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MWPSP MidAmerican Energy

Filed: 2 May 21, 8:00pm
0001081316bhe:NaturalGasUSRegulatedMemberbhe:OtherMemberbhe:RegulatedretailgasMemberbhe:MidamericanEnergyCompanyAndSubsidiariesMemberus-gaap:RegulatedOperationMember2021-01-012021-03-31

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2021
or
☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to _______
Exact name of registrant as specified in its charter
State or other jurisdiction of incorporation or organization
CommissionAddress of principal executive officesIRS Employer
File NumberRegistrant's telephone number, including area codeIdentification No.
001-14881 BERKSHIRE HATHAWAY ENERGY COMPANY 94-2213782
  (An Iowa Corporation)  
  666 Grand Avenue, Suite 500  
  Des Moines, Iowa 50309-2580  
  515-242-4300  
001-05152 PACIFICORP 93-0246090
  (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)



RegistrantSecurities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANYNone
PACIFICORPNone
MIDAMERICAN FUNDING, LLCNone
MIDAMERICAN ENERGY COMPANYNone
NEVADA POWER COMPANYNone
SIERRA PACIFIC POWER COMPANYNone
EASTERN ENERGY GAS HOLDINGS, LLCNone
RegistrantName of exchange on which registered:
BERKSHIRE HATHAWAY ENERGY COMPANYNone
PACIFICORPNone
MIDAMERICAN FUNDING, LLCNone
MIDAMERICAN ENERGY COMPANYNone
NEVADA POWER COMPANYNone
SIERRA PACIFIC POWER COMPANYNone
EASTERN ENERGY GAS HOLDINGS, LLCNone
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.
RegistrantYesNo
BERKSHIRE HATHAWAY ENERGY COMPANY
PACIFICORP
MIDAMERICAN FUNDING, LLC
MIDAMERICAN ENERGY COMPANY
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
EASTERN ENERGY GAS HOLDINGS, LLC
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). Yes  x  No  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
RegistrantLarge accelerated filerAccelerated filerNon-accelerated filerSmaller reporting companyEmerging growth company
BERKSHIRE HATHAWAY ENERGY COMPANY
PACIFICORP
MIDAMERICAN FUNDING, LLC
MIDAMERICAN ENERGY COMPANY
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
EASTERN ENERGY GAS HOLDINGS, LLC
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  o



Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes    No  x
All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of April 29, 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 April 29, 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 April 29, 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 April 29, 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 April 29, 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. As of April 29, 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 is held indirectly by its parent company, Berkshire Hathaway Energy Company, as of April 29, 2021.
This combined Form 10-Q is separately filed by Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.




TABLE OF CONTENTS
 
PART I
 
 
PART II
 

i


Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 2 through 3, and Part II - Items 1 through 6, the following terms have the definitions indicated.
Berkshire Hathaway Energy Company and Related Entities
BHEBerkshire Hathaway Energy Company
Berkshire HathawayBerkshire Hathaway Inc.
Berkshire Hathaway Energy or the CompanyBerkshire Hathaway Energy Company and its subsidiaries
PacifiCorpPacifiCorp and its subsidiaries
MidAmerican FundingMidAmerican Funding, LLC and its subsidiaries
MidAmerican EnergyMidAmerican Energy Company
NV EnergyNV Energy, Inc. and its subsidiaries
Nevada PowerNevada 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 GasEastern Energy Gas Holdings, LLC and its subsidiaries
RegistrantsBerkshire 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 Holdings, LLC and its subsidiaries
Northern PowergridNorthern 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
GT&S TransactionThe acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy and Dominion Questar, exclusive of the Questar Pipeline Group on November 1, 2020
DEIDominion Energy, Inc.
Questar Pipeline GroupDominion Energy Questar Pipeline, LLC and related entities
ii


Certain Industry Terms
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
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
DEAADeferred Energy Accounting Adjustment
DthDecatherm
EBAEnergy Balancing Account
ECAMEnergy Cost Adjustment Mechanism
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
GAAPAccounting principles generally accepted in the United States of America
GEMAGas and Electricity Markets Authority
GHGGreenhouse Gases
GWhGigawatt Hour
GTAGeneral Tariff Application
IPUCIdaho Public Utilities Commission
ICCIllinois Commerce Commission
IRPIntegrated Resource Plan
IUBIowa Utilities Board
kVKilovolt
KHSAKlamath Hydroelectric Settlement Agreement
MWMegawatt
MWhMegawatt Hour
NAAQSNational Ambient Air Quality Standards
NOx
Nitrogen Oxides
OfgemOffice of Gas and Electric Markets
OPUCOregon Public Utility Commission
PTCProduction Tax Credit
PUCNPublic Utilities Commission of Nevada
RACRenewable Adjustment Clause
RECRenewable Energy Credit
RFPRequest for Proposal
RPSRenewable Portfolio Standards
RRA
Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism
SCRSelective Catalytic Reduction
SECUnited States Securities and Exchange Commission
SIPState Implementation Plan
SO2
Sulfur Dioxide
UPSCUtah Public Service Commission
WPSCWyoming Public Service Commission
WUTCWashington 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;
the expected timing and likelihood of completion of the proposed transaction to acquire the remaining portion of DEI's natural gas transmission and storage business, including the ability to obtain the required clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;
unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;
the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and
other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.

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

v


Item 1.Financial Statements
Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp and its subsidiaries
MidAmerican Energy Company
MidAmerican Funding, LLC and its subsidiaries
Nevada Power Company and its subsidiaries
Sierra Pacific Power Company and its subsidiaries
Eastern Energy Gas Holdings, LLC and its subsidiaries


1


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


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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2020, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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


/s/ Deloitte & Touche LLP


Des Moines, Iowa
April 30, 2021
4


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

 As of
 March 31,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$1,276 $1,290 
Restricted cash and cash equivalents117 140 
Trade receivables, net2,416 2,107 
Inventories1,110 1,168 
Mortgage loans held for sale2,065 2,001 
Other current assets3,236 2,741 
Total current assets10,220 9,447 
   
Property, plant and equipment, net86,757 86,128 
Goodwill11,534 11,506 
Regulatory assets3,221 3,157 
Investments and restricted cash and cash equivalents and investments13,010 14,320 
Other assets2,780 2,758 
  
Total assets$127,522 $127,316 

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

5


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

 As of
 March 31,December 31,
20212020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$1,548 $1,867 
Accrued interest642 555 
Accrued property, income and other taxes515 582 
Accrued employee expenses412 383 
Short-term debt2,699 2,286 
Current portion of long-term debt2,011 1,839 
Other current liabilities1,948 1,626 
Total current liabilities9,775 9,138 
  
BHE senior debt12,999 12,997 
BHE junior subordinated debentures100 100 
Subsidiary debt34,351 34,930 
Regulatory liabilities7,355 7,221 
Deferred income taxes11,630 11,775 
Other long-term liabilities4,261 4,178 
Total liabilities80,471 80,339 
   
Commitments and contingencies (Note 9)0
   
Equity:  
BHE shareholders' equity:  
Preferred stock - 100 shares authorized, $0.01 par value, 4 shares issued and outstanding3,750 3,750 
Common stock - 115 shares authorized, 0 par value, 76 shares issued and outstanding
Additional paid-in capital6,377 6,377 
Long-term income tax receivable(658)(658)
Retained earnings35,060 35,093 
Accumulated other comprehensive loss, net(1,440)(1,552)
Total BHE shareholders' equity43,089 43,010 
Noncontrolling interests3,962 3,967 
Total equity47,051 46,977 
  
Total liabilities and equity$127,522 $127,316 

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

6


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

 Three-Month Periods
Ended March 31,
 20212020
Operating revenue:
Energy$4,849 $3,634 
Real estate1,232 893 
Total operating revenue6,081 4,527 
  
Operating expenses: 
Energy: 
Cost of sales1,569 1,038 
Operations and maintenance934 737 
Depreciation and amortization915 809 
Property and other taxes210 151 
Real estate1,120 873 
Total operating expenses4,748 3,608 
   
Operating income1,333 919 
  
Other income (expense): 
Interest expense(530)(483)
Capitalized interest14 17 
Allowance for equity funds26 34 
Interest and dividend income21 20 
(Losses) gains on marketable securities, net(1,118)27 
Other, net(27)
Total other income (expense)(1,579)(412)
  
(Loss) income before income tax benefit and equity loss(246)507 
Income tax benefit(535)(184)
Equity loss(179)(18)
Net income110 673 
Net income attributable to noncontrolling interests106 
Net income attributable to BHE shareholders670 
Preferred dividends38 
(Loss) earnings on common shares$(34)$670 

The accompanying notes are an integral part of these consolidated financial statements.
 
