 California Wildfire Mitigation Plan Update in July 2020 forMarch 2021.

FERC Show Cause Order

On April 15, 2021, the disposition of substantially all of its gas transmission and storage operations, certain cash flow hedges of debt-related items will become probable of not occurring.  See Note 3 for further information.

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)

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES

 

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

$

58

 

 

$

13

 

 

$

71

 

Foreign currency

 

 

5

 

 

 

—

 

 

 

5

 

Total current derivative liabilities(2)

 

 

63

 

 

 

13

 

 

 

76

 

Noncurrent Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate

 

 

121

 

 

 

—

 

 

 

121

 

Foreign currency

 

 

7

 

 

 

—

 

 

 

7

 

Total noncurrent derivative liabilities(3)

 

 

128

 

 

 

—

 

 

 

128

 

Total derivative liabilities

 

$

191

 

 

$

13

 

 

$

204

 

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 June 30, 2020

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

Interest rate(2)

 

$

(4

)

 

$

(4

)

Foreign currency(3)

 

 

5

 

 

 

6

 

Total

 

$

1

 

 

$

2

 

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

Commodity:

 

 

 

 

 

 

 

 

Net income from discontinued operations

 

 

 

 

 

$

—

 

Total commodity

 

$

3

 

 

$

—

 

Interest rate(2)

 

 

(36

)

 

 

(2

)

Foreign currency(3)

 

 

1

 

 

 

4

 

Total

 

$

(32

)

 

$

2

 

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

Interest rate(2)

 

 

(105

)

 

 

(6

)

Foreign currency(3)

 

 

(17

)

 

 

—

 

Total

 

$

(122

)

 

$

(6

)

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

Derivative type and location of gains (losses):

 

 

 

 

 

 

 

 

Commodity:

 

 

 

 

 

 

 

 

Net income from discontinued operations

 

 

 

 

 

$

2

 

Total commodity

 

$

2

 

 

$

2

 

Interest rate(2)

 

 

(60

)

 

 

(1

)

Foreign currency(3)

 

 

(10

)

 

 

(2

)

Total

 

$

(68

)

 

$

(1

)

(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

 

 

Six Months Ended

 

 

 

June 30,

 

 

June 30,

 

 

 

2020

 

 

2019

 

 

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 $121million and $120 million at June 30, 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)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities:(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

$

1,701

 

 

$

2,221

 

 

$

(71

)

 

$

—

 

 

$

3,851

 

Fixed income securities:(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate debt instruments

 

 

577

 

 

 

48

 

 

 

(1

)

 

 

—

 

 

 

624

 

Government securities

 

 

1,119

 

 

 

62

 

 

 

(1

)

 

 

—

 

 

 

1,180

 

Common/collective trust funds

 

 

146

 

 

 

2

 

 

 

—

 

 

 

—

 

 

 

148

 

Insurance contracts

 

 

223

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

223

 

Cash equivalents and other(3)

 

 

(8

)

 

 

2

 

 

 

(2

)

 

 

—

 

 

 

(8

)

Total

 

$

3,758

 

 

$

2,335

 

 

$

(75

)

(4)

$

—

 

(5)

$

6,018

 

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)

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.

(3)

Includes pending purchases of securities of $35 million and $1 million at June 30, 2020 and December 31, 2019, respectively.

(4)

The fair value of securities in an unrealized loss position was $181 million and $298 millionat June 30, 2020 and December 31, 2019, respectively.

(5)

The allowance for credit losses associated with fixed income securities decreased from March 31, 2020 by $21 million.  These recoveries are a result of improvements in credit spreads experienced in the market between March 31, 2020 and June 30, 2020.

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 June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net gains (losses) recognized during the period

 

$

610

 

 

$

156

 

 

$

(288

)

 

$

570

 

Less: Net (gains) losses recognized during the period

   on securities sold during the period

 

 

(5

)

 

 

(25

)

 

 

9

 

 

 

(44

)

Unrealized gains (losses) recognized during the period

   on securities still held at June 30, 2020 and 2019(1)

 

$

605

 

 

$

131

 

 

$

(279

)

 

$

526

 


(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 June 30, 2020 by contractual maturity is as follows:

 

 

Amount

 

(millions)

 

 

 

 

Due in one year or less

 

$

212

 

Due after one year through five years

 

 

486

 

Due after five years through ten years

 

 

485

 

Due after ten years

 

 

769

 

Total

 

$

1,952

 

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 June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proceeds from sales

 

$

1,058

 

 

$

376

 

 

$

1,660

 

 

$

882

 

Realized gains(1)

 

 

74

 

 

 

56

 

 

 

140

 

 

 

99

 

Realized losses(1)

 

 

61

 

 

 

27

 

 

 

130

 

 

 

50

 

(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)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities:(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

$

901

 

 

$

1,028

 

 

$

(46

)

 

$

—

 

 

$

1,883

 

Fixed income securities:(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate debt instruments

 

 

328

 

 

 

26

 

 

 

—

 

 

 

—

 

 

 

354

 

Government securities

 

 

467

 

 

 

23

 

 

 

(1

)

 

 

—

 

 

 

489

 

Common/collective trust funds

 

 

57

 

 

 

—

 

 

 

—

 

 

 

—

 

 

 

57

 

Cash equivalents and other(3)

 

 

(1

)

 

 

—

 

 

 

—

 

 

 

—

 

 

 

(1

)

Total

 

$

1,752

 

 

$

1,077

 

 

$

(47

)

(4)

$

—

 

(5)

$

2,782

 

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.


(3)

Includes pending purchasesof securities of $1 million at June 30, 2020.

(4)

The fair value of securities in an unrealized loss position was $74 million and $185 millionat June 30, 2020 and December 31, 2019, respectively.

(5)

The allowance for credit losses associated with fixed income securities decreased from March 31, 2020 by $12 million.  These recoveries are a result of improvements in credit spreads experienced in the market between March 31, 2020 and June 30, 2020.

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 June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net gains (losses) recognized during the period

 

$

269

 

 

$

70

 

 

$

(154

)

 

$

256

 

Less: Net (gains) losses recognized during the period

   on securities sold during the period

 

 

(3

)

 

 

(7

)

 

 

3

 

 

 

(8

)

Unrealized gains (losses) recognized during the period

   on securities still held at June 30, 2020 and 2019(1)

 

$

266

 

 

$

63

 

 

$

(151

)

 

$

248

 

(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 June 30, 2020 by contractual maturity is as follows:

 

 

Amount

 

(millions)

 

 

 

 

Due in one year or less

 

$

79

 

Due after one year through five years

 

 

227

 

Due after five years through ten years

 

 

273

 

Due after ten years

 

 

321

 

Total

 

$

900

 

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 June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proceeds from sales

 

$

236

 

 

$

194

 

 

$

530

 

 

$

447

 

Realized gains(1)

 

 

24

 

 

 

15

 

 

 

55

 

 

 

25

 

Realized losses(1)

 

 

17

 

 

 

3

 

 

 

48

 

 

 

12

 

(1)

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


Equity Method Investments

Dominion Energy

Dominion Energy’s equity earnings (losses) on its investments totaled $(2.2) billion and $80 million for the six months ended June 30, 2020 and 2019, respectively. Dominion Energy received distributions of $46 million and $57 million for the six months ended June 30, 2020 and 2019, respectively. At June 30, 2020 and December 31, 2019, the net difference between the carrying amount of Dominion Energy’s investments and its share of underlying equity in net assets was $96 million and $110 million, respectively. At June 30, 2020, these differences are comprised of $175 million of equity method goodwill that is not being amortized and a net $79 million basis difference primarily attributable to Dominion Energy’s investments in Fowler Ridge and an unfunded commitment made to Align RNG.  At December 31, 2019, these differences are comprised of $159 million of equity method goodwill that is not being amortized and a net $49 million basis difference from Dominion Energy’s investments in Fowler Ridge, which is being amortized over the useful lives of the underlying assets, in Atlantic Coast Pipeline, which is being amortized over the term of its credit facility, and an unfunded commitment made to Align RNG.

Atlantic Coast Pipeline

In September 2014, Dominion Energy, along with Duke Energy and Southern, announced the formation of Atlantic Coast Pipeline for the purpose of constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of Dominion Energy, Duke Energy and Southern had planned to be customers of the pipeline under 20-year contracts.

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.  Following completion of the acquisition, Dominion Energy owns a 53% noncontrolling membership interest in Atlantic Coast Pipeline with Duke Energy 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 Energy.  As a result, Dominion Energy has the ability to exercise significant influence, but not control, over the investee.

The Atlantic Coast Pipeline Project had been 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 alleged non-compliance on the part of federal and state permitting authorities and adverse ecological consequences if the Atlantic Coast Pipeline Project was permitted to proceed. Since December 2018, notable developments in these challenges included 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), the 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 the 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. 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 and in June 2020, the Supreme Court of the U.S. ruled in favor of the Atlantic Coast Pipeline, reversing the lower court’s decision and remanding the case back to the U.S. Court of Appeals for the Fourth Circuit.

The project also faced new and serious challenges from uncertainty related to NWP 12, specifically, from the decision of the U.S. District Court for the District of Montana in April 2020 vacating an NWP 12 issued by the Army Corps of Engineers, including among other things gas pipelines, followed by a U.S. Court of Appeals for the Ninth Circuit ruling in May 2020 denying a stay of that decision. In July 2020, the Supreme Court of the U.S. issued an order allowing other new oilto show cause and gas pipeline projectsnotice of proposed penalty related to use the NWP 12 process pending appealallegations made by FERC Office of Enforcement staff that PacifiCorp failed to the U.S. Court of Appeals for the Ninth Circuit; however, that did not decrease the uncertaintycomply with certain North American Electric Reliability Corporation (the "NERC") reliability standards associated with an eventual ruling.facility ratings on PacifiCorp's bulk electric system. The Montana district court decision was viewedorder directs PacifiCorp to show cause as likely to prompt similar challenges in other federal circuit courts related to permits issued under NWP 12, including for the Atlantic Coast Pipeline Project.

In July 2020,why it should not be assessed a civil penalty of $42 million as a result of the continued permitting delays, growing legal uncertaintiesalleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and remediate certain discrepancies resulting from transmission facility design and actual field conditions, including transmission line clearances. In July 2021, PacifiCorp filed its answer to the need to incur significant capital expenditures to maintain project timing before such uncertainties could be resolved, DominionFERC's show cause order denying the alleged violation of certain NERC reliability standards. The FERC's reply is due in September 2021.


MidAmerican Energy and Duke Energy announced

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the cancellationcentral United States caused disruptions in natural gas supply from the southern part of the Atlantic Coast Pipeline Project.

AsUnited 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 customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a result ofcustomer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the determination ofincreased costs and longer recovery period resulted in higher working capital requirements during the probable abandonment of the Atlantic Coast Pipeline Project in June 2020, Atlantic Coast Pipeline has provided to Dominion Energy that it recorded net losses of $4.4 billion and $4.3 billion for the three and six monthssix-month period ended June 30, 2021.



45

Renewable Subscription Program

In December 2020, respectively, comparedMidAmerican Energy filed with the IUB a proposed Renewable Subscription Program ("RSP") tariff. As proposed, the program would provide qualified industrial customers with the opportunity to net incomemeet their future energy growth above baseline levels with renewable energy from specific MidAmerican Energy wind-powered generation additions and 100 MWs of $61 millionplanned solar generation for 20 years at fixed prices based on the cost of such facilities. Under the program, MidAmerican Energy would own the facilities, retain PTCs and $114 million forother tax benefits associated with the threefacilities and six months ended June 30, 2019, respectively,include all revenues and that it did not record revenue for any period.  As a result, Dominion Energy has recorded within earnings


(loss)costs from equity method investees a loss of $2.3 billion for both the three and six months ended June 30, 2020 compared to income of $29 million and $53 million for the three and six months ended June 30, 2019, respectively. At June 30, 2020, Dominion Energy has recorded a liability of $1.0 billion within other current liabilitiesprogram in its Consolidated Balance Sheet, asIowa-jurisdictional results of operation, but renewable attributes from the project would be specifically assigned to subscribing customers. In June 2021, the IUB rejected the proposed RSP tariff. In a resultseparate docket, the IUB ordered the exclusion from MidAmerican Energy's energy adjustment clause all PTCs and energy benefits associated with projects addressed in the RSP, resulting in MidAmerican Energy retaining such benefits.


NV Energy (Nevada Power and Sierra Pacific)

Price Stability Tariff

In November 2018, the Nevada Utilities made filings with the PUCN to implement the CPST. The Nevada Utilities have designed the CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of its share of equity losses exceeding its investment which reflects Dominion Energy’s obligations on behalf of Atlantic Coast Pipeline related to its credit facility and AROs.  

In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facilitythe Nevada Revised Statutes, with a stated maturity date of October 2021. As of June 30, 2020, Atlantic Coast Pipeline had borrowed $1.8 billion against the revolving credit facility. In July 2020, the capacity of the revolving credit facility was reduced from $3.4 billion to $1.9 billion.  Dominion Energy’s Consolidated Balance Sheets include a liability of $14 million associated with this guarantee agreement at December 31, 2019. The $1.0 billion liability at June 30, 2020 discussed above includes a $48 million adjustment related to this guarantee agreementmarket-based pricing option that is reflected within equity as a cumulative effect of a change in accounting principle upon adoption of the new credit loss standard in January 2020.

Dominion Energy recorded contributions of $13 million and $33 million during the three months ended June 30, 2020 and 2019, respectively, and $29 million and $128 million during the six months ended June 30, 2020 and 2019, respectively, to Atlantic Coast Pipeline. At June 30, 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 liabilities in the Consolidated Balance Sheets.

Dominion Energy expects to incur additional losses from Atlantic Coast Pipeline as it completes wind-down activities.  While Dominion Energy is unable to precisely estimate the amounts to be incurred by Atlantic Coast Pipeline, the portion of such amounts attributable to Dominion Energy is not expected to be material to Dominion Energy’s results of operations, financial position or statement of cash flows.  In connection with the sale of Dominion Energy’s gas transmission and storage operations to BHE discussed in Note 3, Dominion Energy expects to reflect the results of its equity method investment in Atlantic Coast Pipeline as discontinued operations effective in the third quarter of 2020.

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.

Fowler Ridge

In July 2020, Dominion Energy entered into an agreement to sell its 50% noncontrolling partnership interest in Fowler Ridge to BP and to terminate a long-term power, capacity and renewable energy credit contract for a net payment by Dominion Energy of $150 million. The transaction is expected to close in the third quarter of 2020, subject to approval by FERC. Dominion Energy expects to record a loss of approximately $220 million ($170 million after-tax), consisting of a loss on the contract termination partially offset by a gain on the sale of the partnership interest.

Dominion Energy Gas

Dominion Energy Gas’ equity earnings totaled $23 million and $22 million for the six months ended June 30, 2020 and 2019, respectively. Dominion Energy Gas received distributions of $25 million and $30 million for the six months ended June 30, 2020 and 2019, respectively. At June 30, 2020 and December 31, 2019, the carrying amount of Dominion Energy Gas’ investment of $310 million and $312 million, respectively, 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 $17 million and $26 million for the three months ended June 30, 2020 and 2019, respectively, and $37 million and $57 million for the six months ended June 30, 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 $7 million at both June 30, 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

Other than the items discussed below, 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.

The following table presents acquisitions by Virginia Power of solar projects. Virginia Power expects to claim federal investment tax credits on the projects.

Date Agreement Entered

 

Date Agreement Closed

 

Project Location

 

Project Name

 

Project Cost (millions)(1)

 

 

Date of Commercial Operations

 

MW Capacity

 

May 2020

 

May 2020

 

Virginia

 

Pumpkinseed

 

$

130

 

 

Expected 2022

 

 

60

 

(1)

Includes acquisition cost.

The following table presents acquisitions by Dominion Energy of solar projects. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.

Date Agreement Entered

 

Date Agreement Closed

 

Project Location

 

Project Name

 

Project Cost (millions)(1)

 

 

Date of Commercial Operations

 

MW Capacity

 

August 2019

 

August 2019

 

Virginia

 

Myrtle

 

$

32

 

 

June 2020

 

 

15

 

May 2020

 

May 2020

 

South Carolina

 

Blackville

 

 

15

 

 

Expected 2020

 

 

7

 

May 2020

 

May 2020

 

South Carolina

 

Denmark

 

 

15

 

 

Expected 2020

 

 

6

 

May 2020

 

Expected August 2020

 

South Carolina

 

Yemassee

 

 

20

 

 

Expected 2020

 

 

10

 

May 2020

 

Expected August 2020

 

South Carolina

 

Trask

 

 

25

 

 

Expected 2020

 

 

12

 

June 2020

 

June 2020

 

Ohio

 

Hardin I

 

 

250

 

 

Expected 2020

 

 

150

 

July 2020

 

July 2020

 

Virginia

 

Madison

 

 

125

 

 

Expected 2021

 

 

62

 

(1)

Includes acquisition cost.

In addition to the facilities discussed above, Dominion Energy has also entered into various agreements to install solar facilities, primarily at schools in Virginia, with in-service dates in 2020 or 2021. Through July 2020, Dominion Energy anticipates a total projected cost of approximately $35 million under these agreements with an associated aggregate generation capacity of 18 MW.

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:

 

 

June 30, 2020

 

 

December 31, 2019

 

(millions)

 

 

 

 

 

 

 

 

Dominion Energy

 

 

 

 

 

 

 

 

Regulatory assets:

 

 

 

 

 

 

 

 

Deferred cost of fuel used in electric generation(1)

 

$

—

 

 

$

48

 

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

 

 

49

 

 

 

21

 

Unrecovered gas costs(3)

 

 

42

 

 

 

102

 

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

 

 

58

 

 

 

109

 

Deferred nuclear refueling outage costs(6)

 

 

60

 

 

 

68

 

NND Project costs(7)

 

 

138

 

 

 

138

 

PJM transmission rates(8)

 

 

21

 

 

 

121

 

Other

 

 

248

 

 

 

272

 

Regulatory assets-current

 

 

616

 

 

 

879

 

Pension and other postretirement benefit costs(9)

 

 

1,392

 

 

 

1,431

 

Deferred rate adjustment clause costs for Virginia electric utility(4)(5)(10)(11)

 

 

409

 

 

 

235

 

PJM transmission rates(8)

 

 

154

 

 

 

85

 

Deferred project costs for gas utilities(2)

 

 

557

 

 

 

521

 

Interest rate hedges(12)

 

 

1,302

 

 

 

741

 

AROs and related funding(13)

 

 

312

 

 

 

311

 

Cost of reacquired debt(14)

 

 

252

 

 

 

262

 

NND Project costs(7)

 

 

2,434

 

 

 

2,503

 

Ash pond and landfill closure costs(15)

 

 

2,139

 

 

 

1,016

 

Other

 

 

487

 

 

 

582

 

Regulatory assets-noncurrent

 

 

9,438

 

 

 

7,687

 

Total regulatory assets

 

$

10,054

 

 

$

8,566

 

Regulatory liabilities:

 

 

 

 

 

 

 

 

Deferred cost of fuel used in electric generation(1)

 

$

111

 

 

$

—

 

Provision for future cost of removal and AROs(16)

 

 

142

 

 

 

142

 

Reserve for refunds and rate credits to electric utility customers(17)

 

 

134

 

 

 

143

 

Cost-of-service impact of 2017 Tax Reform Act(18)

 

 

35

 

 

 

4

 

Income taxes refundable through future rates(19)

 

 

140

 

 

 

77

 

Monetization of guarantee settlement(20)

 

 

67

 

 

 

67

 

Other

 

 

120

 

 

 

64

 

Regulatory liabilities-current

 

 

749

 

 

 

497

 

Income taxes refundable through future rates(19)

 

 

4,988

 

 

 

5,088

 

Provision for future cost of removal and AROs(16)

 

 

2,253

 

 

 

2,302

 

Nuclear decommissioning trust(21)

 

 

1,372

 

 

 

1,471

 

Monetization of guarantee settlement(20)

 

 

936

 

 

 

970

 

Reserve for refunds and rate credits to electric utility customers(17)

 

 

588

 

 

 

656

 

Overrecovered other postretirement benefit costs(22)

 

 

212

 

 

 

189

 

Other

 

 

331

 

 

 

325

 

Regulatory liabilities-noncurrent

 

 

10,680

 

 

 

11,001

 

Total regulatory liabilities

 

$

11,429

 

 

$

11,498

 

(1)

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

(2)

Primarilyreflects 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)

During the second quarter of 2020, Virginia Power recorded a charge of $16 million ($15 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.

(12)

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 June 30, 2020.

(13)

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 Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.

(14)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 June 30, 2020.

(15)

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.

(16)

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.

(17)

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.

(18)

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.

(19)

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.

(20)

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.

(21)

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.

(22)

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


 

 

June 30, 2020

 

 

December 31, 2019

 

(millions)

 

 

 

 

 

 

 

 

Virginia Power

 

 

 

 

 

 

 

 

Regulatory assets:

 

 

 

 

 

 

 

 

Deferred cost of fuel used in electric generation(1)

 

$

—

 

 

$

48

 

Deferred rate adjustment clause costs(2)(3)

 

 

58

 

 

 

109

 

Deferred nuclear refueling outage costs(4)

 

 

60

 

 

 

68

 

PJM transmission rates(5)

 

 

21

 

 

 

121

 

Other

 

 

58

 

 

 

87

 

Regulatory assets-current

 

 

197

 

 

 

433

 

Deferred rate adjustment clause costs(2)(3)(6)(7)

 

 

409

 

 

 

235

 

PJM transmission rates(5)

 

 

154

 

 

 

85

 

Interest rate hedges(8)

 

 

956

 

 

 

404

 

Ash pond and landfill closure costs(9)

 

 

2,139

 

 

 

1,016

 

Other

 

 

122

 

 

 

123

 

Regulatory assets-noncurrent

 

 

3,780

 

 

 

1,863

 

Total regulatory assets

 

$

3,977

 

 

$

2,296

 

Regulatory liabilities:

 

 

 

 

 

 

 

 

Deferred cost of fuel used in electric generation(1)

 

$

111

 

 

$

—

 

Provision for future cost of removal(10)

 

 

103

 

 

 

103

 

Income taxes refundable through future rates(11)

 

 

54

 

 

 

54

 

Other

 

 

28

 

 

 

10

 

Regulatory liabilities-current

 

 

296

 

 

 

167

 

Income taxes refundable through future rates(11)

 

 

2,425

 

 

 

2,438

 

Nuclear decommissioning trust(12)

 

 

1,372

 

 

 

1,471

 

Provision for future cost of removal(10)

 

 

993

 

 

 

1,054

 

Deferred cost of fuel used in electric generation(1)

 

 

3

 

 

 

30

 

Other

 

 

161

 

 

 

81

 

Regulatory liabilities-noncurrent

 

 

4,954

 

 

 

5,074

 

Total regulatory liabilities

 

$

5,250

 

 

$

5,241

 

(1)

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

(2)

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.

(3)

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.

(4)

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.

(5)

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.

(6)

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.

(7)

During the second quarter of 2020, Virginia Power recorded a charge of $16 million ($15 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.

(8)

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 26 years as of June 30, 2020.

(9)

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.

(10)

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.

(11)

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.  


(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.

 

 

June 30, 2020

 

 

December 31, 2019

 

(millions)

 

 

 

 

 

 

 

 

Dominion Energy Gas

 

 

 

 

 

 

 

 

Regulatory assets:

 

 

 

 

 

 

 

 

Unrecovered gas costs(1)

 

$

2

 

 

$

2

 

Other

 

 

7

 

 

 

6

 

Regulatory assets-current(2)

 

 

9

 

 

 

8

 

Interest rate hedges(3)

 

 

32

 

 

 

32

 

Other

 

 

5

 

 

 

8

 

Regulatory assets-noncurrent(4)

 

 

37

 

 

 

40

 

Total regulatory assets

 

$

46

 

 

$

48

 

Regulatory liabilities:

 

 

 

 

 

 

 

 

Provision for future cost of removal and AROs(5)

 

$

18

 

 

$

18

 

Overrecovered gas costs(1)

 

 

6

 

 

 

8

 

Other

 

 

13

 

 

 

15

 

Regulatory liabilities-current(6)

 

 

37

 

 

 

41

 

Income taxes refundable through future rates(7)

 

 

566

 

 

 

560

 

Provision for future cost of removal and AROs(5)

 

 

93

 

 

 

95

 

Overrecovered other postretirement benefit costs(8)

 

 

151

 

 

 

133

 

Other

 

 

10

 

 

 

12

 

Regulatory liabilities-noncurrent(9)

 

 

820

 

 

 

800

 

Total regulatory liabilities

 

$

857

 

 

$

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)

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 22 years.

(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)

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.

(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 June 30, 2020, Dominion Energy, Virginia Power and Dominion Energy Gas’ regulatory assets include $4.8 billion, $3.4 billion and $44 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 currentlyrenewable resources. The CPST provides for an energy rate that would replace the Base Tariff Energy Rate and Deferred Energy Accounting Adjustment. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available information, involves elements of judgmentto such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and significant uncertaintiesother intervenors 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.hearing was held in September 2020. 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 CommissionPUCN issued an order approving Questar Gas’ proposalthe tariff with modified pricing and directing the Nevada Utilities to refunddevelop 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 was considered in conjunction with the base rate case that was filed in November 2019. In June 2020, the Wyoming Commission approved a proposal to share the benefits of deferred income taxes for the period January 2018 through August 2020 with customers over a one-year period beginning in September 2020. In addition, new base rates that go into effect in September 2020 will include the prospective impacts of sharing excess deferred income taxes with customers.

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 also revised the depreciable lives of Altavista, Southampton and Hopewell for the mandated retirement to the end of 2028, which will not have a material impact to Virginia Power’s results of operations or cash flows given 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 complylimit with the legislative requirements discussed above.  The legislation allowssame 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.

filed. In May 2020 and July 2020, Virginia Power entered into and closed on separate agreements to acquire Grassfield Solar, Norge Solar and Sycamore Solar. The projects are expected to cost approximately $170 million in aggregate once constructed, including the initial acquisition cost. The facilities are expected to generate 82 MW combined and be placed into service by the end of 2022. Virginia Power expects to file with the Virginia Commission for CPCNs to construct and operate these projects as well as a rider to recover the costs associated with the recovery of certain renewable generation facilities in Virginia by the end of 2020.

Grid Transformation and Security Act of 2018

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 MarchDecember 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 Virginia Power 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’spricing ordered by the PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020 and denying the 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 requested clarification of certain matters, includingan updated CPST with the Smart Charging Infrastructure Pilot Program.  Additionally, Virginia Power requested clarification of certain matters relating to an AMI time-of-use ratePUCN. The enrollment period for the tariff has ended with no customers having enrolled. A final order has not been issued but because no customers have enrolled the order may be dismissed or withdrawn 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 2020tariff will not go into effect. A final order contained all necessary approvals for the smart charging electric vehicle infrastructure pilot program.  Virginia Power intends to file a revised plan 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 in 2021.


Natural Disaster Protection Plan

The Nevada Utilities submitted their initial natural disaster protection plan to commence commercial operations, subject to regulatory approvals associated with the project,PUCN and filed their first application seeking recovery of 2019 expenditures 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. In June 2020, a hearing was held and an order was issued in August 2020 that granted the Virginia Commissionjoint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. Intervenors have filed a revised fuelpetition for judicial review with the District Court in November 2020. In December 2020, the 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 address rate based on an updated projected over-recovery of $103 milliondesign issues raised by intervenors. The comment period for the prior year balance as of June 30, 2020.

Rate Adjustment Clauses

Belowreopened investigation and rulemaking ended in early February 2021 and an order is a discussion of significant riders associated with various Virginia Power projects:

•

The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2020, Virginia Power proposed a $1.0 billion total revenue requirement consisting of $474 million for the transmission component of Virginia Power’s base rates and $529 million for Rider T1 for the rate year beginning September 1, 2020. This total revenue requirement represents a $73 million increase versus the revenues to be produced during the rate year under current rates. In July 2020, the Virginia Commission approved the filing.

•

The Virginia Commission previously approved Riders C1A, C2A and C3Aexpected in connection with cost recovery for DSM programs. In December 2019, Virginia Power filed a petition to approve an additional 10 new energy efficiency programs and 1 new demand response DSM program for five years, subject to future extension, with a $186 million cost cap, and proposed a total $60 million revenue requirement for the rate year beginning September 1, 2020. This total revenue requirement represents an $11 million increase over the previous year. In July 2020, the Virginia Commission approved the filing.


•

The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. In June 2020, Virginia Power proposed an $80 total revenue requirement consisting of $44 million for previously approved phases and $36 million for phase five costs for Rider U for the rate year beginning April 1, 2021. This total revenue requirement represents a $28 million increase over the previous year. This matter is pending.

Additional 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

 

Rider BW

 

October 2019

 

June 2020

 

September 2020

 

 

99

 

 

 

(20

)

Rider US-2

 

October 2019

 

July 2020

 

September 2020

 

 

10

 

 

 

(5

)

Rider B

 

June 2020

 

Pending

 

April 2021

 

 

24

 

 

 

(8

)

Rider GV

 

June 2020

 

Pending

 

April 2021

 

 

154

 

 

 

22

 

Rider R

 

June 2020

 

Pending

 

April 2021

 

 

59

 

 

 

15

 

Rider S

 

June 2020

 

Pending

 

April 2021

 

 

194

 

 

 

(1

)

Rider W

 

June 2020

 

Pending

 

April 2021

 

 

120

 

 

 

14

 

Rider US-3

 

July 2020

 

Pending

 

June 2021

 

 

39

 

 

 

10

 

Rider US-4

 

July 2020

 

Pending

 

June 2021

 

 

12

 

 

 

4

 

Electric Transmission Projects

In December 2019, Virginia PowerMarch 2021, the Nevada Utilities filed an application withseeking recovery of the Virginia Commission2020 expenditures, approval for a CPCNan update to construct a new Evergreen Mills switching station and add approximately one mile of overhead 230 kV double circuit transmission lines from both the existing Brambleton-Yardley Ridge line and Brambleton-Poland Road line in Loudoun County, Virginia, estimated to cost approximately $30 million. In May 2020, the Virginia Commission issued an order approving in part and denying in part the petition. The Virginia Commission approved Virginia Power’s request to construct the new Evergreen Mills switching station and the new 230 kV double circuit transmission line from the existing Brambleton-Yardley Ridge line with a total estimated cost of $25 million.

Additional Virginia Power electric transmission projects approved and applied for are as follows:

Description and Location

of Project

 

Application

Date

 

Approval

Date

 

Type of

Line

 

Miles of

Lines

 

Cost Estimate

(millions)

Rebuild and operate five segments between the Loudoun and Ox substations

 

August 2019

 

June 2020

 

230 kV

 

19

 

70

Rebuild and operate two lines in Chesterfield County, Virginia

 

January 2020

 

June 2020

 

230 kV

 

3

 

15

Bristers-Ladysmith Rebuild Project in the counties of Fauquier, Stafford, Spotsylvania, and Caroline, Virginia

 

May 2020

 

Pending

 

500 kV

 

37

 

110

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 ratesinitial natural disaster protection plan that was ordered by the North Carolina Commission effectivePUCN and filed their first amendment to the 2020 natural disaster protection plan. A hearing related to the application for approval of the first amendment to the 2020 natural disaster protection plan was held in June 2021. The Nevada Utilities filed a partial party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial party stipulation and other intervenors filed legal briefs. The partial party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate for cost recovery. A separate docket remains open regarding the regulatory asset account and the cost recovery mechanism. Parties have submitted testimony and a hearing occurred in July 2021.



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Senate Bill 448 ("SB 448")

SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission development, renewable energy and storage within the state of Nevada and requires the Nevada Utilities to submit a plan to accelerate transportation electrification in the state and file a plan for certain high-voltage transmission infrastructure projects. SB 448 requires the Nevada Utilities to amend its most recently filed resource plan to include a plan for certain high-voltage transmission infrastructure construction projects that will be placed into service not later than December 31, 2028 and requires the IRP to include at least one scenario of low carbon dioxide emissions that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. SB 448 also requires the Nevada Utilities, on or before September 1, 2021, to file a plan to invest in certain transportation electrification programs during the period beginning January 1, 2020.2022, and ending on December 31, 2024, and establishes requirements for the contents of the transportation electrification investment plan for that period. It also establishes requirements for the review and the acceptance or modification of the transportation electrification investment plan by the PUCN. The base rate increase was proposed to recoverPUCN has not yet addressed the significant investmentsregulations in generation,SB 448.

Northern Powergrid Distribution Companies

In December 2020, GEMA, through Ofgem, published its final determinations for transmission and gas distribution infrastructurenetworks in Great Britain. Regarding the 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 Competition and Markets Authority against Ofgem's determination for the benefitcost of North Carolina customers. Virginia Power presentedequity, with an earned returnoutcome expected in October 2021. These determinations do not apply directly to Northern Powergrid, but aspects of 7.52% based uponthe proposals are capable of application at Northern Powergrid's next price control, ("ED2"), which will begin in April 2023.

In December 2020, GEMA published its decision on the methodology it will use to set the next electricity distribution price control, ED2, and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution, and that the financial aspects in respect of electricity distribution would broadly follow the transmission and gas distribution methodology, setting a fully-adjusted test period, compared to its authorized 9.90% return,working assumption for a cost of equity at 4.65% (plus CPIH), ahead of the final determinations in late 2022. When placed on a comparable footing, by adjusting for differences in the assumed equity ratio 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. In January 2020,measure of inflation used, the North Carolina Commission approved a 9.75% ROE and disallowed certain costs associated with coal ash remediation at Chesterfield power station. In February 2020,working assumption for ED2 is approximately 150 basis points lower than the North Carolina Commission issued its final order relating to base rates. current cost of equity.

In July 2020, Virginia Power filed a notice2021, Northern Powergrid submitted and published its draft business plan for April 2023 to March 2028. If adopted, this plan would involve annual capital and operating expenditures of appeal and exceptions to the Supreme Court of North Carolina, arguing that the North Carolina Commission committed reversible error on certain issues relating to the ratemaking treatment of certain coal ash remediation costs. 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 not in current base rates. In February 2020, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $28£642 million, an increase of $7 million over its previous filing, effective March 2020.

South Carolina Regulation

South Carolina Electric Base Rate Case

Pursuantrelative to the SCANA Merger Approval Order, DESC£471 million average annual capital and operating expenditures expected over the current price control period (April 2015 to March 2023). A final business plan submission for 2023-2028 will not file an application for a general rate case with the South Carolina Commission with a requested effective date forbe submitted in December 2021, ahead of GEMA's draft and final determinations which are expected around June and December 2022, respectively. A new rates earlier than January 2021.  In April 2020, the South Carolina Commission issued an order vacating the portion of the SCANA Merger Approval Order requiring that new retail electric ratesprice control can be implemented by January 1, 2021. In July 2020, DESC filedGEMA without the consent of the licensee but, if a notice of intentlicensee disagrees with the South Carolina Commissiondecision, it can appeal the matter to file forthe United Kingdom’s Competition and Markets Authority. In general terms, an increase to base rates for retail electric service no earlier than 30 days followingappeal may also be sought by another licensee whose interests are materially affected by the notice. The net lost revenue recovery portion of the DSM rider would be adjusted lower simultaneously with any approved retail electric base rate increases.

DSM Programs

DESC has approval fordecision, a DSM rider through which it recovers expenditures related to its DSM programs. In January 2020, DESC filed an application with the South Carolina Commission seeking approval to recover $40 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2020, the South Carolina Commission approved the filing.

Cost of Fuel

In February 2020, DESC filed a proposal with the South Carolina Commission to decrease the total fuel 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.

Electric Transmission Projects

In 2020, DESC began several electric transmission projects in connection with two new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approval to construct and operate 28 miles of 230 kV transmission lines in Aiken County, South Carolina estimated to cost approximately $30 million. In June 2020, the South Carolina Commission approved the filing.

Natural Gas Rates

In June 2020, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2020 with a total revenue requirement of $409 million. Thistrade association that represents a $9 million overall annual increase to its natural gas rates underlicensee and Citizens Advice, as the termsrepresentative of consumers whose interests are materially affected by the Natural Gas Rate Stabilization Act effective with the first billing cycle of November 2020. This matter is pending.

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.

decision.


West Virginia Regulation

PREP

In May 2020, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $39 million and $54 million of projected capital investment for 2020 and 2021, respectively. The application also includes a true-up of PREP costs related to the 2019 actual capital investment of $27 million and sets forth $13 million of annual PREP costs to be recovered in proposed rates effective November 1, 2020. This matter is pending.

Wyoming Regulation

Wyoming Base Rate Case

In November 2019, Questar Gas filed its base rate case and schedules with the Wyoming Commission. Questar Gas proposed a non-fuel, base rate increase of $4 million effective September 2020. The base rate increase was proposed to replace aging infrastructure and expand its system. Questar Gas presented an earned return of 7.46%, based upon a fully-adjusted test period, compared to its authorized 9.5% return, and proposed a 10.5% ROE. In June 2020, the Wyoming Commission approved a base rate increase of $2 million annually, with rates effective September 1, 2020. This revenue requirement increase is based on an approved ROE of 9.35%.

FERC – Gas

Cove Point

BHE Pipeline Group

BHE GT&S

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 approximately $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 FebruaryNovember 2020, Cove Point submitted itsreached 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 adjustmentrevenues 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 adjustmentstipulation and agreement and the rate refunds to customers were processed in March 2020.

Overthrust

late April.


47

BHE Transmission

AltaLink

Tariff Refund Application

In May 2020, OverthrustJanuary 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 request FERC authorization2023. The tariff relief measures consist of a proposed refund to construct, operatecustomers of C$150 million of previously collected future income taxes and maintainC$200 million of surplus accumulated depreciation.

In March 2021, the Wamsutter West Expansion projectAUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 customer tariff refund in the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provides Alberta customers 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 were proposed in AltaLink's 2022-2023 GTA.
In April 2021, the AUC confirmed its approval of AltaLink's customer tariff refund as provided in the decision issued in March 2021 and detailed its reasons for the decision. Specifically, the AUC found that the exceptional circumstances faced by Alberta customers in 2021 have brought to bear an unprecedented need for rate relief that has not existed previously. These exceptional circumstances include the current economic downturn due to COVID-19, the collapse in the world price of oil and the resulting significant negative impact to Albertans and businesses. As a result, immediate and temporary relief was warranted.

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 120,000 Dth per daya further tariff reduction over the three year period by refunding previously collected accumulated depreciation surplus of new capacity flowing eastan additional C$31 million. In April 2019, AltaLink filed an update to west fromits 2019-2021 GTA primarily to reflect its 2018 actual results and the Wamsutter interconnectimpact 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 Opal interconnect.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 project facilities are expected2019-2021 negotiated settlement agreement excluded certain matters related to commence commercial operationsthe 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 fourth quartercompliance 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 are expectedC$898 million for 2021, exclusive of the assets transferred to cost $10 million. FERC approved the applicationPiikaniLink Limited Partnership and the KainaiLink Limited Partnership.


48

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.

DETI

In January 2018, DETI2020, AltaLink filed an application to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvaniawith the AUC for the Sweden Valley project.review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In June 2019, DETI withdrewSeptember 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 applicationdecision 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 project dueyears 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to certain regulatory delays. Ascustomers 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 by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year over year increase of approximately 2% in 2022 and 2023 revenue requirements. 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 tariffs 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 considered the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the uncertainty as a result of the project abandonment, duringongoing COVID-19 pandemic, before establishing a process schedule, the secondcommission requested participants to submit comments that addressed 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 customers.

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 alleged that the AUC erred by failing to fulfil its statutory obligation of establishing a fair return and by failing to apply procedural fairness. The Utilities Consumer Advocate additionally filed an application with the AUC for review and variance of the AUC's decision. The basis for the application was the same as the permission to appeal filed with the Court of Appeal.


49

2019 DETI recorded a chargeDeferral Accounts Reconciliation Application

In October 2020, AltaLink filed its application with the AUC, which includes 10 projects with total gross capital additions of $13C$129 million, ($10including 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 million after-tax), includedof 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 impairment of assetsApril 2021. In May 2021, the AUC issued its decision approving the compliance filing application as filed.

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 chargesenvironmental 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 Dominion Energymaterial compliance with all applicable laws and Dominion Energy Gas’ Consolidated Statementsregulations, 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 Income.

Note 14. Leases

Other than the items discussed below, there have been no significant changes regarding the Companies’ leases as described in Note 15 to the Consolidated Financial Statements in the Companies’each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019.

Dominion Energy’s Consolidated Statements2020, 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 goals of Income include $53 millionlimiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius and $85 millionreaching a global peak of greenhouse gas emissions as soon as possible to achieve climate neutrality by mid-century; 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.

Regional and State Activities

Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant, and include:
•On July 27, 2021, the governor of Oregon signed House Bill 2021, which requires utilities to reduce GHG emissions to meet certain clean energy targets. The bill sets a baseline of the average of 2010, 2011, and 2012 emissions and requires utilities to meet the following reductions from that baseline: 80% by 2030, 90% by 2035 and 100% by 2040. No earlier than January 1, 2022, PacifiCorp must file a clean energy plan with the OPUC showing how it will meet the clean energy targets.
50

•On May 17, 2021, the state of Washington passed the Climate Commitment Act (Senate Bill 5126), which creates an economy-wide cap-and-trade program to reduce GHG emissions. Under the Climate Commitment Act, the Washington Department of Ecology must establish progressively declining annual allowance budgets for the three and six months ended June 30, 2020, respectively, and $53 million and $82 million for the three and six months ended June 30, 2019, respectively,emissions of rental revenue included in operating revenue. Dominion Energy’s Consolidated Statements of Income include $27 million and $50 million for the three and six months ended June 30, 2020, respectively, and $24 million and $47 million for the three and six months ended June 30, 2019, respectively, of depreciation expense included in depreciation, depletion and amortization, related to facilitiesGHG beginning January 1, 2023. PacifiCorp is subject to power purchase agreements underthe Climate Commitment Act as an importer of electricity into Washington.

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 Dominion Energy isare 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 lessor.

Corporate Office Leasing Arrangement

EPA. The major Clean Air Act programs most directly affecting the Registrants' operations are described below.


In December 2019, Dominion Energy signed an agreement with

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 lessor, as amended in May 2020, to constructstandard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and lease a1,400 pounds of carbon dioxide per MWh for new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. If Dominion Energy ultimately proceedscoal-fueled generating facilities with the project"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 completion, the projectintroduction 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 completedquickly revisited by September 2024. Dominion Energy has been appointed to act as the construction agent forBiden administration. Because the lessor, during which time Dominion Energysignificant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will request cash draws from the lessor and debt investors to fund all project costs. If the project is terminated under certain events, Dominion Energy could be required to pay upmeet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule April 5, 2021, remanding it for further proceedings.

New Source Performance Standards for Methane Emissions

In August 2020, the EPA finalized regulations to 100%rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. On June 30, 2021, President Biden signed into law a resolution that rescinded the August 2020 rule and reinstated a rule promulgated in 2016. The primary effect of the then funded amount.

resolution is that the 2020 rule is treated as never having taken effect. The lease term will commence once constructionEPA is substantially completedeveloping guidance for stakeholders to comply with the 2016 rule. In addition, reinstating methane rules for new sources imposes a requirement for EPA to also issue rules for existing sources. Until such time as additional regulatory action is taken and litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.



51

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 ablelocated 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 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 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included 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 occupieddesignated 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 endDes 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.

52

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 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 Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2027. At2012 and the EPA's approval was upheld on appeal by the Tenth Circuit Court of Appeals ("Tenth Circuit") in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NOx and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The EPA, U.S. Department of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to install SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement.

53

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 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 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 includes the 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 initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to theEPA published its proposed approval of the participants, at current market terms, (ii) purchaseUtah Regional Haze SIP Alternative, which makes the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalfshutdown of the lessorCarbon 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 a third party using commercially reasonable efforts to obtaininstall SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the highest cash purchase pricefinal 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 property. IfHunter and Huntington plants. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the project is soldTenth 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 proceeds fromstate of Utah moved to intervene in the sale are insufficient to repaylitigation, which has been stayed pending the investors forBiden administration's review of the project costs, Dominion Energy may be requiredrule.

Critical Accounting Estimates

Certain accounting measurements require management to make a payment to the lessor, up to 83% of project costs, for the difference between the project costsestimates and sale proceeds.  Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energyjudgments concerning transactions that will be consideredsettled several years in the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.

Note 15. Variable Interest Entities

There have been no significant changes regarding the entities the Companies consider VIEs as described in Note 16 tofuture. 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.


54

PacifiCorp and its subsidiaries
Consolidated Financial Section

55

PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
PacifiCorp

Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of June 30, 20202021, the related consolidated statements of operations and December 31, 2019, Dominion Energy’s securities due within one year included $32 million and $31 million, respectively, and long-term debt included $258 million and $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 interestchanges 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. In May 2019, Virginia Power entered into an agreement and paid $135 million to terminate the remaining contract with the non-utility generator, effective April 2019. A $135 million ($100 million after-tax) charge was recorded in impairment of assets and other charges in Virginia Power’s Consolidated Statements of Incomeshareholders' equity for the threethree-month and six monthssix-month periods ended June 30, 2019. Virginia Power paid $13 million 2021 and 2020, and of cash flowsfor electric capacity and $1 million for electric energy to the non-utility generator in the six monthssix-month periods ended June 30, 2019.

Dominion Energy Gas

Dominion Energy Gas purchased shared services from DECGS2021 and DEQPS of $3 million and $7 million for the three months ended June 30, 2020, $5 million and $11 million for the three months ended June 30, 2019, $7 million and $14 million for the six months ended June 30, 2020, and $9 million and $20 million for the six months ended June 30, 2019, respectively. Dominion Energy Gas’ Consolidated Balance Sheets included amounts duerelated notes (collectively referred to both DECGS and DEQPSas the "interim financial information"). Based on our reviews, we are not aware of $18 million and $15 million at June 30, 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 $86 million and $27 million for the three months ended June 30, 2020, respectively, and $129 million and $39 million for the three months ended June 30, 2019, $179 million and $58 million for the six months ended June, 30, 2020 and $218 million and $67 million for the six months ended June 30, 2019, respectively. Virginia Power’s Consolidated Balance Sheets include amounts due to DES of $92 million and $102 million at June 30, 2020 and December 31, 2019, respectively, recorded in payables to affiliates. Dominion Energy Gas’ Consolidated Balance Sheets include amounts due to DES of $38 million and $27 million at June 30, 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 June 30, 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

 

 

$

210

 

 

$

103

 

 

$

5,687

 

(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 additionany material modifications that should be made to the credit facility mentioned above, Dominion Energy also has a credit facility which had an original stated maturity date of June 2020 and allowed Dominion Energyaccompanying interim financial information for it to issue up to approximately $21 millionbe in letters of credit. In May 2020, the credit facility was amended to increase the facility capacity to approximately $30 million and extend the maturity date to June 2022. At June 30, 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 June 30, 2020, $225 million was outstanding under the agreement. The proceeds from these borrowings 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 consistentconformity with such allowed ratio under Dominion Energy’s joint revolving credit facility.

DESC 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 June 30, 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 June 30, 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 June 30, 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 bore interest at a variable rate. The proceeds were used to provide for general working capital and other general corporate purposes. In June 2020, Dominion Energy repaid the outstanding balance in full.

In November 2017, Dominion Energy filed a SEC shelf registration statement for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. 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. At June 30, 2020 and December 31, 2019, Dominion Energy’s Consolidated Balance Sheets include $176 million and $75 million, respectively, presented within short-term debt.  The proceeds are used for general corporate purposes and to repay debt.

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 June 30, 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

 

 

$

—

 

 

$

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 June 30, 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 June 30, 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

 

 

$

—

 

 

$

—

 

(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 June 30, 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 StatementsUnited States of Income for the six months ended June 30, 2020.America.

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

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 six months ended June 30, 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 six months ended June 30, 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. In June 2020, Dominion Energy prepaid the remaining balance of $993 million.

In June 2020, East Ohio issued, through private placement, $500 million of 1.30% senior notes, $500 million of 2.00% senior notes and $800 million of 3.00% senior notes that mature in 2025, 2030 and 2050, respectively. East Ohio used the proceeds from this offering to repay intercompany promissory notes with Dominion Energy Gas and a portion of its intercompany revolving credit agreement balance with Dominion Energy.

In June 2020, Virginia Power remarketed 1 series of tax-exempt bonds, with an aggregate outstanding principal of $105 million to new investors. The bonds will bear interest at a coupon rate of 1.20% until May 2024, after which they will bear interest at a market rate to be determined at that time.

Derivative Restructuring

In June 2020, Dominion Energy amended a portfolio of interest rate swaps with a notional value of $2.0 billion, extending the mandatory termination dates from 2020 and 2021 to December 2024. The transaction is viewed as a non-cash financing activity with an embedded interest rate swap. As a result, in June 2020, Dominion Energy recorded $326 million in other long-term debt, representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 1.19%, in its Consolidated Balance Sheets with an embedded interest rate derivative that had a fair value of zero at inception.

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

/s/ Deloitte & Touche LLP

Portland, Oregon
August 6, 2021

56

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)

 As of
 June 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$44 $13 
Trade receivables, net714 703 
Other receivables, net62 48 
Inventories474 482 
Derivative contracts99 27 
Regulatory assets86 116 
Prepaid expenses66 79 
Other current assets18 55 
Total current assets1,563 1,523 
 
Property, plant and equipment, net22,675 22,430 
Regulatory assets1,339 1,279 
Other assets506 470 
 
Total assets$26,083 $25,702 

The merger was accounted for by Dominion Energy following the guidance foraccompanying notes are an integral part of these consolidated financial statements.
57

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

 As of
 June 30,December 31,
20212020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable$667 $772 
Accrued interest125 127 
Accrued property, income and other taxes136 80 
Accrued employee expenses106 84 
Short-term debt301 93 
Current portion of long-term debt479 420 
Regulatory liabilities124 115 
Other current liabilities221 174 
Total current liabilities2,159 1,865 
 
Long-term debt7,735 8,192 
Regulatory liabilities2,753 2,727 
Deferred income taxes2,715 2,627 
Other long-term liabilities1,154 1,118 
Total liabilities16,516 16,529 
 
Commitments and contingencies (Note 9)00
 
Shareholders' equity:
Preferred stock2 2 
Common stock - 750 shares authorized, 0 par value, 357 shares issued and outstanding0 0 
Additional paid-in capital4,479 4,479 
Retained earnings5,105 4,711 
Accumulated other comprehensive loss, net(19)(19)
Total shareholders' equity9,567 9,173 
 
Total liabilities and shareholders' equity$26,083 $25,702 

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

58

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

 Three-Month PeriodsSix-Month Periods
 Ended June 30,Ended June 30,
 2021202020212020
 
Operating revenue$1,298 $1,144 $2,540 $2,350 
   
Operating expenses:
Cost of fuel and energy441 383 865 800 
Operations and maintenance255 243 514 497 
Depreciation and amortization275 210 539 462 
Property and other taxes43 52 104 101 
Total operating expenses1,014 888 2,022 1,860 
   
Operating income284 256 518 490 
   
Other income (expense):  
Interest expense(105)(110)(212)(212)
Allowance for borrowed funds6 12 12 22 
Allowance for equity funds12 23 25 44 
Interest and dividend income5 3 11 6 
Other, net4 8 10 4 
Total other income (expense)(78)(64)(154)(136)
   
Income before income tax (benefit) expense206 192 364 354 
Income tax (benefit) expense(19)26 (30)12 
Net income$225 $166 $394 $342 

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

59

PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)
(Amounts in millions)

 Accumulated 
   Additional OtherTotal
PreferredCommonPaid-inRetainedComprehensiveShareholders'
 StockStockCapitalEarningsLoss, NetEquity
 
Balance, March 31, 2020$2 $0 $4,479 $4,148 $(15)$8,614 
Net income— — — 166 — 166 
Balance, June 30, 2020$2 $0 $4,479 $4,314 $(15)$8,780 
Balance, December 31, 2019$2 $0 $4,479 $3,972 $(16)$8,437 
Net income— — — 342 — 342 
Other comprehensive income— — — — 1 1 
Balance, June 30, 2020$2 $0 $4,479 $4,314 $(15)$8,780 
       
Balance, March 31, 2021$2 $0 $4,479 $4,880 $(19)$9,342 
Net income— — — 225 — 225 
Balance, June 30, 2021$2 $0 $4,479 $5,105 $(19)$9,567 
Balance, December 31, 2020$2 $0 $4,479 $4,711 $(19)$9,173 
Net income— — — 394 — 394 
Balance, June 30, 2021$2 $0 $4,479 $5,105 $(19)$9,567 

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

60


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

 Six-Month Periods
 Ended June 30,
 20212020
Cash flows from operating activities: 
Net income$394  $342 
Adjustments to reconcile net income to net cash flows from operating activities: 
Depreciation and amortization539  462 
Allowance for equity funds(25)(44)
Changes in regulatory assets and liabilities(98) (12)
Deferred income taxes and amortization of investment tax credits22  (24)
Other, net(1)1 
Changes in other operating assets and liabilities:  
Trade receivables, other receivables and other assets(10) 46 
Inventories8  (80)
Derivative collateral, net35  7 
Prepaid expenses12 (1)
Accrued property, income and other taxes, net79 38 
Accounts payable and other liabilities91  35 
Net cash flows from operating activities1,046  770 
   
Cash flows from investing activities:  
Capital expenditures(819) (973)
Other, net0  29 
Net cash flows from investing activities(819) (944)
   
Cash flows from financing activities:  
Proceeds from long-term debt0 987 
Repayments of long-term debt(400)0 
Net proceeds from (repayments of) short-term debt208 (130)
Other, net(4)0 
Net cash flows from financing activities(196) 857 
   
Net change in cash and cash equivalents and restricted cash and cash equivalents31  683 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period19  36 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$50  $719 
The accompanying notes are an integral part of these consolidated financial statements.

61

PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)    General

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a changeUnited 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 interestnumber 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 changessubsidiary 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 connectionaccordance 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, initiallyaccounting principles generally accepted in the formUnited States of 2019 Series A Corporate Units. The Corporate Units are listed onAmerica ("GAAP") for interim financial information and the NYSE under the symbol DCUE. The net proceeds were usedUnited States Securities and Exchange Commission's rules and regulations for general corporate purposesForm 10-Q and to repay short-term debt, including commercial paper.

Each 2019 Series A Corporate Unit consistsArticle 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 upondisclosures required by GAAP for annual financial statements. Management believes the average closing priceunaudited Consolidated Financial Statements contain all adjustments (consisting only of Dominion Energy common stock prior tonormal 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 valuefair presentation of the stock purchase contract paymentsunaudited 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 contractsJune 30, 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) and $14 million ($8.750 per share) for the three and six months ended June 30, 2020, respectively.

(3)

Payments of $41 million were made during the six months ended June 30, 2020. The stock purchase contract liability was $171 million and $212 million at June 30, 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) and $18 million ($23.250 per share) for the threethree- and six monthssix-month periods ended June 30, 2020, respectively.2021 and 2020. The dividend rateConsolidated 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 equalthree- and six-month periods ended June 30, 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 accumulatedthree- and unpaid dividends on the Series B Preferred Stock have been declaredsix-month periods ended June 30, 2021 and paid, Dominion Energy may2020 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.

Holdersnecessarily indicative of the Series B Preferred Stock have no voting rights except inresults to be expected for the limited circumstances provided for in the termsfull 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 Dominion Energy’s 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.

Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In April 2014, Dominion Energy began issuing new common shares for these direct stock purchase plans. In August 2020, Dominion Energy began purchasing its common stock on the open market for these direct stock purchase plans.

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. 2020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the six-month period ended June 30, 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 June 30, 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
June 30,December 31,
20212020
Cash and cash equivalents$44 $13 
Restricted cash included in other current assets3 4 
Restricted cash included in other assets3 2 
Total cash and cash equivalents and restricted cash and cash equivalents$50 $19 

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(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
  As of
 June 30,December 31,
Depreciable Life20212020
Utility Plant: 
Generation15 - 59 years$13,592 $12,861 
Transmission60 - 90 years7,740 7,632 
Distribution20 - 75 years7,815 7,660 
Intangible plant(1)
5 - 75 years1,081 1,054 
Other5 - 60 years1,529 1,510 
Utility plant in service31,757 30,717 
Accumulated depreciation and amortization (10,180)(9,838)
Utility plant in service, net 21,577 20,879 
Other non-regulated, net of accumulated depreciation and amortization14 - 95 years9 9 
Plant, net21,586 20,888 
Construction work-in-progress 1,089 1,542 
Property, plant and equipment, net $22,675 $22,430 

(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 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 $44 million for the three-month period ended June 30, 2021 as compared to the three-month period ended June 30, 2020, and $81 million for the six-month period ended June 30, 2021 compared to the six-month period ended June 30, 2020 based on historical property, plant and equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.

(4)    Recent Financing Transactions

Long-term Debt

In MarchJuly 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 Dominion Energy entered into four separate sales agencyinitiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.

Credit Facilities

In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2022. In June 2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

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(5)    Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
State income tax, net of federal income tax benefit4 3 4 3 
Federal income tax credits(19)(9)(19)(10)
Effects of ratemaking(15)(2)(14)(11)
Other0 1 0 0 
Effective income tax rate(9)%14 %(8)%3 %

Income tax credits relate primarily to production tax credits ("PTC") 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- and six-month periods ended June 30, 2021 and 2020 is primarily attributable to the activity associated with excess deferred income taxes, including the use of excess deferred income taxes of $3 million to amortize certain regulatory asset balances in Wyoming during the six-month period endedJune 30, 2021 and $30 million to accelerate depreciation of certain retired wind equipment in Oregon during the six-month period ended June 30, 2020.

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 six-month period ended June 30, 2021 PacifiCorp received net cash payments for federal and state income tax from BHE totaling $93 million. For the six-month period ended June 30, 2020 PacifiCorp made net cash payments for federal and state income tax to BHE totaling $42 million.

64

(6)    Employee Benefit Plans

Net periodic benefit cost (credit) for the pension and other postretirement benefit plans included the following components (in millions):
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Pension:
Service cost$0 $0 $0 $0 
Interest cost7 9 14 18 
Expected return on plan assets(14)(14)(27)(28)
Net amortization5 4 10 9 
Net periodic benefit credit$(2)$(1)$(3)$(1)
Other postretirement:
Service cost$1 $1 $1 $1 
Interest cost2 2 4 5 
Expected return on plan assets(2)(3)(4)(7)
Net amortization0 0 0 0 
Net periodic benefit cost (credit)$1 $0 $1 $(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 June 30, 2021, $2 million of contributions had been made to the pension plans.

(7)    Risk Management and Hedging Activities

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

PacifiCorp has established a risk management process that is designed to identify, 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 effect sales under a new at-the-market programeffectively 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 pursuant to which it had the ability to offerby monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time upenter into interest rate derivative contracts, such as interest rate swaps or locks, to $500 million aggregate amountmitigate 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 common stock. Dominion Energy did 0t issue any shares under this new program which expiredcommodity price and interest rate risks, thereby exposing the unhedged portion to changes in June 2020.

Repurchase of Common Stock

In July 2020, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded the prior two authorizations from 2005 and 2007.  The repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors.

Dividend Restrictions

At June 30, 2020, DESC’s retained earnings exceed the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is permitted to pay dividends without additional regulatory approval provided that such amounts would not bring the retained earnings balance below the threshold. prices.


There have been no other significant changes in PacifiCorp's accounting policies related to dividend restrictions affectingderivatives. Refer to Note 8 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 Companies describednormal 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):
65

OtherOtherOther 
CurrentOtherCurrentLong-term
AssetsAssetsLiabilitiesLiabilitiesTotal
As of June 30, 2021
Not designated as hedging contracts(1):
Commodity assets$118 $23 $7 $0 $148 
Commodity liabilities(3)(1)(26)(16)(46)
Total115 22 (19)(16)102 
     
Total derivatives115 22 (19)(16)102 
Cash collateral (payable) receivable(16)0 5 0 (11)
Total derivatives - net basis$99 $22 $(14)$(16)$91 
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)
Total27 6 (22)(28)(17)
      
Total derivatives27 6 (22)(28)(17)
Cash collateral receivable0 0 15 9 24 
Total derivatives - net basis$27 $6 $(7)$(19)$7 

(1)PacifiCorp's commodity derivatives are generally included in Note 21,rates. As of June 30, 2021 a regulatory liability of $102 million was recorded related to the net derivative asset of $102 million. As of December 31, 2020 a regulatory asset of $17 million was recorded related to the net derivative liability of $17 million.