7


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)

 Three-Month Periods
Ended March 31,
 20212020
 
Net income$110 $673 
 
Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $4 and $1134 
Foreign currency translation adjustment91 (548)
Unrealized gains (losses) on cash flow hedges, net of tax of $5 and $(10)14 (33)
Total other comprehensive income (loss), net of tax112 (547)
   
Comprehensive income222 126 
Comprehensive income attributable to noncontrolling interests106 
Comprehensive income attributable to BHE shareholders$116 $123 

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

8


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
 BHE Shareholders' Equity
Long-termAccumulated
AdditionalIncomeOther
PreferredCommonPaid-inTaxRetainedComprehensiveNoncontrollingTotal
 StockStockCapitalReceivableEarningsLoss, NetInterestsEquity
Balance, December 31, 2019$$$6,389 $(530)$28,296 $(1,706)$129 $32,578 
Net income— — 670 673 
Other comprehensive loss— — (547)(547)
Common stock purchases— (6)— (120)(126)
Distributions— — (5)(5)
Other equity transactions— (1)— (1)
Balance, March 31, 2020$$$6,382 $(530)$28,846 $(2,253)$127 $32,572 
        
Balance, December 31, 2020$3,750 $$6,377 $(658)$35,093 $(1,552)$3,967 $46,977 
Net income— — 106 110 
Other comprehensive income— — 112 112 
Preferred stock dividend— — — — (38)— — (38)
Distributions— (113)(113)
Other equity transactions— 
Balance, March 31, 2021$3,750 $$6,377 $(658)$35,060 $(1,440)$3,962 $47,051 

The accompanying notes are an integral part of these consolidated financial statements.
9


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
 Three-Month Periods
Ended March 31,
 20212020
Cash flows from operating activities:
Net income$110 $673 
Adjustments to reconcile net income to net cash flows from operating activities:
Losses (gains) on marketable securities, net1,118 (27)
Depreciation and amortization927 821 
Allowance for equity funds(26)(34)
Equity loss, net of distributions221 29 
Changes in regulatory assets and liabilities(9)
Deferred income taxes and amortization of investment tax credits(135)47 
Other, net63 
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets(249)(118)
Derivative collateral, net14 (19)
Pension and other postretirement benefit plans(21)(23)
Accrued property, income and other taxes, net(453)(364)
Accounts payable and other liabilities19 117 
Net cash flows from operating activities1,525 1,165 
Cash flows from investing activities:  
Capital expenditures(1,295)(1,356)
Purchases of marketable securities(128)(188)
Proceeds from sales of marketable securities104 180 
Equity method investments(26)(153)
Other, net(29)43 
Net cash flows from investing activities(1,374)(1,474)
Cash flows from financing activities:  
Proceeds from BHE senior debt3,231 
Repayments of BHE senior debt(450)(350)
Common stock purchases(126)
Proceeds from subsidiary debt1,093 
Repayments of subsidiary debt(26)(1,347)
Net proceeds from (repayments of) short-term debt409 (1,109)
Distributions to noncontrolling interests(115)(2)
Other, net(9)(32)
Net cash flows from financing activities(191)1,358 
Effect of exchange rate changes(13)
Net change in cash and cash equivalents and restricted cash and cash equivalents(39)1,036 
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period1,445 1,268 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$1,406 $2,304 
The accompanying notes are an integral part of these consolidated financial statements.
10


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)    General

Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed 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 segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns 4 utility companies in the United States serving customers in 11 states, 2 electricity distribution companies in Great Britain, 5 interstate natural gas pipeline companies and interests in 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 1 of the largest residential real estate brokerage franchise networks in the United States.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month period ended March 31, 2021 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company'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 the Company's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.


11


(2)    Business Acquisition

BHE GT&S Acquisition

Transaction Description

On November 1, 2020, BHE completed its acquisition of substantially all of the 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 Consideration"), and assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments, for 100% of the equity interests of Eastern Gas Transmission and Storage, Inc. ("EGTS") (formerly known as Dominion Energy Transmission, Inc.) and Carolina Gas Transmission, LLC (formerly known as Dominion Energy Carolina Gas Transmission, LLC); 50% of the equity interests of Iroquois Gas Transmission System L.P. ("Iroquois"); and a 25% economic interest in Cove Point LNG, LP ("Cove Point") (formerly known as Dominion Energy Cove Point LNG, LP), consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE became the operator of Cove Point after the GT&S Transaction. The GT&S Transaction received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval") in October 2020, and approval by the Department of Energy with respect to a change in control of Cove Point and the Federal Communications Commission with respect to the transfer of certain licenses earlier in 2020.

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

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

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

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

Included in BHE's Consolidated Statement of Operations within the BHE Pipeline Group reportable segment for the three-month periods ended March 31, 2021, is operating revenue and net income attributable to BHE shareholders of $559 million and $107 million, respectively, as a result of including BHE GT&S from November 1, 2020.
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Preliminary Allocation of Purchase Price

BHE GT&S' assets acquired and liabilities assumed were measured at estimated fair value at closing. The majority of BHE GT&S' operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission ("FERC") and are accounted for pursuant to GAAP, including the authoritative guidance for regulated operations. The rate-setting and cost-recovery provisions provide for revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of BHE GT&S' assets acquired and liabilities assumed subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, no fair value adjustments have been reflected related to these amounts.

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

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

The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):
Fair Value
Current assets, including cash and cash equivalents of $104$569 
Property, plant and equipment9,254 
Goodwill1,732 
Regulatory assets108 
Deferred income taxes275 
Other long-term assets1,424 
Total assets13,362 
Current liabilities, including current portion of long-term debt of $1,2001,567 
Long-term debt, less current portion4,415 
Regulatory liabilities661 
Other long-term liabilities289 
Total liabilities6,932 
Noncontrolling interest3,916 
Net assets acquired$2,514 
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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 is reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily for the long-term opportunity to improve operating results through the efficient management of operating expenses and the deployment of capital. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. For income tax purposes, the GT&S Acquisition is treated as a 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 amount of tax goodwill is approximately $0.9 billion and will be amortized over 15 years.

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of BHE and the amortization of the purchase price adjustments assuming the acquisition had taken place on January 1, 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):
Three-Month Period
Ended March 31, 2020
Operating revenue$5,056 
Net income attributable to BHE shareholders$773 

(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
   As of
 Depreciable March 31, December 31,
Life20212020
Regulated assets:   
Utility generation, transmission and distribution systems5-80 years $87,898  $86,730 
Interstate natural gas pipeline assets3-80 years 16,712  16,667 
   104,610 103,397 
Accumulated depreciation and amortization  (31,653) (30,662)
Regulated assets, net  72,957 72,735 
      
Nonregulated assets:     
Independent power plants5-30 years 7,034  7,012 
Other assets3-40 years 5,794  5,659 
   12,828 12,671 
Accumulated depreciation and amortization  (2,337) (2,586)
Nonregulated assets, net  10,491 10,085 
      
Net operating assets  83,448 82,820 
Construction work-in-progress  3,309  3,308 
Property, plant and equipment, net  $86,757 $86,128 

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

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
 March 31,December 31,
20212020
Investments:
BYD Company Limited common stock$4,773 $5,897 
Rabbi trusts452 440 
Other288 263 
Total investments5,513 6,600 
   
Equity method investments:
BHE Renewables tax equity investments5,399 5,626 
Iroquois Gas Transmission System, L.P.586 580 
Electric Transmission Texas, LLC581 594 
JAX LNG, LLC80 75 
Bridger Coal Company68 74 
Other113 118 
Total equity method investments6,827 7,067 
Restricted cash and cash equivalents and investments:  
Quad Cities Station nuclear decommissioning trust funds697 676 
Other restricted cash and cash equivalents130 155 
Total restricted cash and cash equivalents and investments827 831 
   
Total investments and restricted cash and cash equivalents and investments$13,167 $14,498 
Reflected as:
Current assets$157 $178 
Noncurrent assets13,010 14,320 
Total investments and restricted cash and cash equivalents and investments$13,167 $14,498 

Investments

(Losses) gains on marketable securities, net recognized during the period consists of the following (in millions):
Three-Month Periods
Ended March 31,
20212020
Unrealized (losses) gains recognized on marketable securities still held at the reporting date$(1,119)$25 
Net gains recognized on marketable securities sold during the period
(Losses) gains on marketable securities, net$(1,118)$27 


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Equity Method Investments

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

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
As of
March 31,December 31,
20212020
Cash and cash equivalents$1,276 $1,290 
Restricted cash and cash equivalents117 140 
Investments and restricted cash and cash equivalents and investments13 15 
Total cash and cash equivalents and restricted cash and cash equivalents$1,406 $1,445 

(5)    Recent Financing Transactions

Long-Term Debt

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

Credit Facilities

In April 2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one-year revolving credit facility to April 2022, by exercising a one-year extension option.
16


(6)    Income Taxes

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

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax benefit is as follows:
Three-Month Periods
Ended March 31,
 20212020
 
Federal statutory income tax rate21 %21 %
Income tax credits136 (46)
State income tax, net of federal income tax impacts21 
Income tax effect of foreign income(3)
Effects of ratemaking10 (8)
Equity income15 (1)
Noncontrolling interest
Other, net(1)
Effective income tax rate217 %(36)%

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

The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and Iowa state income tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. The Company made 0 payments for federal income taxes to Berkshire Hathaway for the three-month period ended March 31, 2021, and made payments for federal income taxes to Berkshire Hathaway totaling $100 million for the three-month period ended March 31, 2020.


17


(7)    Employee Benefit Plans

Domestic Operations

Net periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):
 Three-Month Periods
Ended March 31,
 20212020
Pension:
Service cost$$
Interest cost20 23 
Expected return on plan assets(33)(35)
Net amortization
Net periodic benefit cost$$
Other postretirement:
Service cost$$
Interest cost
Expected return on plan assets(5)(9)
Net amortization(1)(1)
Net periodic benefit cost (credit)$$(3)

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

Foreign Operations

Net periodic benefit credit for the United Kingdom pension plan included the following components (in millions):
Three-Month Periods
Ended March 31,
 20212020
 
Service cost$$
Interest cost10 
Expected return on plan assets(28)(25)
Net amortization14 10 
Net periodic benefit credit$(2)$(1)

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

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(8)    Fair Value Measurements

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

Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 — Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

The following table presents the Company's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Input Levels for Fair Value Measurements
Level 1Level 2Level 3
Other(1)
Total
As of March 31, 2021
Assets:
Commodity derivatives$$72 $154 $(18)$209 
Foreign currency exchange rate derivatives— 12 — — 12 
Interest rate derivatives33 47 — 80 
Mortgage loans held for sale2,065 — 2,065 
Money market mutual funds(2)
807 — 807 
Debt securities:
United States government obligations210 — 210 
International government obligations— 
Corporate obligations71 — 71 
Municipal obligations— 
Agency, asset and mortgage-backed obligations— 
Equity securities:
United States companies395 — 395 
International companies4,780 — 4,780 
Investment funds256 — 256 
 $6,449 $2,265 $201 $(18)$8,897 
Liabilities:     
Commodity derivatives$$(90)$(30)$39 $(81)
Foreign currency exchange rate derivatives— (1)— — (1)
Interest rate derivatives(3)(14)(6)— (23)
$(3)$(105)$(36)$39 $(105)
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Input Levels for Fair Value Measurements
Level 1Level 2Level 3
Other(1)
Total
As of December 31, 2020
Assets:
Commodity derivatives$$73 $135 $(21)$188 
Foreign currency exchange rate derivatives— 20 — — 20 
Interest rate derivatives62 — 62 
Mortgage loans held for sale2,001 — 2,001 
Money market mutual funds(2)
873 — 873 
Debt securities:
United States government obligations200 — 200 
International government obligations— 
Corporate obligations73 — 73 
Municipal obligations— 
Agency, asset and mortgage-backed obligations— 
Equity securities:
United States companies381 — 381 
International companies5,906 — 5,906 
Investment funds201 — 201 
 $7,562 $2,180 $197 $(21)$9,918 
Liabilities:
Commodity derivatives$(1)$(90)$(19)$56 $(54)
Foreign currency exchange rate derivatives— (2)— — (2)
Interest rate derivatives(5)(60)— (65)
$(6)$(152)$(19)$56 $(121)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $21 million and $35 million as of March 31, 2021 and December 31, 2020, respectively.
(2)Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.

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

20


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

The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
 Three-Month Periods
Ended March 31,
Interest
 CommodityRate
DerivativesDerivatives
2021:
Beginning balance$116 $62 
Changes included in earnings(1)
(6)(21)
Changes in fair value recognized in OCI(1)
Changes in fair value recognized in net regulatory assets16 
Settlements(1)
Ending balance$124 $41 
2020:
Beginning balance$97 $14 
Changes included in earnings(1)
(3)31 
Changes in fair value recognized in net regulatory assets(40)
Purchases
Settlements(4)
Ending balance$52 $45 

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

The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):
 As of March 31, 2021As of December 31, 2020
 CarryingFairCarryingFair
ValueValueValueValue
 
Long-term debt$49,461 $55,926 $49,866 $60,633 

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(9)    Commitments and Contingencies

Legal Matters

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
    
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 March 31, 2021, PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.

Environmental Laws and Regulations

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


22


Hydroelectric Relicensing

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

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

Guarantees

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


23


(10)    Revenue from Contracts with Customers

Energy Products and Services

The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated energy and nonregulated energy, with further disaggregation of regulated energy by line of business, including a reconciliation to the Company's reportable segment information included in Note 13 (in millions):
For the Three-Month Period Ended March 31, 2021
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$1,145 $452 $511 $$$$$$2,108 
Retail gas460 38 498 
Wholesale36 125 15 17 193 
Transmission and
   distribution
25 15 21 263 172 496 
Interstate pipeline815 (41)774 
Other23 25 
Total Regulated1,229 1,052 585 263 834 172 (41)4,094 
Nonregulated10 10 237 166 187 618 
Total Customer Revenue1,229 1,062 585 273 1,071 180 166 146 4,712 
Other revenue13 27 22 24 40 137 
Total$1,242 $1,067 $591 $300 $1,093 $180 $190 $186 $4,849 

For the Three-Month Period Ended March 31, 2020
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$1,122 $410 $529 $$$$$$2,061 
Retail gas187 47 234 
Wholesale64 14 (1)77 
Transmission and
   distribution
22 15 23 233 169 462 
Interstate pipeline400 (48)352 
Other26 27 
Total Regulated1,170 676 614 233 400 169 (49)3,213 
Nonregulated159 127 303 
Total Customer Revenue1,170 682 615 240 400 172 159 78 3,516 
Other revenue36 26 19 25 118 
Total$1,206 $686 $622 $266 $401 $172 $178 $103 $3,634 


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

24


Real Estate Services

The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):
HomeServices
Three-Month Periods
Ended March 31,
20212020
Customer Revenue:
Brokerage$1,022 $777 
Franchise18 16 
Total Customer Revenue1,040 793 
Mortgage and other revenue192 100 
Total$1,232 $893 

Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of March 31, 2021, by reportable segment (in millions):
Performance obligations expected to be satisfied:
Less than 12 monthsMore than 12 monthsTotal
BHE Pipeline Group$2,521 $20,918 $23,439 
BHE Transmission513 513 
Total$3,034 $20,918 $23,952 

(11)    BHE Shareholders' Equity

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

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

The following table shows the change in accumulated other comprehensive income (loss) attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income tax (in millions):
UnrecognizedForeignUnrealizedAOCI
Amounts onCurrency(Losses) GainsAttributable
RetirementTranslationon CashTo BHE
BenefitsAdjustmentFlow HedgesShareholders, Net
Balance, December 31, 2019$(417)$(1,296)$$(1,706)
Other comprehensive income (loss)34 (548)(33)(547)
Balance, March 31, 2020$(383)$(1,844)$(26)$(2,253)
Balance, December 31, 2020$(482)$(1,062)$(8)$(1,552)
Other comprehensive income91 14 112 
Balance, March 31, 2021$(475)$(971)$$(1,440)