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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Beginning balance$0 $84 $17 $62 
Changes in fair value(102)(6)(119)28 
Net (losses) gains reclassified to operating revenue(5)5 (5)13 
Net gains (losses) reclassified to cost of fuel and energy5 (15)5 (35)
Ending balance$(102)$68 $(102)$68 

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 ofJune 30,December 31,
Measure20212020
Electricity sales, netMegawatt hours0 (1)
Natural gas purchasesDecatherms121 100 

66

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 June 30, 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 $42 million and $51 million as of June 30, 2021 and December 31, 2020, respectively, for which PacifiCorp had posted collateral of $5 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 June 30, 2021 and December 31, 2020, PacifiCorp would have been required to post $27 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.

(8)    Fair Value Measurements

The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.

•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•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.

67

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 June 30, 2021    
Assets:    
Commodity derivatives$0 $148 $0 $(27)$121 
Money market mutual funds(2)
36 0 0 — 36 
Investment funds31 0 0 — 31 
 $67 $148 $0 $(27)$188 
Liabilities - Commodity derivatives$0 $(46)$0 $16 $(30)
As of December 31, 2020
Assets:
Commodity derivatives$0 $36 $0 $(3)$33 
Money market mutual funds(2)
6 0 0 — 6 
Investment funds25 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 payable of $11 million and a net cash collateral receivable of $24 million as of June 30, 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 7 for further discussion regarding PacifiCorp's risk management and hedging activities.

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

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PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):
 As of June 30, 2021As of December 31, 2020
 CarryingFairCarryingFair
 ValueValueValueValue
     
Long-term debt$8,214 $10,133 $8,612 $10,995 

(9)    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

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 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 June 30, 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.

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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.

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. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC, the Karuk Tribe, the Yurok Tribe and the States as co-licensees. The transfer will be effective after PacifiCorp secures property transfer approvals from its state public utility commissions and 30 days following the issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions approved the property transfer.

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.

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(10)    Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Customer Revenue:
Retail:
Residential$429 $384 $912 $844 
Commercial393 346 752 704 
Industrial282 268 553 545 
Other retail84 68 116 95 
Total retail1,188 1,066 2,333 2,188 
Wholesale (1)
30 17 66 17 
Transmission37 24 62 46 
Other Customer Revenue31 20 54 46 
Total Customer Revenue1,286 1,127 2,515 2,297 
Other revenue12 17 25 53 
Total operating revenue$1,298 $1,144 $2,540 $2,350 

(1)Includes net payments to counterparties for the financial settlement of certain non-derivative forward contracts for energy sales.
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Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations

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

Results of Operations for the Second Quarter and First Six Months of 2021 and 2020

Overview

Net income for the second quarter of 2021 was $225 million, an increase of $59 million, or 36%, compared to 2020. Net income increased primarily due to higher utility margin of $96 million, favorable income tax expense primarily due to the impacts of ratemaking of $27 million and higher PTCs recognized due to new wind-powered generating facilities placed in-service of $23 million, and lower property taxes of $9 million, partially offset by higher depreciation and amortization expense of $65 million, including the impacts of the depreciation study for which rates became effective January 2021, lower allowances for equity and borrowed funds used during construction of $17 million and higher operations and maintenance expense of $12 million. Utility margin increased primarily due to the higher retail, wheeling, and wholesale revenue, higher deferred net power costs in accordance with established adjustment mechanisms and lower purchased electricity volumes, partially offset by higher purchased electricity prices and higher thermal generation costs. Retail customer volumes increased 11.6%, primarily due to higher customer usage, favorable impacts of weather and an increase in the average number of customers. Energy generated increased 26% for the second quarter of 2021 compared to 2020 primarily due to higher coal-fueled, natural gas-fueled and wind-powered generation, partially offset by lower hydroelectric generation. Wholesale electricity sales volumes increased 33% and purchased electricity volumes decreased 22%.

Net income for the first six months of 2021 was $394 million, an increase of $52 million, or 15%, compared to 2020. Net income increased primarily due to higher utility margin of $125 million, favorable income tax expense primarily from higher PTCs recognized due to new wind-powered generating facilities placed in-service of $37 million, partially offset by higher depreciation and amortization expense of $77 million, including the impacts of the depreciation study for which rates became effective January 2021, lower allowances for equity and borrowed funds used during construction of $29 million, and higher operations and maintenance expense of $17 million. Utility margin increased primarily due to the higher retail, wholesale, and wheeling revenue, higher deferred net power costs in accordance with established adjustment mechanisms and lower purchased electricity volumes, partially offset by higher purchased electricity prices and higher thermal generation costs. Retail customer volumes increased 5.7%, primarily due to higher customer usage, favorable impacts of weather and an increase in the average number of customers. Energy generated increased 16% for the first six months of 2021 compared to 2020 primarily due to higher coal-fueled, wind-powered, and natural gas-fueled generation, partially offset by lower hydroelectric generation. Wholesale electricity sales volumes increased 28% and purchased electricity volumes decreased 17%.

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):
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Second QuarterFirst Six Months
20212020Change20212020Change
Utility margin:
Operating revenue$1,298 $1,144 $154 13 %$2,540 $2,350 $190 8 %
Cost of fuel and energy441 383 58 15 865 800 65 8 
Utility margin857 761 96 13 1,675 1,550 125 8 
Operations and maintenance255 243 12 5 514 497 17 3 
Depreciation and amortization275 210 65 31 539 462 77 17 
Property and other taxes43 52 (9)(17)104 101 3 3 
Operating income$284 $256 $28 11 %$518 $490 $28 6 %
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Utility Margin

A comparison of key operating results related to utility margin is as follows:
Second QuarterFirst Six Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$1,298 $1,144 $154 13 %$2,540 $2,350 $190 8 %
Cost of fuel and energy441 383 58 15 865 800 65 8 
Utility margin$857 $761 $96 13 %$1,675 $1,550 $125 8 %
Sales (GWhs):
Residential4,032 3,656 376 10 %8,664 8,077 587 7 %
Commercial4,633 3,948 685 17 9,103 8,358 745 9 
Industrial, irrigation and other5,127 4,759 368 8 9,601 9,461 140 1 
Total retail13,792 12,363 1,429 12 27,368 25,896 1,472 6 
Wholesale1,244 932 312 33 2,835 2,213 622 28 
Total sales15,036 13,295 1,741 13 %30,203 28,109 2,094 7 %
Average number of retail customers
 (in thousands)		1,998 1,964 34 2 %1,994 1,959 35 2 %
Average revenue per MWh:
Retail$86.26 $86.19 $0.07 — %$85.21 $84.51 $0.70 1 %
Wholesale$31.08 $33.97 $(2.89)(9)%$30.97 $29.56 $1.41 5 %
Heating degree days1,228 1,333 (105)(8)%5,915 5,938 (23)— %
Cooling degree days746 439 307 70 %746 439 307 70 %
Sources of energy (GWhs)(1):
Coal7,502 6,197 1,305 21 %15,146 13,425 1,721 13 %
Natural gas3,223 2,202 1,021 46 6,288 5,243 1,045 20 
Hydroelectric(2)
678 891 (213)(24)1,601 1,937 (336)(17)
Wind and other(2)
1,408 864 544 63 3,211 1,976 1,235 63 
Total energy generated12,811 10,154 2,657 26 26,246 22,581 3,665 16 
Energy purchased3,321 4,233 (912)(22)6,349 7,624 (1,275)(17)
Total16,132 14,387 1,745 12 %32,595 30,205 2,390 8 %
Average cost of energy per MWh:
Energy generated(3)
$17.84 $17.19 $0.65 4 %$17.75 $17.53 $0.22 1 %
Energy purchased$65.62 $38.25 $27.37 72 %$56.80 $42.33 $14.47 34 %

(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.
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Quarter Ended June 30, 2021 compared to Quarter Ended June 30, 2020

Utility margin increased $96 million, or 13%, for the second quarter of 2021 compared to 2020 primarily due to:
•$124 million increase in retail revenue primarily due to higher customer volumes, partially offset by lower rates due to certain general rate case orders. Retail customer volumes increased 11.6%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers;
•$56 million of higher deferred net power costs in accordance with established adjustment mechanisms;
•$14 million of higher wheeling revenue; and
•$7 million of higher wholesale revenue from higher wholesale volumes, partially offset by lower average wholesale market prices.
The increases above were partially offset by:
•$55 million of higher purchased electricity costs from higher average market prices, partially offset by lower volumes;
•$34 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes; and
•$20 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.
Operations and maintenance increased $12 million, or 5%, for the second quarter of 2021 compared to 2020 primarily due to higher plant maintenance costs, partially offset by lower employee related expenses and bad debt expense.

Depreciation and amortization increased $65 million, or 31%, for the second quarter of 2021 compared to 2020 primarily due to the impacts of a depreciation study effective January 1, 2021 of approximately $44 million, including accelerated depreciation on coal-fueled units in Washington, incremental decommissioning as a result of general rate case orders, and higher plant-in-service balances.

Property and other taxes decreased$9 million, or 17%, for the second quarter of 2021 compared to 2020 primarily due to lower property taxes from lower assessed property values.
Allowance for borrowed and equity funds decreased $17 million, or 49%, for the second quarter of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.

Income tax (benefit) expense decreased $45 million to a benefit of $19 million for the second quarter of 2021 compared to expense of $26 million for the second quarter of 2020. The effective tax rate was (9)% for 2021 and 14% for 2020. The effective tax rate decreased primarily as a result of higher effects of ratemaking associated with excess deferred income tax amortization in the current year and increased PTCs from PacifiCorp's new wind-powered generating facilities.

First Six Months of 2021 compared to First Six Months of 2020

Utility margin increased $125 million, or 8%, for the first six months of 2021 compared to 2020 primarily due to:
•$144 million increase in retail revenue primarily due to higher customer volumes, partially offset by lower rates due to certain general rate case orders. Retail customer volumes increased 5.7%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers;
•$48 million of higher deferred net power costs in accordance with established adjustment mechanisms;
•$22 million of higher wholesale revenue due to higher wholesale volumes and higher average wholesale market prices; and
•$17 million of higher wheeling revenue.
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The increases above were partially offset by:
•$46 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes;
•$37 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes; and
•$26 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.
Operations and maintenance increased $17 million, or 3%, for the first six months of 2021 compared to 2020 primarily due to higher vegetation management costs and higher plant maintenance costs, partially offset by lower bad debt expense.

Depreciation and amortization increased $77 million, or 17%, for the first six months of 2021 compared to 2020 primarily due to the impacts of a depreciation study effective January 1, 2021 of approximately $81 million, including accelerated depreciation on coal-fueled units in Washington, incremental decommissioning as a result of general rate case orders and higher placed-in-service balances, 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 first quarter of 2021 (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)).

Allowance for borrowed and equity funds decreased $29 million, or 44%, for the first six months of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.

Other, net increased $6 million for the first six months of 2021 compared to 2020 primarily due to market movements related to corporate-owned life insurance policies.

Income tax (benefit) expense decreased $42 million to a benefit of $30 million for the first six months of 2021 compared to expense of $12 million the first six months of 2020. The effective tax rate was (8)% for 2021 and 3% for 2020. The effective tax rate decreased primarily as a result of increased PTCs from PacifiCorp's new wind-powered generating facilities.

Liquidity and Capital Resources

As of June 30, 2021, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents$44 
Credit facilities1,200 
Less:
Short-term debt(301)
Tax-exempt bond support(218)
Net credit facilities681 
Total net liquidity$725 
Credit facilities:
Maturity dates2024 
Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $1,046 million and $770 million, respectively. The change was primarily due to higher cash received for income taxes, higher collections from retail customers, and higher collateral received related to natural gas swaps, partially offset by higher operating expense payments.

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.

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Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020 were $(819) million and $(944) million, respectively. The change is primarily due to an increase in capital expenditures of $154 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 six-month period ended June 30, 2021 was $(196) million. Sources of cash consisted of $208 million from the borrowing of short-term debt. Uses of cash consisted substantially of $400 million for the repayment of long-term debt.

Net cash flows from financing activities for the six-month period ended June 30, 2020 was $857 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $987 million. Uses of cash consisted of $130 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 June 30, 2021, PacifiCorp had $301 million of short-term debt outstanding at a weighted average interest rate of 0.17%. As of December 31, 2020, PacifiCorp had $93 million of short-term debt outstanding at a weighted average interest rate of 0.16%.

Long-term Debt

In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.

Debt Authorizations

Following the July 2021 long-term debt issuance, PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $2 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.

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Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Six-Month PeriodsAnnual
Ended June 30,Forecast
202020212021
Wind generation$443 $82 $180 
Electric distribution215 326 711 
Electric transmission192 136 347 
Other123 275 544 
Total$973 $819 $1,782 

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 $79 million and $395 million for the six-month periods ended June 30, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020, 476 MWs that were placed in service in the first six months of 2021 and an additional 40 MWs expected to be placed in-service in the second half of 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 $39 million for 2021.
◦Repowering of wind-powered generating facilities at PacifiCorp totaling $3 million and $46 million for the six-month periods ended June 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first six months of 2021. The energy production from these existing 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 repowering of wind-powered generating facilities totals $47 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 $117 million and $12 million for the six-month periods ended June 30, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with these activities will total an additional $90 million in the second half of 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 additional Energy Gateway Transmission segments to be placed in service in 2024-2026 totals $112 million in 2021.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $47 million and $31 million for the six-month periods ended June 30, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with information technology will total an additional $100 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.

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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 was submitted to OPUC in June 2021. PacifiCorp will initiate negotiations with shortlisted bids that include approximately 1,792 MWs of new wind capacity, 1,306 MWs of solar capacity and 697 MWs of battery storage to its portfolio by 2024. PacifiCorp expects that 590 MWs of the 1,792 MWs of new wind capacity will be owned with the remainder of the wind, solar and storage capacity being contracted resources.

Contractual Obligations

As of June 30, 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.

2020.


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

Regulatory Matters

PacifiCorp is subject to governmental examinations (including bycomprehensive 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), inquiriesmatters.

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 designedregarding 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 healthimpact 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 planningare administered by various federal, state and existing operations. They can resultlocal agencies. PacifiCorp believes it is in increased capital, operatingmaterial 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 permittingcourts. Environmental laws and other requirements.

MATS

In February 2019, the EPA published a proposed ruleregulations continue to reverse its previous finding that itevolve, and PacifiCorp is appropriate and necessary to regulate hazardous air pollutant emissions from coal- and oil-fired electric generating units. In May 2020, the EPA’s final rule became effective. 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. 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 orthe 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 impactfuture. Amounts recognized on the Companies’ resultsConsolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of operationsjudgment and cash flows.

Oiluncertainty and Gas NSPS

In August 2012, the EPA issued an NSPS impacting new and modified facilitieswill likely change in the natural gas production and gathering sectors and made revisions to the NSPSfuture 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 replacementaccounting for the Clean Power Plan. The 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 was to be reduced by approximately 3 percent per year through 2030, resulting in an ultimate cap of 19.6 million tons. The final rule included a provision for VDEQ to delay implementation of the rule pending authorization from the General Assembly and Governor of Virginia. In April 2020, Virginia legislation was enacted authorizing VDEQ to implement the final rule. In June 2020, the VDEQ signed the CO2 Budget Trading Program rule outlining the requirements for Virginia’s participation in RGGI starting in 2021. The regulatory framework in Virginia provides rate recovery mechanisms that are expected to substantially mitigate any such impact.

The legislation discussed above 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 rangetypes 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 are 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 by the end of 2021. At both June 30, 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 $11 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 June 30, 2020 and December 31, 2019 include reserves of $538 million and $696 million, respectively, and insurance


receivables of $8 million and $111 million, respectively, included within other receivables. During the six months ended June 30, 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 and six months ended June 30, 2019, Dominion Energy’s Consolidated Statements of Income include charges of $100 million ($75 million after-tax) and $278 million ($208 million after-tax), respectively, included within impairment of assetsregulation, derivatives, pension and other charges.

Ratepayer Class Actions

In May 2018, a consolidated complaint against DESC, SCANApostretirement benefits, income taxes and the Staterevenue recognition-unbilled revenue. For additional discussion of South Carolina was filed in the State CourtPacifiCorp'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, of which $26 million had been transferred as of June 30, 2020.

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. In July 2020, the court issued a final approval of the settlement agreement. The settlement will become effective upon the expiration of a 30-day appellate period. 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 will be dismissed upon the effective date of the Santee Cooper Ratepayer Case settlement. 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 will be dismissed upon the effective date of the Santee Cooper Ratepayer Case settlement. 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 July 2020, the court granted final approval of the settlement agreement. In August 2020, SCANA paid the balance of $32.5 million in cash to satisfy the settlement.

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. In June 2020, the plaintiffs filed a motion to dismiss the appeal with the South Carolina Court of Appeals, which was granted in July 2020. 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. In May 2020, SCANA filed a motion to intervene. 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 plaintiff alleges, 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. In June 2020, the U.S. Attorney’s Office for the District of South Carolina filed a motion to intervene and stay the SEC civil action, which the court granted. The stay is currently in effect but does not preclude the SEC’s Division of Enforcement from presenting the proposed settlement with SCANA and DESC to the SEC. 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. A former executive officer of SCANA entered a plea agreement with the U.S. Attorney’s Office and the South Carolina Attorney General’s Office in June 2020 and entered a guilty plea with the U.S. District Court for the District of South Carolina in July 2020. 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. The NRC approved the external flooding hazards for Surry in May 2020. NRC acceptance of the external flooding hazards reevaluations for Millstone has not yet been received, although the NRC is expected to accept the analysis 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

Nuclear Insurance

During the second quarter of 2020, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from $13.9 billion to $13.8 billion. This decrease does not impact Dominion Energy’s responsibility per active unit under the Price-Anderson Amendments Act of 1988.

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, Dominion2020. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2020.

79

MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section

80

PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Virginia Power entered into contractsShareholder of
MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of June 30, 2021, the related statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 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 DOE for the disposal of spent nuclear fuel under provisionsstandards of the Nuclear Waste Policy ActPublic Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of 1982.


In June 2018, a lawsuit for Kewaunee was filedMidAmerican Energy as of December 31, 2020, and the related statements of operations, 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 incurredshareholder'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, 2018. 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 matterinterim financial information is pending.  

Guarantees, Surety Bondsthe responsibility of MidAmerican Energy's management. We are a public accounting firm registered with the PCAOB and Lettersare 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 Credit

Dominion Energy’s guarantee agreement to supportthe 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 portionwhole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Des Moines, Iowa
August 6, 2021

81

MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)

As of
June 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$30 $38 
Trade receivables, net508 234 
Income tax receivable49 0 
Inventories237 278 
Other current assets91 73 
Total current assets915 623 
Property, plant and equipment, net19,473 19,279 
Regulatory assets455 392 
Investments and restricted investments977 911 
Other assets237 232 
Total assets$22,057 $21,437 

The accompanying notes are an integral part of Atlantic Coast Pipeline’s obligation underthese financial statements.
82

MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

As of
June 30,December 31,
20212020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable$288 $408 
Accrued interest78 78 
Accrued property, income and other taxes267 161 
Other current liabilities188 183 
Total current liabilities821 830 
Long-term debt7,224 7,210 
Regulatory liabilities1,254 1,111 
Deferred income taxes3,164 3,054 
Asset retirement obligations709 709 
Other long-term liabilities459 458 
Total liabilities13,631 13,372 
Commitments and contingencies (Note 9)00
Shareholder's equity:
Common stock - 350 shares authorized, 0 par value, 71 shares issued and outstanding0 0 
Additional paid-in capital561 561 
Retained earnings7,865 7,504 
Total shareholder's equity8,426 8,065 
Total liabilities and shareholder's equity$22,057 $21,437 

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

83

MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Operating revenue:
Regulated electric$586 $518 $1,131 $989 
Regulated natural gas and other107 95 629 305 
Total operating revenue693 613 1,760 1,294 
Operating expenses:
Cost of fuel and energy103 71 254 151 
Cost of natural gas purchased for resale and other57 42 489 170 
Operations and maintenance184 182 377 347 
Depreciation and amortization209 175 416 351 
Property and other taxes37 35 73 69 
Total operating expenses590 505 1,609 1,088 
Operating income103 108 151 206 
Other income (expense):
Interest expense(74)(74)(148)(150)
Allowance for borrowed funds2 4 4 7 
Allowance for equity funds8 9 14 17 
Other, net15 21 26 16 
Total other income (expense)(49)(40)(104)(110)
Income before income tax benefit54 68 47 96 
Income tax benefit(159)(141)(313)(264)
Net income$213 $209 $360 $360 

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

84

MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions)

Common StockAdditional Paid-in CapitalRetained
Earnings		Total Shareholder's
Equity
Balance, March 31, 2020$0 $561 $6,830 $7,391 
Net income— — 209 209 
Balance, June 30, 2020$0 $561 $7,039 $7,600 
Balance, December 31, 2019$0 $561 $6,679 $7,240 
Net income— — 360 360 
Balance, June 30, 2020$0 $561 $7,039 $7,600 
Balance, March 31, 2021$0 $561 $7,651 $8,212 
Net income— — 213 213 
Other equity transactions— — 1 1 
Balance, June 30, 2021$0 $561 $7,865 $8,426 
Balance, December 31, 2020$0 $561 $7,504 $8,065 
Net income— — 360 360 
Other equity transactions— — 1 1 
Balance, June 30, 2021$0 $561 $7,865 $8,426 

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

85

MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

Six-Month Periods
Ended June 30,
20212020
Cash flows from operating activities:
Net income$360 $360 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization416 351 
Amortization of utility plant to other operating expenses17 17 
Allowance for equity funds(14)(17)
Deferred income taxes and amortization of investment tax credits196 131 
Settlements of asset retirement obligations(19)(25)
Other, net11 8 
Changes in other operating assets and liabilities:
Trade receivables and other assets(275)(1)
Inventories41 (31)
Pension and other postretirement benefit plans0 (11)
Accrued property, income and other taxes, net56 (409)
Accounts payable and other liabilities(68)(47)
Net cash flows from operating activities721 326 
Cash flows from investing activities:
Capital expenditures(720)(824)
Purchases of marketable securities(109)(210)
Proceeds from sales of marketable securities105 202 
Other, net(2)14 
Net cash flows from investing activities(726)(818)
Cash flows from financing activities:
Net proceeds from short-term debt0 195 
Other, net(2)(1)
Net cash flows from financing activities(2)194 
Net change in cash and cash equivalents and restricted cash and cash equivalents(7)(298)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period45 330 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$38 $32 

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

86

MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

(1)    General

MidAmerican Energy Company ("MidAmerican Energy") is a revolving credit facilitypublic utility with electric and natural gas operations and is describedthe 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 Note 10. In addition, atDes Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of June 30, 2020, Dominion Energy had issued an additional $27 million2021, and for the three- and six-month periods ended June 30, 2021 and 2020. The Statements of guarantees, primarily to support other equity method investees. No amounts related to the other guaranteesComprehensive Income have been recorded.

Dominion Energy also enters into guarantee arrangements on behalfomitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 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 underoperations for the contractsthree- 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 issix-month periods ended June 30, 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. Termsnecessarily indicative of the guarantees typically end once obligations have been paid. Dominion Energy currently believes it is unlikely that it wouldresults to be required to perform or otherwise incur any losses associated with guaranteesexpected for the full year.


The preparation of its subsidiaries’ obligations.

At June 30, 2020, Dominion Energy had issued the following subsidiary guarantees:

 

 

Maximum

Exposure

 

(millions)

 

 

 

 

Commodity transactions(1)

 

$

2,215

 

Nuclear obligations(2)

 

 

224

 

Cove Point(3)

 

 

1,900

 

Solar(4)

 

 

449

 

Other(5)

 

 

460

 

Total(6)

 

$

5,248

 

(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 and in Note 14 in this report.

Additionally, at June 30, 2020, Dominion Energy had purchased $177 million of surety bonds, including $89 million at Virginia Power and $27 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $103 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 Consolidatedunaudited 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.

At2020, 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 policies during the six-month period ended June 30, 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 June 30, 2021 and December 31, 2020, Dominion Energy’s grossconsist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 30, 2021 and December 31, 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
June 30,December 31,
20212020
Cash and cash equivalents$30 $38 
Restricted cash and cash equivalents in other current assets8 7 
Total cash and cash equivalents and restricted cash and cash equivalents$38 $45 

87

(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
As of
June 30,December 31,
Depreciable Life20212020
Utility plant in service, net:
Generation20-70 years$17,083 $16,980 
Transmission52-75 years2,364 2,365 
Electric distribution20-75 years4,468 4,369 
Natural gas distribution29-75 years1,988 1,955 
Utility plant in service25,903 25,669 
Accumulated depreciation and amortization(7,241)(6,902)
Utility plant in service, net18,662 18,767 
Nonregulated property, net:
Nonregulated property gross20-50 years7 7 
Accumulated depreciation and amortization(1)(1)
Nonregulated property, net6 6 
18,668 18,773 
Construction work-in-progress805 506 
Property, plant and equipment, net$19,473 $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 MidAmerican Energy's customers, the Iowa Utilities Board ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the six-month period ended June 30, 2021.

88

(5)    Recent Financing Transactions

Long-Term Debt

In July 2021, MidAmerican Energy issued $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Energy used the net proceeds to finance a portion of the capital expenditures, disbursed during the period from July 22, 2019 to September 27, 2019, with respect to investments in its 2,000-megawatt Wind XI project, its 592-megawatt Wind XII project, its 207-megawatt Wind XII Expansion project and the repowering of certain of its existing wind-powered generating facilities, which were previously financed with MidAmerican Energy's general funds.

Credit Facilities

In June 2021, MidAmerican Energy amended and restated its existing $900 million unsecured credit exposurefacility expiring in June 2022. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to consent of the lenders. Additionally, in June 2021, MidAmerican Energy terminated its existing $600 million unsecured credit facility expiring in August 2021.

(6)    Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
Income tax credits(271)(186)(634)(257)
State income tax, net of federal income tax impacts(31)(35)(32)(33)
Effects of ratemaking(15)(9)(21)(7)
Other, net2 2 0 1 
Effective income tax rate(294)%(207)%(666)%(275)%

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 June 30, 2021 and 2020 totaled $146 million and $127 million, respectively, and for the six-month periods ended June 30, 2021 and 2020 totaled $297 million and $247 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 computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to 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 received net cash payments for income tax from BHE totaling $558 million for the six-month period ended June 30, 2021, and made net cash payments for income tax to BHE totaling $19 million for the six-month period ended June 30, 2020.

(7)    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.

89

Net periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Pension:
Service cost$5 $1 $10 $2 
Interest cost5 6 11 12 
Expected return on plan assets(10)(10)(19)(20)
Net amortization1 1 1 1 
Net periodic benefit cost (credit)$1 $(2)$3 $(5)
Other postretirement:
Service cost$2 $1 $4 $2 
Interest cost2 1 4 3 
Expected return on plan assets(3)(3)(5)(6)
Net amortization(1)(2)(2)(3)
Net periodic benefit (credit) cost$0 $(3)$1 $(4)

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 June 30, 2021, $4 million and $6 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(8)    Fair Value Measurements

The carrying value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.

•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•Level 3 — Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.

90

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 1Level 2Level 3
Other(1)
Total
As of June 30, 2021:
Assets:
Commodity derivatives$0 $20 $4 $(4)$20 
Money market mutual funds(2)
7 0 0 — 7 
Debt securities:
United States government obligations222 0 0 — 222 
International government obligations0 5 0 — 5 
Corporate obligations0 78 0 — 78 
Municipal obligations0 2 0 — 2 
Agency, asset and mortgage-backed obligations0 1 0 — 1 
Equity securities:
United States companies412 0 0 — 412 
International companies8 0 0 — 8 
Investment funds24 0 0 — 24 
$673 $106 $4 $(4)$779 
Liabilities - commodity derivatives$(1)$(2)$(5)$7 $(1)

Input Levels for Fair Value Measurements
Level 1Level 2Level 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 obligations200 0 0 — 200 
International government obligations0 5 0 — 5 
Corporate obligations0 73 0 — 73 
Municipal obligations0 2 0 — 2 
Agency, asset and mortgage-backed obligations0 6 0 — 6 
Equity securities:
United States companies381 0 0 — 381 
International companies9 0 0 — 9 
Investment funds17 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 receivable of $3 million and $— million as of June 30, 2021 and December 31, 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.
91

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 June 30, 2021As of December 31, 2020
Carrying
Value		Fair
Value		Carrying
Value		Fair
Value
Long-term debt$7,224 $8,698 $7,210 $9,130 

(9)    Commitments and Contingencies

Construction Commitments

During the six-month period ended June 30, 2021, MidAmerican Energy entered into firm construction commitments totaling $558 million through the remainder of 2021 and 2022 related to the repowering and construction of wind-powered generating facilities and the construction of solar-powered generating facilities.

Easements

During the six-month period ended June 30, 2021, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $87 million through 2061 for land in Iowa on which some of its wind- and solar-powered generating facilities will be located.

Legal Matters

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

Environmental Laws and Regulations

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.

92

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 June 30, 2021, has accrued a $10 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.

93

(10)    Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 11, (in millions):
For the Three-Month Period Ended June 30, 2021For the Six-Month Period Ended June 30, 2021
ElectricNatural GasOtherTotalElectricNatural GasOtherTotal
Customer Revenue:
Retail:
Residential$170 $59 $— $229 $331 $367 $— $698 
Commercial80 18 — 98 151 147 — 298 
Industrial230 3 — 233 420 15 — 435 
Natural gas transportation services— 9 — 9 — 19 — 19 
Other retail(1)
36 0 — 36 66 1 — 67 
Total retail516 89 — 605 968 549 — 1,517 
Wholesale52 17 — 69 126 68 — 194 
Multi-value transmission projects15 — — 15 30 — — 30 
Other Customer Revenue— — 1 1 — — 11 11 
Total Customer Revenue583 106 1 690 1,124 617 11 1,752 
Other revenue3 0 0 3 7 1 0 8 
Total operating revenue$586 $106 $1 $693 $1,131 $618 $11 $1,760 

For the Three-Month Period Ended June 30, 2020For the Six-Month Period Ended June 30, 2020
ElectricNatural GasOtherTotalElectricNatural GasOtherTotal
Customer Revenue:
Retail:
Residential$166 $59 $— $225 $314 $187 $— $501 
Commercial73 15 — 88 143 58 — 201 
Industrial197 3 — 200 360 7 — 367 
Natural gas transportation services— 7 — 7 — 18 — 18 
Other retail(1)
32 1 — 33 61 1 — 62 
Total retail468 85 — 553 878 271 — 1,149 
Wholesale28 9 — 37 70 31 — 101 
Multi-value transmission projects17 — — 17 33 — — 33 
Other Customer Revenue— — 0 0 — — 1 1 
Total Customer Revenue513 94 0 607 981 302 1 1,284 
Other revenue5 1 0 6 8 2 0 10 
Total operating revenue$518 $95 $0 $613 $989 $304 $1 $1,294 

(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.