25


(13)    Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
 Three-Month Periods
Ended March 31,
 20212020
Operating revenue:
PacifiCorp$1,242 $1,206 
MidAmerican Funding1,067 686 
NV Energy591 622 
Northern Powergrid300 266 
BHE Pipeline Group1,093 401 
BHE Transmission180 172 
BHE Renewables190 178 
HomeServices1,232 893 
BHE and Other(1)
186 103 
Total operating revenue$6,081 $4,527 
Depreciation and amortization:
PacifiCorp$264 $252 
MidAmerican Funding207 176 
NV Energy136 124 
Northern Powergrid71 63 
BHE Pipeline Group118 64 
BHE Transmission58 60 
BHE Renewables60 71 
HomeServices11 11 
BHE and Other(1)
Total depreciation and amortization$927 $821 

26


 Three-Month Periods
Ended March 31,
 20212020
Operating income:
PacifiCorp$234 $234 
MidAmerican Funding48 102 
NV Energy70 79 
Northern Powergrid151 132 
BHE Pipeline Group618 249 
BHE Transmission81 76 
BHE Renewables33 17 
HomeServices112 20 
BHE and Other(1)
(14)10 
Total operating income1,333 919 
Interest expense(530)(483)
Capitalized interest14 17 
Allowance for equity funds26 34 
Interest and dividend income21 20 
(Losses) gains on marketable securities, net(1,118)27 
Other, net(27)
Total (loss) income before income tax benefit and equity loss$(246)$507 
Interest expense:
PacifiCorp$107 $102 
MidAmerican Funding78 81 
NV Energy52 58 
Northern Powergrid33 32 
BHE Pipeline Group38 14 
BHE Transmission38 38 
BHE Renewables40 42 
HomeServices
BHE and Other(1)
143 111 
Total interest expense$530 $483 
(Loss) earnings on common shares:
PacifiCorp$169 $176 
MidAmerican Funding144 150 
NV Energy34 20 
Northern Powergrid104 87 
BHE Pipeline Group383 179 
BHE Transmission59 55 
BHE Renewables16 95 
HomeServices84 10 
BHE and Other(1,027)(102)
(Loss) earnings on common shares$(34)$670 

27


 As of
 March 31,December 31,
20212020
Assets:
PacifiCorp$26,956 $26,862 
MidAmerican Funding24,098 23,530 
NV Energy14,594 14,501 
Northern Powergrid8,980 8,782 
BHE Pipeline Group19,651 19,541 
BHE Transmission9,341 9,208 
BHE Renewables11,935 12,004 
HomeServices5,186 4,955 
BHE and Other(1)
6,781 7,933 
Total assets$127,522 $127,316 

(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
 Three-Month Periods
Ended March 31,
 20212020
Operating revenue by country:
United States$5,597 $4,089 
United Kingdom300 266 
Canada177 171 
Philippines and other
Total operating revenue by country$6,081 $4,527 
(Loss) income before income tax benefit and equity loss by country:
United States$(423)$354 
United Kingdom132 109 
Canada39 40 
Philippines and other
Total (loss) income before income tax benefit and equity loss by country$(246)$507 

The following table shows the change in the carrying amount of goodwill by reportable segment for the three-month period ended March 31, 2021 (in millions):
BHE Pipeline Group
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 
Acquisitions— — — — — — — 
Foreign currency translation21 27 
March 31, 2021$1,129 $2,102 $2,369 $1,006 $1,803 $1,572 $95 $1,458 $11,534 

28


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

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

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

29


Results of Operations for the First Quarter of 2021 and 2020

Overview

Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):
First Quarter
20212020Change
Operating revenue:
PacifiCorp$1,242 $1,206 $36 %
MidAmerican Funding1,067 686 381 56 
NV Energy591 622 (31)(5)
Northern Powergrid300 266 34 13 
BHE Pipeline Group1,093 401 692 *
BHE Transmission180 172 
BHE Renewables190 178 12 
HomeServices1,232 893 339 38 
BHE and Other186 103 83 81 
Total operating revenue$6,081 $4,527 $1,554 34 %
(Loss) earnings on common shares:
PacifiCorp$169 $176 $(7)(4)%
MidAmerican Funding144 150 (6)(4)
NV Energy34 20 14 70 
Northern Powergrid104 87 17 20 
BHE Pipeline Group383 179 204 *
BHE Transmission59 55 
BHE Renewables(1)
16 95 (79)(83)
HomeServices84 10 74 *
BHE and Other(1,027)(102)(925)*
(Loss) earnings on common shares$(34)$670 $(704)*

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

*    Not meaningful

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

The decrease in earnings on common shares for the first quarter of 2021 compared to 2020 was primarily due to the following:
$204 million higher net income at BHE Pipeline Group, primarily due to $107 million of incremental net income from BHE GT&S, acquired in November 2020, higher gross margin on gas sales and higher transportation revenue at Northern Natural Gas, largely due to the favorable impact of the February 2021 polar vortex weather event, and the impacts of the 2020 rate case settlement at Northern Natural Gas;
$79 million lower net income at BHE Renewables, primarily due to lower wind tax equity investment earnings from net losses on existing tax equity investments, largely due to the February 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation;
30


$74 million higher net income at HomeServices, primarily due to higher earnings from mortgage services (63% increase in funded mortgage volume) and brokerage services (35% increase in closed transaction volume) largely attributable to the favorable interest rate environment; and
$925 higher net loss at BHE and Other due to the $857 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.

Reportable Segment Results

PacifiCorp

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

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

MidAmerican Funding

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

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


31


NV Energy

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

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

Northern Powergrid

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

BHE Pipeline Group

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

BHE Transmission

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

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


32


HomeServices

Operating revenue increased $339 million for the first quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $228 million from a 35% increase in closed transaction volume and higher mortgage revenue of $92 million from a 63% increase in funded mortgage volume due to an increase in refinance activity from the favorable interest rate environment. Net income increased $74 million for the first quarter of 2021 compared to 2020, primarily due to higher earnings from mortgage services of $36 million and brokerage services of $27 million largely attributable to the favorable interest rate environment.
BHE and Other
Operating revenue increased $83 million for the first quarter of 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes. Net loss increased $925 million for the first quarter of 2021 compared to 2020, primarily due to the $857 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.

Liquidity and Capital Resources

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

As of March 31, 2021, the Company's total net liquidity was as follows (in millions):
MidAmericanNVNorthernBHE
BHEPacifiCorpFundingEnergyPowergridCanadaOtherTotal
Cash and cash equivalents$418 $43 $38 $103 $83 $71 $520 $1,276 
Credit facilities3,500 1,200 1,509 650 207 935 3,232 11,233 
Less:
Short-term debt— (95)(387)(55)— (218)(1,944)(2,699)
Tax-exempt bond support and letters of credit— (218)(370)— — (2)— (590)
Net credit facilities3,500 887 752 595 207 715 1,288 7,944 
Total net liquidity$3,918 $930 $790 $698 $290 $786 $1,808 $9,220 
Credit facilities:
Maturity dates202220222021, 2022202220232021, 20242021, 2022



33


Operating Activities

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

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

Investing Activities

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

Financing Activities

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

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

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

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

Future Uses of Cash

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

Capital Expenditures

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

34


The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Three-Month PeriodsAnnual
Ended March 31,Forecast
202020212021
Capital expenditures by business:
PacifiCorp$366 $439 $1,897 
MidAmerican Funding472 298 2,200 
NV Energy163 167 854 
Northern Powergrid159 179 732 
BHE Pipeline Group120 102 1,204 
BHE Transmission56 77 279 
BHE Renewables12 18 95 
HomeServices39 
BHE and Other(1)
78 
Total$1,356 $1,295 $7,378 
Capital expenditures by type:
Wind generation$273 $97 $1,158 
Electric distribution365 427 1,849 
Electric transmission185 157 1,006 
Natural gas transmission and storage49 85 1,032 
Solar generation— 295 
Other484 525 2,038 
Total$1,356 $1,295 $7,378 

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

The Company's historical and forecast capital expenditures consisted mainly of the following:
Wind generation expenditures include the following:
Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $154 million for the three-month period ended March 31, 2020. MidAmerican Energy's forecast expenditures in 2021 for the construction of additional wind-powered generating facilities total $391 million and include 202 MWs of wind-powered generating facilities expected to be placed in-service in 2021.
Repowering of wind-powered generating facilities at MidAmerican Energy totaling $24 million and $6 million for the three-month periods ended March 31, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $379 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of March 31, 2021, 80 MWs are currently expected to qualify for 100% of the federal PTCs available for 10 years following each facility's return to service, 591 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.
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Construction of wind-powered generating facilities at PacifiCorp totaling $27 million and $89 million for the three-month periods ended March 31, 2021 and 2020, respectively, and includes the 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs expected to be placed in-service in 2021. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $100 million for 2021.
Repowering existing wind-powered generating facilities at PacifiCorp totaling $5 million and $16 million for the three-month periods ended March 31, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects were placed in service in 2019 and 2020 and the remaining repowering projects are expected to be placed in-service in 2021. The energy production from such repowered facilities is expected to qualify for 100% of the federal PTCs available for 10 years following each facility's return to service. Planned additional spending for certain existing wind-powered generating facilities totals $6 million for 2021.
Acquisition and repowering of wind-powered generating facilities at PacifiCorp totaling $1 million for the three-month period ended March 31, 2021. Planned additional spending for these wind-powered generating facilities totals $44 million for 2021.
Electric distribution includes both growth and operating expenditures. Growth expenditures include new customer connections and enhancements to existing customer connections. Operating expenditures include ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, damage restoration and storm damage repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
Electric transmission includes both growth and operating expenditures. Growth expenditures include PacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020, the Nevada Utilities' Greenlink Nevada transmission expansion program and AltaLink's directly assigned projects from the Alberta Electric System Operator. Operating expenditures include system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, the Northern Natural Gas New Lisbon Expansion and Twin Cities Area Expansion projects. Operating expenditures include, among other items, asset modernization and pipeline integrity projects.
Solar generation includes growth expenditures, including MidAmerican Energy's current plan for the construction of 117 MWs of small- and utility-scale solar generation during 2021, of which 37 MWs are expected to be placed in-service in 2021. Nevada Power's solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility. Commercial operation at Dry Lake is expected by the end of 2023.
Other capital expenditures includes both growth and operating expenditures, including routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.

Other Renewable Investments

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

    
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Contractual Obligations

As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the 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 compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding. In November 2020, the PJM announced that the next capacity auction will be conducted in May 2021.

On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.

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.

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Regulatory Matters

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

PacifiCorp

Utah

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

Oregon

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

Wyoming

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

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

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

Idaho

In March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $14 million for deferred costs in 2020. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, changes in PTCs, RECs, and a resource tracking mechanism to match costs with the benefits of new wind and wind repowering projects until they are reflected in base rates. This reflects a 1.1% decrease compared to current rates.

California

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

FERC Show Cause Order

On April 15, 2021, the FERC issued an order to show cause and notice of proposed penalty related to allegations made by FERC Office of Enforcement staff that PacifiCorp failed to comply with certain North American Electric Reliability Corporation (the "NERC") reliability standards associated with facility ratings on PacifiCorp's bulk electric system. The order directs PacifiCorp to show cause as to why it should not be assessed a civil penalty of $42 million as a result of the alleged 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. PacifiCorp will file a response to the allegations with the FERC.

MidAmerican Energy

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the central United States caused disruptions in 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 customers, the IUB ordered the recovery of these higher costs to be applied to natural gas sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the three-month period ended March 31, 2021.


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NV Energy (Nevada Power and Sierra Pacific)

Price Stability Tariff

In November 2018, the Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The Nevada Utilities have designed the CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option that is based on renewable resources. The CPST provides for an energy rate that would replace the Base Tariff Energy Rate and DEAA. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the 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 other intervenors and a hearing was held in September 2020. In November 2020, the PUCN issued an order approving the tariff with modified pricing and directing the Nevada Utilities to develop a methodology by which all eligible participants may have the opportunity to participate in the CPST program up to a limit with the same proportion of governmental entities' and non-governmental entities' MWh reserved for potentially interested customers as filed. In December 2020, the Nevada Utilities filed a petition for reconsideration of the pricing 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 an updated CPST tariff with the PUCN. An order is expected in the second quarter of 2021.

Natural Disaster Protection Plan

The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. Intervenors have filed a petition 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 design issues raised by intervenors. The comment period for the reopened investigation and rulemaking ended in early February 2021 and an order is expected in the second quarter of 2021. In March 2021, the Nevada Utilities filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial natural disaster protection plan that was ordered by the PUCN and filed their first amendment to the 2020 natural disaster protection plan.
        
Northern Powergrid Distribution Companies

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

In December 2020, in respect of electricity distribution, GEMA published its decision on the methodology it will use to set the ED2 price control 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.

GEMA published a separate decision in March 2021, confirming that the financial aspects in respect of electricity distribution would broadly follow the transmission and gas distribution methodology, setting a 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 the measure of inflation used, the working assumption for ED2 is approximately 150 basis points lower than the current cost of equity.

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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 $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April.

BHE Transmission

AltaLink

Tariff Refund Application

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

In March 2021, the AUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 tariff refund in the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provides Alberta ratepayers with immediate tariff relief in 2021. The approved 2021 tariff refund includes a refund of C$150 million of previously collected future income tax and a refund of C$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 will be proposed in AltaLink's 2022-2023 GTA.

2019-2021 General Tariff Application

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

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


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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 compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.

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

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

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

2022-2023 General Tariff Application    

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

2022 Generic Cost of Capital Proceeding

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

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

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

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

2019 Deferral Accounts Reconciliation Application

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

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

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020, and new environmental matters occurring in 2021.

Climate Change

In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021, President Biden announced new climate goals to cut GHG 50%-52% economy-wide by 2030 compared to 2005 levels, and to reach 100% carbon pollution-free electricity by 2035. Additional details on how the United States will implement these goals is anticipated to be released through fall 2021.

Clean Air Act Regulations

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

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through the introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be quickly revisited by the Biden administration. Because the significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will be required to meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule April 5, 2021, remanding it for further proceedings.

National Ambient Air Quality Standards

Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx, particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Currently, with the exceptions described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainment of the current NAAQS.

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

44


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 designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyoming as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further action by PacifiCorp is required.

Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.

The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from power 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.

45


The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which 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 EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon plant federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and the state of Utah moved to intervene in the litigation, which has been stayed pending the Biden administration's review of the rule.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2020.

46


PacifiCorp and its subsidiaries
Consolidated Financial Section

47


PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
PacifiCorp

Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of March 31, 2021, the related consolidated statements of operations, changes in shareholders' equity and cash flows for the three-month periods ended March 31, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of 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
April 30, 2021

48


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

 As of
 March 31,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$43 $13 
Trade receivables, net650 703 
Other receivables, net48 48 
Inventories475 482 
Regulatory assets107 116 
Prepaid expenses73 79 
Other current assets109 82 
Total current assets1,505 1,523 
 
Property, plant and equipment, net22,535 22,430 
Regulatory assets1,279 1,279 
Other assets479 470 
 
Total assets$25,798 $25,702 

The accompanying notes are an integral part of these consolidated financial statements.
49


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

 As of
 March 31,December 31,
20212020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable$615 $772 
Accrued interest114 127 
Accrued property, income and other taxes118 80 
Accrued employee expenses112 84 
Short-term debt95 93 
Current portion of long-term debt879 420 
Regulatory liabilities111 115 
Other current liabilities178 174 
Total current liabilities2,222 1,865 
 
Long-term debt7,734 8,192 
Regulatory liabilities2,728 2,727 
Deferred income taxes2,666 2,627 
Other long-term liabilities1,106 1,118 
Total liabilities16,456 16,529 
 
Commitments and contingencies (Note 8)00
 
Shareholders' equity:
Preferred stock
Common stock - 750 shares authorized, 0 par value, 357 shares issued and outstanding
Additional paid-in capital4,479 4,479 
Retained earnings4,880 4,711 
Accumulated other comprehensive loss, net(19)(19)
Total shareholders' equity9,342 9,173 
 
Total liabilities and shareholders' equity$25,798 $25,702 

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

50


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

 Three-Month Periods
 Ended March 31,
 20212020
 
Operating revenue$1,242 $1,206 
  
Operating expenses:
Cost of fuel and energy424 417 
Operations and maintenance259 254 
Depreciation and amortization264 252 
Property and other taxes61 49 
Total operating expenses1,008 972 
  
Operating income234 234 
  
Other income (expense): 
Interest expense(107)(102)
Allowance for borrowed funds10 
Allowance for equity funds13 21 
Interest and dividend income
Other, net(4)
Total other income (expense)(76)(72)
  
Income before income tax benefit158 162 
Income tax benefit(11)(14)
Net income$169 $176 