94

(11)    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 PeriodsSix-Month Periods
 Ended June 30,Ended June 30,
2021202020212020
Operating revenue:
Regulated electric$586 $518 $1,131 $989 
Regulated natural gas106 95 618 304 
Other1 0 11 1 
Total operating revenue$693 $613 $1,760 $1,294 
Operating income:
Regulated electric$103 $101 $112 $160 
Regulated natural gas0 7 39 46 
Other0 0 0 0 
Total operating income103 108 151 206 
Interest expense(74)(74)(148)(150)
Allowance for borrowed funds2 4 4 7 
Allowance for equity funds8 9 14 17 
Other, net15 21 26 16 
Income before income tax benefit$54 $68 $47 $96 

As of
June 30,
2021		December 31,
2020
Assets:
Regulated electric$20,349 $19,892 
Regulated natural gas1,708 1,544 
Other0 1 
Total assets$22,057 $21,437 


95



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Managers and Member of
MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of June 30, 2021, the related consolidated statements of operations and changes in member's equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 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
August 6, 2021

96

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)

As of
June 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$31 $39 
Trade receivables, net508 234 
Income tax receivable49 0 
Inventories237 278 
Other current assets92 74 
Total current assets917 625 
Property, plant and equipment, net19,474 19,279 
Goodwill1,270 1,270 
Regulatory assets455 392 
Investments and restricted investments979 913 
Other assets236 232 
Total assets$23,331 $22,711 

The accompanying notes are an integral part of these consolidated financial statements.
97

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

As of
June 30,December 31,
20212020
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable$288 $408 
Accrued interest84 83 
Accrued property, income and other taxes267 161 
Note payable to affiliate183 177 
Other current liabilities188 183 
Total current liabilities1,010 1,012 
Long-term debt7,464 7,450 
Regulatory liabilities1,254 1,111 
Deferred income taxes3,162 3,052 
Asset retirement obligations709 709 
Other long-term liabilities459 458 
Total liabilities14,058 13,792 
Commitments and contingencies (Note 9)00
Member's equity:
Paid-in capital1,679 1,679 
Retained earnings7,594 7,240 
Total member's equity9,273 8,919 
Total liabilities and member's equity$23,331 $22,711 

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

98

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Operating revenue:
Regulated electric$586 $518 $1,131 $989 
Regulated natural gas and other107 98 629 313 
Total operating revenue693 616 1,760 1,302 
Operating expenses:
Cost of fuel and energy103 71 254 151 
Cost of natural gas purchased for resale and other57 42 489 171 
Operations and maintenance184 183 377 348 
Depreciation and amortization209 175 416 351 
Property and other taxes37 35 73 69 
Total operating expenses590 506 1,609 1,090 
Operating income103 110 151 212 
Other income (expense):
Interest expense(78)(78)(156)(159)
Allowance for borrowed funds2 4 4 7 
Allowance for equity funds8 9 14 17 
Other, net16 21 26 15 
Total other income (expense)(52)(44)(112)(120)
Income before income tax benefit51 66 39 92 
Income tax benefit(160)(142)(316)(266)
Net income$211 $208 $355 $358 

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

99

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)
(Amounts in millions)

Paid-in
Capital		Retained
Earnings		Total Member's
Equity
Balance, March 31, 2020$1,679 $6,572 $8,251 
Net income— 208 208 
Balance, June 30, 2020$1,679 $6,780 $8,459 
Balance, December 31, 2019$1,679 $6,422 $8,101 
Net income— 358 358 
Balance, June 30, 2020$1,679 $6,780 $8,459 
Balance, March 31, 2021$1,679 $7,384 $9,063 
Net income— 211 211 
Other equity transactions— (1)(1)
Balance, June 30, 2021$1,679 $7,594 $9,273 
Balance, December 31, 2020$1,679 $7,240 $8,919 
Net income— 355 355 
Other equity transactions— (1)(1)
Balance, June 30, 2021$1,679 $7,594 $9,273 

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

100

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

Six-Month Periods
Ended June 30,
20212020
Cash flows from operating activities:
Net income$355 $358 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization416 351 
Amortization of utility plant to other operating expenses17 17 
Allowance for equity funds(14)(17)
Deferred income taxes and amortization of investment tax credits195 134 
Settlements of asset retirement obligations(19)(25)
Other, net11 8 
Changes in other operating assets and liabilities:
Trade receivables and other assets(275)0 
Inventories41 (31)
Pension and other postretirement benefit plans0 (11)
Accrued property, income and other taxes, net56 (414)
Accounts payable and other liabilities(68)(47)
Net cash flows from operating activities715 323 
Cash flows from investing activities:
Capital expenditures(721)(824)
Purchases of marketable securities(109)(210)
Proceeds from sales of marketable securities105 202 
Other, net(1)15 
Net cash flows from investing activities(726)(817)
Cash flows from financing activities:
Net change in note payable to affiliate6 4 
Net proceeds from short-term debt0 195 
Other, net(2)(1)
Net cash flows from financing activities4 198 
Net change in cash and cash equivalents and restricted cash and cash equivalents(7)(296)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period46 331 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$39 $35 

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

101

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 marketingbusinesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct, wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct, wholly owned nonregulated subsidiary is Midwest Capital Group, Inc.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2021, and for the three- and six-month periods ended June 30, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and six-month periods ended June 30, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 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 six-month period ended June 30, 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 June 30, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 30, 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
June 30,December 31,
20212020
Cash and cash equivalents$31 $39 
Restricted cash and cash equivalents in other current assets8 7 
Total cash and cash equivalents and restricted cash and cash equivalents$39 $46 

102

(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)    Recent Financing Transactions

Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.

(6)    Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit is as follows:
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
Income tax credits(286)(192)(764)(269)
State income tax, net of federal income tax impacts(33)(37)(41)(35)
Effects of ratemaking(16)(9)(26)(7)
Other, net0 2 0 1 
Effective income tax rate(314)%(215)%(810)%(289)%

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 June 30, 2021 and 2020 totaled $146 million and $127 million, respectively, and for the six-month periods ended June 30, 2021 and 2020 totaled $297 million and $247 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 received net cash payments for income tax from BHE totaling $560 million for the six-month period ended June 30, 2021, and made net cash payments for income tax to BHE totaling $19 million for the six-month period ended June 30, 2020.

(7)    Employee Benefit Plans

Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements.

103

(8)    Fair Value Measurements

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):
As of June 30, 2021As of December 31, 2020
Carrying
Value		Fair
Value		Carrying
Value		Fair
Value
Long-term debt$7,464 $9,020 $7,450 $9,466 

(9)    Commitments and Contingencies

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

Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.

(10)    Revenue from Contracts with Customers

Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $— million and $3 million for the three-month periods ended June 30, 2021 and 2020, respectively, and $— million and $8 million for the six-month periods ended June 30, 2021 and 2020, respectively.

104

(11)    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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Operating revenue:
Regulated electric$586 $518 $1,131 $989 
Regulated natural gas106 95 618 304 
Other1 3 11 9 
Total operating revenue$693 $616 $1,760 $1,302 
Operating income:
Regulated electric$103 $101 $112 $160 
Regulated natural gas0 7 39 46 
Other0 2 0 6 
Total operating income103 110 151 212 
Interest expense(78)(78)(156)(159)
Allowance for borrowed funds2 4 4 7 
Allowance for equity funds8 9 14 17 
Other, net16 21 26 15 
Income before income tax benefit$51 $66 $39 $92 

As of
June 30,
2021		December 31,
2020
Assets(1):
Regulated electric$21,540 $21,083 
Regulated natural gas1,787 1,623 
Other4 5 
Total assets$23,331 $22,711 
(1)Assets by reportable segment reflect the assignment of goodwill to applicable reporting units.

105

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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with MidAmerican Funding's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.

Results of Operations for the Second Quarter and First Six Months of 2021 and 2020

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the second quarter of 2021 was $213 million, an increase of $4 million, or 2%, compared to 2020 primarily due to higher electric utility margin of $36 million and a favorable income tax benefit of $18 million, partially offset by higher depreciation and amortization expense of $34 million from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020, lower natural gas utility margin from lower customer volumes and unfavorable changes in the cash surrender value of corporate-owned life insurance policies. 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. Electric utility margin increased primarily due to higher retail customer volumes.

MidAmerican Energy's net income for the first six months of 2021 was $360 million, unchanged from 2020, primarily due to higher depreciation and amortization expense of $65 million from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020 and $30 million higher operations and maintenance expenses, partially offset by a favorable income tax benefit of $49 million and higher electric utility margin of $39 million. 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. Electric utility margin increased primarily due to higher retail customer volumes, partially offset by lower wholesale utility margin from a lower average per-unit margin due to higher thermal generation and purchased power costs.

MidAmerican Funding -

MidAmerican Funding's net income for the second quarter of 2021 was $211 million, an increase of $3 million, or 1%, compared to 2020. MidAmerican Funding's net income for the first six months of 2021 was $355 million, a decrease of $3 million, or 1%, compared to 2020. The variances in net income were 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.


106

MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's expense included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):
Second QuarterFirst Six Months
20212020Change20212020Change
Electric utility margin:
Operating revenue$586 $518 $68 13 %$1,131 $989 $142 14 %
Cost of fuel and energy103 71 32 45 254 151 103 68 
Electric utility margin483 447 36 8 %877 838 39 5 %
Natural gas utility margin:
Operating revenue106 95 11 12 %618 304 314 *
Natural gas purchased for resale57 42 15 36 489 170 319 *
Natural gas utility margin49 53 (4)(8)%129 134 (5)(4)%
Utility margin532 500 32 6 %1,006 972 34 3 %
Other operating revenue1 — 1 *11 1 10 *
Operations and maintenance184 182 2 1 377 347 30 9 
Depreciation and amortization209 175 34 19 416 351 65 19 
Property and other taxes37 35 2 6 73 69 4 6 
Operating income$103 $108 $(5)(5)%$151 $206 $(55)(27)%

*    Not meaningful.

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Electric Utility Margin

A comparison of key operating results related to electric utility margin is as follows:
Second QuarterFirst Six Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$586 $518 $68 13 %$1,131 $989 $142 14 %
Cost of fuel and energy103 71 32 45 254 151 103 68 
Utility margin$483 $447 $36 8 %$877 $838 $39 5 %
Sales (GWhs):
Residential1,486 1,505 (19)(1)%3,224 3,173 51 2 %
Commercial894 818 76 9 1,832 1,787 45 3 
Industrial4,056 3,602 454 13 7,875 7,126 749 11 
Other401 334 67 20 771 719 52 7 
Total retail6,837 6,259 578 9 13,702 12,805 897 7 
Wholesale3,872 2,560 1,312 51 7,923 4,994 2,929 59 
Total sales10,709 8,819 1,890 21 %21,625 17,799 3,826 21 %
Average number of retail customers (in thousands)8037949 1 %8027939 1 %
Average revenue per MWh:
Retail$75.62 $74.77 $0.85 1 %$70.71 $68.63 $2.08 3 %
Wholesale$12.06 $10.64 $1.42 13 %$14.40 $13.11 $1.29 10 %
Heating degree days588 650 (62)(10)%3,799 3,602 197 5 %
Cooling degree days426 360 66 18 %426 360 66 18 %
Sources of energy (GWhs)(1):
Wind and other(2)
5,877 5,148 729 14 %11,999 9,994 2,005 20 %
Coal2,791 1,029 1,762 *5,693 2,602 3,091 *
Nuclear1,009 909 100 11 1,904 1,902 2 — 
Natural gas336 77 259 *479 193 286 *
Total energy generated10,013 7,163 2,850 40 20,075 14,691 5,384 37 
Energy purchased842 1,783 (941)(53)1,860 3,426 (1,566)(46)
Total10,855 8,946 1,909 21 %21,935 18,117 3,818 21 %
Average cost of energy per MWh:
Energy generated(3)
$6.43 $3.87 $2.56 66 %$6.29 $4.45 $1.84 41 %
Energy purchased$45.70 $24.50 $21.20 87 %$68.55 $25.02 $43.53 *

*    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.
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Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows:
Second QuarterFirst Six Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$106 $95 $11 12  %$618 $304 $314 *
Natural gas purchased for resale57 42 15 36 489 170 319 *
Utility margin$49 $53 $(4)(8) %$129 $134 $(5)(4) %
Throughput (000's Dths):
Residential6,272 7,046 (774)(11)%31,554 30,956 598 2  %
Commercial3,011 3,012 (1)— 14,744 13,963 781 6 
Industrial1,069 1,070 (1)— 2,506 2,582 (76)(3)
Other11 13 (2)(15)48 48 — — 
Total retail sales10,363 11,141 (778)(7)48,852 47,549 1,303 3 
Wholesale sales5,817 5,859 (42)(1)16,590 18,769 (2,179)(12)
Total sales16,180 17,000 (820)(5)65,442 66,318 (876)(1)
Natural gas transportation service26,853 22,165 4,688 21 56,493 57,119 (626)(1)
Total throughput43,033 39,165 3,868 10  %121,935 123,437 (1,502)(1) %
Average number of retail customers (in thousands)776 770 6 1 %777 770 7 1 %
Average revenue per retail Dth sold$7.81 $6.97 $0.84 12  %$10.88 $5.34 $5.54 *
Heating degree days625 710 (85)(12) %3,926 3,777 149 4  %
Average cost of natural gas per retail Dth sold$3.99 $2.96 $1.03 35  %$8.62 $2.92 $5.70 *
Combined retail and wholesale average cost of natural gas per Dth sold$3.54 $2.49 $1.05 42  %$7.47 $2.57 $4.90 *

*    Not meaningful.

Quarter Ended June 30, 2021 Compared to Quarter Ended June 30, 2020

MidAmerican Energy -

Electric utility margin increased $36 million, or 8%, for the second quarter of 2021 compared to 2020, due to:
•a $39 million increase in retail utility margin primarily due to $23 million from higher usage for certain industrial customers; $7 million from the favorable impact of weather; $6 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $2 million due to price risk management activities totaled $215 million. Of this amount, investment grade counterparties,impacts from changes in sales mix; partially offset by
•a $3 million decrease in Multi-Value Projects ("MVP") transmission revenue; as
•wholesale utility margin was unchanged due to the increase in sales volumes being offset by lower margins per unit, reflecting higher energy costs.
Natural gas utility margin decreased $4 million, or 8%, for the second quarter of 2021 compared to 2020 primarily due to:
•a $6 million decrease from lower average prices primarily due to the timing of recoveries through a capital tracker mechanism; and
•a $1 million decrease from the unfavorable impact of weather; partially offset by
109

•a $3 million increase from higher natural gas energy efficiency program revenue (offset in operations and maintenance expense).
Operations and maintenance increased $2 million, or 1%, for the second quarter of 2021 compared to 2020 primarily due to higher energy efficiency program expense of $5 million (offset in operating revenue) and higher electric and natural gas distribution costs of $3 million, partially offset by lower employee-related expenses.

Depreciation and amortization for the second quarter of 2021 increased $34 million, or 19%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service and $13 million from a regulatory mechanism deferring certain depreciation expense in 2020.

Allowance for borrowed and equity funds decreased $3 million, or 23%, for the second quarter of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net decreased $6 million, or 29%, for the second quarter of 2021 compared to 2020 primarily due to lower cash surrender values of corporate-owned life insurance policies.

Income tax benefit increased $18 million, or 13%, for the second quarter of 2021 compared to 2020, and the effective tax rate was (294)% for 2021 and (207)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to the higher PTCs and a lower pretax income.

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 internally rated, represented 95%. NaN single counterparty, whether investment gradefacilities 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 second quarter of 2021 and 2020 totaled $146 million and $127 million, respectively.

MidAmerican Funding -

Income tax benefit increased $18 million, or non-investment grade, exceeded $5313%, for the second quarter of 2021 compared to 2020, and the effective tax rate was (314)% for 2021 and (215)% for 2020. The changes in the effective tax rates were due to the factors discussed for MidAmerican Energy.

First Six Months of 2021 compared to First Six Months of 2020

MidAmerican Energy -

Electric utility margin increased $39 million, or 5%, for the first six months of 2021 compared to 2020, due to:
•a $54 million increase in retail utility margin primarily due to $22 million from higher usage for certain industrial customers; $13 million from the favorable impact of weather; $12 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $7 million due to price impacts from changes in sales mix; 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 58.7%; and
•a $3 million decrease in MVP transmission revenue.
Natural gas utility margin decreased $5 million, or 4%, for the first six months of 2021 compared to 2020 primarily due to:
•a $7 million decrease from higher refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit);
•a $6 million decrease from lower average prices primarily due to the timing of a capital cost tracking mechanism; partially offset by
•a $6 million increase in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
•a $1 million increase from the favorable impact of weather.

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Operations and maintenance increased $30 million, or 9%, for the first six months of 2021 compared to 2020 primarily due to higher energy efficiency program expense of $10 million (offset in operating revenue), higher generation operations and maintenance expenses of $9 million due to additional wind turbines and easements and higher electric and natural gas distribution costs of $8 million.

Depreciation and amortization for the first six months of 2021 increased $65 million, or 19%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service and $26 million from a regulatory mechanism deferring certain depreciation expense in 2020.

Interest expense decreased $2 million, or 1%, for the first six months of 2021 compared to 2020 due to lower average interest rates on variable rate long-term debt.

Allowance for borrowed and equity funds decreased $6 million, or 25%, for the first six months of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net increased $10 million, or 63%, for the first six months of 2021 compared to 2020 primarily due to higher cash surrender values of corporate-owned life insurance policies.

Income tax benefit increased $49 million, or 19%, for the first six months of 2021 compared to 2020, and the effective tax rate was (666)% for 2021 and (275)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to the higher PTCs and a lower pretax income, partially offset by the effects of ratemaking. PTCs for the first six months of 2021 and 2020 totaled $297 million and $247 million, respectively.

MidAmerican Funding -

Income tax benefit increased $50 million, or 19%, for the first six months of 2021 compared to 2020, and the effective tax rate was (810)% for 2021 and (289)% for 2020. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.


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Liquidity and Capital Resources

As of June 30, 2021, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):

MidAmerican Energy:
Cash and cash equivalents$30 
Credit facilities, maturing 2022 and 20241,505 
Less:
Tax-exempt bond support(370)
Net credit facilities1,135 
MidAmerican Energy total net liquidity$1,165 
MidAmerican Funding:
MidAmerican Energy total net liquidity$1,165 
Cash and cash equivalents1 
MHC, Inc. credit facility, maturing 20224 
MidAmerican Funding total net liquidity$1,170 

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020, were $721 million and $326 million, respectively. MidAmerican Funding's net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020, were $715 million and $323 million, respectively. Cash flows from operating activities reflect higher income tax receipts, partially offset by 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 customer bills 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 the six-month period ended June 30, 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 six-month periods ended June 30, 2021 and 2020, were $(726) million and $(818) million, respectively. MidAmerican Funding's net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020, were $(726) million and $(817) 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.


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Financing Activities

MidAmerican Energy's net cash flows from financing activities for the six-month periods ended June 30, 2021 and 2020 were $(2) million and $194 million, respectively. MidAmerican Funding's net cash flows from financing activities for the six-month periods ended June 30, 2021 and 2020, were $4 million and $198 million, respectively. Through its commercial paper program, MidAmerican Energy received $— million in 2021 and $195 million in 2020. MidAmerican Funding received $6 million and $4 million in 2021 and 2020, respectively, through its note payable with BHE.

Debt Authorizations

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 $1.5 billion unsecured credit facility expiring in June 2024. 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. 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 13, 2024. Additionally, following the July 2021 issuance of $500 million of exposure. Atfirst mortgage bonds, MidAmerican Energy has authorization from the FERC to issue, through June 30, 2023, long-term debt securities up to an aggregate of $2.0 billion and preferred stock up to an aggregate of $500 million and from the Illinois Commerce Commission to issue long-term debt securities up to an aggregate of $350 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.

MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Six-Month PeriodsAnnual
Ended June 30,Forecast
202020212021
Wind generation$419 $286 $802 
Electric distribution104 96 282 
Electric transmission97 54 214 
Solar generation1 63 238 
Other203 221 634 
Total$824 $720 $2,170 

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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 $172 million for 2021 and $388 million for 2020. Planned spending for the construction of additional wind-powered generating facilities totals $198 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.
◦Repowering of wind-powered generating facilities totaled $82 million for 2021 and $19 million for 2020. Planned spending for repowering generating facilities totals $284 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 June 30, 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 141 MWs of small- and utility-scale solar generation during 2021, of which 61 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 June 30, 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.

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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.

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, Virginia Power’s exposurewherein 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.

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.

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.

In May 2021, the PJM conducted its capacity auction as scheduled, and because Illinois has not implemented an FRR program, the MOPR applied to Quad Cities Station in the capacity auction. The MOPR prevented Quad Cities Station from clearing in the auction.


115

Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism under which Quad Cities Station would be removed from the PJM's capacity auction. At the direction of the PJM Board of Managers, the PJM and its stakeholders are considering MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs, which the PJM filed at the FERC on July 30, 2021.

Regulatory Matters

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

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding 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.
116

Nevada Power Company and its subsidiaries
Consolidated Financial Section

117

PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of June 30, 2021, the related consolidated statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 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.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Las Vegas, Nevada
August 6, 2021

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NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)

As of
June 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$79 $25 
Trade receivables, net318 234 
Inventories64 69 
Derivative contracts51 26 
Regulatory assets47 48 
Prepayments36 38 
Other current assets21 26 
Total current assets616 466 
Property, plant and equipment, net6,813 6,701 
Finance lease right of use assets, net344 351 
Regulatory assets717 746 
Other assets73 72 
Total assets$8,563 $8,336 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable$296 $181 
Accrued interest32 32 
Accrued property, income and other taxes44 25 
Current portion of finance lease obligations33 27 
Regulatory liabilities49 50 
Customer deposits42 47 
Asset retirement obligation14 25 
Other current liabilities38 22 
Total current liabilities548 409 
Long-term debt2,498 2,496 
Finance lease obligations321 334 
Regulatory liabilities1,163 1,163 
Deferred income taxes742 738 
Other long-term liabilities281 257 
Total liabilities5,553 5,397 
Commitments and contingencies (Note 8)00
Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding0 0 
Additional paid-in capital2,308 2,308 
Retained earnings705 634 
Accumulated other comprehensive loss, net(3)(3)
Total shareholder's equity3,010 2,939 
Total liabilities and shareholder's equity$8,563 $8,336 
The accompanying notes are an integral part of the consolidated financial statements.
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NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Operating revenue$559 $509 $929 $898 
Operating expenses:
Cost of fuel and energy252 197 417 367 
Operations and maintenance77 74 140 156 
Depreciation and amortization100 91 201 181 
Property and other taxes12 11 24 23 
Total operating expenses441 373 782 727 
Operating income118 136 147 171 
Other income (expense):
Interest expense(39)(40)(77)(82)
Allowance for borrowed funds1 1 2 2 
Allowance for equity funds2 2 3 4 
Other, net9 7 18 6 
Total other income (expense)(27)(30)(54)(70)
Income before income tax expense91 106 93 101 
Income tax expense9 23 9 22 
Net income$82 $83 $84 $79 
The accompanying notes are an integral part of these consolidated financial statements.

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NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)

Accumulated
AdditionalOtherTotal
Common StockPaid-inRetainedComprehensiveShareholder's
SharesAmountCapitalEarningsLoss, NetEquity
Balance, March 31, 20201,000 $0 $2,308 $490 $(4)$2,794 
Net income— — — 83 — 83 
Dividends declared— — — (85)— (85)
Balance, June 30, 20201,000 $0 $2,308 $488 $(4)$2,792 
Balance, December 31, 20191,000 $0 $2,308 $493 $(4)$2,797 
Net income— — — 79 — 79 
Dividends declared— — — (85)— (85)
Other equity transactions— — — 1 — 1 
Balance, June 30, 20201,000 $0 $2,308 $488 $(4)$2,792 
Balance, March 31, 20211,000 $0 $2,308 $636 $(3)$2,941 
Net income— — — 82 — 82 
Dividends declared— — — (13)— (13)
Balance, June 30, 20211,000 $0 $2,308 $705 $(3)$3,010 
Balance, December 31, 20201,000 $0 $2,308 $634 $(3)$2,939 
Net income— — — 84 — 84 
Dividends declared— — — (13)— (13)
Balance, June 30, 20211,000 $0 $2,308 $705 $(3)$3,010 
The accompanying notes are an integral part of these consolidated financial statements.

121

NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

Six-Month Periods
Ended June 30,
20212020
Cash flows from operating activities:
Net income$84 $79 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization201 181 
Allowance for equity funds(3)(4)
Changes in regulatory assets and liabilities(17)1 
Deferred income taxes and amortization of investment tax credits(20)(7)
Deferred energy(1)15 
Amortization of deferred energy7 (11)
Other, net0 6 
Changes in other operating assets and liabilities:
Trade receivables and other assets(83)(80)
Inventories5 2 
Accrued property, income and other taxes21 28 
Accounts payable and other liabilities116 (3)
Net cash flows from operating activities310 207 
Cash flows from investing activities:
Capital expenditures(237)(257)
Net cash flows from investing activities(237)(257)
Cash flows from financing activities:
Proceeds from long-term debt0 718 
Repayments of long-term debt0 (575)
Dividends paid(13)(85)
Other, net(8)(8)
Net cash flows from financing activities(21)50 
Net change in cash and cash equivalents and restricted cash and cash equivalents52 0 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period36 25 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$88 $25 
The accompanying notes are an integral part of these consolidated financial statements.

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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 June 30, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 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 six-month period ended June 30, 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 June 30, 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 June 30, 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
June 30,December 31,
20212020
Cash and cash equivalents$79 $25 
Restricted cash and cash equivalents included in other current assets9 11 
Total cash and cash equivalents and restricted cash and cash equivalents$88 $36 

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(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
As of
Depreciable LifeJune 30,December 31,
20212020
Utility plant:
Generation30 - 55 years$3,776 $3,690 
Transmission45 - 70 years1,483 1,468 
Distribution20 - 65 years3,836 3,771 
General and intangible plant5 - 65 years800 791 
Utility plant9,895 9,720 
Accumulated depreciation and amortization(3,285)(3,162)
Utility plant, net6,610 6,558 
Other non-regulated, net of accumulated depreciation and amortization45 years1 1 
Plant, net6,611 6,559 
Construction work-in-progress202 142 
Property, plant and equipment, net$6,813 $6,701 

(4)    Recent Financing Transactions

Credit Facilities

In June 2021, Nevada Power amended and restated its existing $400 million secured credit facility expiring in June 2022 with no remaining one-year extension options. The amendment extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

(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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
Effects of ratemaking(11)1 (11)1 
Effective income tax rate10 %22 %10 %22 %

Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to wholesalethe 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2021.

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(6)    Employee Benefit Plans

Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
As of
June 30,December 31,
20212020
Qualified Pension Plan:
Other non-current assets$10 $8 
Non-Qualified Pension Plans:
Other current liabilities(1)(1)
Other long-term liabilities(9)(9)
Other Postretirement Plans:
Other non-current assets4 4 

(7)    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 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.

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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 1Level 2Level 3Total
As of June 30, 2021
Assets:
Commodity derivatives$0 $0 $52 $52 
Money market mutual funds(1)
70 0 0 70 
Investment funds2 0 0 2 
$72 $0 $52 $124 
Liabilities - commodity derivatives$0 $0 $(27)$(27)
As of December 31, 2020
Assets:
Commodity derivatives$0 $0 $26 $26 
Money market mutual funds(1)
21 0 0 21 
Investment funds2 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.

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

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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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Beginning balance$27 $(38)$15 $(8)
Changes in fair value recognized in regulatory assets(6)(13)5 (44)
Settlements4 7 5 8 
Ending balance$25 $(44)$25 $(44)

Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long‑term debt (in millions):
As of June 30, 2021As of December 31, 2020
CarryingFairCarryingFair
ValueValueValueValue
Long-term debt$2,498 $3,105 $2,496 $3,245 

(8)    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.

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(9)    Revenue from Contracts with Customers

The following table summarizes Nevada Power's revenue from contracts with customers totaled $59 million. Of("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Customer Revenue:
Retail:
Residential$326 $304 $521 $497 
Commercial110 96 194 190 
Industrial95 83 158 154 
Other3 2 6 5 
Total fully bundled534 485 879 846 
Distribution only service5 6 10 13 
Total retail539 491 889 859 
Wholesale, transmission and other15 12 29 27 
Total Customer Revenue554 503 918 886 
Other revenue5 6 11 12 
Total revenue$559 $509 $929 $898 


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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of 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 amount, investment grade counterparties, including those internally rated, represented 100%. NaN single counterparty, whether investment gradeForm 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.

Results of Operations for the Second Quarter and First Six Months of 2021 and 2020

Overview

Net income for the second quarter of 2021 was $82 million, a decrease of $1 million, or non-investment grade, exceeded $531%, compared to 2020 primarily due to $5 million of exposure. Atlower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021 and an adjustment to regulatory-related revenue deferrals, partially offset by price impacts from changes in sales mix, $9 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, and $3 million of higher operations and maintenance expenses, primarily due to a higher accrual for earnings sharing and higher plant operations and maintenance costs, partially offset by lower net regulatory instructed deferrals and amortizations. These decreases are offset by $14 million of lower income tax expense primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.

Net income for the first six months of 2021 was $84 million, an increase of $5 million, or 6%, compared to 2020 primarily due to $16 million of lower operations and maintenance expenses, primarily due to lower net regulatory instructed deferrals and amortizations of $17 million, partially offset by a higher accrual for earnings sharing, $13 million of lower income tax expense primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021, $12 million of higher other, net, mainly due to higher cash surrender value of corporate-owned life insurance policies of $7 million, lower pension expense and higher interest income, and lower interest expense of $5 million. These increases are offset by $20 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, and $19 million of lower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021 and an adjustment to regulatory-related revenue deferrals, partially offset by price impacts from changes in sales mix.

129

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):
Second QuarterFirst Six Months
20212020Change20212020Change
Utility margin:
Operating revenue$559 $509 $50 10 %$929 $898 $31 3 %
Cost of fuel and energy252 197 55 28 417 367 50 14 
Utility margin307 312 (5)(2)512 531 (19)(4)
Operations and maintenance77 74 3 4 140 156 (16)(10)
Depreciation and amortization100 91 9 10 201 181 20 11 
Property and other taxes12 11 1 9 24 23 1 4 
Operating income$118 $136 $(18)(13)%$147 $171 $(24)(14)%

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Utility Margin

A comparison of key operating results related to utility margin is as follows:
Second QuarterFirst Six Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$559 $509 $50 10 %$929 $898 $31 3 %
Cost of fuel and energy252 197 55 28 417 367 50 14 
Utility margin$307 $312 $(5)(2)%$512 $531 $(19)(4)%
Sales (GWhs):
Residential2,807 2,635 172 7 %4,394 4,179 215 5 %
Commercial1,271 1,071 200 19 2,225 2,082 143 7 
Industrial1,310 1,107 203 18 2,367 2,258 109 5 
Other45 46 (1)(2)92 94 (2)(2)
Total fully bundled(1)
5,433 4,859 574 12 9,078 8,613 465 5 
Distribution only service620 501 119 24 1,136 1,112 24 2 
Total retail6,053 5,360 693 13 10,214 9,725 489 5 
Wholesale89 81 8 10 173 234 (61)(26)
Total GWhs sold6,142 5,441 701 13 %10,387 9,959 428 4 %
Average number of retail customers (in thousands)982 965 17 2 %980 963 17 2 %
Average revenue per MWh:
Retail - fully bundled(1)
$98.10 $99.89 $(1.79)(2)%$96.86 $98.20 $(1.34)(1)%
Wholesale$42.94 $22.07 $20.87 95 %$46.09 $28.29 $17.80 63 %
Heating degree days14 42 (28)(67)%1,008 984 24 2 %
Cooling degree days1,477 1,308 169 13 %1,483 1,310 173 13 %
Sources of energy (GWhs)(2)(3):
Natural gas3,547 3,118 429 14 %6,081 5,740 341 6 %
Renewables20 20 — — 36 36 — — 
Total energy generated3,567 3,138 429 14 6,117 5,776 341 6 
Energy purchased2,104 1,926 178 9 3,459 3,166 293 9 
Total5,671 5,064 607 12 %9,576 8,942 634 7 %
Average cost of energy per MWh(4):
Energy generated$21.82 $17.53 $4.29 24 %$18.96 $19.55 $(0.59)(3)%
Energy purchased$82.70 $73.80 $8.90 12 %$87.07 $80.36 $6.71 8 %

(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 249 GWhs and 318 GWhs of gas generated energy that is purchased at cost by related parties for the second quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 932 GWhs and 1,028 GWhs of gas generated energy that is purchased at cost by related parties for the first six months 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.
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Quarter Ended June 30, 2021 Compared to Quarter Ended June 30, 2020
Utility margin decreased $5 million, or 2%, for the second quarter of 2021 compared to 2020 primarily due to:
•$15 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,
•$6 million due to an adjustment to regulatory-related revenue deferrals,
•$2 million due to lower energy efficiency program rates (offset in operations and maintenance expense) and
•$1 million of lower other revenue due to a regulatory amortization of an impact fee that ended December 2020.
The decrease in utility margin was offset by:
•$15 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 12.9% primarily due to the impacts from COVID-19 recovery, which resulted in higher industrial, commercial and distribution only service customer usage, and higher residential customer usage, mainly from the favorable impact of weather and
•$2 million due to an increase in the average number of customers, primarily from the residential customer class.

Operations and maintenance increased $3 million, or 4%, for the second quarter of 2021 compared to 2020 primarily due to a higher accrual for earnings sharing of $6 million and higher plant operations and maintenance costs, partially offset by lower net regulatory instructed deferrals and amortizations of $6 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 and lower energy efficiency program costs (offset in operating revenue).

Depreciation and amortization increased $9 million, or 10%, for the second 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 $1 million, or 3%, for the second quarter of 2021 compared to 2020 primarily due to lower carrying charges on regulatory items.

Other, net increased $2 million, or 29%, for the second quarter of 2021 compared to 2020 primarily due to lower pension expense and higher interest income, mainly from carrying charges on regulatory items, partially offset by lower cash surrender value of corporate-owned life insurance policies.

Income tax expense decreased $14 million, or 61%, for the second quarter of 2021 compared to 2020. The effective tax rate was 10% in 2021 and 22% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.

First Six Months Ended June 30, 2021 Compared to First Six Months Ended June 30, 2020

Utility margin decreased $19 million, or 4%, for the first six months of 2021 compared to 2020 primarily due to:
•$24 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,
•$6 million due to an adjustment to regulatory-related revenue deferrals,
•$4 million due to lower energy efficiency program rates (offset in operations and maintenance expense) and
•$2 million of lower other revenue due to a regulatory amortization of an impact fee that ended December 2020.
The decrease in utility margin was offset by:
•$14 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 5.0% primarily due to the impacts from COVID-19 recovery, which resulted in higher commercial, industrial and distribution only service customer usage, and higher residential customer usage, mainly from the favorable impact of weather and
•$2 million due to an increase in the average number of customers, mainly residential.


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Operations and maintenance decreased $16 million, or 10%, for the first six months of 2021 compared to 2020 primarily due to lower net regulatory instructed deferrals and amortizations of $17 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 and lower energy efficiency program costs (offset in operating revenue), partially offset by a higher accrual for earnings sharing.

Depreciation and amortization increased $20 million, or 11%, for the first six months 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 $5 million, or 6%, for the first six months of 2021 compared to 2020 primarily due to lower carrying charges on regulatory items and lower interest expense on long-term debt.

Other, net increased $12 million for the first six months of 2021 compared to 2020 primarily due to higher cash surrender value of corporate-owned life insurance policies of $5 million, lower pension expense and higher interest income, mainly from carrying charges on regulatory items.

Income tax expense decreased $13 million, or 59%, for the first six months of 2021 compared to 2020. The effective tax rate was 10% in 2021 and 22% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.

Liquidity and Capital Resources

As of June 30, 2021, Nevada Power's total net liquidity was as follows (in millions):

Cash and cash equivalents$79 
Credit facility400 
Total net liquidity$479 
Credit facility:
Maturity date2024

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $310 million and $207 million, respectively. The change was primarily due to the timing of payments for operating costs, higher collections from customers, increased collections of customer advances, timing of payments for fuel and energy costs and lower inventory purchases, partially offset by higher payments for income taxes.

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020 were $(237) million and $(257) million, respectively. The change was primarily due to decreased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the six-month periods ended June 30, 2021 and 2020 were $(21) million and $50 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 and lower dividends paid to NV Energy, Inc.
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.


133

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):
Six-Month PeriodsAnnual
Ended June 30,Forecast
202020212021
Electric distribution$128 $87 $184 
Electric transmission22 25 76 
Solar generation— 5 32 
Other107 120 197 
Total$257 $237 $489 

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.
•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.


134

Contractual Obligations

As of June 30, 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.
135

Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section

136

PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of June 30, 2021, the related consolidated statements of operations and changes in shareholder's equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 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 Sierra Pacific 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 Sierra Pacific's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Las Vegas, Nevada
August 6, 2021

137

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)

As of
June 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$9 $19 
Trade receivables, net100 97 
Inventories67 77 
Derivative contracts17 9 
Regulatory assets121 67 
Other current assets42 36 
Total current assets356 305 
Property, plant and equipment, net3,232 3,164 
Regulatory assets269 267 
Other assets185 183 
Total assets$4,042 $3,919 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable$135 $108 
Accrued interest14 14 
Accrued property, income and other taxes16 14 
Short-term debt74 45 
Regulatory liabilities24 34 
Customer deposits15 15 
Other current liabilities31 25 
Total current liabilities309 255 
Long-term debt1,164 1,164 
Finance lease obligations118 121 
Regulatory liabilities464 463 
Deferred income taxes390 374 
Other long-term liabilities141 131 
Total liabilities2,586 2,508 
Commitments and contingencies (Note 8)00
Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding0 0 
Additional paid-in capital1,111 1,111 
Retained earnings346 301 
Accumulated other comprehensive loss, net(1)(1)
Total shareholder's equity1,456 1,411 
Total liabilities and shareholder's equity$4,042 $3,919 
The accompanying notes are an integral part of the consolidated financial statements.

138

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Operating revenue:
Regulated electric$189 $165 $370 $349 
Regulated natural gas20 20 59 68 
Total operating revenue209 185 429 417 
Operating expenses:
Cost of fuel and energy93 72 175 152 
Cost of natural gas purchased for resale8 10 29 40 
Operations and maintenance41 41 77 83 
Depreciation and amortization36 34 72 68 
Property and other taxes6 5 12 11 
Total operating expenses184 162 365 354 
Operating income25 23 64 63 
Other income (expense):
Interest expense(13)(14)(27)(28)
Allowance for borrowed funds1 1 1 1 
Allowance for equity funds2 1 3 2 
Other, net3 3 9 4 
Total other income (expense)(7)(9)(14)(21)
Income before income tax expense18 14 50 42 
Income tax expense1 1 5 4 
Net income$17 $13 $45 $38 
The accompanying notes are an integral part of these consolidated financial statements.

139

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)

Accumulated
AdditionalOtherTotal
Common StockPaid-inRetainedComprehensiveShareholder's
SharesAmountCapitalEarningsLoss, NetEquity
Balance, March 31, 20201,000 $0 $1,111 $235 $(1)$1,345 
Net income— — — 13 — 13 
Dividends declared— — — (20)— (20)
Balance, June 30, 20201,000 $0 $1,111 $228 $(1)$1,338 
Balance, December 31, 20191,000 $0 $1,111 $210 $(1)$1,320 
Net income— — — 38 — 38 
Dividends declared— — — (20)— (20)
Balance, June 30, 20201,000 $0 $1,111 $228 $(1)$1,338 
Balance, March 31, 20211,000 $— $1,111 $329 $(1)$1,439 
Net income— — — 17 — 17 
Balance, June 30, 20211,000 $0 $1,111 $346 $(1)$1,456 
Balance, December 31, 20201,000 $0 $1,111 $301 $(1)$1,411 
Net income— — — 45 — 45 
Balance, June 30, 20211,000 $0 $1,111 $346 $(1)$1,456 
The accompanying notes are an integral part of these consolidated financial statements.

140

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

Six-Month Periods
Ended June 30,
20212020
Cash flows from operating activities:
Net income$45 $38 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization72 68 
Allowance for equity funds(3)(2)
Changes in regulatory assets and liabilities(20)(24)
Deferred income taxes and amortization of investment tax credits8 (6)
Deferred energy(47)21 
Amortization of deferred energy2 1 
Other, net(2)1 
Changes in other operating assets and liabilities:
Trade receivables and other assets(1)11 
Inventories10 (19)
Accrued property, income and other taxes(1)10 
Accounts payable and other liabilities29 18 
Net cash flows from operating activities92 117 
Cash flows from investing activities:
Capital expenditures(128)(110)
Net cash flows from investing activities(128)(110)
Cash flows from financing activities:
Net proceeds from short-term debt29 0 
Dividends paid0 (20)
Other, net(4)(2)
Net cash flows from financing activities25 (22)
Net change in cash and cash equivalents and restricted cash and cash equivalents(11)(15)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period26 32 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$15 $17 
The accompanying notes are an integral part of these consolidated financial statements.

141

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 June 30, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-month periods ended June 30, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 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 six-month period ended June 30, 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 June 30, 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 June 30, 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
June 30,December 31,
20212020
Cash and cash equivalents$9 $19 
Restricted cash and cash equivalents included in other current assets6 7 
Total cash and cash equivalents and restricted cash and cash equivalents$15 $26 

142

(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
As of
Depreciable LifeJune 30,December 31,
20212020
Utility plant:
Electric generation25 - 60 years$1,140 $1,130 
Electric transmission50 - 100 years917 908 
Electric distribution20 - 100 years1,774 1,754 
Electric general and intangible plant5 - 70 years191 189 
Natural gas distribution35 - 70 years432 429 
Natural gas general and intangible plant5 - 70 years15 15 
Common general5 - 70 years357 355 
Utility plant4,826 4,780 
Accumulated depreciation and amortization(1,806)(1,755)
Utility plant, net3,020 3,025 
Other non-regulated, net of accumulated depreciation and amortization70 years2 2 
Plant, net3,022 3,027 
Construction work-in-progress210 137 
Property, plant and equipment, net$3,232 $3,164 

(4)    Recent Financing Transactions

Credit Facilities

In June 2021, Sierra Pacific amended and restated its existing $250 million secured credit facility expiring in June 2022 with no remaining one-year extension options. The amendment extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.

(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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
Effects of ratemaking(11)(14)(9)(10)
Income tax credits(1)0 0 0 
Other(3)0 (2)(1)
Effective income tax rate6 %7 %10 %10 %

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.

143

(6)    Employee Benefit Plans

Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
As of
June 30,December 31,
20212020
Qualified Pension Plan:
Other non-current assets$29 $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)

(7)    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 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.

144

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 1Level 2Level 3Total
As of June 30, 2021
Assets:
Commodity derivatives$0 $0 $18 $18 
Money market mutual funds(1)
8 0 0 8 
$8 $0 $18 $26 
Liabilities - commodity derivatives$0 $0 $(6)$(6)
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 June 30, 2021As of December 31, 2020
CarryingFairCarryingFair
ValueValueValueValue
Long-term debt$1,164 $1,324 $1,164 $1,358 


145

(8)    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.

(9)    Revenue from Contracts with Customers

The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 10 (in millions):
Three-Month Periods
Ended June 30,
20212020
ElectricNatural GasTotalElectricNatural GasTotal
Customer Revenue:
Retail:
Residential$68 $13 $81 $63 $14 $77 
Commercial64 5 69 56 4 60 
Industrial42 2 44 34 2 36 
Other1 0 1 1 0 1 
Total fully bundled175 20 195 154 20 174 
Distribution only service1 0 1 1 0 1 
Total retail176 20 196 155 20 175 
Wholesale, transmission and other12 0 12 9 0 9 
Total Customer Revenue188 20 208 164 20 184 
Other revenue1 0 1 1 0 1 
Total revenue$189 $20 $209 $165 $20 $185 

146

Six-Month Periods
Ended June 30,
20212020
ElectricNatural GasTotalElectricNatural GasTotal
Customer Revenue:
Retail:
Residential$138 $38 $176 $132 $44 $176 
Commercial117 15 132 112 17 129 
Industrial81 5 86 75 6 81 
Other3 0 3 2 0 2 
Total fully bundled339 58 397 321 67 388 
Distribution only service2 0 2 2 0 2 
Total retail341 58 399 323 67 390 
Wholesale, transmission and other28 0 28 24 0 24 
Total Customer Revenue369 58 427 347 67 414 
Other revenue1 1 2 2 1 3 
Total revenue$370 $59 $429 $349 $68 $417 

147

(10)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 PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Operating revenue:
Regulated electric$189 $165 $370 $349 
Regulated natural gas20 20 59 68 
Total operating revenue$209 $185 $429 $417 
Operating income:
Regulated electric$21 $20 $52 $53 
Regulated natural gas4 3 12 10 
Total operating income25 23 64 63 
Interest expense(13)(14)(27)(28)
Allowance for borrowed funds1 1 1 1 
Allowance for equity funds2 1 3 2 
Other, net3 3 9 4 
Income before income tax expense$18 $14 $50 $42 

As of
June 30,December 31,
20212020
Assets:
Regulated electric$3,665 $3,540 
Regulated natural gas350 342 
Other(1)
27 37 
Total assets$4,042 $3,919 

(1)    Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.
148

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

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

Results of Operations for the Second Quarter and First Six Monthsof 2021 and 2020

Overview

Net income for the second quarter of 2021 was $17 million, an increase of $4 million, or 31%, compared to 2020 primarily due to $3 million of higher electric utility margin, mainly from price impacts from changes in sales mix, partially offset by lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, and $2 million of higher natural gas utility margin, mainly from higher commercial usage due to the impacts from COVID-19 recovery.

Net income for the first six months of 2021 was $45 million, an increase of $7 million, or 18%, compared to 2020 primarily due to $6 million of lower operations and maintenance expenses, mainly due to lower plant operations and maintenance expenses, a lower accrual for earnings sharing and lower regulatory amortizations, and $5 million of higher other, net, mainly due to lower pension costs, higher cash surrender value of corporate-owned life insurance policies and higher interest income, partially offset by $4 million of higher depreciation and amortization, mainly from regulatory amortizations and higher plant 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, 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.
149

Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
Second QuarterFirst Six Months
20212020Change20212020Change
Electric utility margin:
Operating revenue$189 $165 $24 15 %$370 $349 $21 6 %
Cost of fuel and energy93 72 21 29 175 152 23 15 
Electric utility margin96 93 3 3 195 197 (2)(1)
Natural gas utility margin:
Operating revenue20 20 — — %59 68 (9)(13)%
Natural gas purchased for resale8 10 (2)(20)29 40 (11)(28)
Natural gas utility margin12 10 2 20 30 28 2 7 
Utility margin108 103 5 5 %225 225 — — %
Operations and maintenance41 41 — — %77 83 (6)(7)%
Depreciation and amortization36 34 2 6 72 68 4 6 
Property and other taxes6 5 1 20 12 11 1 9 
Operating income$25 $23 $2 9 %$64 $63 $1 2 %

150

Electric Utility Margin

A comparison of key operating results related to electric utility margin is as follows:
Second QuarterFirst Six Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$189 $165 $24 15 %$370 $349 $21 6 %
Cost of fuel and energy93 72 21 29 175 152 23 15 
Utility margin$96 $93 $3 3 %$195 $197 $(2)(1)%
Sales (GWhs):
Residential626 585 41 7 %1,297 1,220 77 6 %
Commercial788 722 66 9 1,465 1,423 42 3 
Industrial900 811 89 11 1,797 1,720 77 4 
Other3 4 (1)(25)7 8 (1)(13)
Total fully bundled(1)
2,317 2,122 195 9 4,566 4,371 195 4 
Distribution only service420 425 (5)(1)817 837 (20)(2)
Total retail2,737 2,547 190 7 5,383 5,208 175 3 
Wholesale125 96 29 30 300 289 11 4 
Total GWhs sold2,862 2,643 219 8 %5,683 5,497 186 3 %
Average number of retail customers (in thousands)365 358 7 2 %364 357 7 2 %
Average revenue per MWh:
Retail - fully bundled(1)
$75.42 $72.25 $3.17 4 %$74.31 $73.54 $0.77 1 %
Wholesale$52.18 $42.75 $9.43 22 %$56.84 $46.96 $9.88 21 %
Heating degree days498591(93)(16)%2,696 2,657 39 1 %
Cooling degree days369 220 149 68 %369 220 149 68 %
Sources of energy (GWhs)(2):
Natural gas1,133 1,165 (32)(3)%2,215 2,380 (165)(7)%
Coal436 154 282 *465 220 245 *
Renewables(3)
13 13 — — 19 19 — — 
Total energy generated1,582 1,332 250��19 2,699 2,619 80 3 
Energy purchased1,149 1,127 22 2 2,522 2,452 70 3 
Total2,731 2,459 272 11 %5,221 5,071 150 3 %
Average cost of energy per MWh(4):
Energy generated$23.88 $27.52 $(3.64)(13)%$24.44 $27.04 $(2.60)(10)%
Energy purchased$48.21 $30.57 $17.64 58 %$43.16 $32.94 $10.22 31 %

*    Not meaningful
(1)    Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2)    GWh amounts are net of energy used by the related generating facilities.
(3)    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.
151

Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows:
Second QuarterFirst Six Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$20 $20 $— — %$59 $68 $(9)(13)%
Natural gas purchased for resale8 10 (2)(20)29 40 (11)(28)
Utility margin$12 $10 $2 20 %$30 $28 $2 7 %
Sold (000's Dths):
Residential1,450 1,552 (102)(7)%6,108 5,938 170 3 %
Commercial775 718 57 8 3,079 2,885 194 7 
Industrial395 342 53 15 1,140 995 145 15 
Total retail2,620 2,612 8 — %10,327 9,818 509 5 %
Average number of retail customers (in thousands)177 174 3 2 %176 173 3 2 %
Average revenue per retail Dth sold$7.62 $7.98 $(0.36)(5)%$5.69 $6.95 $(1.26)(18)%
Heating degree days498 591 (93)(16)%2,696 2,657 39 1 %
Average cost of natural gas per retail Dth sold$3.21 $3.66 $(0.45)(12)%$2.86 $4.07 $(1.22)(30)%

Quarter Ended June 30, 2021 Compared to Quarter Ended June 30, 2020

Electric utility margin increased$3 million, or 3%, for the second quarter of 2021 compared to 2020 primarily due to:
•$5 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 7.4% primarily due to the impacts from COVID-19 recovery, which resulted in higher industrial and commercial usage, and higher residential customer usage, mainly from the favorable impact of weather and
•$1 million due to an increase in the average number of customers, primarily from the residential customer class.
The increase in utility margin was offset by:
•$3 million due to an adjustment to regulatory-related revenue deferrals and
•$1 million due to lower energy efficiency program rates (offset in operations and maintenance expense).

Natural gas utility margin increased $2 million, or 20%, for the second quarter of 2021 compared to 2020 primarily due to higher commercial usage due to the impacts from COVID-19 recovery.

Depreciation and amortization increased $2 million, or 6%, for the second quarter of 2021 compared to 2020 primarily due to regulatory amortizations.

152

First Six Months Ended June 30, 2021 Compared to First Six Months Ended June 30, 2020

Electric utility margin decreased$2 million, or 1%, for the first six months of 2021 compared to 2020 primarily due to:
•$3 million in lower revenue recognized due to a favorable regulatory decision,
•$3 million due to an adjustment to regulatory-related revenue deferrals and
•$1 million due to lower energy efficiency program rates (offset in operations and maintenance expense).
The decrease in utility margin was offset by:
•$4 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 3.4% primarily due to the impacts from COVID-19 recovery, which resulted in higher industrial and commercial usage and consistent distribution only service usage and higher residential customer usage, mainly from the favorable impact of weather and
•$1 million due to an increase in the average number of customers, mainly residential.
Natural gas utility margin increased $2 million, or 7%, for the first six months of 2021 compared to 2020 primarily due to higher commercial usage due to the impacts from COVID-19 recovery.

Operations and maintenance decreased $6 million, or 7%, for the first six months of 2021 compared to 2020 primarily due to lower plant operations and maintenance expenses, a lower accrual for earnings sharing and lower regulatory amortizations.

Depreciation and amortization increased $4 million, or 6%, for the first six months of 2021 compared to 2020 primarily due to regulatory amortizations and higher plant in service.

Other, net increased $5 million for the first six months of 2021 compared to 2020 primarily due to lower pension costs, higher cash surrender value of corporate-owned life insurance policies and higher interest income, mainly from carrying charges on regulatory items.

Income tax expense increased $1 million, or 25%, for the first six months of 2021 compared to 2020. The effective tax rate was 10% in 2021 and 2020.

Liquidity and Capital Resources

As of June 30, 2021, Sierra Pacific's total net liquidity was as follows (in millions):

Cash and cash equivalents$9 
Credit facility250 
Less -
Short-term debt(74)
Net credit facility176 
Total net liquidity$185 
Credit facility:
Maturity date2024

Operating Activities

Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $92 million and $117 million, respectively. The change was primarily due to the timing of payments for fuel and energy costs and lower collections from customers partially offset by lower inventory purchases, increased collections of customer advances and the timing of payments for operating costs.
153

Investing Activities

Net cash flows from investing activities for the six-month periods ended June 30, 2021 and 2020 were $(128) million and $(110) 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 six-month periods ended June 30, 2021 and 2020 were $25 million and $(22) million, respectively. The change was primarily due to higher proceeds from short-term debt and lower dividends paid to NV Energy, Inc.

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.

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):
Six-Month PeriodsAnnual
Ended June 30,Forecast
202020212021
Electric distribution$68 $42 $118 
Electric transmission17 31 103 
Solar generation— — 18 
Other25 55 114 
Total$110 $128 $353 

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.
154

•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.
•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 June 30, 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.

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.

155

Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
156

PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors of
Eastern Energy Gas Holdings, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of June 30, 2021, the related consolidated statements of operations, comprehensive income and changes in equity for the three-month and six-month periods ended June 30, 2021 and 2020, and of cash flows for the six-month periods ended June 30, 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.

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


/s/ Deloitte & Touche LLP


Richmond, Virginia
August 6, 2021

157

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of
June 30, 2021December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents$86 $35 
Restricted cash and cash equivalents11 13 
Trade receivables, net147 177 
Receivables from affiliates55 139 
Income taxes receivable96 20 
Other receivables39 51 
Inventories123 119 
Other current assets108 102 
Total current assets665 656 
Property, plant and equipment, net10,135 10,144 
Goodwill1,286 1,286 
Investments260 244 
Other assets184 291 
Total assets$12,530 $12,621 

The accompanying notes are an integral part of these consolidated financial statements.
158

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

As of
June 30, 2021December 31, 2020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$59 $71 
Accounts payable to affiliates34 39 
Accrued interest14 19 
Accrued property, income and other taxes71 29 
Notes payable0 9 
Current portion of long-term debt0 500 
Other current liabilities155 147 
Total current liabilities333 814 
Long-term debt3,916 3,925 
Regulatory liabilities650 669 
Other long-term liabilities233 218 
Total liabilities5,132 5,626 
Commitments and contingencies (Note 9)00
Equity:
Member's equity:
Membership interests3,366 2,957 
Accumulated other comprehensive loss, net(40)(53)
Total member's equity3,326 2,904 
Noncontrolling interests4,072 4,091 
Total equity7,398 6,995 
Total liabilities and equity$12,530 $12,621 

The accompanying notes are an integral part of these consolidated financial statements.
159

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Operating revenue$437 $510 $923 $1,066 
Operating expenses:
(Excess) cost of gas(10)1 (10)9 
Operations and maintenance113 635 237 803 
Depreciation and amortization81 94 161 187 
Property and other taxes38 32 77 71 
Total operating expenses222 762 465 1,070 
Operating income (loss)215 (252)458 (4)
Other income (expense):
Interest expense(42)(50)(86)(108)
Allowance for equity funds1 5 3 10 
Interest and dividend income0 27 0 57 
Other, net1 14 2 28 
Total other income (expense)(40)(4)(81)(13)
Income (loss) before income tax expense (benefit) and equity income175 (256)377 (17)
Income tax expense (benefit)22 (82)49 (30)
Equity income7 8 23 23 
Net income (loss)160 (166)351 36 
Net income attributable to noncontrolling interests100 32 202 65 
Net income (loss) attributable to Eastern Energy Gas$60 $(198)$149 $(29)

The accompanying notes are an integral part of these consolidated financial statements.
160

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)


Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Net income (loss)$160 $(166)$351 $36 
 
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $0, $0, $0 and $12 2 4 3 
Unrealized gains (losses) on cash flow hedges, net of tax of $0, $1, $3 and $(29)3 (2)13 (87)
Total other comprehensive income (loss), net of tax5 0 17 (84)
 
Comprehensive income (loss)165 (166)368 (48)
Comprehensive income attributable to noncontrolling interests100 32 206 65 
Comprehensive income (loss) attributable to Eastern Energy Gas$65 $(198)$162 $(113)

The accompanying notes are an integral part of these consolidated financial statements.
161

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)

Accumulated
Other
MembershipComprehensiveNoncontrollingTotal
InterestsLoss, NetInterestsEquity
Balance, March 31, 2020$8,968 $(271)$1,381 $10,078 
Net (loss) income(198)— 32 (166)
Distributions(1,418)— (38)(1,456)
Balance, June 30, 2020$7,352 $(271)$1,375 $8,456 
Balance, December 31, 2019$9,031 $(187)$1,385 $10,229 
Net (loss) income(29)— 65 36 
Other comprehensive loss— (84)— (84)
Distributions(1,650)— (75)(1,725)
Balance, June 30, 2020$7,352 $(271)$1,375 $8,456 
Balance, March 31, 2021$3,035 $(45)$4,088 $7,078 
Net income60 — 100 160 
Other comprehensive income— 5 — 5 
Contributions271 — — 271 
Distributions— — (116)(116)
Balance, June 30, 2021$3,366 $(40)$4,072 $7,398 
Balance, December 31, 2020$2,957 $(53)$4,091 $6,995 
Net income149 — 202 351 
Other comprehensive income— 13 4 17 
Contributions282 — — 282 
Distributions(22)— (225)(247)
Balance, June 30, 2021$3,366 $(40)$4,072 $7,398 

The accompanying notes are an integral part of these consolidated financial statements.
162

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

Six-Month Periods
Ended June 30,
20212020
Cash flows from operating activities:
Net income$351 $36 
Adjustments to reconcile net income to net cash flows from operating activities:
Losses on other items, net3 482 
Depreciation and amortization161 187 
Allowance for equity funds(3)(10)
Equity (income) loss, net of distributions(3)2 
Changes in regulatory assets and liabilities1 12 
Deferred income taxes118 (97)
Other, net(9)7 
Changes in other operating assets and liabilities:
Trade receivables and other assets65 429 
Derivative collateral, net(1)11 
Pension and other postretirement benefit plans0 (35)
Accrued property, income and other taxes(63)(7)
Accounts payable and other liabilities(39)(9)
Net cash flows from operating activities581 1,008 
Cash flows from investing activities:
Capital expenditures(150)(147)
Repayment of loans by affiliates268 1,165 
Loans to affiliates(158)(263)
Other, net(12)(4)
Net cash flows from investing activities(52)751 
Cash flows from financing activities:
Repayments of long-term debt(500)0 
Net repayments of short-term debt0 (62)
(Repayment) issuance of notes payable, net(9)54 
Proceeds from equity contributions256 0 
Distributions(225)(1,725)
Other, net(2)(1)
Net cash flows from financing activities(480)(1,734)
Net change in cash and cash equivalents and restricted cash and cash equivalents49 25 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period48 39 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$97 $64 

The accompanying notes are an integral part of these consolidated financial statements.
163

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(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, Gas’ exposure primarilyInc. ("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"). In July 2021, Dominion Energy Questar Corporation ("Dominion Questar") and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Transaction. Prior to the completion of the GT&S Transaction, Eastern Energy Gas finalized a restructuring whereby Eastern Energy Gas distributed the Questar Pipeline Group and a 50% noncontrolling interest in 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 June 30, 2021 and for the three- and six-month periods ended June 30, 2021 and 2020. The results of operations for the three- and six-month periods ended June 30, 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 six-month period ended June 30, 2021.

164

(2)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
As of
June 30,December 31,
Depreciable Life20212020
Utility Plant:
Interstate natural gas pipeline assets24 - 43 years$8,457 $8,382 
Intangible plant5 - 10 years111 115 
Utility plant in service8,568 8,497 
Accumulated depreciation and amortization(2,816)(2,759)
Utility plant in service, net5,752 5,738 
Nonutility Plant:
LNG facility40 years4,465 4,454 
Intangible plant14 years25 25 
Nonutility plant in service4,490 4,479 
Accumulated depreciation and amortization(366)(283)
Nonutility plant in service, net4,124 4,196 
Plant, net9,876 9,934 
Construction work-in-progress259 210 
Property, plant and equipment, net$10,135 $10,144 

Construction work-in-progress includes $246 million and $196 million as of June 30, 2021 and December 31, 2020, respectively, related to wholesalethe construction of utility plant.

165

(3)    Investments and Restricted Cash and Cash Equivalents

Investments and restricted cash and cash equivalents consists of the following (in millions):
As of
June 30,December 31,
20212020
Investments:
Investment funds$13 $0 
Equity method investments:
Iroquois247 244 
Total investments260 244 
Restricted cash and cash equivalents:
Customer deposits11 13 
Total restricted cash and cash equivalents11 13 
Total investments and restricted cash and cash equivalents$271 $257 
Reflected as:
Current assets$11 $13 
Noncurrent assets260 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 June 30, 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 $20 million and $25 million for the six-month periods ended June 30, 2021 and 2020, respectively.


166

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 June 30, 2021 and December 31, 2020 consist of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of June 30, 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
June 30,December 31,
20212020
Cash and cash equivalents$86 $35 
Restricted cash and cash equivalents11 13 
Total cash and cash equivalents and restricted cash and cash equivalents$97 $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) estimated charge for disallowance of capitalized allowance for funds used during construction. As a condition of the December 2020 ruling, EGTS filed its proposed accounting entries and supporting documentation with the FERC during the second quarter of 2021. During the finalization of these entries, EGTS refined the estimated charge for disallowance of capitalized allowance for funds used during construction, which resulted in a reduction to the estimated charge of $11 million ($8 million after-tax) that was recorded in operations and maintenance expense in its Consolidated Statements of Operations in the second quarter of 2021.

In December 2014, EGTS entered into a precedent agreement with Atlantic Coast Pipeline, LLC ("Atlantic Coast Pipeline") for the project previously intended for EGTS to provide approximately 1,500,000 decatherms ("Dth") of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). As a result of the cancellation of the Atlantic Coast Pipeline project, in the second quarter of 2020 Eastern Energy Gas recorded a charge of $482 million ($359 million after-tax) in operations and maintenance expense in its Consolidated Statements of Operations associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million asset retirement obligation. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.
167

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 $27$7 million. Of this

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.


(5)    Recent Financing Transactions
amount, investment grade counterparties, including those internally rated, represented 88%. NaN single counterparty, whether investment grade
On June 30, 2021, as part of an intercompany transaction with its wholly owned subsidiary EGTS, Eastern Energy Gas exchanged a total of $1.6 billion of its issued and outstanding third party notes, making EGTS the primary obligor of the exchanged notes. The intercompany debt exchange was a common control transaction accounted for as a debt modification with no gain or non-investment grade, exceeded $3 millionloss recognized in the Consolidated Financial Statements. The following table details the exchanged notes prior to, and subsequent to, the transaction (in millions):

Prior to ExchangeSubsequent to Exchange
Eastern Energy Gas Par ValueEastern Energy Gas Par ValueEGTS
Par Value
3.6% Senior Notes due 2024$450 $339 $111 
3.0% Senior Notes due 2029600 174 426 
4.8% Senior Notes due 2043400 54 346 
4.6% Senior Notes due 2044500 56 444 
3.9% Senior Notes due 2049300 27 273 
$2,250 $650 $1,600 


168

(6)    Income Taxes

A reconciliation of exposure.  

For the three and six monthsfederal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:

Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
State income tax, net of federal income tax benefit2 11 3 114 
Equity interest1 (1)1 (27)
Effects of ratemaking(1)1 (1)17 
AFUDC-equity0 0 0 11 
Noncontrolling interest(12)3 (11)78 
Write-off of regulatory assets0 (3)0 (39)
Other, net2 0 0 1 
Effective income tax rate13 %32 %13 %176 %

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 June 30, 2021 from 25% as of June 30, 2020. Additionally, Eastern Energy Gas' effective tax rate for the period ended June 30, 2020 is primarily a function of the Export Customers comprised approximately 36%impacts associated with the cancellation of the Atlantic Coast Pipeline project and 34%, respectively,the nominal year-to date pre-tax income driven by charges associated with the Supply Header Project.

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 net cash payments for income tax to BHE totaling $5 million for the six-month period ended June 30, 2021.

(7)    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 Gas’ total operating revenue,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 Gas’ largest customer representing approximately 19%Retiree Health and 18%, respectively,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.
169

Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Pension:
Service cost$0 $2 $0 $3 
Interest cost0 2 0 5 
Expected return on plan assets0 (14)0 (28)
Net amortization0 2 0 4 
Net periodic benefit credit$0 $(8)$0 $(16)
Other Postretirement:
Service cost$0 $0 $0 $1 
Interest cost0 1 0 2 
Expected return on plan assets0 (5)0 (10)
Net amortization0 0 0 (1)
Net periodic benefit credit$0 $(4)$0 $(8)

(8)    Fair Value Measurements

The carrying value of such amounts duringEastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the periods. Forshort-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 six months ended June 2019,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 Export Customers comprised approximately 34%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.


170

The following table presents Eastern Energy Gas' financial assets and 33%, respectively,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 1Level 2Level 3Total
As of June 30, 2021
Assets:
Foreign currency exchange rate derivatives$0 $16 $0 $16 
Money market mutual funds(1)
45 0 0 45 
Investment funds13 0 0 13 
$58 $16 $0 $74 
Liabilities:
Foreign currency exchange rate derivatives$0 $(5)$0 $(5)
$0 $(5)$0 $(5)
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 derivatives0 (2)0 (2)
Interest rate derivatives0 (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 Dominionthese 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’ total operating revenue,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 Dominioninternal 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’ largest customer representing approximately 18%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 17%, respectively,duration of such amounts duringcontracts.


171

Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the periods.

Credit-Related Contingent Provisions

Consolidated Balance Sheets. The majorityfair value of Dominion Energy’s derivative instruments contain credit-related contingent provisions. These provisions require DominionEastern Energy to provide collateralGas' long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the occurrencepresent value of specific events, primarily afuture cash flows discounted at rates consistent with comparable maturities with similar credit rating downgrade. Ifrisks. The carrying value of Eastern Energy Gas' variable-rate long-term debt approximates fair value because of the credit-related contingent features underlyingfrequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Eastern Energy Gas' long-term debt (in millions):


As of June 30, 2021As of December 31, 2020
CarryingFairCarryingFair
ValueValueValueValue
Long-term debt$3,916 $4,298 $4,425 $5,012 

(9)    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 aresuch 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 a liability positionmaterial compliance with all applicable laws and not fully collateralizedregulations.

(10)    Revenue from Contracts with cash were fully triggeredCustomers

The following table summarizes Eastern Energy Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):
Three-Month PeriodsSix-Month Periods
Ended June 30,Ended June 30,
2021202020212020
Customer Revenue:
Regulated:
Gas transportation and storage$246 $302 $525 $646 
Wholesale0 0 17 2 
Other(2)2 (2)3 
Total regulated244 304 540 651 
Nonregulated190 205 380 413 
Total Customer Revenue434 509 920 1,064 
Other revenue3 1 3 2 
Total operating revenue$437 $510 $923 $1,066 


172

Remaining Performance Obligations

The following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2021 (in millions):
Performance obligations expected to be satisfied
Less than 12 monthsMore than 12 monthsTotal
Eastern Energy Gas$1,571 $16,779 $18,350 

(11)    Components of Accumulated Other Comprehensive Loss, Net

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

UnrecognizedAccumulated
Amounts OnUnrealizedOther
RetirementLosses on CashNoncontrollingComprehensive
BenefitsFlow HedgesInterestsLoss, Net
Balance, December 31, 2019$(106)$(81)$0 $(187)
Other comprehensive income (loss)3 (87)0 (84)
Balance, June 30, 2020$(103)$(168)$0 $(271)
Balance, December 31, 2020$(12)$(51)$10 $(53)
Other comprehensive income (loss)4 13 (4)13 
Balance, June 30, 2021$(8)$(38)$6 $(40)

(12)    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 for each of the three-month periods ended June 30, 2021 and 2020, and December 31, 2019, Dominion Energy would have been required to post $13$6 million and $10$7 million respectively, of additional collateral to its counterparties. The collateral that would be required to be posted includesfor 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 atsix-month periods ended June 30, 2021 and 2020, relatedrespectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash and had posted 0 collateral at December 31, 2019. The aggregate fair valueCarolina Gas Services of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash was $17$28 million and $10$22 million at June 30, 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 as of June 30, 20202021 and December 31, 2019, Virginia Power would have been required2020, 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 postdirect 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.

173

Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Questar Pipeline Services, Inc. ("DEQPS"), an additional $2affiliated VIE, of $7 million and $8$14 million respectively, of collateral to its counterparties.

Credit-related contingent provisions for Dominion Energy Gas were not material as ofthe three- and six-month periods ended June 30, 2020, respectively. 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 December 31, 2019. See Note 9 for further information about derivative instruments.

Note 19. Related-Party Transactions

Virginia Powerbenefits 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 $27 million and $58 million for the three- and six-month periods ended June 30, 2020, respectively. Eastern Energy Gas engagedetermined 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.

(13)    Related Party Transactions

Transactions Prior to the GT&S Transaction

Prior to the GT&S Transaction, Eastern Energy Gas engaged in related-partyrelated party transactions primarily with other Dominion EnergyDEI subsidiaries (affiliates). Virginia Power and DominionEastern Energy Gas’Gas' receivable and payable balances with affiliates arewere settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power and DominionThrough October 31, 2020, Eastern Energy Gas arewas included in Dominion Energy'sDEI's consolidated federal income tax return and, where applicable, combined state income tax returns for Dominionreturns. 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 transactsGas transacted with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Virginia PowerAdditionally, Eastern Energy Gas provided transportation and storage services to affiliates. Eastern Energy Gas also entersentered into certain commodity derivativeother contracts with affiliates. Virginia Power uses theseaffiliates, 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 June 30, 2020, Virginia Power’s derivative assets and liabilities with affiliates were $3 million and $19 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 participatesinvolving commodities or services. Eastern Energy Gas participated in certain Dominion EnergyDEI 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 June 30, 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 $838 million and $782 million, respectively.  At June 30, 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 $318 million and $287 million, respectively.

7.


DES, Carolina Gas Services, DEQPS and other affiliates provideprovided accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power providesEastern 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 presentedthe three-month and six-month periods ended June 30, 2020 include costs for certain general, administrative and corporate expenses assigned by DES, Carolina Gas Services and DEQPS to Virginia PowerEastern Energy Gas on the basis of direct and allocated methods in accordance with Virginia Power’sEastern Energy Gas' services agreements with DES.DES, Carolina Gas Services and DEQPS. Where costs incurred cannot be determined by specific identification, the costs arewere 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.


174

Presented below are Virginia Power’sEastern Energy Gas' significant transactions with DES, Carolina Gas Services, DEQPS and other affiliates:

affiliated and related parties for the three- and six-month periods ended June 30, 2020 (in millions):

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity purchases from affiliates

 

$

104

 

 

$

119

 

 

$

315

 

 

$

391

 

Services provided by affiliates(1)

 

 

114

 

 

 

161

 

 

 

235

 

 

 

280

 

Services provided to affiliates

 

 

4

 

 

 

8

 

 

 

9

 

 

 

14

 


(1)

Includes capitalized expenditures of $34 million for both the three months ended June 30, 2020 and 2019, and $68 million and $67 million for the six months ended June 30, 2020 and 2019, respectively.

Three-Month PeriodSix-Month Period
Ended June 30, 2020Ended June 30, 2020
Sales of natural gas and transportation and storage services$60 $128 
Purchases of natural gas and transportation and storage services3 6 
Services provided by related parties(1)
37 80 
Services provided to related parties(2)
29 61 

Virginia Power has borrowed funds

(1)    Includes capitalized expenditures of $4 million and $7 million for the three- and six-month periods ended June 30, 2020, respectively.
(2)    Amounts primarily attributable to Atlantic Coast Pipeline, LLC, a related-party VIE prior to the GT&S Transaction.

Interest income related to Eastern Energy Gas' affiliated notes receivable from DominionDEI was $12 million and $23 million for the three- and six-month periods ended June 30, 2020, respectively.

Interest income related to Eastern Energy under short-term borrowing arrangements. There were $340Gas' affiliated notes receivable from East Ohio Gas Company was $15 million in short-term demand note borrowingsand $33 million for the three- and six-month periods ended June 30, 2020, respectively.

For the six-month period ended June 30, 2020, Eastern Energy Gas distributed $1.7 billion 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 Dominion EnergyBHE of $76 million and $20 million as of June 30, 20202021 and $107 million in short-term demand note borrowings from Dominion Energy as of December 31, 2019. Virginia Power had 0 outstanding borrowings, net2020, respectively.

Presented below are Eastern Energy Gas' significant transactions with affiliated and related parties for the three- and six-month periods ended June 30, 2021 (in millions):

Three-Month PeriodSix-Month Period
Ended June 30, 2021Ended June 30, 2021
Sales of natural gas and transportation and storage services$7 $14 
Services provided by related parties8 15 
Services provided to related parties7 16 

Other assets included amounts due from an affiliate of repayments, under the Dominion Energy money pool for its nonregulated subsidiaries$5 million and $7 million as of June 30, 20202021 and December 31, 2019. Interest charges related to Virginia Power’s borrowings2020, respectively.

Eastern Energy Gas has a $400 million intercompany revolving credit agreement from Dominion Energy were immaterialits parent, BHE GT&S, LLC ("BHE GT&S") expiring in November 2021. The credit facility, which is for general corporate purposes and provides for the three and six months ended June 30, 2020 and 2019.

There were 0 issuancesissuance of Virginia Power’s common stock to Dominion Energy for the three and six months ended June 30, 2020 and 2019.

Dominion Energy Gas

Transactions with Related Parties

Dominion Energy Gas transacts with affiliates for certain quantitiesletters of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Energy Gas provides transportation and storage services to affiliates. Dominion Energy Gas also enters into certain other contracts with affiliates and related parties, including construction services, which are presented separately from contracts involving commodities or services.credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") plus a fixed spread. As of June 30, 20202021 and December 31, 2019, Dominion2020, $— 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 7expiring 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 June 30, 2021 and 9 for more information. See Note 10 for information regarding transactions with Atlantic Coast Pipeline. See Note 3 for information regardingDecember 31, 2020, $16 million and $124 million, respectively, was outstanding under the Dominion Energy Gas Restructuring, an affiliated transaction.

Dominioncredit agreement.


Eastern Energy Gas participates in certain DominionMidAmerican Energy benefit plans as described in Note 217. As of June 30, 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.



175

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 Second Quarter and First Six Months of 2021 and 2020

Overview

Net income attributable to Eastern Energy Gas for the second quarter of 2021 was $60 million, an increase of $258 million compared to 2020. Net income increased primarily due to a 2020 after-tax charge of $359 million associated with the probable abandonment of a significant portion of a project previously intended for EGTS to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). This increase is partially offset by an increase in net income attributable to noncontrolling interests due to DEI's 50% noncontrolling interest in Cove Point LNG, LP ("Cove Point") of $68 million, the November 2020 disposition of Questar Pipeline Group of $19 million and interest income from DEI and its affiliates recognized in 2020 of $27 million, all of which were a result of the GT&S Transaction.

Net income attributable to Eastern Energy Gas for the first six months of 2021 was $149 million, an increase of $178 million compared to 2020. Net income increased primarily due to a 2020 after-tax charge of $359 million associated with the probable abandonment of a significant portion of the Supply Header Project. This increase is partially offset by an increase in net income attributable to noncontrolling interests due to DEI's 50% noncontrolling interest in Cove Point of $137 million, the November 2020 disposition of Questar Pipeline Group of $42 million, and interest income from DEI and its affiliates recognized in 2020 of $56 million, all of which were a result of the GT&S Transaction.

Quarter Ended June 30, 2021 Compared to Quarter Ended June 30, 2020

Operating revenue decreased $73 million, or 14%, for the second quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $56 million and a decrease in services performed for Atlantic Coast Pipeline, LLC of $16 million, which is offset in operations and maintenance expense.

(Excess) cost of gas was a credit of $10 million for the second quarter of 2021 compared to an expense of $1 million for the second quarter of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices.

Operations and maintenance decreased $522 million, or 82%, for the second quarter of 2021 compared to 2020, primarily due to a 2020 charge associated with the probable abandonment of a significant portion of the Supply Header Project of $482 million, a decrease in services performed for Atlantic Coast Pipeline, LLC of $17 million and the November 2020 disposition of Questar Pipeline Group of $11 million.

Depreciation and amortization decreased $13 million, or 14%, for the second quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.

Property and other taxes increased $6 million, or 19%, for the second quarter of 2021 compared to 2020, primarily due to higher tax assessments.

Interest expense decreased$8 million, or 16%, for the second quarter of 2021 compared to 2020, primarily due to lower interest expense of $3 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and the November 2020 disposition of Questar Pipeline Group of $5 million.

Allowance for equity funds decreased $4 million, or 80%, for the second quarter of 2021 compared to 2020, primarily due to lower capital expenditures related to the Supply Header Project as a result of the abandonment of the project.

Interest and dividend income decreased $27 million for the second quarter of 2021 compared to 2020, due to interest income from the East Ohio Gas Company of $15 million and DEI of $12 million recognized in 2020 as a result of the GT&S Transaction.

176

Other, net decreased $13 million, or 93%, for the second 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 (benefit) was an expense of $22 million for the second quarter of 2021 compared to a benefit of $82 million for the second quarter of 2020 and the effective tax rate was 13% for the second quarter of 2021 and 32% for the second quarter of 2020. The effective tax rate decreased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction and lower pre-tax income driven by charges associated with the Supply Header Project.

Net income attributable to noncontrolling interests increased $68 million for the second quarter of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.

First Six Months Ended June 30, 2021 Compared to First Six Months Ended June 30, 2020

Operating revenue decreased $143 million, or 13%, for the first six months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $120 million and a decrease in services performed for Atlantic Coast Pipeline, LLC of $33 million, which is offset in operations and maintenance expense. This decrease in operating revenue was partially offset by an increase in regulated gas sales for operational and system balancing purposes primarily due to increased volumes of $17 million.

(Excess) cost of gas was a credit of $10 million for the first six months of 2021 compared to an expense of $9 million for the first six months of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices of $30 million and the November 2020 disposition of Questar Pipeline Group of $2 million, partially offset by an increase in volumes sold of $14 million.

Operations and maintenance decreased $566 million, or 70%, for the first six months of 2021 compared to 2020, primarily due to a 2020 charge associated with the probable abandonment of a significant portion of the Supply Header Project of $482 million, a decrease in services performed for Atlantic Coast Pipeline, LLC of $34 million and the November 2020 disposition of Questar Pipeline Group of $26 million.

Depreciation and amortization decreased $26 million, or 14%, for the first six months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.

Property and other taxes increased$6 million, or 8%, for the first six months of 2021 compared to 2020, primarily due to higher tax assessments.

Interest expense decreased $22 million, or 20%, for the first six months of 2021 compared to 2020, primarily due to lower interest expense of $10 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and the November 2020 disposition of Questar Pipeline Group of $10 million.

Allowance for equity funds decreased $7 million, or 70%, for the first six months of 2021 compared to 2020, primarily due to lower capital expenditures related to the Supply Header Project as a result of the abandonment of the project.

Interest and dividend income decreased $57 million for the first six months of 2021 compared to 2020, primarily due to interest income from the East Ohio Gas Company of $33 million and DEI of $23 million recognized in 2020 as a result of the GT&S Transaction.

Other, net decreased $26 million, or 93%, for the first six months 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 (benefit) was an expense of $49 million for the first six months of 2021 compared to a benefit of $30 million for the first six months of 2020 and the effective tax rate was 13% for the first six months of 2021 and 176% for the first six months of 2020. The effective tax rate decreased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction and lower pre-tax income driven by charges associated with the Supply Header Project.

Net income attributable to noncontrolling interests increased $137 million for the first six months of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.

177

Liquidity and Capital Resources

As of June 30, 2021, Eastern Energy Gas' total net liquidity was $486 million as follows (in millions):

Cash and cash equivalents$86 
Intercompany credit agreement(1)
400 
Less:
Notes payable— 
Net intercompany credit agreement400 
Total net liquidity$486 
Intercompany credit agreement:
Maturity date2021

(1)Refer to Note 13 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 six-month periods ended June 30, 2021 and 2020 were $581 million and $1.0 billion, respectively. The change was primarily due to lower collections from affiliates, lower income tax receipts and the timing of payments of operating costs.

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 six-month periods ended June 30, 2021 and 2020 were $(52) million and $751 million, respectively. The change was primarily due to a decrease in repayments of loans by affiliates of $897 million, partially offset by a decrease in loans to affiliates of $105 million.

Financing Activities

Net cash flows from financing activities for the six-month period ended June 30, 2021 were $(480) million. Sources of cash totaled $256 million and consisted of proceeds from equity contributions, that primarily included a contribution from its indirect parent, BHE, to Eastern Energy Gas to assist in the repayment of $500 million of debt. Uses of cash totaled $736 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $225 million and repayment of notes to affiliates of $9 million.

Net cash flows from financing activities for the six-month period ended June 30, 2020 were $(1.7) billion. Sources of cash consisted of $54 million from the net issuances of affiliated current borrowings. Uses of cash totaled $1.8 billion and consisted mainly of distributions to DEI of $1.7 billion and repayments of short-term debt of $62 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.
178

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):
Six-Month PeriodsAnnual
Ended June 30,Forecast
202020212021
Natural gas transmission and storage$49 $11 $22 
Other98 139 448 
Total$147 $150 $470 

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 June 30, 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 June 30, 20202020.

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 DominionRegulations

Eastern Energy associatedGas 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 chargesauthority to levy substantial penalties for noncompliance, including fines, injunctive relief and other assetssanctions. 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 $334 millionFinancial Statements based on such estimates involve numerous assumptions subject to varying and $326 million, respectively. At June 30, 2020potentially significant degrees of judgment and December 31, 2019, Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Retiree Healthuncertainty and Welfare Plan included in other deferred charges and other assetswill likely change in the Consolidated Balance Sheets were $20 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 statementsfuture 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 measuresaccounting for the relevant DES, DECGSeffects of certain types of regulation, impairment of goodwill and DEQPS service. Management believes the assumptionslong-lived assets and methodologies underlying the allocationincome taxes. For additional discussion of general corporate overhead expenses are reasonable.


Presented below are DominionEastern Energy Gas’ significant transactions with DES, DECGS, DEQPS and other affiliates and related parties:

 

 

Three Months Ended June 30,

 

 

Six Months Ended June 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales of natural gas and transportation and storage services

 

$

60

 

 

$

60

 

 

$

128

 

 

$

127

 

Purchases of natural gas and transportation storage services

 

 

3

 

 

 

—

 

 

 

6

 

 

 

—

 

Services provided by related parties(1)

 

 

37

 

 

 

59

 

 

 

80

 

 

 

104

 

Services provided to related parties(2)

 

 

29

 

 

 

45

 

 

 

61

 

 

 

90

 

(1)

Includes capitalized expenditures of $4 million and $5 million for the three months ended June 30, 2020 and 2019, respectively, and $7 million and $11 million for the six months ended June 30, 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 DominionGas' critical accounting estimates, see Item 7 of Eastern Energy Gas’ Consolidated Balance Sheets:

 

 

June 30, 2020

 

 

December 31, 2019

 

(millions)

 

 

 

 

 

 

 

 

Other receivables(1)

 

$

7

 

 

$

7

 

Imbalances receivable from affiliates

 

 

3

 

 

 

8

 

Imbalances payable to affiliates(2)

 

 

2

 

 

 

1

 

Other deferred charges and other assets

 

 

10

 

 

 

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 June 30, 2020 and December 31, 2019 included $18 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.

Dominion2020. There have been no significant changes in Eastern Energy Gas had $263 million in affiliated notes receivable under the Dominion Energy money pool as of June 30, 2020 and 0 outstanding receivables as ofGas' assumptions regarding critical accounting estimates since December 31, 2019. Interest income related to2020.

179

Item 3.Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the affiliated notes receivable was less than $1 million and $2 million for the three and six months ended June 30, 2020, respectively.

Interest income on affiliated notes receivable from East Ohio and DGP for borrowings under intercompany revolving credit agreements with Dominion Energy Gas was $3 million and $8 million for the three and six months ended June 30, 2019, respectively.

Interest income earned on DMLPHCII’s promissory note to Dominion Energy was immaterial for both the three and six months ended June 30, 2020 and 2019.

Interest income related to Dominion Energy’s promissory note borrowings with Cove Point was $27 million and $54 million for the three and six months ended June 30, 2019, respectively.

Dominion Energy Gas’ affiliated notes receivable from Dominion Energy totaled $2.3 billion and $1.8 billion at June 30, 2020 and December 31, 2019, respectively. Interest income on these promissory notes was $12 million and $23 million for the three and six months ended June 30, 2020, respectively.

At December 31, 2019, Dominion Energy Gas’ affiliated notes receivable from East Ohio totaled $1.7 billion. In June 2020, East Ohio repaid the remaining principal balance outstanding. Interest income on these promissory notes were $15 million and $33 million for the three and six months ended June 30, 2020, respectively.

Dominion Energy Gas’ borrowings under the intercompany revolving credit agreement with Dominion Energy totaled $314 million and $251 million asRegistrants, see Item 7A of June 30, 2020 and December 31, 2019, respectively. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were less than $1 million and $2 million for the three months and six months ended June 30, 2020, respectively, and were less than $1 million and $1 million for the three and six months ended June 30, 2019, respectively.


Interest charges related to DCP’s total borrowings from Dominion Energy under an intercompany revolving credit agreement totaled $29 million and $58 million for the three and six months ended June 30, 2019, respectively.

DCP had borrowings of $9 million with DES as of December 31, 2019. No amounts were outstanding as of June 30, 2020. Interest related to DCP’s total borrowings from DES were less than $1 million for the three and six months ended June 30, 2020 and were less than $1 million and $2 million for the three and six months ended June 2019, respectively.

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 $3 million and $6 million were incurred for the three and six months ended June 30, 2019, respectively.

For the six months ended June 30, 2020 and 2019, Dominion Energy Gas, including entities acquired in the Dominion Energy Gas Restructuring, distributed $1.7 billion and $323 million to Dominion Energy, respectively.

Note 20. Employee Benefit Plans

Dominion Energy

The service cost component and non-service cost components of net periodic benefit (credit) cost are reflected in other operations and maintenance expense and other income, respectively, in the Consolidated Statements of Income. The components of Dominion Energy’s provision for net periodic benefit cost (credit) are as follows:

 

 

Pension Benefits

 

 

Other Postretirement Benefits

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

43

 

 

$

40

 

 

$

7

 

 

$

6

 

Interest cost

 

 

90

 

 

 

98

 

 

 

15

 

 

 

17

 

Expected return on plan assets

 

 

(192

)

 

 

(176

)

 

 

(39

)

 

 

(35

)

Amortization of prior service cost (credit)

 

 

1

 

 

 

1

 

 

 

(13

)

 

 

(13

)

Amortization of net actuarial loss

 

 

48

 

 

 

43

 

 

 

2

 

 

 

3

 

Settlement and curtailment(1)

 

 

2

 

 

 

71

 

 

 

—

 

 

 

42

 

Net periodic benefit cost (credit)

 

$

(8

)

 

$

77

 

 

$

(28

)

 

$

20

 

Six Months Ended June 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

86

 

 

$

80

 

 

$

14

 

 

$

13

 

Interest cost

 

 

181

 

 

 

199

 

 

 

30

 

 

 

34

 

Expected return on plan assets

 

 

(385

)

 

 

(353

)

 

 

(78

)

 

 

(68

)

Amortization of prior service cost (credit)

 

 

1

 

 

 

1

 

 

 

(25

)

 

 

(26

)

Amortization of net actuarial loss

 

 

97

 

 

 

82

 

 

 

3

 

 

 

7

 

Settlement and curtailment(1)

 

 

2

 

 

 

73

 

 

 

—

 

 

 

42

 

Net periodic benefit cost (credit)

 

$

(18

)

 

$

82

 

 

$

(56

)

 

$

2

 

(1) 2019 amounts relate primarily to a voluntary retirement program.

Voluntary Retirement Program

In March 2019, the Companies announced a voluntary retirement program to employees that meet certain age and service requirements. In the second quarter of 2019, upon the determinations made concerning the number of employees that elected to participate in the program, Dominion Energy recorded a charge of $423 million ($316 million after-tax) included within other operations and maintenance expense ($288 million), other taxes ($23 million) and other income ($112 million), Virginia Power recorded a charge of $194 million ($144 million after-tax) included within other operations and maintenance expense ($186 million)  and other taxes ($8 million) and Dominion Energy Gas recorded a charge of $74 million ($58 million after-tax) included within other operations and maintenance expense ($39 million), other taxes ($2 million), other income ($1 million) and discontinued operations ($32 million) in their respective Consolidated Statements of Income. See 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, 20192020. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2020. Refer to Note 7 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for more information.

Employer Contributions

Duringdisclosure of the six monthsrespective Registrant's derivative positions as of June 30, 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 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 such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended June 30, 2021 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

180

PART II

Item 1.Legal Proceedings

Berkshire Hathaway Energy and PacifiCorp

On September 30, 2020, Dominiona putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20cv33885, Circuit Court, Multnomah County, Oregon. The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. 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 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 amend the complaint to 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 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 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.

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 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.

Other individual lawsuits alleging similar claims have been filed in Oregon and California related to the 2020 Wildfires. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, made 0 contributionsrefer 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.


Following closingNote 9 of the transaction with BHE described in Note 3, Dominion Energy expectsNotes to utilize $250 million of the proceeds from the sale to contribute to its qualified defined benefit pension plans by the end of 2020.  In addition, Dominion Energy would not expect to make any further contributions to other postretirement plans in 2020.

Dominion Energy Gas

Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 22 to the Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 9 of the Companies’Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.


Item 1A.Risk Factors

There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019. See Note 19 for more information.

2020.

The service cost component
Item 2.Unregistered Sales of Equity Securities and non-service cost componentsUse of net periodic benefit (credit) cost are reflected in other operationsProceeds

Not applicable.

Item 3.Defaults Upon Senior Securities

Not applicable.

181

Item 4.Mine Safety Disclosures

Information regarding Berkshire Hathaway Energy's and maintenance expensePacifiCorp's mine safety violations and other income, respectively,legal matters disclosed in the Consolidated Statements of Income. The components of Dominion Energy Gas’ provision for net periodic benefit cost (credit) for employees represented by collective bargaining units are as follows:

 

 

Pension Benefits

 

 

Other Postretirement Benefits

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

2

 

 

$

4

 

 

$

—

 

 

$

1

 

Interest cost

 

 

2

 

 

 

8

 

 

 

1

 

 

 

2

 

Expected return on plan assets

 

 

(14

)

 

 

(39

)

 

 

(5

)

 

 

(7

)

Amortization of prior service credit

 

 

—

 

 

 

—

 

 

 

(1

)

 

 

(1

)

Amortization of net actuarial loss

 

 

2

 

 

 

5

 

 

 

1

 

 

 

1

 

Curtailment(1)

 

 

—

 

 

 

1

 

 

 

—

 

 

 

1

 

Net periodic benefit credit

 

$

(8

)

 

$

(21

)

 

$

(4

)

 

$

(3

)

Six Months Ended June 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

3

 

 

$

8

 

 

$

1

 

 

$

2

 

Interest cost

 

 

5

 

 

 

16

 

 

 

2

 

 

 

5

 

Expected return on plan assets

 

 

(28

)

 

 

(78

)

 

 

(10

)

 

 

(14

)

Amortization of prior service credit

 

 

—

 

 

 

—

 

 

 

(2

)

 

 

(2

)

Amortization of net actuarial loss

 

 

4

 

 

 

10

 

 

 

1

 

 

 

2

 

Curtailment(1)

 

 

—

 

 

 

1

 

 

 

—

 

 

 

1

 

Net periodic benefit credit

 

$

(16

)

 

$

(43

)

 

$

(8

)

 

$

(6

)

(1) 2019 amounts relate to a voluntary retirement program.

Employer Contributions

During the six months ended June 30, 2020, Dominion Energy Gas made 0 contributions to its qualified defined benefit pension plan or other postretirement benefit plans. Dominion Energy Gas does 0t expect to make contributions to its qualified defined benefit pension plan and expects to contribute approximately $12 million 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 and services sold in the U.S. A descriptionaccordance with Section 1503(a) of the operationsDodd-Frank Wall Street Reform and Consumer Protection Act is included in the Companies’ primary operating segmentsExhibit 95 to this Form 10-Q.


Item 5.Other Information

Not applicable.

Item 6.Exhibits

The following is a list of exhibits filed as follows:

part of this Quarterly Report.

182

Primary Operating Segment

Description of Operations

Dominion

Energy

Virginia

Power

Dominion

Energy

Gas

Dominion Energy Virginia

Exhibit No.

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)Description

Includes Virginia Power’s nonjurisdictional generation operations.

(2)

Includes gathering and processing activities.


BERKSHIRE HATHAWAY ENERGY

(3)

Includes Wexpro’s gas development

4.1
Fiscal Agency Agreement, dated as of April 9, 2021, by and production operations.

In addition to the operating segments above, the Companies also report a Corporate 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 for the year ended December 31, 2019, in December 2019, Dominion Energy realigned its segments which resulted in the formation of five primary operating segments. The information for the six months ended June 30, 2019 presented herein has been recast to reflect the current segment presentation.

In the six months ended June 30, 2020, Dominion Energy reported after-tax net expenses of $3.1 billion for specific items in the Corporate and Other segment, with $2.9 billion of net expenses attributable to its operating segments. In the six months ended June 30, 2019, Dominion Energy reported after-tax net expenses of $2.1 billion for specific items in the Corporate and Other segment, with $1.8 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 related to the impact of the following items:

•

$2.8 billion ($2.2 billion after-tax)between Northern Natural Gas Company and The Bank of charges associated withNew York Mellon Trust Company, N.A., Fiscal Agent, relating to the cancellation$550,000,000 in principal amount of the Atlantic Coast Pipeline Project and the related portions of the Supply Header Project, attributable3.40% Senior Notes due 2051 (incorporated by reference to Gas Transmission & Storage;

•

A $751 million ($564 million after-tax) charge primarily relatedExhibit 4.1 to the planned early retirement of certain Virginia Power electric generation facilities, attributable to DominionBerkshire Hathaway Energy Virginia; and

•

A $145 million ($115 million after-tax) loss related to investments in nuclear decommissioning trust funds, attributable to:

•

Contracted Generation ($100 million after-tax) and;

•

Dominion Energy Virginia ($15 million after-tax).


The net expense for specific items attributable to Dominion Energy’s operating segments in 2019 primarily related to the impact 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;

•

$446 million ($339 million after-tax) of merger and integration-related costs associated with the SCANA Combination, including a $425 million ($317 million after-tax) charge related to a voluntary retirement program, attributable to:

•

Dominion Energy Virginia ($145 million after-tax);

•

Gas Transmission & Storage ($39 million after-tax);

•

Gas Distribution ($53 million after-tax);

•

Dominion Energy South Carolina ($64 million after-tax) and;

•

Contracted Generation ($38 million after-tax).

•

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;

•

$278 million ($209 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina;

•

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;

•

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;

•

A $135 million ($100 million after-tax) charge related to Virginia Power’s contract termination with a non-utility generator, attributable to Dominion Energy Virginia; and

•

A $114 million ($86 million after-tax) charge for property, plant and equipment acquired in the SCANA Combination primarily for which Dominion Energy committed to forego recovery, attributable to Dominion Energy South Carolina; partially offset by

•

A $336 million ($251 million after-tax) net gain related to investments in nuclear decommissioning trust funds, attributable to:

•

Contracted Generation ($222 million after-tax) and;

•

Dominion Energy Virginia ($29 million after-tax); and

•

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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenue from external customers

 

$

1,818

 

 

$

528

 

 

$

400

 

 

$

634

 

 

$

238

 

 

$

(32

)

 

$

(1

)

 

$

3,585

 

Intersegment revenue

 

 

(4

)

 

 

49

 

 

 

2

 

 

 

1

 

 

 

5

 

 

 

262

 

 

 

(315

)

 

 

—

 

Total operating revenue

 

 

1,814

 

 

 

577

 

 

 

402

 

 

 

635

 

 

 

243

 

 

 

230

 

 

 

(316

)

 

 

3,585

 

Net income (loss) attributable to Dominion Energy

 

 

437

 

 

 

184

 

 

 

87

 

 

 

75

 

 

 

21

 

 

 

(1,973

)

 

 

—

 

 

 

(1,169

)

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenue from external customers

 

$

1,945

 

 

$

664

 

 

$

397

 

 

$

701

 

 

$

249

 

 

$

(18

)

 

$

32

 

 

$

3,970

 

Intersegment revenue

 

 

(2

)

 

 

91

 

 

 

3

 

 

 

2

 

 

 

4

 

 

 

386

 

 

 

(484

)

 

 

—

 

Total operating revenue

 

 

1,943

 

 

 

755

 

 

 

400

 

 

 

703

 

 

 

253

 

 

 

368

 

 

 

(452

)

 

 

3,970

 

Net income (loss) attributable to Dominion Energy

 

 

393

 

 

 

177

 

 

 

66

 

 

 

95

 

 

 

13

 

 

 

(690

)

 

 

—

 

 

 

54

 

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenue from external customers

 

$

3,756

 

 

$

1,172

 

 

$

1,287

 

 

$

1,347

 

 

$

524

 

 

$

(4

)

 

$

(1

)

 

$

8,081

 

Intersegment revenue

 

 

(7

)

 

 

106

 

 

 

5

 

 

 

2

 

 

 

9

 

 

 

541

 

 

 

(656

)

 

 

—

 

Total operating revenue

 

 

3,749

 

 

 

1,278

 

 

 

1,292

 

 

 

1,349

 

 

 

533

 

 

 

537

 

 

 

(657

)

 

 

8,081

 

Net income (loss) attributable to Dominion Energy

 

 

866

 

 

 

405

 

 

 

312

 

 

 

169

 

 

 

80

 

 

 

(3,271

)

 

 

—

 

 

 

(1,439

)

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenue from external customers

 

$

3,946

 

 

$

1,647

 

 

$

1,314

 

 

$

1,390

 

 

$

601

 

 

$

(1,070

)

 

$

—

 

 

$

7,828

 

Intersegment revenue

 

 

(6

)

 

 

146

 

 

 

7

 

 

 

2

 

 

 

7

 

 

 

663

 

 

 

(819

)

 

 

—

 

Total operating revenue

 

 

3,940

 

 

 

1,793

 

 

 

1,321

 

 

 

1,392

 

 

 

608

 

 

 

(407

)

 

 

(819

)

 

 

7,828

 

Net income (loss) attributable to Dominion Energy

 

 

754

 

 

 

399

 

 

 

271

 

 

 

166

 

 

 

115

 

 

 

(2,331

)

 

 

—

 

 

 

(626

)

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 for the year ended December 31, 2019, in December 2019, Virginia Power realigned its segments which resulted in the formation of one primary operating segment. The information for the six months ended June 30, 2019 presented herein has been recast to reflect the current segment presentation.

In the six months ended June 30, 2020, Virginia Power reported after-tax net expenses of $654 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment. In the six months ended June 30, 2019, Virginia Power reported after-tax expense of $652 million for specific items in the Corporate and Other segment, with $607 million of net expenses attributable to its operating segment.

The net expense for specific items attributable to Virginia Power’s operating segment in 2020 primarily related to a $751 million ($559 million after-tax) charge related to the planned early retirement of certain electric generation facilities.

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 $192 million ($143 million after-tax) charge related to a voluntary retirement program;


•

A $160 million ($119 million after-tax) charge related to the planned early retirement of certain automated meter reading infrastructure;

•

A $135 million ($100 million after-tax) charge related to a contract termination with a non-utility generator; and

•

A $62 million ($46 million after-tax) charge related the abandonment of a project at an electric generating facility; 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 June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

1,805

 

 

$

—

 

 

$

1,805

 

Net income

 

 

435

 

 

 

55

 

 

 

490

 

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

1,938

 

 

$

—

 

 

$

1,938

 

Net income (loss)

 

 

393

 

 

 

(293

)

 

 

100

 

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

3,735

 

 

$

—

 

 

$

3,735

 

Net income (loss)

 

 

862

 

 

 

(652

)

 

 

210

 

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

3,932

 

 

$

(29

)

 

$

3,903

 

Net income (loss)

 

 

751

 

 

 

(631

)

 

 

120

 

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 for the year ended December 31, 2019, in December 2019, Dominion Energy Gas realigned its segments which resulted in the formation of one primary operating segment. The information for six months ended June 30, 2019 presented herein has been recast to reflect the current segment presentation.

In the six months ended June 30, 2020, Dominion Energy Gas reported after-tax net expenses of $365 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment. In the six months ended June 30, 2019, Dominion Energy Gas reported after-tax net expenses of $44 million for specific items in the Corporate and Other segment, with $43 million of net expenses attributable to its operating segment.

The net expense for specific items attributable to Dominion Energy Gas’ operating segment in 2020 primarily related to a $482 million ($359 million after-tax) charge associated with the Supply Header Project.


The net expense for specific items attributable to Dominion Energy Gas’ operating segment in 2019 primarily related to a $42 million ($31 million after-tax) charge related to a voluntary retirement program.

The following table presents segment information pertaining to Dominion Energy Gas’ operations:

 

 

Gas

Transmission

& Storage

 

 

Corporate

and Other

 

 

Consolidated

Total

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

510

 

 

$

—

 

 

$

510

 

Net income (loss) attributable to Dominion Energy Gas

 

 

163

 

 

 

(361

)

 

 

(198

)

Three Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

530

 

 

$

—

 

 

$

530

 

Net income from discontinued operations

 

 

—

 

 

 

26

 

 

 

26

 

Net income attributable to Dominion Energy Gas

 

 

116

 

 

 

3

 

 

 

119

 

Six Months Ended June 30, 2020

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

1,066

 

 

$

—

 

 

$

1,066

 

Net income (loss) attributable to Dominion Energy Gas

 

 

337

 

 

 

(366

)

 

 

(29

)

Six Months Ended June 30, 2019

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

1,096

 

 

$

—

 

 

$

1,096

 

Net income from discontinued operations

 

 

—

 

 

 

80

 

 

 

80

 

Net income attributable to Dominion Energy Gas

 

 

254

 

 

 

55

 

 

 

309

 


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 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, other 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;

•

The expected timing and likelihood of completion of the proposed transaction with BHE, including the ability to obtain the requisite regulatory approvals and the terms and conditions of such regulatory approvals;

•

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 in Part I. 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 the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

The Companies’ forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. 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 of June 30, 2020, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019. The policies disclosed included 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 of Operations

Presented below is a summary of Dominion Energy’s consolidated results:

 

 

2020

 

 

2019

 

 

$ Change

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

Second Quarter

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Dominion Energy

 

$

(1,169

)

 

$

54

 

 

$

(1,223

)

Diluted EPS

 

 

(1.41

)

 

 

0.05

 

 

 

(1.46

)

Year-To-Date

 

 

 

 

 

 

 

 

 

 

 

 

Net loss attributable to Dominion Energy

 

$

(1,439

)

 

$

(626

)

 

$

(813

)

Diluted EPS

 

 

(1.75

)

 

 

(0.78

)

 

 

(0.97

)

Overview

Second Quarter 2020 vs. 2019

Net income attributable to Dominion Energy decreased $1.2 billion, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project partially offset by an increase in net investment earnings on nuclear decommissioning trust funds, the absence of charges related to a voluntary retirement program, the absence of a charge for Virginia Power’s contract termination with a non-utility generator, the absence of a charge for litigation acquired in the SCANA Combination and the absence of a charge for the abandonment of a project at a Virginia Power electric generating facility.

Year-To-Date 2020 vs. 2019

Net loss attributable to Dominion Energy increased $813 million, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project, 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. These increases in net loss were partially offset by 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, the absence of charges for the planned early retirement of certain Virginia Power automated meter reading infrastructure and the absence of charges related to a voluntary retirement program.

Analysis of Consolidated Operations

Presented below are selected amounts related to Dominion Energy’s results of operations:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

$ Change

 

 

2020

 

 

2019

 

 

$ Change

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

3,585

 

 

$

3,970

 

 

$

(385

)

 

$

8,081

 

 

$

7,828

 

 

$

253

 

Electric fuel and other energy-related purchases

 

 

505

 

 

 

718

 

 

 

(213

)

 

 

1,173

 

 

 

1,509

 

 

 

(336

)

Purchased electric capacity

 

 

11

 

 

 

24

 

 

 

(13

)

 

 

13

 

 

 

63

 

 

 

(50

)

Purchased gas

 

 

74

 

 

 

227

 

 

 

(153

)

 

 

501

 

 

 

957

 

 

 

(456

)

Net revenue

 

 

2,995

 

 

 

3,001

 

 

 

(6

)

 

 

6,394

 

 

 

5,299

 

 

 

1,095

 

Other operations and maintenance

 

 

995

 

 

 

1,283

 

 

 

(288

)

 

 

2,038

 

 

 

2,285

 

 

 

(247

)

Depreciation, depletion and amortization

 

 

673

 

 

 

661

 

 

 

12

 

 

 

1,346

 

 

 

1,312

 

 

 

34

 

Other taxes

 

 

256

 

 

 

284

 

 

 

(28

)

 

 

540

 

 

 

576

 

 

 

(36

)

Impairment of assets and other charges

 

 

531

 

 

 

312

 

 

 

219

 

 

 

1,299

 

 

 

1,147

 

 

 

152

 

Other income

 

 

502

 

 

 

53

 

 

 

449

 

 

 

50

 

 

 

400

 

 

 

(350

)

Earnings (loss) from equity method investees

 

 

(2,281

)

 

 

39

 

 

 

(2,320

)

 

 

(2,228

)

 

 

80

 

 

 

(2,308

)

Interest and related charges

 

 

449

 

 

 

452

 

 

 

(3

)

 

 

939

 

 

 

921

 

 

 

18

 

Income tax expense (benefit)

 

 

(556

)

 

 

43

 

 

 

(599

)

 

 

(575

)

 

 

157

 

 

 

(732

)

Noncontrolling interests

 

 

37

 

 

 

4

 

 

 

33

 

 

 

68

 

 

 

7

 

 

 

61

 

An analysis of Dominion Energy’s results of operations follows:

Second Quarter 2020 vs. 2019

Net revenue remained substantially consistent, primarily reflecting:

•

A $60 million decrease in sales to electric utility retail customers from a decrease in cooling degree days;

•

A $44 million decrease in sales to electric utility retail customers associated with usage factors impacted by COVID-19;

•

A $20 million decrease due to unfavorable pricing at Millstone, including the effects of the Millstone 2019 power purchase agreements; and

•

A $14 million net unrealized loss on freestanding commodity derivatives.

These decreases were substantially offset by:

•

A $98 million increase from Virginia Power rate adjustment clauses;

•

The absence of a $24 million loss as a result of the contribution of SEMI to Wrangler; and

•

A $16 million decrease in Virginia Power electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($21 million) partially offset by the expiration of various contracts ($5 million).

Other operations and maintenance decreased 22%, primarily reflecting:

•

The absence of a charge related to a voluntary retirement program ($288 million);

•

A $38 million decrease in salaries, wages and benefits; and

•

A $30 million decrease in outage costs; partially offset by

•

A $22 million increase in allowance for credit risk on customer accounts related to the effects of COVID-19;

•

A $16 million increase in certain Virginia Power expenditures, which are primarily recovered through state and FERC rates and do not impact net income; and


•

A $14 million increase in outside services and safety equipment related to the effects of COVID-19.

Depreciation, depletion and amortization increased 2%, primarily due to various projects being placed into service ($32 million), partially offset by the absence of depreciation from certain electric generation facilities that have been committed to be retired early ($16 million).

Other taxes decreased 10%, primarily due to the absence of a charge related to a voluntary retirement program ($23 million).

Impairment of assets and other charges increased 70%, primarily due to:

•

A $482 million charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project; and

•

An increase in dismantling costs associated with certain Virginia Power electric generation facilities ($30 million); partially offset by

•

The absence of a $135 million charge related to Virginia Power’s contract termination with a non-utility generator;

•

The absence of a $100 million charge associated with litigation acquired in the SCANA Combination; and

•

The absence of a $62 million charge related to the abandonment of a project at a Virginia Power electric generating facility.

Other income increased $449 million, primarily due to an increase in net investment earnings on nuclear decommissioning trust funds ($311 million) and the absence of a charge related to a voluntary retirement program ($112 million).

Earnings (loss) from equity method investees decreased $2.3 billion, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project.

Interest and related charges remained substantially consistent, primarily reflecting lower interest expense from early redemptions of certain securities in 2019 and 2020 ($37 million) and a reduction in commercial paper borrowings ($13 million), substantially offset by increased borrowings in response to COVID-19 ($24 million) and increases for unrealized losses associated with freestanding derivatives ($23 million).

Income tax expense decreased $599 million, primarily due to a larger pre-tax loss ($683 million), partially offset by charges associated with the cancellation of the Atlantic Coast Pipeline Project and related Supply Header Project ($81 million).

Noncontrolling interests increased $33 million, primarily due to the sale of a 25% noncontrolling limited partnership interest in Cove Point to Brookfield in December 2019.

Year-To-Date 2020 vs. 2019

Net revenue increased 21%, 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 $226 million increase from Virginia Power rate adjustment clauses; and

•

A $48 million decrease in Virginia Power electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($51 million) and a contract termination with a non-utility generator ($13 million) partially offset by the expiration of various contracts ($16 million).

These increases were partially offset by:

•

An $83 million decrease in sales to electric utility retail customers from a decrease in cooling degree days during the cooling season ($60 million) and a net decrease in heating degree days during the heating season ($23 million);

•

A $61 million decrease due to unfavorable pricing at Millstone, including the effects of the Millstone 2019 power purchase agreements;

•

A $46 million decrease in sales to electric utility retail customers associated with usage factors impacted by COVID-19;

•

A $22 million decrease as a result of the contribution of SEMI to Wrangler; and


•

A $20 million decrease in services performed for Atlantic Coast Pipeline.

Other operations and maintenance decreased 11%, primarily reflecting:

•

The absence of a charge related to a voluntary retirement program ($288 million);

•

A decrease in merger and integration-related costs associated with the SCANA Combination ($96 million);

•

A $56 million decrease in salaries, wages and benefits;

•

A $40 million decrease in outage costs; and

•

A $20 million decrease in services performed for Atlantic Coast Pipeline; partially offset by

•

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);

•

A $55 million increase in certain Virginia Power expenditures, which are primarily recovered through state and FERC rates and do not impact net income; and

•

A $22 million increase in allowance for credit risk on customer accounts related to the effects of COVID-19.

Depreciation, depletion and amortization increased 3%, primarily due to various projects being placed into service ($59 million) partially offset by the absence of depreciation from certain electric generation facilities that were, or have been committed to be retired early ($25 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($16 million).

Impairment of assets and other charges increased 13%, primarily due to:

•

A $482 million charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project;

•

An increase in charges associated with the planned early retirements of certain electric generation facilities in Virginia ($379 million); and

•

An increase in dismantling costs associated with certain Virginia Power electric generation facilities ($30 million); partially offset by

•

The absence of charges associated with litigation acquired in the SCANA Combination ($278 million);

•

The absence of a $160 million charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure;

•

The absence of a $135 million charge related to Virginia Power’s contract termination with a non-utility generator;

•

A decrease in charges for property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($103 million); and

•

The absence of a $62 million charge related to the abandonment of a project at a Virginia Power electric generating facility.

Other income decreased 88%, primarily reflecting net investment losses in 2020 compared to net investment gains in 2019 on nuclear decommissioning trust funds ($481 million) and charges associated with litigation acquired in the SCANA Combination ($25 million), partially offset by the absence of a charge related to a voluntary retirement program ($112 million) and an increase in non-service components of pension and other postretirement employee benefit plan credits ($26 million).

Earnings (loss) from equity method investees decreased $2.3 billion, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project.

Interest and related charges increased 2%, primarily related to increases for unrealized losses associated with freestanding derivatives ($81 million), charges associated with the early redemption of certain securities in the first quarter of 2020 ($25 million) and increased borrowings in response to COVID-19 ($24 million), partially offset by lower interest expense from early redemptions of certain securities in 2019 and 2020 ($94 million) and reductions in commercial paper borrowings ($17 million).

Income tax expense decreased $732 million, primarily due to a larger pre-tax loss ($623 million) and 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 charges associated with the cancellation of the Atlantic Coast Pipeline Project and related Supply Header Project ($81 million).

Noncontrolling interests increased $61 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 income (loss) attributable to Dominion Energy:

 

 

Net Income (Loss) Attributable to

Dominion Energy

 

 

Diluted EPS

 

 

 

2020

 

 

2019

 

 

$ Change

 

 

2020

 

 

2019

 

 

$ Change

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Second Quarter

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dominion Energy Virginia

 

$

437

 

 

$

393

 

 

$

44

 

 

$

0.52

 

 

$

0.49

 

 

$

0.03

 

Gas Transmission & Storage

 

 

184

 

 

 

177

 

 

 

7

 

 

 

0.22

 

 

 

0.22

 

 

 

(0.00

)

Gas Distribution

 

 

87

 

 

 

66

 

 

 

21

 

 

 

0.10

 

 

 

0.08

 

 

 

0.02

 

Dominion Energy South Carolina

 

 

75

 

 

 

95

 

 

 

(20

)

 

 

0.09

 

 

 

0.12

 

 

 

(0.03

)

Contracted Generation

 

 

21

 

 

 

13

 

 

 

8

 

 

 

0.03

 

 

 

0.02

 

 

 

0.01

 

Corporate and Other

 

 

(1,973

)

 

 

(690

)

 

 

(1,283

)

 

 

(2.37

)

 

 

(0.88

)

 

 

(1.49

)

Consolidated

 

$

(1,169

)

 

$

54

 

 

$

(1,223

)

 

$

(1.41

)

 

$

0.05

 

 

$

(1.46

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year-To-Date

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dominion Energy Virginia

 

$

866

 

 

$

754

 

 

$

112

 

 

$

1.03

 

 

$

0.95

 

 

$

0.08

 

Gas Transmission & Storage

 

 

405

 

 

 

399

 

 

 

6

 

 

 

0.48

 

 

 

0.50

 

 

 

(0.02

)

Gas Distribution

 

 

312

 

 

 

271

 

 

 

41

 

 

 

0.37

 

 

 

0.34

 

 

 

0.03

 

Dominion Energy South Carolina

 

 

169

 

 

 

166

 

 

 

3

 

 

 

0.20

 

 

 

0.21

 

 

 

(0.01

)

Contracted Generation

 

 

80

 

 

 

115

 

 

 

(35

)

 

 

0.10

 

 

 

0.14

 

 

 

(0.04

)

Corporate and Other

 

 

(3,271

)

 

 

(2,331

)

 

 

(940

)

 

 

(3.93

)

 

 

(2.92

)

 

 

(1.01

)

Consolidated

 

$

(1,439

)

 

$

(626

)

 

$

(813

)

 

$

(1.75

)

 

$

(0.78

)

 

$

(0.97

)

Dominion Energy Virginia

Presented below are selected operating statistics related to Dominion Energy Virginia’s operations:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

% Change

 

 

2020

 

 

2019

 

 

% Change

 

Electricity delivered (million MWh)

 

 

18.7

 

 

 

20.6

 

 

 

(9

)%

 

 

39.5

 

 

 

42.4

 

 

 

(7

)%

Electricity supplied (million MWh):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utility

 

 

20.1

 

 

 

20.9

 

 

 

(4

)

 

 

42.5

 

 

 

42.8

 

 

 

(1

)

Degree days (electric distribution and utility

   service area):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cooling

 

 

438

 

 

 

644

 

 

 

(32

)

 

 

452

 

 

 

649

 

 

 

(30

)

Heating

 

 

371

 

 

 

150

 

 

 

147

 

 

 

1,889

 

 

 

2,042

 

 

 

(7

)

Average electric distribution customer accounts

   (thousands)

 

 

2,656

 

 

 

2,622

 

 

 

1

 

 

 

2,652

 

 

 

2,620

 

 

 

1

 


Presented below, on an after-tax basis, are the key factors impacting Dominion Energy Virginia’s net income contribution:

 

 

Second Quarter

2020 vs. 2019

Increase (Decrease)

 

 

Year-To-Date

2020 vs. 2019

Increase (Decrease)

 

 

 

Amount

 

 

EPS

 

 

Amount

 

 

EPS

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated electric sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weather

 

$

(22

)

 

$

(0.03

)

 

$

(48

)

 

$

(0.06

)

Other

 

 

(15

)

 

 

(0.02

)

 

 

(11

)

 

 

(0.01

)

Rate adjustment clause equity return

 

 

32

 

 

 

0.04

 

 

 

55

 

 

 

0.07

 

Electric capacity

 

 

9

 

 

 

0.01

 

 

 

33

 

 

 

0.04

 

Outages

 

 

14

 

 

 

0.02

 

 

 

22

 

 

 

0.02

 

Salaries, wages and benefits

 

 

15

 

 

 

0.02

 

 

 

26

 

 

 

0.03

 

Depreciation and amortization

 

 

9

 

 

 

0.01

 

 

 

21

 

 

 

0.02

 

Renewable energy investment tax credits

 

 

(10

)

 

 

(0.01

)

 

 

19

 

 

 

0.02

 

Other

 

 

12

 

 

 

0.01

 

 

 

(5

)

 

 

—

 

Share dilution

 

 

—

 

 

 

(0.02

)

 

 

—

 

 

 

(0.05

)

Change in net income contribution

 

$

44

 

 

$

0.03

 

 

$

112

 

 

$

0.08

 

Gas Transmission & Storage

Presented below are selected operating statistics related to Gas Transmission & Storage’s operations:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

% Change

 

 

2020

 

 

2019

 

 

% Change

 

Average retail energy marketing customer

   accounts(1) (thousands)

 

 

400

 

 

 

790

 

 

 

(49

)%

 

 

399

 

 

 

792

 

 

 

(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:

 

 

Second Quarter

2020 vs. 2019

Increase (Decrease)

 

 

Year-To-Date

2020 vs. 2019

Increase (Decrease)

 

 

 

Amount

 

 

EPS

 

 

Amount

 

 

EPS

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Noncontrolling interest

 

$

(24

)

 

$

(0.03

)

 

$

(44

)

 

$

(0.06

)

Contribution to Wrangler

 

 

6

 

 

 

0.01

 

 

 

(11

)

 

 

(0.01

)

Atlantic Coast Pipeline equity earnings

 

 

(4

)

 

 

(0.01

)

 

 

4

 

 

 

0.01

 

Salaries, wages and benefits

 

 

6

 

 

 

0.01

 

 

 

9

 

 

 

0.01

 

Interest expense, net

 

 

23

 

 

 

0.03

 

 

 

49

 

 

 

0.06

 

Other

 

 

—

 

 

 

—

 

 

 

(1

)

 

 

—

 

Share dilution

 

 

—

 

 

 

(0.01

)

 

 

—

 

 

 

(0.03

)

Change in net income contribution

 

$

7

 

 

$

0.00

 

 

$

6

 

 

$

(0.02

)


Gas Distribution

Presented below are selected operating statistics related to Gas Distribution’s operations:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

% Change

 

 

2020

 

 

2019

 

 

% Change

 

Gas distribution throughput (bcf):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales

 

 

24

 

 

 

24

 

 

—

%

 

 

104

 

 

 

112

 

 

 

(7

%)

Transportation

 

 

190

 

 

 

161

 

 

 

18

 

 

 

440

 

 

 

401

 

 

 

10

 

Heating degree days (gas distribution service area):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

North Carolina

 

 

314

 

 

 

155

 

 

 

103

 

 

 

1,648

 

 

 

1,811

 

 

 

(9

)

Ohio and West Virginia

 

 

804

 

 

 

526

 

 

 

53

 

 

 

3,246

 

 

 

3,441

 

 

 

(6

)

Utah, Wyoming and Idaho

 

 

547

 

 

 

634

 

 

 

(14

)

 

 

2,879

 

 

 

3,204

 

 

 

(10

)

Average gas distribution customer accounts

   (thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales

 

 

1,885

 

 

 

1,846

 

 

 

2

 

 

 

1,888

 

 

 

1,847

 

 

 

2

 

Transportation

 

 

1,130

 

 

 

1,116

 

 

 

1

 

 

 

1,122

 

 

 

1,112

 

 

 

1

 

Presented below, on an after-tax basis, are the key factors impacting Gas Distribution’s net income contribution:

 

 

Second Quarter

2020 vs. 2019

Increase (Decrease)

 

 

Year-To-Date

2020 vs. 2019

Increase (Decrease)

 

 

 

Amount

 

 

EPS

 

 

Amount

 

 

EPS

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated gas sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weather

 

$

3

 

 

$

—

 

 

$

(2

)

 

$

—

 

Other

 

 

1

 

 

 

—

 

 

 

12

 

 

 

0.01

 

Salaries, wages and benefits

 

 

8

 

 

 

0.01

 

 

 

12

 

 

 

0.02

 

Interest expense, net

 

 

5

 

 

 

0.01

 

 

 

11

 

 

 

0.01

 

Other

 

 

4

 

 

 

—

 

 

 

8

 

 

 

0.01

 

Share dilution

 

 

—

 

 

 

—

 

 

 

—

 

 

 

(0.02

)

Change in net income contribution

 

$

21

 

 

$

0.02

 

 

$

41

 

 

$

0.03

 

Dominion Energy South Carolina

Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

% Change

 

 

2020

 

 

2019

 

 

% Change

 

Electricity delivered (million MWh)

 

 

5.2

 

 

 

5.8

 

 

 

(10

%)

 

 

10.3

 

 

 

10.9

 

 

 

(6

%)

Electricity supplied (million MWh)

 

 

5.4

 

 

 

6.2

 

 

 

(13

)

 

 

10.7

 

 

 

11.4

 

 

 

(6

)

Degree days (electric distribution service areas):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cooling

 

 

171

 

 

 

268

 

 

 

(36

)

 

 

176

 

 

 

268

 

 

 

(34

)

Heating

 

 

32

 

 

 

38

 

 

 

(16

)

 

 

610

 

 

 

698

 

 

 

(13

)

Average electric distribution customer accounts

   (thousands)

 

 

750

 

 

 

738

 

 

 

2

 

 

 

748

 

 

 

736

 

 

 

2

 

Gas distribution throughput (bcf):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales

 

 

14

 

 

 

15

 

 

 

(7

)

 

 

33

 

 

 

33

 

 

 

—

 

Average gas distribution customer accounts

   (thousands)

 

 

397

 

 

 

385

 

 

 

3

 

 

 

396

 

 

 

383

 

 

 

3

 


Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution:

 

 

Second Quarter

2020 vs. 2019

Increase (Decrease)

 

 

Year-To-Date

2020 vs. 2019

Increase (Decrease)

 

 

 

Amount

 

 

EPS

 

 

Amount

 

 

EPS

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulated electric sales:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weather

 

$

(23

)

 

$

(0.03

)

 

$

(14

)

 

$

(0.02

)

Other

 

 

(4

)

 

 

—

 

 

 

1

 

 

 

—

 

Regulated gas sales

 

 

2

 

 

 

—

 

 

 

6

 

 

 

0.01

 

Regulatory rider equity return

 

 

(4

)

 

 

—

 

 

 

(4

)

 

 

(0.01

)

Interest expense, net

 

 

2

 

 

 

—

 

 

 

10

 

 

 

0.01

 

Other

 

 

7

 

 

 

0.01

 

 

 

4

 

 

 

0.01

 

Share dilution

 

 

—

 

 

 

(0.01

)

 

 

—

 

 

 

(0.01

)

Change in net income contribution

 

$

(20

)

 

$

(0.03

)

 

$

3

 

 

$

(0.01

)

Contracted Generation

Presented below are selected operating statistics related to Contracted Generation’s operations:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

% Change

 

 

2020

 

 

2019

 

 

% Change

 

Electricity supplied (million MWh)

 

 

4.5

 

 

 

4.4

 

 

 

2

%

 

 

9.8

 

 

 

9.6

 

 

 

2

%

Presented below, on an after-tax basis, are the key factors impacting Contracted Generation’s net income contribution:

 

 

Second Quarter

2020 vs. 2019

Increase (Decrease)

 

 

Year-To-Date

2020 vs. 2019

Increase (Decrease)

 

 

 

Amount

 

 

EPS

 

 

Amount

 

 

EPS

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Margin

 

$

(6

)

 

$

(0.01

)

 

$

(50

)

 

$

(0.06

)

Planned outage costs

 

 

8

 

 

 

0.01

 

 

 

8

 

 

 

0.01

 

Renewable energy investment tax credits

 

 

7

 

 

 

0.01

 

 

 

7

 

 

 

0.01

 

Other

 

 

(1

)

 

 

—

 

 

 

—

 

 

 

—

 

Share dilution

 

 

—

 

 

 

—

 

 

 

—

 

 

 

—

 

Change in net income contribution

 

$

8

 

 

$

0.01

 

 

$

(35

)

 

$

(0.04

)

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

$ Change

 

 

2020

 

 

2019

 

 

$ Change

 

(millions, except EPS)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Specific items attributable to operating segments

 

$

(1,906

)

 

$

(482

)

 

$

(1,424

)

 

$

(2,937

)

 

$

(1,817

)

 

$

(1,120

)

Specific items attributable to Corporate and Other

   segment

 

 

31

 

 

 

(83

)

 

 

114

 

 

 

(139

)

 

 

(301

)

 

 

162

 

Total specific items

 

 

(1,875

)

 

 

(565

)

 

 

(1,310

)

 

 

(3,076

)

 

 

(2,118

)

 

 

(958

)

Other corporate operations(1)

 

 

(98

)

 

 

(125

)

 

 

27

 

 

 

(195

)

 

 

(213

)

 

 

18

 

Total net income (expense)

 

$

(1,973

)

 

$

(690

)

 

$

(1,283

)

 

$

(3,271

)

 

$

(2,331

)

 

$

(940

)

EPS impact

 

$

(2.37

)

 

$

(0.88

)

 

$

(1.49

)

 

$

(3.93

)

 

$

(2.92

)

 

$

(1.01

)

(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 in this report for discussion of these items in more detail. Corporate 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:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

$ Change

 

 

2020

 

 

2019

 

 

$ Change

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

490

 

 

$

100

 

 

$

390

 

 

$

210

 

 

$

120

 

 

$

90

 

Overview

Second Quarter 2020 vs. 2019

Net income increased $390 million, primarily due to the absence of charges related to a voluntary retirement program, a contract termination with a non-utility generator and the abandonment of a project at an electric generating facility.

Year-To-Date 2020 vs. 2019

Net income increased $90 million, primarily due to the absence of charges related to the planned early retirement of certain automated meter reading infrastructure, a voluntary retirement program and a contract termination with a non-utility generator. These increases were partially offset by an increase in charges related to the planned early retirements of certain electric generation facilities and the absence of a revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019.

Analysis of Consolidated Operations

Presented below are selected amounts related to Virginia Power’s results of operations:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

$ Change

 

 

2020

 

 

2019

 

 

$ Change

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

1,805

 

 

$

1,938

 

 

$

(133

)

 

$

3,735

 

 

$

3,903

 

 

$

(168

)

Electric fuel and other energy-related purchases

 

 

366

 

 

 

536

 

 

 

(170

)

 

 

858

 

 

 

1,132

 

 

 

(274

)

Purchased (excess) electric capacity

 

 

(8

)

 

 

13

 

 

 

(21

)

 

 

(17

)

 

 

46

 

 

 

(63

)

Net revenue

 

 

1,447

 

 

 

1,389

 

 

 

58

 

 

 

2,894

 

 

 

2,725

 

 

 

169

 

Other operations and maintenance

 

 

376

 

 

 

565

 

 

 

(189

)

 

 

794

 

 

 

844

 

 

 

(50

)

Depreciation and amortization

 

 

307

 

 

 

299

 

 

 

8

 

 

 

618

 

 

 

603

 

 

 

15

 

Other taxes

 

 

85

 

 

 

90

 

 

 

(5

)

 

 

172

 

 

 

175

 

 

 

(3

)

Impairment of assets and other charges

 

 

44

 

 

 

197

 

 

 

(153

)

 

 

808

 

 

 

743

 

 

 

65

 

Other income

 

 

52

 

 

 

16

 

 

 

36

 

 

 

—

 

 

 

53

 

 

 

(53

)

Interest and related charges

 

 

137

 

 

 

135

 

 

 

2

 

 

 

263

 

 

 

270

 

 

 

(7

)

Income tax expense

 

 

60

 

 

 

19

 

 

 

41

 

 

 

29

 

 

 

23

 

 

 

6

 

An analysis of Virginia Power’s results of operations follows:

Second Quarter 2020 vs. 2019

Net revenue increased 4%, primarily reflecting:

•

A $98 million increase from rate adjustment clauses; and

•

A $16 million decrease in electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($21 million), partially offset by the expiration of various contracts ($5 million); partially offset by


•

A $30 million decrease in sales to retail customers from a decrease in cooling degree days; and

•

A $24 million decrease in sales to retail customers associated with usage factors impacted by COVID-19.

Other operations and maintenance decreased 33%, primarily reflecting the absence of a charge related to a voluntary retirement program ($186 million), a decrease in salaries, wages and benefits ($17 million) and a decrease in planned outage costs ($19 million). These decreases were partially offset by an increase in certain expenses which are primarily recovered through state and FERC rates and do not impact net income ($16 million) and an increase in allowance for credit risk on customer accounts related to COVID-19 ($13 million).

Depreciation and amortization increased 3%, primarily due to various projects being placed into service ($28 million), partially offset by the absence of depreciation from certain electric generation facilities that have been committed to be retired early ($16 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($8 million).

Impairment of assets and other charges decreased 78%, primarily due to the absence of charges related to a contract termination with a non-utility generator ($135 million) and the abandonment of a project at an electric generating facility ($62 million), partially offset by an increase in dismantling costs associated with certain electric generation facilities ($30 million) and the write-off of the portion of a regulatory asset no longer probable of recovery as a result of the enactment of the VCEA ($16 million).

Other income increased $36 million, primarily reflecting an increase in net investment earnings on nuclear decommissioning trust funds.

Income tax expense increased $41 million, primarily due to higher pre-tax income ($80 million), partially offset by higher investment tax credits ($39 million).

Year-To-Date 2020 vs. 2019

Net revenue increased 6%, primarily reflecting:

•

A $226 million increase from rate adjustment clauses; and

•

A $48 million decrease in electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($51 million) and a contract termination with a non-utility generator ($13 million) partially offset by the expiration of various contracts ($16 million); partially offset by

•

A $65 million decrease in sales to retail customers from a decrease in cooling degree days during the cooling season ($30 million) and a decrease in heating degree days during the heating season ($35 million); and

•

A $24 million decrease in sales to electric retail customers associated with usage factors impacted by COVID-19.

Other operations and maintenance decreased 6%, primarily reflecting the absence of a charge related to a voluntary retirement program ($186 million), a decrease in salaries, wages and benefits ($34 million) and a decrease in planned outage costs ($29 million). These decreases were partially offset by 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), an increase in certain expenses which are primarily recovered through state and FERC rates and do not impact net income ($55 million) and an increase in allowance for credit risk on customer accounts related to COVID-19 ($13 million).

Depreciation and amortization increased 2%, primarily due to various projects being placed into service ($52 million), partially offset by the absence of depreciation from certain electric generation facilities that were, or have committed to be, retired early ($25 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($16 million).

Impairment of assets and other charges increased 9%, primarily due to:

•

An increase in charges associated with the planned early retirements of certain electric generation facilities ($379 million); and

•

An increase in dismantling costs associated with certain electric generation facilities ($30 million); partially offset by

•

The absence of a charge related to the planned early retirement of certain automated meter reading infrastructure ($160 million);

•

The absence of a $135 million charge related to contract termination with a non-utility generator; and


•

The absence of a $62 million charge related to the abandonment of a project at an electric generating facility.

Other income decreased $53 million, primarily reflecting net investment losses in 2020 compared to net investment gains in 2019 on nuclear decommissioning trust funds.

Income tax expense increased 26%, primarily due to higher pre-tax income ($25 million), partially offset by higher investment tax credits ($19 million).

Dominion Energy Gas

Results of Operations

Presented below is a summary of Dominion Energy Gas’ consolidated results:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

$ Change

 

 

2020

 

 

2019

 

 

$ Change

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Dominion Energy Gas

 

$

(198

)

 

$

119

 

 

$

(317

)

 

$

(29

)

 

$

309

 

 

$

(338

)

Overview

Second Quarter 2020 vs. 2019

Net income attributable to Dominion Energy Gas decreased $317 million, primarily due to a charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project and the absence of net income from discontinued operations related to the Dominion Energy Gas Restructuring, partially offset by the absence of a charge related to a voluntary retirement program and a decrease in interest and related charges from lower outstanding debt balances.

Year-To-Date 2020 vs. 2019

Net income attributable to Dominion Energy Gas decreased $338 million, primarily due to a charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project and the absence of net income from discontinued operations related to the Dominion Energy Gas Restructuring, partially offset by the absence of a charge related to a voluntary retirement program and 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:

 

 

Second Quarter

 

 

Year-To-Date

 

 

 

2020

 

 

2019

 

 

$ Change

 

 

2020

 

 

2019

 

 

$ Change

 

(millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenue

 

$

510

 

 

$

530

 

 

$

(20

)

 

$

1,066

 

 

$

1,096

 

 

$

(30

)

Purchased gas

 

 

—

 

 

 

(3

)

 

 

3

 

 

 

8

 

 

 

9

 

 

 

(1

)

Other energy-related purchases

 

 

1

 

 

 

1

 

 

 

—

 

 

 

1

 

 

 

1

 

 

 

—

 

Net revenue

 

 

509

 

 

 

532

 

 

 

(23

)

 

 

1,057

 

 

 

1,086

 

 

 

(29

)

Other operations and maintenance

 

 

150

 

 

 

210

 

 

 

(60

)

 

 

315

 

 

 

386

 

 

 

(71

)

Depreciation and amortization

 

 

94

 

 

 

92

 

 

 

2

 

 

 

187

 

 

 

182

 

 

 

5

 

Other taxes

 

 

35

 

 

 

38

 

 

 

(3

)

 

 

77

 

 

 

78

 

 

 

(1

)

Impairment of assets and other charges

 

 

482

 

 

 

13

 

 

 

469

 

 

 

482

 

 

 

13

 

 

 

469

 

Earnings from equity method investees

 

 

8

 

 

 

9

 

 

 

(1

)

 

 

23

 

 

 

22

 

 

 

1

 

Other income

 

 

46

 

 

 

44

 

 

 

2

 

 

 

95

 

 

 

85

 

 

 

10

 

Interest and related charges

 

 

50

 

 

 

86

 

 

 

(36

)

 

 

108

 

 

 

173

 

 

 

(65

)

Income tax expense (benefit)

 

 

(82

)

 

 

23

 

 

 

(105

)

 

 

(30

)

 

 

66

 

 

 

(96

)

Net income from discontinued operations

 

 

—

 

 

 

26

 

 

 

(26

)

 

 

—

 

 

 

80

 

 

 

(80

)

Noncontrolling interests

 

 

32

 

 

 

30

 

 

 

2

 

 

 

65

 

 

 

66

 

 

 

(1

)


An analysis of Dominion Energy Gas’ results of operations follows:

Second Quarter 2020 vs. 2019

Net revenue decreased 4%, primarily reflecting:

•

A $9 million decrease in services performed for Atlantic Coast Pipeline,

•

A $6 million decrease in services provided to affiliates; and

•

A $5 million decrease due to DETI contract changes.

Other operations and maintenance decreased 29%, primarily reflecting:

•

A $39 million decrease due to the absence of a charge related to a voluntary retirement program; and

•

A $9 million decrease in services performed for Atlantic Coast Pipeline.

Impairment of assets and other charges increased $469 million, due to a $482 million charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project, partially offset by the absence of a $13 million charge related to the abandonment of the Sweden Valley project.

Interest and related charges decreased 42%,primarily due to the absence of interest expense from Cove Point’s term loan borrowings ($32 million), partially offset by interest expense on Dominion Energy Gas’ November 2019 senior note issuance ($8 million).

Income tax expense decreased $105 million, primarily due to lower pre-tax income.

Year-To-Date 2020 vs. 2019

Net revenue decreased 3%, primarily reflecting:

•

A $20 million decrease in services performed for Atlantic Coast Pipeline; and

•

An $8 million decrease in services provided to affiliates.

Other operations and maintenance decreased 18%, primarily reflecting:

•

A $39 million decrease due to the absence of a charge related to a voluntary retirement program; and

•

A $20 million decrease in services performed for Atlantic Coast Pipeline.


Impairment of assets and other charges increased $469 million, due to a $482 million charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project, partially offset by the absence of a $13 million charge related to the abandonment of the Sweden Valley project.

Other income increased 12%, primarily due to an increase in non-service components of pension and other postretirement employee benefit plan credits.

Interest and related charges decreased 38%,primarily due to the absence of interest expense from Cove Point’s term loan borrowings ($68 million), partially offset by interest expense on Dominion Energy Gas’ November 2019 senior note issuance ($15 million).

Income tax expense decreased $96 million, primarily due to lower 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 June 30, 2020, Dominion Energy had $5.7 billion of unused capacity under its joint revolving credit facility. In addition, Dominion Energy had $675 million available under a $900 million 364-Day Revolving Credit Agreement entered into in 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. In addition, Dominion Energy borrowed $1.1 billion under two 364-Day Term Loan Credit Agreements and issued $2.3 billion of senior notes. In June 2020, Dominion Energy repaid the outstanding balance of $625 million associated with one of the 364-Day Term Loan Credit Agreements. 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

 

 

3,136

 

 

 

2,313

 

Investing activities

 

 

(3,334

)

 

 

(1,833

)

Financing activities

 

 

671

 

 

 

(311

)

Net increase in cash, restricted cash and equivalents

 

 

473

 

 

 

169

 

Cash, restricted cash and equivalents at June 30

 

$

742

 

 

$

560

 

Operating Cash Flows

Net cash provided by Dominion Energy’s operating activities increased $823 million, primarily due to higher deferred fuel cost recoveries, lower payments for income taxes, the absence of a contract termination payment 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. In December 2019, Dominion Energy’s Board of Directors established an annual dividend rate for 2020 of $3.76 per share of common stock. In January 2020, Dominion Energy’s Board of Directors declared dividends payable in March 2020 of 94 cents per share of common stock, and in May 2020, Dominion Energy’s Board of Directors declared dividends payable in June 2020 of 94 cents per share of common stock. In July 2020, Dominion Energy’s Board of Directors declared dividends payable in September 2020 of 94 cents per share of common stock. Also in July 2020, Dominion Energy announced that it currently expects to make a fourth dividend payment in December 2020 of approximately 63 cents per share of common stock reflecting the expected timing of the closing of the proposed transaction with BHE. Dividends are subject to declaration by the Board of Directors.


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 Part I. 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 the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

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 June 30, 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)

 

$

88

 

 

$

—

 

 

$

88

 

Non-investment grade(2)

 

 

3

 

 

 

—

 

 

 

3

 

No external ratings:

 

 

 

 

 

 

 

 

 

 

 

 

Internally rated—investment grade(3)

 

 

117

 

 

 

—

 

 

 

117

 

Internally rated—non-investment grade(4)

 

 

7

 

 

 

—

 

 

 

7

 

Total(5)

 

$

215

 

 

$

—

 

 

$

215

 

(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 29% 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 53% 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 $1.5 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. In June 2020, Dominion Energy filed a SEC shelf registration statement for the sale of debt and equity securities which replaced the shelf registration statement filed by Dominion Energy in June 2017.

Net cash provided by Dominion Energy's financing activities was $671 million for the six months ended June 30, 2020, compared to net cash used by financing activities of $311 million for the six months ended June 30, 2019, primarily due to higher issuances of short- and long-term debt to buttress liquidity as a strategic response to COVID-19 and lower repayments of long-term debt, partially offset by higher repayments of short-term debt and the absence of the issuance of the 2019 Equity Units.

In November 2017, Dominion Energy filed a SEC shelf registration statement for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability InvestmentSM. 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 June 30, 2020 was $176 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.

In July 2020, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded the prior two authorizations from 2005 and 2007.  The repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors.

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 June 30, 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 June 30, 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 June 30, 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 June 30, 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, with the exception of the following matter.

In December 2019, Dominion Energy signed an agreement with a lessor, as amended in May 2020, to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. If Dominion Energy ultimately proceeds with the project through completion, the project is expected to be completed by September 2024. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs. If the project is terminated under certain events, Dominion Energy could be required to pay up to 100% of the then funded amount.

The lease term will commence once construction is substantially complete and the facility is able to be occupied and end in December 2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 83% of project costs, for the difference between the project costs and sale proceeds.  Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.


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, Future Issues and Other Matters in MD&A in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 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, Note 17 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and Note 17 to the Consolidated Financial Statements in this report for additional information on various environmental matters.

Legal Matters

SeeNotes 13 and 23 to the Consolidated Financial Statements 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 and Item 1. Legal Proceedings in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 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, Note 13 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and Note 13 to the Consolidated Financial Statements in this report for additional information on various regulatory matters.

Atlantic Coast Pipeline and Supply Header Projects

In July 2020, Dominion Energy and Duke Energy announced the cancellation of the Atlantic Coast Pipeline Project. As a result, Dominion Energy recorded an abandonment for a significant portion of the Supply Header Project. See Notes 2 and 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 district 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 district court also enjoined the Army Corps of Engineers from authorizing any dredge or fill activities under NWP 12. Following the district court’s ruling, the Army Corps of Engineers suspended the NWP 12. In May 2020, the district court amended its order to authorize the use of NWP 12 for all utility line projects other than new oil and gas pipeline projects. The Army Corps of Engineers sought emergency relief of the district court’s order from the U.S. Court of Appeals for the Ninth Circuit and the U.S. Supreme Court.  In July 2020, the U.S. Supreme Court issued an order limiting the scope of the district court’s order to the construction of the Keystone XL pipeline, allowing other new oil and gas pipeline projects to use the NWP 12 process pending the appeal of the district court’s order to the U.S. Court of Appeals for the Ninth Circuit. As a result of the amended order, the cancellation of the Atlantic Coast Pipeline Project and the pending sale of its gas transmission operations to BHE, Dominion Energy does not currently expect this matter to have a material impact to its results of operations, financial position or cash flows.

COVID-19


Dominion Energy continues to monitor the global outbreak of COVID-19 and has taken appropriate steps to mitigate the potential risks to Dominion Energy, its employees and its customers posed by the spread of the virus. Dominion Energy provides a critical service to its customers which means that it is paramount for the company to keep 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 have been 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. Working with a medical advisor, Dominion Energy developed a COVID-19 training program, which has been rolled out to employees. Dominion Energy is providing all appropriate personal protection equipment to keep employees safe and has implemented additional protections such as temperature screenings, testing services, and mandatory face covering policies. 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 $31 million and $50 million of Dominion Energy’s commodity-based derivative instruments as of June 30, 2020 and December 31, 2019, respectively.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease in fair value of $42 million and $54 million of Virginia Power’s commodity-based derivative instruments as of June 30, 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 June 30, 2020 or December 31, 2019.  

The Companies also use interest rate derivatives, including forward-starting swaps, as hedges of forecasted interest payments. As of June 30, 2020, Dominion Energy, Virginia Power and Dominion Energy Gas had $8.5 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 $95 million, $50 million and $7 million, respectively, in the fair value of Dominion Energy, Virginia Power and Dominion Energy Gas’ interest rate derivatives at June 30, 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 June 30, 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 not have resulted in a material decrease in the fair value of Dominion Energy Gas’ foreign currency swaps at June 30, 2020 or 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 $207 million for the six months ended June 30, 2020, and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $603 million for the six months ended June 30, 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 $37 million and $65 million for the six months ended June 30, 2020 and 2019, respectively, 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 $119 million for the six months ended June 30, 2020, and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $282 million for the six months ended June 30, 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 increase in unrealized gains on debt investments of $20 million and $31 million for the six months ended June 30, 2020 and 2019, respectively, 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. In July 2020, the consent decree was entered by order of the U.S. District Court for the Eastern District of Virginia.

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 the Companies’Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.2021).

•

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 and updated in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020,which should be taken into consideration when reviewing the information contained in this report. 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 and the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. 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 in MD&A in this report.

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)

4/1/20-4/30/20

—

$

—

—

19,629,059 shares/

$1.18 billion

5/1/20-5/31/20

10.1

—

—

—

19,629,059 shares/

$1.18 billion

6/1/20-6/30/20

—

—

—

19,629,059 shares/

$1.18 billion

Total

—

$

—

—

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.


(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.

In July 2020, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded the prior two authorizations from 2005 and 2007.  The repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors.


ITEM 6. EXHIBITS

Exhibit

Number

Description

Dominion Energy

Virginia Power

Dominion Energy Gas

  2.1

Purchase3,500,000,000 Second Amended and SaleRestated Credit Agreement, dated as of July 3, 2020, by andJune 30, 2021, among Dominion Energy, Inc., Dominion Energy Questar Corporation and Berkshire Hathaway Energy Company, (Exhibit 2.1, Form 8-K filed July 6, 2020, File No. 1-8489).as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Union Bank, N.A, as Administrative Agent and the LC Issuing Banks.

X

  3.1.a

15.1

Dominion Energy, Inc. ArticlesAwareness Letter of Incorporation, as restated, effective December 13, 2019 (Exhibit 3.1, Form 8-K filed December 13, 2019, File No.1-8489).Independent Registered Public Accounting Firm.

X

  3.1.b

31.1

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 July 30, 2020 (Exhibit 3.1, Form 8-K filed July 31, 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


Exhibit

Number

Description

Dominion Energy

Virginia Power

Dominion Energy Gas

31.a

Certification by ChiefPrincipal Executive Officer of Dominion Energy, Inc. pursuantCertification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).2002.

X

31.b

31.2

Certification by ChiefPrincipal Financial Officer of Dominion Energy, Inc. pursuantCertification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).2002.

X

31.c

32.1

Certification by ChiefPrincipal Executive Officer Certification Pursuant to Section 906 of Virginia Electric and Power Company pursuantthe Sarbanes-Oxley Act of 2002.
32.2
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

PACIFICORP
15.2
Awareness Letter of Independent Registered Public Accounting Firm.
31.3
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).2002.

X

31.d

31.4

Certification by ChiefPrincipal Financial Officer of Virginia Electric and Power Company pursuantCertification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).2002.

X

31.e

32.3

Certification by ChiefPrincipal Executive Officer Certification Pursuant to Section 906 of Dominion Energy Gas Holdings, LLC pursuantthe Sarbanes-Oxley Act of 2002.
32.4
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
4.2
Thirty-Second Supplemental Indenture, dated as of July 1, 2021, to the Mortgage and Deed of Trust dated as of January 9, 1989 between PacifiCorp and the Bank of New York Mellon Trust Company, N.A., as successor Trustee (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated July 9, 2021).
10.2
$1,200,000,000 Second Amended and Restated Credit Agreement dated as of June 30, 2021, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JP Morgan Chase Bank, N.A. as Administrative Agent and the LC Issuing Banks.
95
Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

MIDAMERICAN ENERGY
15.3
Awareness Letter of Independent Registered Public Accounting Firm.
31.5
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).2002.

X

31.f

31.6

Certification by ChiefPrincipal Financial Officer of Dominion Energy Gas Holdings, LLC pursuantCertification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).2002.

X

32.a

32.5

Certification to the Securities and Exchange Commission by ChiefPrincipal Executive Officer and Chief Financial Officer of Dominion Energy, Inc. as required byCertification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).2002.

X

32.b

32.6

Certification to the Securities and Exchange Commission by Chief Executive Officer and ChiefPrincipal Financial Officer of Virginia Electric and Power Company as required byCertification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).2002.



183

X

Exhibit No.

Description

BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY

32.c

4.3

CertificationTenth Supplemental Indenture, dated as of July 22, 2021, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the SecuritiesIndenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated July 22, 2021).
4.4
Specimen of the 2.70% First Mortgage Bonds due 2052 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated July 22, 2021).
10.3
$1,500,000,000 Second Amended and Exchange Commission by ChiefRestated Credit Agreement, dated as of June 30, 2021, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Mizuho Bank, Ltd., as Administrative Agent and the LC Issuing Banks.

MIDAMERICAN FUNDING
31.7
Principal Executive Officer and ChiefCertification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.8
Principal Financial Officer Certification Pursuant to Section 302 of Dominion Energy Gas Holdings, LLC as required bythe Sarbanes-Oxley Act of 2002.
32.7
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).2002.

X

99

32.8

Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

NEVADA POWER

Condensed consolidated earnings statements (filed herewith).

X

X

X

15.4

Awareness Letter of Independent Registered Public Accounting Firm.

101

31.9

Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.10
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.9
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.10
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
10.4
$400,000,000 Fourth Amended and Restated Credit Agreement, dated as of June 30, 2021, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.

SIERRA PACIFIC
31.11
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.12
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.11
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.12
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
10.5
$250,000,000 Fourth Amended and Restated Credit Agreement, dated as of June 30, 2021, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.

184


Exhibit No.Description

EASTERN ENERGY GAS
31.13
Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.14
Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.13
Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.14
Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS
4.5
Fifteenth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as trustee, to the Indenture dated as of October 1, 2013, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated July 1, 2021).
4.6
Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.
4.7
First Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.900% Senior Notes due 2049.
4.8
Second Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.600% Senior Notes due 2044.
4.9
Third Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.800% Senior Notes due 2043.
4.10
Fourth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.000% Senior Notes due 2029.
4.11
Fifth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.600% Senior Notes due 2024.

ALL REGISTRANTS
101The following financial statementsinformation from Dominion Energy, Inc.’seach respective Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, filed on August 5, 2020,2021, is formatted in iXBRL (Inline eXtensible Business Reporting Language): and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (ii)Operations, (iii) the Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia ElectricStatements, tagged in summary and Power Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, filed on August 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 June 30, 2020, filed on August 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

detail.

104

Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.

X

X

X


185

SIGNATURE


SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, theeach registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


BERKSHIRE HATHAWAY ENERGY COMPANY

Date: August 6, 2021

DOMINION ENERGY, INC.

Registrant

/s/ Calvin D. Haack

Calvin D. Haack

August 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

August 5, 2020

/s/ Michele L. Cardiff

Date: August 6, 2021

Michele/s/ Nikki L. Cardiff

Kobliha

Nikki L. Kobliha
Vice President, ControllerChief Financial Officer and

Chief Accounting Officer

Treasurer

(principal financial and accounting officer)

DOMINION

MIDAMERICAN FUNDING, LLC
MIDAMERICAN ENERGY COMPANY
Date: August 6, 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: August 6, 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: August 6, 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

August 5, 2020

/s/ Michele L. Cardiff

Date: August 6, 2021

Michele L. Cardiff

/s/ Scott C. Miller

Scott C. Miller
Vice President, ControllerChief Financial Officer and

Chief Accounting Officer

Treasurer
(principal financial and accounting officer)

130

186