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

51


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

 Accumulated 
   Additional OtherTotal
PreferredCommonPaid-inRetainedComprehensiveShareholders'
 StockStockCapitalEarningsLoss, NetEquity
 
Balance, December 31, 2019$$$4,479 $3,972 $(16)$8,437 
Net income— — — 176 — 176 
Other comprehensive income— — — 
Balance, March 31, 2020$$$4,479 $4,148 $(15)$8,614 
       
Balance, December 31, 2020$$$4,479 $4,711 $(19)$9,173 
Net income— — — 169 — 169 
Balance, March 31, 2021$$$4,479 $4,880 $(19)$9,342 

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

52



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

 Three-Month Periods
 Ended March 31,
 20212020
Cash flows from operating activities: 
Net income$169  $176 
Adjustments to reconcile net income to net cash flows from operating activities: 
Depreciation and amortization264  252 
Allowance for equity funds(13)(21)
Changes in regulatory assets and liabilities(4) (16)
Deferred income taxes and amortization of investment tax credits13  (30)
Other, net(2)
Changes in other operating assets and liabilities:  
Trade receivables, other receivables and other assets61  85 
Inventories (26)
Derivative collateral, net (1)
Prepaid expenses(3)
Accrued property, income and other taxes, net12 18 
Accounts payable and other liabilities(51) (3)
Net cash flows from operating activities469  437 
   
Cash flows from investing activities:  
Capital expenditures(439) (366)
Other, net(1) 27 
Net cash flows from investing activities(440) (339)
   
Cash flows from financing activities:  
Net proceeds from (repayments of) short-term debt(74)
Other, net(1)
Net cash flows from financing activities (74)
   
Net change in cash and cash equivalents and restricted cash and cash equivalents30  24 
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$49  $60 
 
The accompanying notes are an integral part of these consolidated financial statements.

53


PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)    General

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

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month periods ended March 31, 2021 and 2020 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 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 three-month period ended March 31, 2021.

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

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
As of
March 31,December 31,
20212020
Cash and cash equivalents$43 $13 
Restricted cash included in other current assets
Restricted cash included in other assets
Total cash and cash equivalents and restricted cash and cash equivalents$49 $19 

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(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
  As of
 March 31,December 31,
Depreciable Life20212020
Utility Plant: 
Generation15 - 59 years$13,355 $12,861 
Transmission60 - 90 years7,686 7,632 
Distribution20 - 75 years7,725 7,660 
Intangible plant(1)
5 - 75 years1,069 1,054 
Other5 - 60 years1,513 1,510 
Utility plant in service31,348 30,717 
Accumulated depreciation and amortization (9,980)(9,838)
Utility plant in service, net 21,368 20,879 
Other non-regulated, net of accumulated depreciation and amortization14 - 95 years
Plant, net21,377 20,888 
Construction work-in-progress 1,158 1,542 
Property, plant and equipment, net $22,535 $22,430 

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

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

(4)    Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
Three-Month Periods
Ended March 31,
20212020
Federal statutory income tax rate21 %21 %
State income tax, net of federal income tax benefit
Federal income tax credits(20)(11)
Effects of ratemaking(13)(22)
Other
Effective income tax rate(7)%(9)%

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

55


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

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

(5)    Employee Benefit Plans

Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):
Three-Month Periods
Ended March 31,
20212020
Pension:
Service cost$$
Interest cost
Expected return on plan assets(13)(14)
Net amortization
Net periodic benefit credit$(1)$
Other postretirement:
Service cost$$
Interest cost
Expected return on plan assets(2)(4)
Net amortization
Net periodic benefit credit$$(1)

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

(6)    Risk Management and Hedging Activities

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

56


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

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
OtherOtherOther 
CurrentOtherCurrentLong-term
AssetsAssetsLiabilitiesLiabilitiesTotal
As of March 31, 2021
Not designated as hedging contracts(1):
Commodity assets$45 $$$$53 
Commodity liabilities(2)(27)(24)(53)
Total43 (25)(24)
     
Total derivatives43 (25)(24)
Cash collateral receivable13 17 
Total derivatives - net basis$43 $$(12)$(20)$17 
As of December 31, 2020
Not designated as hedging contracts(1):
Commodity assets$29 $$$$36 
Commodity liabilities(2)(23)(28)(53)
Total27 (22)(28)(17)
      
Total derivatives27 (22)(28)(17)
Cash collateral receivable15 24 
Total derivatives - net basis$27 $$(7)$(19)$

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

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The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
Three-Month Periods
Ended March 31,
20212020
Beginning balance$17 $62 
Changes in fair value(17)34 
Net gains reclassified to operating revenue
Net losses reclassified to cost of fuel and energy(20)
Ending balance$$84 

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
Unit ofMarch 31,December 31,
Measure20212020
Electricity sales, netMegawatt hours(1)
Natural gas purchasesDecatherms114 100 

Credit Risk

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

Collateral and Contingent Features

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

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $52 million and $51 million as of March 31, 2021 and December 31, 2020, respectively, for which PacifiCorp had posted collateral of $17 million and $24 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of March 31, 2021 and December 31, 2020, PacifiCorp would have been required to post $30 million and $25 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

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(7)    Fair Value Measurements

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

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

Level 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.

The following table presents PacifiCorp's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 Input Levels for Fair Value Measurements    
Level 1 Level 2 Level 3 
Other(1)
 Total
As of March 31, 2021    
Assets:    
Commodity derivatives$$53 $$(4)$49 
Money market mutual funds(2)
36 — 36 
Investment funds30 — 30 
 $66 $53 $$(4)$115 
Liabilities - Commodity derivatives$$(53)$$21 $(32)
As of December 31, 2020
Assets:
Commodity derivatives$$36 $$(3)$33 
Money market mutual funds(2)
— 
Investment funds25 — 25 
$31 $36 $$(3)$64 
Liabilities - Commodity derivatives$$(53)$$27 $(26)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $17 million and $24 million as of March 31, 2021 and December 31, 2020, respectively.

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

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

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

PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):
 As of March 31, 2021As of December 31, 2020
 CarryingFairCarryingFair
 ValueValueValueValue
     
Long-term debt$8,613 $10,198 $8,612 $10,995 

(8)    Commitments and Contingencies

Legal Matters

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

    California and Oregon 2020 Wildfires

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

Environmental Laws and Regulations

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.

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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(9)    Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):
Three-Month Periods
Ended March 31,
20212020
Customer Revenue:
Retail:
Residential$483 $460 
Commercial359 358 
Industrial271 277 
Other retail32 27 
Total retail1,145 1,122 
Wholesale (1)
36 
Transmission25 22 
Other Customer Revenue23 26 
Total Customer Revenue1,229 1,170 
Other revenue13 36 
Total operating revenue$1,242 $1,206 

(1)Includes net payments to counterparties for the financial settlement of certain non-derivative forward contracts for energy sales.
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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 First Quarter of 2021 and 2020

Overview

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

Non-GAAP Financial Measure

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

PacifiCorp's cost of fuel and energy is generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
First Quarter
20212020Change
Utility margin:
Operating revenue$1,242 $1,206 $36 %
Cost of fuel and energy424 417 
Utility margin818 789 29 
Operations and maintenance259 254 
Depreciation and amortization264 252 12 
Property and other taxes61 49 12 24 
Operating income$234 $234 $— — %

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Utility Margin

A comparison of key operating results related to utility margin is as follows for the quarters ended March 31:
First Quarter
20212020Change
Utility margin (in millions):
Operating revenue$1,242 $1,206 $36 %
Cost of fuel and energy424 417 
Utility margin$818 $789 $29 %
Sales (GWhs):
Residential4,632 4,421 211 %
Commercial4,470 4,410 60 
Industrial, irrigation and other4,474 4,702 (228)(5)
Total retail13,576 13,533 43 — 
Wholesale1,591 1,281 310 24 
Total sales15,167 14,814 353 %
Average number of retail customers
 (in thousands)
1,989 1,955 34 %
Average revenue per MWh:
Retail$84.15 $82.97 $1.18 %
Wholesale$30.89 $26.35 $4.54 17 %
Heating degree days4,687 4,605 82 %
Sources of energy (GWhs)(1):
Coal7,644 7,228 416 %
Natural gas3,065 3,041 24 
Hydroelectric(2)
923 1,046 (123)(12)
Wind and other(2)
1,803 1,112 691 62 
Total energy generated13,435 12,427 1,008 
Energy purchased3,028 3,391 (363)(11)
Total16,463 15,818 645 %
Average cost of energy per MWh:
Energy generated(3)
$17.66 $17.80 $(0.14)(1)%
Energy purchased$47.13 $47.41 $(0.28)(1)%

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

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

(3)    The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
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Quarter Ended March 31, 2021 Compared to Quarter Ended March 31, 2020

Utility margin increased $29 million, or 4%, for the first quarter of 2021 compared to 2020 primarily due to:
$20 million increase in retail revenue primarily due to higher customer volumes and higher average rates from sales mix, partially offset by lower prices due to certain general rate case orders. Retail customer volumes increased 0.3%, primarily due to an increase in the average number of customers across the service territory and favorable impact of weather, partially offset by lower customer usage;
$18 million of lower purchased electricity costs from lower market prices and lower purchased volumes, partially due to higher wind generation from new Energy Vision 2020 ("EV 2020") generation and repowered facilities; and
$15 million of higher wholesale revenue due to higher wholesale volumes and higher average wholesale market prices.
The increases above were partially offset by:
$12 million of higher natural gas-fueled generation costs primarily due to higher average prices;
$8 million primarily from higher net amortization of deferred net power costs in accordance with established adjustment mechanisms; and
$6 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.
Operations and maintenance increased $5 million, or 2%, for the first quarter of 2021 compared to 2020 primarily due to higher vegetation management costs of $14 million, partially offset by cost savings from the retirement of Cholla unit 4 in December 2020 and decreased bad debt expense.

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

Property and other taxes increased $12 million, or 24%, for the first quarter of 2021 compared to 2020 primarily due to higher property taxes from higher assessed property values.
Interest expense increased $5 million, or 5%, for the first quarter of 2021 compared to 2020 primarily due to a higher average long-term debt balance.

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

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

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

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Liquidity and Capital Resources

As of March 31, 2021, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents$43 
 
Credit facilities1,200 
Less:
Short-term debt(95)
Tax-exempt bond support(218)
Net credit facilities887 
 
Total net liquidity$930 
 
Credit facilities:
Maturity dates2022 
Operating Activities

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

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

Investing Activities

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

Financing Activities

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

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

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

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $3 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.

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Future Uses of Cash

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

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

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Three-Month PeriodsAnnual
Ended March 31,Forecast
202020212021
Wind generation$106 $33 $193 
Electric distribution99 195 730 
Electric transmission92 60 426 
Other69 151 548 
Total$366 $439 $1,897 

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

Wind generation includes both growth projects and operating expenditures. Growth projects include:

Construction of wind-powered generating facilities at PacifiCorp totaling $27 million and $89 million for the three-month periods ended March 31, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs expected to be placed in-service in 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $100 million for 2021.
Repowering existing wind-powered generating facilities at PacifiCorp totaling $5 million and $16 million for the three-month periods ended March 31, 2021 and 2020, respectively. Certain repowering projects were placed in service in 2019 and 2020 with the remaining repowering projects expected to be placed in-service in 2021. The energy production from such repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned additional spending for certain existing wind-powered generating facilities totals $6 million for 2021.
Acquisition and repowering of wind-powered generating facilities totals $1 million for the three-month period ended March 31, 2021. Planned additional spending for these wind-powered generating facilities totals $44 million for 2021.
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Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes planned spend on wildfire mitigation, wildfire damage restoration and storm damage repairs. Expenditures for these items totaled $83 million and $4 million for the three-month periods ended March 31, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with these activities will total an additional $145 million in 2021. Remaining investments relate to expenditures for new connections and distribution.

Electric transmission includes both growth projects and operating expenditures. Transmission investment through 2020 primarily reflects costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020. Planned spending for the additional Energy Gateway Transmission segments totals $182 million in 2021 and are expected to be placed in service in 2023 - 2024.

Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $13 million and $10 million for the three-month periods ended March 31, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with information technology will total an additional $118 million for 2021. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.

Requests for Proposals

PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load or state-specific compliance obligations. Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.

PacifiCorp issued the 2020 All Source RFP to the market in July 2020. The 2020 All Source RFP sought bids for resources capable of coming online by the end of 2024 up to the level of resources identified in PacifiCorp's 2019 IRP. An initial shortlist was identified in October 2020. The final shortlist of winning bids will be identified by June 2021.

Contractual Obligations

As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2020.


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Regulatory Matters

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

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, pension and other postretirement benefits, income taxes and revenue recognition-unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2020. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2020.
69


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

70


PART I
Item 1.Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
MidAmerican Energy Company

Results of Review of Interim Financial Information

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2020, and the related statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

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

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


/s/ Deloitte & Touche LLP


Des Moines, Iowa
April 30, 2021

71


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

As of
March 31,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$37 $38 
Trade receivables, net521 234 
Income tax receivable293 
Inventories231 278 
Other current assets103 73 
Total current assets1,185 623 
Property, plant and equipment, net19,223 19,279 
Regulatory assets439 392 
Investments and restricted investments938 911 
Other assets215 232 
Total assets$22,000 $21,437 

The accompanying notes are an integral part of these financial statements.
72


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

As of
March 31,December 31,
20212020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable$292 $408 
Accrued interest86 78 
Accrued property, income and other taxes124 161 
Short-term debt387 
Other current liabilities186 183 
Total current liabilities1,075 830 
Long-term debt7,224 7,210 
Regulatory liabilities1,257 1,111 
Deferred income taxes3,107 3,054 
Asset retirement obligations711 709 
Other long-term liabilities414 458 
Total liabilities13,788 13,372 
Commitments and contingencies (Note 8)00
Shareholder's equity:
Common stock - 350 shares authorized, 0 par value, 71 shares issued and outstanding
Additional paid-in capital561 561 
Retained earnings7,651 7,504 
Total shareholder's equity8,212 8,065 
Total liabilities and shareholder's equity$22,000 $21,437 

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

73


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

Three-Month Periods
Ended March 31,
20212020
Operating revenue:
Regulated electric$545 $471 
Regulated natural gas and other522 210 
Total operating revenue1,067 681 
Operating expenses:
Cost of fuel and energy151 80 
Cost of natural gas purchased for resale and other432 128 
Operations and maintenance193 165 
Depreciation and amortization207 176 
Property and other taxes36 34 
Total operating expenses1,019 583 
Operating income48 98 
Other income (expense):
Interest expense(74)(76)
Allowance for borrowed funds
Allowance for equity funds
Other, net11 (5)
Total other income (expense)(55)(70)
(Loss) income before income tax benefit(7)28 
Income tax benefit(154)(123)
Net income$147 $151 

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

74


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, December 31, 2019$$561 $6,679 $7,240 
Net income— — 151 151 
Balance, March 31, 2020$$561 $6,830 $7,391 
Balance, December 31, 2020$$561 $7,504 $8,065 
Net income— — 147 147 
Balance, March 31, 2021$$561 $7,651 $8,212 

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

75


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

Three-Month Periods
Ended March 31,
20212020
Cash flows from operating activities:
Net income$147 $151 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization207 176 
Amortization of utility plant to other operating expenses
Allowance for equity funds(6)(8)
Deferred income taxes and amortization of investment tax credits154 91 
Settlements of asset retirement obligations(4)(2)
Other, net(4)14 
Changes in other operating assets and liabilities:
Trade receivables and other assets(299)15 
Inventories46 (6)
Derivative collateral, net(14)
Pension and other postretirement benefit plans(6)
Accrued property, income and other taxes, net(331)(286)
Accounts payable and other liabilities10 70 
Net cash flows from operating activities(85)219 
Cash flows from investing activities:
Capital expenditures(298)(472)
Purchases of marketable securities(52)(127)
Proceeds from sales of marketable securities47 124 
Other, net
Net cash flows from investing activities(303)(470)
Cash flows from financing activities:
Net proceeds from short-term debt387 50 
Other, net(1)
Net cash flows from financing activities387 49 
Net change in cash and cash equivalents and restricted cash and cash equivalents(1)(202)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period45 330 
Cash and cash equivalents and restricted cash and cash equivalents at end of period$44 $128 

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

76


MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

(1)    General

MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct, wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of March 31, 2021, and for the three-month periods ended March 31, 2021 and 2020. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month period ended March 31, 2021 and 2020. The results of operations for the three-month periods ended March 31, 2021, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2020, 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 three-month period ended March 31, 2021.

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

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation and, as of December 31, 2020, the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
As of
March 31,December 31,
20212020
Cash and cash equivalents$37 $38 
Restricted cash and cash equivalents in other current assets
Total cash and cash equivalents and restricted cash and cash equivalents$44 $45 

77


(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
As of
March 31,December 31,
Depreciable Life20212020
Utility plant in service, net:
Generation20-70 years$17,083 $16,980 
Transmission52-75 years2,372 2,365 
Electric distribution20-75 years4,433 4,369 
Natural gas distribution29-75 years1,970 1,955 
Utility plant in service25,858 25,669 
Accumulated depreciation and amortization(7,061)(6,902)
Utility plant in service, net18,797 18,767 
Nonregulated property, net:
Nonregulated property gross20-50 years
Accumulated depreciation and amortization(1)(1)
Nonregulated property, net
18,803 18,773 
Construction work-in-progress420 506 
Property, plant and equipment, net$19,223 $19,279 

(4)    Regulatory Matters

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. These increased costs are reflected in cost of natural gas purchased for resale and other on the Statement of Operations and their recovery through the Purchased Gas Adjustment Clause is reflected in regulated natural gas and other revenue.

To mitigate the impact to customers, the Iowa Utilities Board ordered the recovery of these higher costs to be applied to natural gas sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during three-month period ended March 31, 2021.

78


(5)    Income Taxes

The effective income tax rate for the three-month period ended March 31, 2021, is 2,200% and results from a $154 million income tax benefit associated with a $7 million pre-tax loss. The $154 million income tax benefit is primarily comprised of a $2 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss and a $168 million benefit (2,400%) from income tax credits, partially offset by a $13 million expense (186%) from the effects of ratemaking.

A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:
Three-Month Periods
Ended March 31,
20212020
Federal statutory income tax rate21 %21 %
Income tax credits2,400 (430)
State income tax, net of federal income tax impacts(29)(28)
Effects of ratemaking(186)(3)
Other, net(6)
Effective income tax rate2,200 %(439)%

Income tax credits relate primarily to production tax credits ("PTCs") from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. MidAmerican Energy recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods ended March 31, 2021 and 2020 totaled $151 million and $120 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been 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 made 0 cash payments for income tax to BHE for the three-month period ended March 31, 2021, and made net cash payments for income tax to BHE totaling $46 million for the three-month period ended March 31, 2020.

(6)    Employee Benefit Plans

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.

79


Net periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
Three-Month Periods
Ended March 31,
20212020
Pension:
Service cost$$
Interest cost
Expected return on plan assets(9)(10)
Net periodic benefit cost (credit)$$(3)
Other postretirement:
Service cost$$
Interest cost
Expected return on plan assets(2)(3)
Net amortization(1)(1)
Net periodic benefit cost (credit)$$(1)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and $12 million, respectively, during 2021. As of March 31, 2021, $2 million and $3 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(7)    Fair Value Measurements

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

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

Level 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.

80


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 March 31, 2021:
Assets:
Commodity derivatives$— $$$(2)$
Money market mutual funds(2)
38 — 38 
Debt securities:
United States government obligations210 — 210 
International government obligations— 
Corporate obligations71 — 71 
Municipal obligations— 
Agency, asset and mortgage-backed obligations— 
Equity securities:
United States companies395 — 395 
International companies— 
Investment funds24 — 24 
$675 $86 $$(2)$761 
Liabilities - commodity derivatives$$(1)$(1)$$

Input Levels for Fair Value Measurements
Level 1Level 2Level 3
Other(1)
Total
As of December 31, 2020:
Assets:
Commodity derivatives$$$$(5)$
Money market mutual funds(2)
41 — 41 
Debt securities:
United States government obligations200 — 200 
International government obligations— 
Corporate obligations73 — 73 
Municipal obligations— 
Agency, asset and mortgage-backed obligations— 
Equity securities:
United States companies381 — 381 
International companies— 
Investment funds17 — 17 
$648 $90 $$(5)$738 
Liabilities - commodity derivatives$$(4)$(3)$$(2)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $— million as of March 31, 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.
81


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

MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):
As of March 31, 2021As of December 31, 2020
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Long-term debt$7,224 $8,305 $7,210 $9,130 

(8)    Commitments and Contingencies

Legal Matters

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

Environmental Laws and Regulations

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

Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using Federal Energy Regulatory Commission ("FERC")-approved formula rates subject to true-up for actual cost of service. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the approved base return on equity ("ROE") effective January 2015. Prior to September 2016, the rates in effect were based on a 12.38% ROE. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the 12.38% ROE no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively. In September 2016, the FERC issued an order for the first complaint, which reduces the base ROE to 10.32% and required refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. In November 2019, the FERC issued an order addressing the second complaint and issues on appeal in the first complaint. The order established a ROE of 9.88% (10.38% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 forward. In May 2020, the FERC issued an order on rehearing of the November 2019 order. The May 2020 order affirmed the FERC's prior decision to dismiss the second complaint and established an ROE of 10.02% (10.52% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 to the date of the May 2020 order. These orders continue to be subject to judicial appeal. MidAmerican Energy cannot predict the ultimate outcome of these matters and, as of March 31, 2021, has accrued a $10 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.

82


(9)    Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 10, (in millions):
For the Three-Month Period Ended March 31, 2021
ElectricNatural GasOtherTotal
Customer Revenue:
Retail:
Residential$161 $308 $— $469 
Commercial71 129 — 200 
Industrial190 12 — 202 
Natural gas transportation services— 10 — 10 
Other retail(1)
30 — 31 
Total retail452 460 — 912 
Wholesale74 51 — 125 
Multi-value transmission projects15 — — 15 
Other Customer Revenue— — 10 10 
Total Customer Revenue541 511 10 1,062 
Other revenue
Total operating revenue$545 $512 $10 $1,067 

For the Three-Month Period Ended March 31, 2020
ElectricNatural GasOtherTotal
Customer Revenue:
Retail:
Residential$148 $128 $— $276 
Commercial70 43 — 113 
Industrial163 — 167 
Natural gas transportation services— 11 — 11 
Other retail(1)
29 — 29 
Total retail410 186 — 596 
Wholesale42 22 — 64 
Multi-value transmission projects16 — — 16 
Other Customer Revenue— — 
Total Customer Revenue468 208 677 
Other revenue
Total operating revenue$471 $209 $$681 

(1)    Other retail includes provisions for rate refunds, for which any actual refunds will be reflected in the applicable customer classes upon resolution of the related regulatory proceeding.

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(10)    Segment Information

MidAmerican Energy has identified 2 reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost.

The following tables provide information on a reportable segment basis (in millions):
Three-Month Periods
 Ended March 31,
20212020
Operating revenue:
Regulated electric$545 $471 
Regulated natural gas512 209 
Other10 
Total operating revenue$1,067 $681 
Operating income:
Regulated electric$$59 
Regulated natural gas39 39 
Total operating income48 98 
Interest expense(74)(76)
Allowance for borrowed funds
Allowance for equity funds
Other, net11 (5)
(Loss) income before income tax benefit$(7)$28 

As of
March 31,
2021
December 31,
2020
Assets:
Regulated electric$20,272 $19,892 
Regulated natural gas1,725 1,544 
Other
Total assets$22,000 $21,437 


84




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


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

Results of Review of Interim Financial Information

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2020, and the related consolidated statements of operations, changes in member's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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


/s/ Deloitte & Touche LLP


Des Moines, Iowa
April 30, 2021

85


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

As of
March 31,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$38 $39 
Trade receivables, net521 234 
Income tax receivable295 
Inventories231 278 
Other current assets102 74 
Total current assets1,187 625 
Property, plant and equipment, net19,223 19,279 
Goodwill1,270 1,270 
Regulatory assets439 392 
Investments and restricted investments940 913 
Other assets215 232 
Total assets$23,274 $22,711 

The accompanying notes are an integral part of these consolidated financial statements.
86


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

As of
March 31,December 31,
20212020
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable$292 $408 
Accrued interest87 83 
Accrued property, income and other taxes124 161 
Note payable to affiliate184 177 
Short-term debt387 — 
Other current liabilities187 183 
Total current liabilities1,261 1,012 
Long-term debt7,464 7,450 
Regulatory liabilities1,257 1,111 
Deferred income taxes3,104 3,052 
Asset retirement obligations711 709 
Other long-term liabilities414 458 
Total liabilities14,211 13,792 
Commitments and contingencies (Note 8)00
Member's equity: