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D Dominion Energy Gas

Filed: 7 Nov 21, 7:00pm
0001081316us-gaap:AccumulatedOtherComprehensiveIncomeMemberbhe:PacificorpMember2020-01-012020-09-30

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 September 30, 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  
  Des Moines, Iowa 50309-2580  
  515-242-4300  
001-05152 PACIFICORP 93-0246090
  (An Oregon Corporation)  
  825 N.E. Multnomah Street, Suite 1900  
  Portland, Oregon 97232  
  888-221-7070  
333-90553MIDAMERICAN FUNDING, LLC47-0819200
(An Iowa Limited Liability Company)
666 Grand Avenue
Des Moines, Iowa 50309-2580
515-242-4300
333-15387MIDAMERICAN ENERGY COMPANY42-1425214
(An Iowa Corporation)
666 Grand Avenue
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 November 4, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 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 November 4, 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
EGTSEastern Gas Transmission and Storage, Inc.
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
CPSTCustomer Price Stability Tariff
CPUCCalifornia Public Utilities Commission
CSAPRCross-State Air Pollution Rule
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
DthDecatherm
ECAMEnergy Cost Adjustment Mechanism
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
FIPFederal Implementation Plan
GAAPAccounting principles generally accepted in the United States of America
GEMAGas and Electricity Markets Authority
GHGGreenhouse Gases
GTAGeneral Tariff Application
GWhGigawatt Hour
IPUCIdaho Public Utilities Commission
IRPIntegrated Resource Plan
IUBIowa Utilities Board
kVKilovolt
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
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;
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 September 30, 2021, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-month periods ended September 30, 2021 and 2020, and of cash flows for the nine-month periods ended September 30, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

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

Basis for Review Results

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

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


/s/ Deloitte & Touche LLP


Des Moines, Iowa
November 5, 2021
4


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

 As of
 September 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$2,709 $1,290 
Restricted cash and cash equivalents216 140 
Trade receivables, net2,545 2,107 
Inventories1,129 1,168 
Mortgage loans held for sale1,687 2,001 
Other current assets2,142 2,741 
Total current assets10,428 9,447 
   
Property, plant and equipment, net88,062 86,128 
Goodwill11,572 11,506 
Regulatory assets3,372 3,157 
Investments and restricted cash and cash equivalents and investments15,218 14,320 
Other assets2,902 2,758 
  
Total assets$131,554 $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
 September 30,December 31,
20212020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$1,798 $1,867 
Accrued interest622 555 
Accrued property, income and other taxes670 582 
Accrued employee expenses556 383 
Short-term debt1,968 2,286 
Current portion of long-term debt1,179 1,839 
Other current liabilities2,054 1,626 
Total current liabilities8,847 9,138 
  
BHE senior debt13,001 12,997 
BHE junior subordinated debentures100 100 
Subsidiary debt35,818 34,930 
Regulatory liabilities6,958 7,221 
Deferred income taxes12,910 11,775 
Other long-term liabilities4,304 4,178 
Total liabilities81,938 80,339 
   
Commitments and contingencies (Note 9)00
   
Equity:  
BHE shareholders' equity:  
Preferred stock - 100 shares authorized, $0.01 par value, 2 and 4 shares issued and outstanding2,300 3,750 
Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding— — 
Additional paid-in capital6,374 6,377 
Long-term income tax receivable(658)(658)
Retained earnings39,199 35,093 
Accumulated other comprehensive loss, net(1,523)(1,552)
Total BHE shareholders' equity45,692 43,010 
Noncontrolling interests3,924 3,967 
Total equity49,616 46,977 
  
Total liabilities and equity$131,554 $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 PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Operating revenue:
Energy$5,225 $4,451 $14,375 $11,504 
Real estate1,743 1,742 4,738 3,828 
Total operating revenue6,968 6,193 19,113 15,332 
    
Operating expenses:   
Energy:   
Cost of sales1,385 1,169 4,064 3,095 
Operations and maintenance1,001 1,033 2,972 2,564 
Depreciation and amortization946 789 2,797 2,323 
Property and other taxes194 152 593 456 
Real estate1,608 1,503 4,312 3,492 
Total operating expenses5,134 4,646 14,738 11,930 
     
Operating income1,834 1,547 4,375 3,402 
    
Other income (expense):   
Interest expense(531)(504)(1,593)(1,490)
Capitalized interest18 24 46 60 
Allowance for equity funds34 50 90 122 
Interest and dividend income18 17 65 57 
Gains on marketable securities, net294 1,797 1,142 2,407 
Other, net36 64 61 
Total other income (expense)(159)1,420 (186)1,217 
    
Income before income tax (benefit) expense and equity loss1,675 2,967 4,189 4,619 
Income tax (benefit) expense(355)80 (563)(111)
Equity loss(5)(41)(234)(91)
Net income2,025 2,846 4,518 4,639 
Net income attributable to noncontrolling interests103 311 11 
Net income attributable to BHE shareholders1,922 2,842 4,207 4,628 
Preferred dividends26 — 101 — 
Earnings on common shares$1,896 $2,842 $4,106 $4,628 

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 PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
 
Net income$2,025 $2,846 $4,518 $4,639 
 
Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $7, $(3), $12 and $1022 (6)44 38 
Foreign currency translation adjustment(218)244 (59)(195)
Unrealized gains (losses) on cash flow hedges, net of tax of $12, $2, $16 and $(5)33 48 (20)
Total other comprehensive (loss) income, net of tax(163)242 33 (177)
     
Comprehensive income1,862 3,088 4,551 4,462 
Comprehensive income attributable to noncontrolling interests103 315 11 
Comprehensive income attributable to BHE shareholders$1,759 $3,084 $4,236 $4,451 

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, June 30, 2020$— $— $6,377 $(530)$29,962 $(2,125)$101 $33,785 
Net income— — — — 2,842 — 2,845 
Other comprehensive income— — — — — 242 — 242 
Distributions— — — — — — (4)(4)
Other equity transactions— — — — — — 
Balance, September 30, 2020$— $— $6,377 $(530)$32,804 $(1,883)$101 $36,869 
        
Balance, December 31, 2019$— $— $6,389 $(530)$28,296 $(1,706)$129 $32,578 
Net income— — — — 4,628 — 10 4,638 
Other comprehensive loss— — — — — (177)— (177)
Common stock purchases— — (6)— (120)— — (126)
Distributions— — — — — — (11)(11)
Purchase of noncontrolling interest— — (5)— — — (28)(33)
Other equity transactions— — (1)— — — — 
Balance, September 30, 2020$— $— $6,377 $(530)$32,804 $(1,883)$101 $36,869 
Balance, June 30, 2021$3,750 $— $6,377 $(658)$37,303 $(1,360)$3,953 $49,365 
Net income— — — — 1,922 — 103 2,025 
Other comprehensive loss— — — — — (163)— (163)
Preferred stock redemptions(1,450)— — — — — — (1,450)
Preferred stock dividend— — — — (26)— — (26)
Distributions— — — — — — (130)(130)
Purchase of noncontrolling interest— — (3)— — — — (3)
Other equity transactions— — — — — — (2)(2)
Balance, September 30, 2021$2,300 $— $6,374 $(658)$39,199 $(1,523)$3,924 $49,616 
        
Balance, December 31, 2020$3,750 $— $6,377 $(658)$35,093 $(1,552)$3,967 $46,977 
Net income— — — — 4,207 — 311 4,518 
Other comprehensive income— — — — — 29 33 
Preferred stock redemptions(1,450)— — — — — — (1,450)
Preferred stock dividend— — — — (101)— — (101)
Distributions— — — — — — (364)(364)
Contributions— — — — — — 
Purchase of noncontrolling interest— — (3)— — — — (3)
Other equity transactions— — — — — — (3)(3)
Balance, September 30, 2021$2,300 $— $6,374 $(658)$39,199 $(1,523)$3,924 $49,616 

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)
 Nine-Month Periods
Ended September 30,
 20212020
Cash flows from operating activities:
Net income$4,518 $4,639 
Adjustments to reconcile net income to net cash flows from operating activities:
Gains on marketable securities, net(1,142)(2,407)
Depreciation and amortization2,834 2,357 
Allowance for equity funds(90)(122)
Equity loss, net of distributions346 146 
Changes in regulatory assets and liabilities(518)(87)
Deferred income taxes and investment tax credits, net661 791 
Other, net(88)(6)
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets(13)(1,668)
Derivative collateral, net115 53 
Pension and other postretirement benefit plans(37)(69)
Accrued property, income and other taxes, net(29)97 
Accounts payable and other liabilities427 796 
Net cash flows from operating activities6,984 4,520 
Cash flows from investing activities:  
Capital expenditures(4,594)(4,607)
Acquisitions, net of cash acquired(64)— 
Purchases of marketable securities(243)(322)
Proceeds from sales of marketable securities222 308 
Proceeds from other investments1,296 13 
Equity method investments(54)(2,062)
Other, net(91)37 
Net cash flows from investing activities(3,528)(6,633)
Cash flows from financing activities:  
Preferred stock redemptions(1,450)— 
Preferred dividends(86)— 
Common stock purchases— (126)
Proceeds from BHE senior debt— 3,231 
Repayments of BHE senior debt(450)(350)
Proceeds from subsidiary debt2,014 2,648 
Repayments of subsidiary debt(1,271)(1,558)
Net repayments of short-term debt(316)(815)
Purchase of noncontrolling interest— (33)
Distributions to noncontrolling interests(366)(13)
Contributions from noncontrolling interests
Other, net(44)(52)
Net cash flows from financing activities(1,960)2,937 
Effect of exchange rate changes
Net change in cash and cash equivalents and restricted cash and cash equivalents1,497 828 
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$2,942 $2,096 

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 September 30, 2021 and for the three- and nine-month periods ended September 30, 2021 and 2020. The results of operations for the three- and nine-month periods ended September 30, 2021 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in 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 nine-month period ended September 30, 2021.

11


(2)    Business Acquisition

BHE GT&S Acquisition

Transaction Description

On November 1, 2020, BHE completed its acquisition of substantially all of the 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.

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

On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval for a cash 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 was included in other current assets on the Consolidated Balance Sheet as of December 31, 2020, to Dominion Questar on November 2, 2020. Pursuant to the Q-Pipe Purchase Agreement, Dominion Questar agreed that, if the Q-Pipe Transaction did not close, it would repay all or (depending upon the repayment date) substantially all of the Q-Pipe Cash Consideration (the "Purchase Price Repayment Amount") to BHE on or prior to December 31, 2021.

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

Included in BHE's Consolidated Statement of Operations within the BHE Pipeline Group reportable segment for the three- and nine-month periods ended September 30, 2021, is operating revenue of $516 million and $1,563 million, respectively and net income attributable to BHE shareholders of $74 million and $247 million, respectively, as a result of including BHE GT&S from November 1, 2020.
12


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 following table summarizes the 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$582 
Property, plant and equipment9,264 
Goodwill1,741 
Regulatory assets108 
Deferred income taxes284 
Other long-term assets1,424 
Total assets13,403 
Current liabilities, including current portion of long-term debt of $1,2001,616 
Long-term debt, less current portion4,415 
Regulatory liabilities650 
Other long-term liabilities292 
Total liabilities6,973 
Noncontrolling interest3,916 
Net assets acquired$2,514 

During the nine-month period ended September 30, 2021, the Company made revisions to certain contracts and property, plant and equipment related to non-regulated operations, the equity method investment and associated deferred income tax amounts based upon the receipt of additional information about the facts and circumstances that existed as of the acquisition date. Provisional amounts were subject to further revision for up to 12 months following the acquisition date until the related valuations were completed.

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.
13


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):
Nine-Month Period
Ended September 30, 2020
Operating revenue$16,791 
Net income attributable to BHE shareholders$4,468 

(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
   As of
 Depreciable September 30, December 31,
Life20212020
Regulated assets:   
Utility generation, transmission and distribution systems5-80 years $89,026  $86,730 
Interstate natural gas pipeline assets3-80 years 17,044  16,667 
   106,070 103,397 
Accumulated depreciation and amortization  (32,444) (30,662)
Regulated assets, net  73,626 72,735 
      
Nonregulated assets:     
Independent power plants5-30 years 7,058  7,012 
Other assets3-40 years 5,951  5,659 
   13,009 12,671 
Accumulated depreciation and amortization  (2,916) (2,586)
Nonregulated assets, net  10,093 10,085 
      
Net operating assets  83,719 82,820 
Construction work-in-progress  4,343  3,308 
Property, plant and equipment, net  $88,062 $86,128 

Construction work-in-progress includes $3.9 billion as of September 30, 2021 and $3.2 billion as of December 31, 2020, related to the construction of regulated assets.

14


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

Investments and restricted cash and cash equivalents and investments consists of the following (in millions):
 As of
 September 30,December 31,
20212020
Investments:
BYD Company Limited common stock$7,023 $5,897 
Rabbi trusts473 440 
Other295 263 
Total investments7,791 6,600 
   
Equity method investments:
BHE Renewables tax equity investments5,253 5,626 
Iroquois Gas Transmission System, L.P.583 580 
Electric Transmission Texas, LLC578 594 
JAX LNG, LLC87 75 
Bridger Coal Company60 74 
Other163 118 
Total equity method investments6,724 7,067 
Restricted cash and cash equivalents and investments:  
Quad Cities Station nuclear decommissioning trust funds727 676 
Other restricted cash and cash equivalents233 155 
Total restricted cash and cash equivalents and investments960 831 
   
Total investments and restricted cash and cash equivalents and investments$15,475 $14,498 
Reflected as:
Current assets$257 $178 
Noncurrent assets15,218 14,320 
Total investments and restricted cash and cash equivalents and investments$15,475 $14,498 

Investments

Gains on marketable securities, net recognized during the period consists of the following (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Unrealized gains recognized on marketable securities still held at the reporting date$294 $1,794 $1,141 $2,403 
Net gains recognized on marketable securities sold during the period— 
Gains on marketable securities, net$294 $1,797 $1,142 $2,407 


15


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 $353 million, or after-tax income of $123 million inclusive of production tax credits ("PTCs") of $401 million and other income tax benefits of $79 million, during the nine-month period ended September 30, 2021, on its tax equity investments, largely due to the February 2021 polar vortex weather event. The losses for the impacted tax equity investments were based upon the terms of each partnership agreement, as amended, and are subject to change as project-by-project discussions are ongoing among the Company and the respective hedge provider and project sponsor. As of September 30, 2021, the carrying value of the impacted tax equity investments totaled $2.8 billion.

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, consist substantially of funds restricted for debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
As of
September 30,December 31,
20212020
Cash and cash equivalents$2,709 $1,290 
Restricted cash and cash equivalents216 140 
Investments and restricted cash and cash equivalents and investments17 15 
Total cash and cash equivalents and restricted cash and cash equivalents$2,942 $1,445 

(5)    Recent Financing Transactions

Long-Term Debt

In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.

In September 2021, HomeServices entered into a $150 million unsecured amortizing term loan due September 2026. The net proceeds were used to fund the repayment of its existing unsecured amortizing term loan due September 2022. The amortizing term loan has an underlying variable interest rate based on the London Interbank Offered Rate plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter.

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

In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due June 2052. PacifiCorp used the net proceeds to finance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily from the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and the construction and acquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general funds.
16


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

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

Credit Facilities

In September 2021, HomeServices amended and restated its existing $600 million unsecured credit facility expiring in September 2022. The amendment increased the lender commitment to $700 million and extended the expiration date to September 2026.

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

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

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

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

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

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

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

17


(6)    Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax (benefit) expense is as follows:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
 
Federal statutory income tax rate21 %21 %21 %21 %
Income tax credits(31)(20)(29)(23)
State income tax, net of federal income tax impacts(4)— 
Income tax effect of foreign income(1)— 
Effects of ratemaking(6)(2)(5)(2)
Equity income— — (1)— 
Noncontrolling interest(1)— (2)— 
Other, net— — 
Effective income tax rate(21)%%(13)%(2)%

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 nine-month periods ended September 30, 2021 and 2020 totaled $1.2 billion and $1.0 billion, respectively.

Income tax effect on foreign income includes, among other items, a deferred income tax charge of $109 million recognized in June 2021 upon the enactment of an increase in the United Kingdom's corporate income tax rate from 19% to 25% effective April 1, 2023, and a deferred income tax charge of $35 million recognized in July 2020 related to the United Kingdom's corporate income tax rate that was scheduled to decrease from 19% to 17% effective April 1, 2020; however, the rate was maintained at 19% through amended legislation enacted in July 2020.

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. For the nine-month periods ended September 30, 2021 and 2020, the Company received net cash payments for federal income taxes from Berkshire Hathaway totaling $1.3 billion and $1.0 billion, respectively.

18


(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 PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Pension:
Service cost$$$22 $11 
Interest cost21 23 59 69 
Expected return on plan assets(32)(35)(101)(105)
Settlement— — 
Net amortization19 25 
Net periodic benefit cost$$— $$— 
Other postretirement:
Service cost$$$$
Interest cost14 16 
Expected return on plan assets(5)(9)(16)(25)
Net amortization— (1)(2)(5)
Net periodic benefit cost (credit)$$(3)$$(9)

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 September 30, 2021, $9 million and $10 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 PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
 
Service cost$$$12 $12 
Interest cost10 23 30 
Expected return on plan assets(28)(26)(84)(76)
Net amortization14 11 42 32 
Net periodic benefit credit$(2)$(1)$(7)$(2)

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 £20 million during 2021. As of September 30, 2021, £17 million, or $24 million, of contributions had been made to the United Kingdom pension plan.

19


(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 September 30, 2021
Assets:
Commodity derivatives$15 $436 $88 $(49)$490 
Foreign currency exchange rate derivatives— — — 
Interest rate derivatives— 12 30 — 42 
Mortgage loans held for sale— 1,687 — — 1,687 
Money market mutual funds2,017 — — — 2,017 
Debt securities:
United States government obligations228 — — — 228 
International government obligations— — — 
Corporate obligations— 86 — — 86 
Municipal obligations— — — 
Agency, asset and mortgage-backed obligations— — — 
Equity securities:
United States companies398 — — — 398 
International companies7,031 — — — 7,031 
Investment funds264 — — — 264 
 $9,953 $2,235 $118 $(49)$12,257 
Liabilities:     
Commodity derivatives$(2)$(134)$(56)$80 $(112)
Foreign currency exchange rate derivatives— (4)— — (4)
Interest rate derivatives(1)(11)(2)— (14)
$(3)$(149)$(58)$80 $(130)
20


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 derivatives— — 62 — 62 
Mortgage loans held for sale— 2,001 — — 2,001 
Money market mutual funds873 — — — 873 
Debt securities:
United States government obligations200 — — — 200 
International government obligations— — — 
Corporate obligations— 73 — — 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 $31 million and $35 million as of September 30, 2021 and December 31, 2020, respectively.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.

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


21


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

The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
InterestInterest
 CommodityRateCommodityRate
DerivativesDerivativesDerivativesDerivatives
2021:
Beginning balance$105 $41 $116 $62 
Changes included in earnings(1)
(18)(13)(34)(34)
Changes in fair value recognized in OCI(6)— (13)— 
Changes in fair value recognized in net regulatory assets12 — 21 — 
Purchases— — 
Settlements(62)— (60)— 
Ending balance$32 $28 $32 $28 

Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
InterestInterest
CommodityRateCommodityRate
DerivativesDerivativesDerivativesDerivatives
2020:
Beginning balance$44 $78 $97 $14 
Changes included in earnings(1)
(7)10 (11)74 
Changes in fair value recognized in net regulatory assets20 — (36)— 
Purchases— — 
Settlements38 — 42 — 
Ending balance$96 $88 $96 $88 

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


22


The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):
 As of September 30, 2021As of December 31, 2020
 CarryingFairCarryingFair
ValueValueValueValue
 
Long-term debt$50,098 $57,902 $49,866 $60,633 

(9)    Commitments and Contingencies

Construction Commitments

During the nine-month period ended September 30, 2021, MidAmerican Energy entered into firm construction commitments totaling $405 million through the remainder of 2021 and 2022 related to the repowering and construction of wind-powered generating facilities and the construction of solar-powered generating facilities.

Easements

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

Legal Matters

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated 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 "2020 Wildfires"). The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. 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.


23


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

As of September 30, 2021, PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.

Environmental Laws and Regulations

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

Hydroelectric Relicensing

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

In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application by January 16, 2021, to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC and the States as co-licensees. The transfer will be effective after PacifiCorp secures property transfer approvals from its state public utility commissions and 30 days following the issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions approved the property transfer. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah.

Guarantees

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

24



(10)    Revenue from Contracts with Customers

Energy Products and Services

The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business, including a reconciliation to the Company's reportable segment information included in Note 13 (in millions):
For the Three-Month Period Ended September 30, 2021
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$1,352 $736 $1,008 $— $— $— $— $— $3,096 
Retail gas— 84 16 — — — — — 100 
Wholesale58 113 19 — 14 — — (1)203 
Transmission and
   distribution
55 15 35 241 — 175 — — 521 
Interstate pipeline— — — — 514 — — (28)486 
Other26 — — — (2)— — — 24 
Total Regulated1,491 948 1,078 241 526 175 — (29)4,430 
Nonregulated— — 257 12 288 141 708 
Total Customer Revenue1,491 950 1,078 249 783 187 288 112 5,138 
Other revenue— 16 28 (2)28 87 
Total$1,491 $966 $1,085 $277 $785 $185 $316 $120 $5,225 
For the Nine-Month Period Ended September 30, 2021
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$3,685 $1,704 $2,227 $— $— $— $— $(1)$7,615 
Retail gas— 633 74 — — — — — 707 
Wholesale124 307 44 — 31 — — (2)504 
Transmission and
   distribution
117 45 78 747 — 525 — — 1,512 
Interstate pipeline— — — — 1,787 — — (94)1,693 
Other80 — — (1)— — — 80 
Total Regulated4,006 2,689 2,424 747 1,817 525 — (97)12,111 
Nonregulated— 13 26 726 27 693 452 1,938 
Total Customer Revenue4,006 2,702 2,425 773 2,543 552 693 355 14,049 
Other revenue25 24 18 84 41 (5)80 59 326 
Total$4,031 $2,726 $2,443 $857 $2,584 $547 $773 $414 $14,375 
25


For the Three-Month Period Ended September 30, 2020
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$1,344 $661 $977 $— $— $— $— $(1)$2,981 
Retail gas— 70 14 — — — — — 84 
Wholesale59 56 14 — — — — 130 
Transmission and
   distribution
33 15 30 208 — 169 — — 455 
Interstate pipeline— — — — 264 — — (29)235 
Other42 — — — — — — — 42 
Total Regulated1,478 802 1,035 208 264 169 — (29)3,927 
Nonregulated— (1)— 270 145 430 
Total Customer Revenue1,478 806 1,034 214 264 175 270 116 4,357 
Other revenue32 — — 39 94 
Total$1,479 $812 $1,042 $246 $264 $175 $309 $124 $4,451 
For the Nine-Month Period Ended September 30, 2020
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE Pipeline GroupBHE TransmissionBHE Renewables
BHE and
Other(1)
Total
Customer Revenue:
Regulated:
Retail electric$3,532 $1,539 $2,144 $— $— $— $— $(1)$7,214 
Retail gas— 341 81 — — — — — 422 
Wholesale76 157 34 — — — — (1)266 
Transmission and
   distribution
79 48 75 632 — 502 — — 1,336 
Interstate pipeline— — — — 885 — — (103)782 
Other88 — — — — — — 89 
Total Regulated3,775 2,085 2,335 632 885 502 — (105)10,109 
Nonregulated— 13 18 — 14 641 394 1,081 
Total Customer Revenue3,775 2,098 2,336 650 885 516 641 289 11,190 
Other revenue54 16 23 83 — 90 43 314 
Total$3,829 $2,114 $2,359 $733 $890 $516 $731 $332 $11,504 

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

Real Estate Services

The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):
HomeServices
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Customer Revenue:
Brokerage$1,563 $1,449 $4,154 $3,183 
Franchise23 23 65 54 
Total Customer Revenue1,586 1,472 4,219 3,237 
Mortgage and other revenue157 270 519 591 
Total$1,743 $1,742 $4,738 $3,828 
26


Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of September 30, 2021, by reportable segment (in millions):
Performance obligations expected to be satisfied:
Less than 12 monthsMore than 12 monthsTotal
BHE Pipeline Group$2,586 $21,377 $23,963 
BHE Transmission175 — 175 
Total$2,761 $21,377 $24,138 

(11)    BHE Shareholders' Equity

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

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

The following table shows the change in accumulated other comprehensive income (loss) by each component of other comprehensive income (loss), net of applicable income tax (in millions):
UnrecognizedForeignUnrealizedAOCI
Amounts onCurrency(Losses) GainsAttributable
RetirementTranslationon CashNoncontrollingTo BHE
BenefitsAdjustmentFlow HedgesInterestsShareholders, Net
Balance, December 31, 2019$(417)$(1,296)$$— $(1,706)
Other comprehensive income (loss)38 (195)(20)— (177)
Balance, September 30, 2020$(379)$(1,491)$(13)$— $(1,883)
Balance, December 31, 2020$(492)$(1,062)$(8)$10 $(1,552)
Other comprehensive income (loss)44 (59)48 (4)29 
Balance, September 30, 2021$(448)$(1,121)$40 $$(1,523)

27


(13)    Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Operating revenue:
PacifiCorp$1,491 $1,479 $4,031 $3,829 
MidAmerican Funding966 812 2,726 2,114 
NV Energy1,085 1,042 2,443 2,359 
Northern Powergrid277 246 857 733 
BHE Pipeline Group785 264 2,584 890 
BHE Transmission185 175 547 516 
BHE Renewables316 309 773 731 
HomeServices1,743 1,742 4,738 3,828 
BHE and Other(1)
120 124 414 332 
Total operating revenue$6,968 $6,193 $19,113 $15,332 
Depreciation and amortization:
PacifiCorp$272 $234 $811 $696 
MidAmerican Funding218 179 634 530 
NV Energy138 128 411 377 
Northern Powergrid73 69 217 195 
BHE Pipeline Group124 45 363 134 
BHE Transmission59 61 177 176 
BHE Renewables61 72 182 214 
HomeServices14 11 37 34 
BHE and Other(1)
Total depreciation and amortization$960 $800 $2,834 $2,357 

28


 Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Operating income:  
PacifiCorp$394 $361 $911 $851 
MidAmerican Funding287 232 438 444 
NV Energy348 347 563 587 
Northern Powergrid126 106 403 327 
BHE Pipeline Group303 101 1,166 442 
BHE Transmission90 79 256 236 
BHE Renewables149 143 279 244 
HomeServices135 239 426 336 
BHE and Other(1)
(61)(67)(65)
Total operating income1,834 1,547 4,375 3,402 
Interest expense(531)(504)(1,593)(1,490)
Capitalized interest18 24 46 60 
Allowance for equity funds34 50 90 122 
Interest and dividend income18 17 65 57 
Gains on marketable securities, net294 1,797 1,142 2,407 
Other, net36 64 61 
Total income before income tax (benefit) expense and equity loss$1,675 $2,967 $4,189 $4,619 
Interest expense:
PacifiCorp$110 $107 $322 $319 
MidAmerican Funding81 79 237 238 
NV Energy51 56 154 171 
Northern Powergrid33 34 98 97 
BHE Pipeline Group33 15 111 44 
BHE Transmission39 38 117 111 
BHE Renewables39 41 119 125 
HomeServices
BHE and Other(1)
144 133 432 376 
Total interest expense$531 $504 $1,593 $1,490 
Earnings on common shares:
PacifiCorp$333 $286 $728 $629 
MidAmerican Funding373 337 728 695 
NV Energy282 249 416 367 
Northern Powergrid83 26 162 172 
BHE Pipeline Group144 78 627 321 
BHE Transmission65 58 184 173 
BHE Renewables163 162 360 395 
HomeServices102 177 321 246 
BHE and Other(1)
351 1,469 580 1,630 
Total earnings on common shares$1,896 $2,842 $4,106 $4,628 

29


 As of
 September 30,December 31,
20212020
Assets:
PacifiCorp$28,230 $26,862 
MidAmerican Funding25,038 23,530 
NV Energy15,105 14,501 
Northern Powergrid9,043 8,782 
BHE Pipeline Group19,993 19,541 
BHE Transmission9,383 9,208 
BHE Renewables11,766 12,004 
HomeServices5,065 4,955 
BHE and Other(1)
7,931 7,933 
Total assets$131,554 $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 PeriodsNine-Month Periods
Ended September 30,Ended September 30,
 2021202020212020
Operating revenue by country:
United States$6,499 $5,773 $17,700 $14,086 
United Kingdom277 246 857 733 
Canada180 174 537 512 
Philippines and other12 — 19 
Total operating revenue by country$6,968 $6,193 $19,113 $15,332 
Income before income tax (benefit) expense and equity loss by country:
United States$1,511 $2,839 $3,699 $4,220 
United Kingdom107 82 343 250 
Canada49 44 134 130 
Philippines and other13 19 
Total income before income tax (benefit) expense and equity loss by country$1,675 $2,967 $4,189 $4,619 

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2021 (in millions):
BHE Pipeline Group
PacifiCorpMidAmerican FundingNV EnergyNorthern PowergridBHE TransmissionBHE RenewablesHomeServices
Total
 
December 31, 2020$1,129 $2,102 $2,369 $1,000 $1,803 $1,551 $95 $1,457 $11,506 
Acquisitions— — — — 11 — — 59 70 
Foreign currency translation— — — (10)— — — (4)
September 30, 2021$1,129 $2,102 $2,369 $990 $1,814 $1,557 $95 $1,516 $11,572 

30


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

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

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

31


Results of Operations for the Third Quarter and First Nine Months of 2021 and 2020

Overview

Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):
Third QuarterFirst Nine Months
20212020Change20212020Change
Operating revenue:
PacifiCorp$1,491 $1,479 $12 %$4,031 $3,829 $202 %
MidAmerican Funding966 812 154 19 2,726 2,114 612 29 
NV Energy1,085 1,042 43 2,443 2,359 84 
Northern Powergrid277 246 31 13 857 733 124 17 
BHE Pipeline Group785 264 521 *2,584 890 1,694 *
BHE Transmission185 175 10 547 516 31 
BHE Renewables316 309 773 731 42 
HomeServices1,743 1,742 — 4,738 3,828 910 24 
BHE and Other120 124 (4)(3)414 332 82 25 
Total operating revenue$6,968 $6,193 $775 13 %$19,113 $15,332 $3,781 25 %
Earnings on common shares:
PacifiCorp$333 $286 $47 16 %$728 $629 $99 16 %
MidAmerican Funding373 337 36 11 728 695 33 
NV Energy282 249 33 13 416 367 49 13 
Northern Powergrid83 26 57 *162 172 (10)(6)
BHE Pipeline Group144 78 66 85 627 321 306 95 
BHE Transmission65 58 12 184 173 11 
BHE Renewables(1)
163 162 360 395 (35)(9)
HomeServices102 177 (75)(42)321 246 75 30
BHE and Other351 1,469 (1,118)(76)580 1,630 (1,050)(64)
Total earnings on common shares$1,896 $2,842 $(946)(33)%$4,106 $4,628 $(522)(11)%

(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 $946 million for the third quarter of 2021 compared to 2020. The third quarter of 2021 included a pre-tax unrealized gain of $296 million ($253 million after-tax) compared to a pre-tax unrealized gain in the third quarter of 2020 of $1,787 million ($1,299 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 third quarter of 2021 was $1,643 million, an increase of $100 million, or 6%, compared to adjusted earnings on common shares in the third quarter of 2020 of $1,543 million.
Earnings on common shares decreased $522 million for the first nine months of 2021 compared to 2020. The first nine months of 2021 included a pre-tax unrealized gain of $1,126 million ($855 million after-tax) compared to a pre-tax unrealized gain in the first nine months of 2020 of $2,402 million ($1,746 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 nine months of 2021 was $3,251 million, an increase of $369 million, or 13%, compared to adjusted earnings on common shares in the first nine months of 2020 of $2,882 million.


32


The decreases in earnings on common shares for the third quarter and for the first nine months of 2021 compared to 2020 were primarily due to the following:
The Utilities' earnings increased $116 million for the third quarter and $181 million for the first nine months of 2021 compared to 2020, reflecting higher electric utility margin, favorable income tax expense, from higher PTCs recognized and the impacts of ratemaking, and lower operations and maintenance expense, partially offset by higher depreciation and amortization expense. Electric retail customer volumes increased 4.8% for the first nine months of 2021 compared to 2020, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers;
Northern Powergrid's earnings increased $57 million for the third quarter and decreased $10 million for the first nine months of 2021 compared to 2020, primarily due to deferred income tax charges ($35 million in third quarter 2020 and $109 million in second quarter 2021) related to enacted increases in the United Kingdom corporate income tax rate and higher distribution revenue;
BHE Pipeline Group's earnings increased $66 million for the third quarter and $306 million for the first nine months of 2021 compared to 2020, largely due to $74 million and $247 million, respectively, of incremental earnings from BHE GT&S, acquired in November 2020. In addition, earnings for the first nine months increased from the effects of higher margins on natural gas sales and higher transportation revenue at Northern Natural Gas, largely due to the favorable impacts of the February 2021 polar vortex weather event;
BHE Renewables' earnings decreased $35 million for the first nine months of 2021 compared to 2020, primarily due to lower tax equity investment earnings from the February 2021 polar vortex weather event, partially offset by earnings from tax equity investment projects reaching commercial operation and higher operating revenue from owned renewable energy projects;
HomeServices' earnings decreased $75 million for the third quarter and increased $75 million for the first nine months of 2021 compared to 2020, primarily due to lower earnings from mortgage services due to a decrease in refinance activity. In addition, earnings for the first nine months was favorably impacted by higher earnings from brokerage services due to an increase in closed transaction volume and an increase in mortgage services earnings due to an unfavorable 2020 contingent earn-out remeasurement; and
BHE and Other's earnings decreased $1,118 million for the third quarter and $1,050 million for the first nine months of 2021 compared to 2020, mainly due to $1,046 million and $891 million, respectively, of unfavorable changes in the after-tax unrealized position of the Company's investment in BYD Company Limited, and dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020.

Reportable Segment Results

PacifiCorp

Operating revenue increased $12 million for the third quarter of 2021 compared to 2020, primarily due to higher retail revenue of $8 million and higher wholesale and other revenue of $4 million. Retail revenue increased due to higher customer volumes of $28 million, partially offset by price impacts of $20 million from lower rates primarily due to certain general rate case orders. Retail customer volumes increased 2.1%, primarily due to an increase in the average number of customers and higher customer usage. Wholesale and other revenue increased primarily due to higher wheeling revenue and REC sales, partially offset by $27 million from the Oregon RAC settlement (offset in depreciation expense) recognized in 2020.

Earnings increased $47 million for the third quarter of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $65 million, favorable income tax expense, from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and higher utility margin of $6 million, partially offset by higher depreciation and amortization expense of $38 million and lower allowances for equity and borrowed funds used during construction of $24 million. Utility margin increased primarily due to higher deferred net power costs in accordance with established adjustment mechanisms and the higher retail and wheeling revenue, partially offset by higher purchased power and thermal generation costs and higher wheeling expenses. Operations and maintenance expense decreased primarily due to 2020 costs associated with the Klamath Hydroelectric Settlement Agreement and wildfires and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.


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Operating revenue increased $202 million for the first nine months of 2021 compared to 2020, primarily due to higher retail revenue of $152 million and higher wholesale and other revenue of $50 million. Retail revenue increased due to higher customer volumes of $176 million, partially offset by price impacts of $24 million from lower rates primarily due to certain general rate case orders. Retail customer volumes increased 4.4%, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather. Wholesale and other revenue increased primarily due to higher wheeling revenue, wholesale volumes and REC sales, partially offset by $34 million from the Oregon RAC settlement (offset in depreciation expense) recognized in 2020.

Earnings increased $99 million for the first nine months of 2021 compared to 2020, primarily due to higher utility margin of $131 million, favorable income tax expense, from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking, and lower operations and maintenance expense of $48 million, partially offset by higher depreciation and amortization expense of $115 million and lower allowances for equity and borrowed funds used during construction of $53 million. Utility margin increased primarily due to the higher retail, wholesale and wheeling revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power and thermal generation costs and higher wheeling expenses. Operations and maintenance expense decreased primarily due to 2020 costs associated with the Klamath Hydroelectric Settlement Agreement and wildfires and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.

MidAmerican Funding

Operating revenue increased $154 million for the third quarter of 2021 compared to 2020, primarily due to higher electric operating revenue of $126 million and higher natural gas operating revenue of $30 million. Electric operating revenue increased due to higher retail revenue of $67 million and higher wholesale and other revenue of $59 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $43 million (largely offset in cost of sales) and higher customer volumes of $24 million. Electric retail customer volumes increased 5.6% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased mainly due to higher average wholesale per-unit prices of $34 million and higher wholesale volumes of $17 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $24 million (offset in cost of sales).

Earnings increased $36 million for the third quarter of 2021 compared to 2020, primarily due to higher electric utility margin of $78 million and lower operations and maintenance expense of $12 million, mainly due to 2020 costs associated with storm restoration activities, partially offset by higher depreciation and amortization expense of $39 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service as well as from the impacts of certain regulatory mechanisms.

Operating revenue increased $612 million for the first nine months of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $344 million and higher electric operating revenue of $268 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $345 million (offset in cost of sales), primarily due to the February 2021 polar vortex weather event. Electric operating revenue increased due to higher retail revenue of $157 million and higher wholesale and other revenue of $111 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $91 million (largely offset in cost of sales), higher customer volumes of $59 million and price impacts of $7 million from changes in sales mix. Electric retail customer volumes increased 6.5% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased due to higher wholesale volumes of $64 million and higher average wholesale per-unit prices of $42 million.

Earnings increased $33 million for the first nine months of 2021 compared to 2020, primarily due to higher electric utility margin of $117 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $104 million, higher operations and maintenance expense of $18 million and lower allowances for equity and borrowed funds of $12 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. Operations and maintenance expense increased primarily due to higher costs associated with additional wind-powered generating facilities placed in-service as well as higher natural gas distribution costs, partially offset by 2020 costs associated with storm restoration activities. The increase in depreciation and amortization expense was primarily due to additional assets placed in-service as well as from the impacts of certain regulatory mechanisms. The favorable income tax benefit was from higher PTCs recognized due to new wind-powered generating facilities placed in-service, partially offset by the impacts of ratemaking.

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On October 29, 2021, the IUB issued an order extending for three years the depreciation deferral regulatory mechanism approved by the IUB in MidAmerican Energy's 2013 electric rate case. In December 2020, the cumulative deferral reached the limit previously set by the IUB, resulting in higher depreciation expense of $13 million for the third quarter and $39 million for the first nine months of 2021. With the extension of the deferral, annual depreciation expense will be approximately $50 million lower in years 2021 through 2023 than would have been recognized absent the order. The annual amount of the deferral for 2021 will be recognized in the fourth quarter.

NV Energy

Operating revenue increased $43 million for the third quarter of 2021 compared to 2020 due to higher electric operating revenue, which increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $80 million and an increase in the average number of customers, partially offset by lower base tariff general rates of $27 million at Nevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 3.9%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.

Earnings increased $33 million for the third quarter of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $51 million, lower income tax expense from the impacts of ratemaking and lower interest expense of $5 million, partially offset by lower electric utility margin of $39 million and higher depreciation and amortization expense of $9 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decision in 2020, partially offset by an increase in the average number of customers. Operations and maintenance expense decreased primarily due to lower earnings sharing at Nevada Power and lower regulatory deferrals and amortizations. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.

Operating revenue increased $84 million for the first nine months of 2021 compared to 2020, primarily due to higher electric operating revenue of $92 million, partially offset by lower natural gas operating revenue of $8 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $153 million, higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers, partially offset by lower base tariff general rates of $51 million at Nevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 4.2%, primarily due to higher customer usage and the favorable impact of weather. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold (offset in cost of sales).

Earnings increased $49 million for the first nine months of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $72 million, lower income tax expense from the impacts of ratemaking, lower interest expense of $17 million, lower pension costs of $10 million, higher interest and dividend income of $8 million and favorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by lower electric utility margin of $61 million and higher depreciation and amortization expense of $34 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decision in 2020, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers. Operations and maintenance expense decreased primarily due to lower regulatory deferrals and amortizations and lower earnings sharing at Nevada Power. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.

Northern Powergrid

Operating revenue increased $31 million for the third quarter of 2021 compared to 2020, primarily due to $17 million from the weaker United States dollar and higher distribution revenue of $17 million, mainly from 4.1% higher units distributed of $10 million and increased tariff rates of $8 million.

Earnings increased $57 million for the third quarter of 2021 compared to 2020, primarily due to a deferred income tax charge in July 2020 of $35 million related to the United Kingdom corporate income tax rate not decreasing from 19% to 17% effective April 1, 2020, as had previously been announced, and the higher distribution revenue.

Operating revenue increased $124 million for the first nine months of 2021 compared to 2020, primarily due to $69 million from the weaker United States dollar and higher distribution revenue of $56 million, mainly from increased tariff rates of $27 million and 4.5% higher units distributed of $26 million.

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Earnings decreased $10 million for the first nine months of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by the higher distribution revenue, a deferred income tax charge in July 2020 of $35 million related to the United Kingdom corporate income tax rate not decreasing from 19% to 17% effective April 1, 2020, as had previously been announced, and $11 million from the weaker United States dollar.

BHE Pipeline Group

Operating revenue increased $521 million for the third quarter of 2021 compared to 2020, primarily due to $516 million of incremental revenue at BHE GT&S, acquired in November 2020, and higher transportation revenue of $23 million at Kern River largely due to higher rates, partially offset by lower transportation revenue of $19 million at Northern Natural Gas primarily due to lower volumes.

Earnings increased $66 million for the third quarter of 2021 compared to 2020, primarily due to $74 million of incremental earnings at BHE GT&S and higher earnings of $16 million at Kern River from the higher transportation revenue, partially offset by lower earnings of $25 million at Northern Natural Gas, primarily due to the lower transportation revenue.

Operating revenue increased $1,694 million for the first nine months of 2021 compared to 2020, primarily due to $1,563 million of incremental revenue at BHE GT&S, higher gas sales of $77 million and higher transportation revenue of $49 million at Northern Natural Gas, each due to the favorable impacts of the February 2021 polar vortex weather event, higher gas sales at Northern Natural Gas of $33 million (largely offset in cost of sales) and higher transportation revenue of $25 million at Kern River largely due to higher rates, partially offset by lower transportation revenue of $69 million at Northern Natural Gas primarily due to lower volumes.

Earnings increased $306 million for the first nine months of 2021 compared to 2020, primarily due to $247 million of incremental earnings at BHE GT&S, higher earnings of $39 million at Northern Natural Gas and favorable earnings of $18 million at Kern River from the higher transportation revenue. Northern Natural Gas' improved performance was primarily due to higher gross margin on gas sales and higher transportation revenue, each due to the favorable impacts of the February 2021 polar vortex weather event, partially offset by the lower transportation revenue due primarily to lower volumes.

BHE Transmission

Operating revenue increased $10 million for the third 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 of $5 million, partially offset by the impact of a regulatory decision received in November 2020 at AltaLink.

Earnings increased $7 million for the third quarter of 2021 compared to 2020, primarily due to higher earnings from the Montana-Alberta Tie-Line.

Operating revenue increased $31 million for the first nine months of 2021 compared to 2020, primarily due to $40 million from the stronger United States dollar and higher revenue from the Montana-Alberta Tie-Line of $10 million, partially offset by the impacts of regulatory decisions received in April and November 2020 at AltaLink.

Earnings increased $11 million for the first nine months of 2021 compared to 2020, primarily due to $11 million from the stronger United States dollar, higher earnings from the Montana-Alberta Tie-Line and lower non-regulated interest expense at BHE Canada, partially offset by the impact of a regulatory decision received in April 2020 at AltaLink.

BHE Renewables

Operating revenue increased $7 million for the third quarter of 2021 compared to 2020, primarily due to higher hydro, natural gas and solar revenues from higher generation and favorable market conditions, partially offset by an unfavorable change in the valuation of a power purchase agreement of $8 million and lower geothermal revenues from lower generation.

Earnings increased $1 million for the third quarter 2021 compared to 2020, primarily due to higher wind earnings of $6 million, mainly from tax equity investments offset by the unfavorable change in the valuation of a power purchase agreement, and higher hydro earnings of $5 million from higher generation, partially offset by lower geothermal earnings of $12 million, primarily due to lower geothermal generation and natural gas margin.

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Operating revenue increased $42 million for the first nine months of 2021 compared to 2020, primarily due to higher natural gas, hydro and solar revenues from favorable market conditions and higher generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $22 million.

Earnings decreased $35 million for the first nine months of 2021 compared to 2020, primarily due to lower wind earnings of $56 million, largely from lower tax equity investment earnings of $48 million and the unfavorable change in the valuation of a power purchase agreement, partially offset by higher solar earnings of $18 million, mainly due to higher generation and lower depreciation expense, and higher hydro earnings of $5 million from higher generation. Tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $123 million, primarily due to the February 2021 polar vortex weather event, partially offset by $79 million of earnings from projects reaching commercial operation.

HomeServices

Operating revenue increased $1 million for the third quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $117 million, partially offset by lower mortgage revenue of $112 million from a 27% decrease in funded volume. The increase in brokerage revenue was due to $67 million from acquired companies and a 5% increase in closed transaction volume at existing companies, resulting from an increase in average sales price offset by fewer closed units.

Earnings decreased $75 million for the third quarter of 2021 compared to 2020, primarily due to lower earnings from mortgage services of $76 million, largely attributable to the decrease in funded volume.

Operating revenue increased $910 million for the first nine months of 2021 compared to 2020, primarily due to higher brokerage revenue of $933 million from a 34% increase in closed transaction volume, resulting from increases in closed units and average sales price, partially offset by lower mortgage revenue of $71 million from a decrease in refinance activity.

Earnings increased $75 million for the first nine months of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $84 million, largely due to the increase in closed transaction volume, partially offset by lower earnings from mortgage services of $28 million, largely attributable to the decrease in refinance activity offset by an unfavorable 2020 contingent earn-out remeasurement.

BHE and Other

Operating revenue decreased $4 million for the third quarter of 2021 compared to 2020, primarily due to lower electricity sales revenue at MidAmerican Energy Services, LLC, from lower volumes offset by favorable pricing.

Earnings decreased $1,118 million for the third quarter of 2021 compared to 2020, primarily due to the $1,046 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $86 million of lower federal income tax credits recognized on a consolidated basis, $26 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 October 2020 and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by lower other corporate costs and higher earnings of $18 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts.

Operating revenue increased $82 million for the first nine months of 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes.

Earnings decreased $1,050 million for the first nine months of 2021 compared to 2020, primarily due to the $891 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $101 million of dividends on BHE's 4.00% Perpetual Preferred Stock, $44 million of lower federal income tax credits recognized on a consolidated basis, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by higher earnings of $30 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts, and favorable changes in the cash surrender value of corporate-owned life insurance policies.

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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 September 30, 2021, the Company's total net liquidity was as follows (in millions):
MidAmericanNVNorthernBHE
BHEPacifiCorpFundingEnergyPowergridCanadaOtherTotal
Cash and cash equivalents$300 $893 $542 $99 $14 $72 $789 $2,709 
Credit facilities(1)
3,500 1,200 1,509 650 204 848 3,450 11,361 
Less:
Short-term debt— — — (127)(68)(230)(1,543)(1,968)
Tax-exempt bond support and letters of credit— (218)(370)— — (1)— (589)
Net credit facilities3,500 982 1,139 523 136 617 1,907 8,804 
Total net liquidity$3,800 $1,875 $1,681 $622 $150 $689 $2,696 $11,513 
Credit facilities:
Maturity dates202420242022, 2024202420232022, 20252022, 2026

(1)    Includes drawn uncommitted credit facilities totaling $1 million at Northern Powergrid Holdings.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020 were $7.0 billion and $4.5 billion, respectively. The increase was primarily due to $886 million of incremental net cash flows from operating activities at BHE GT&S, improved operating results, changes in working capital and favorable income tax cash flows.

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 nine-month periods ended September 30, 2021 and 2020 were $(3.5) billion and $(6.6) billion, respectively. The change was primarily due to lower funding of tax equity investments and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2021 was $(2.0) billion. Uses of cash totaled $4.0 billion and consisted mainly of preferred stock redemptions totaling $1.5 billion, repayments of subsidiary debt totaling $1.3 billion, repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $366 million and net repayments of short-term debt totaling $316 million. Sources of cash totaled $2.0 billion and consisted of proceeds from subsidiary debt issuances.
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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 nine-month period ended September 30, 2020 was $2.9 billion. Sources of cash totaled $5.9 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.6 billion. Uses of cash totaled $2.9 billion and consisted mainly of repayments of subsidiary debt totaling $1.6 billion, net repayments of short-term debt totaling $815 million, repayments of BHE senior debt totaling $350 million and common stock repurchases totaling $126 million.

Debt Repurchases

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.

Preferred Stock Redemptions

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

Common Stock Transactions

For the nine-month period ended September 30, 2020, BHE repurchased 180,358 shares of its common stock for $126 million.

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.

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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):
Nine-Month PeriodsAnnual
Ended September 30,Forecast
202020212021
Capital expenditures by business:
PacifiCorp$1,618 $1,157 $1,558 
MidAmerican Funding1,341 1,266 1,943 
NV Energy509 519 829 
Northern Powergrid492 564 748 
BHE Pipeline Group428 684 1,262 
BHE Transmission276 234 268 
BHE Renewables46 129 166 
HomeServices21 29 42 
BHE and Other(1)
(124)12 27 
Total$4,607 $4,594 $6,843 
Capital expenditures by type:
Wind generation$1,388 $872 $1,122 
Electric distribution1,182 1,217 1,745 
Electric transmission745 539 845 
Natural gas transmission and storage385 647 1,097 
Solar generation104 218 
Other905 1,215 1,816 
Total$4,607 $4,594 $6,843 
(1)BHE and Other represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.

The Company's historical and forecast capital expenditures consisted mainly of the following:
Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $275 million and $676 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $73 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.
Repowering of wind-powered generating facilities at MidAmerican Energy totaling $274 million and $25 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the repowering of wind-powered generating facilities totals $101 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 892 MWs of current repowering projects not in-service as of September 30, 2021, 591 MWs are currently expected to qualify for 80% of the PTCs available for 10 years following each facility's return to service and 301 MWs are expected to qualify for 60% of such credits.
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Construction of wind-powered generating facilities at PacifiCorp totaling $99 million and $705 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in service in the first nine months of 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. Planned spending for the construction of additional wind-powered generating facilities totals $17 million for the remainder of 2021.
Repowering of wind-powered generating facilities at PacifiCorp totaling $9 million and $99 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first nine months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned spending for the repowering of wind-powered generating facilities totals $7 million for the remainder of 2021.
Construction of wind-powered generating facilities at BHE Renewables totaling $75 million for the nine-month period ended September 30, 2021. In May 2021, BHE Renewables completed the asset acquisition of a 54 MW wind-powered generating facility located in Iowa. BHE Renewables anticipates costs to complete construction of this facility will total an additional $10 million in 2021.
Electric distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, storm damage restoration and repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for PacifiCorp's 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 spending for system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for asset modernization, pipeline integrity projects and natural gas transmission, storage and liquefied natural gas terminalling infrastructure needs to serve existing and expected demand.
Solar generation includes growth expenditures, including MidAmerican Energy's current plan for the construction of 141 MWs of small- and utility-scale solar generation during 2021, of which 61 MWs are expected to be placed in-service in 2021. Nevada Power's solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility. Commercial operation at Dry Lake is expected by the end of 2023.
Other capital expenditures includes both growth and operating expenditures, including spending for routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.


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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 nine-month period ended September 30, 2021, and has commitments as of September 30, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $766 million for the remainder of 2021 and $414 million in 2022 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. However, the Company expects to assign its rights and obligations under these equity capital contribution agreements, including any related funding commitments, to an entity affiliated through common ownership. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.

Contractual Obligations

As of September 30, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of 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 state 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 expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year in May 2021. 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. A number of parties, including Exelon, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.

As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that auction.

At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions at the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to Quad Cities Station. A request for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms was filed on October 5, 2021, and remains pending.

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Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.

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 Energy Balancing Account 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.

In March 2021, PacifiCorp filed its annual Energy Balancing Account application with the UPSC requesting recovery of $2 million of deferred net power costs from customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflected a $36 million reduction, or 1.7% decrease compared to current rates. In June 2021, PacifiCorp updated the requested recovery to $7 million to correct certain load related data reflected in the initial application. The updated recovery request reflects a $31 million reduction, or 1.5% decrease compared to current rates.

In August 2021, PacifiCorp filed an application with the UPSC for alternative cost recovery of a major plant addition to recover the incremental revenue requirement related to the delayed portions of the Pryor Mountain and TB Flats wind-powered generating facilities that are not currently reflected in rates from the last general rate case. PacifiCorp's request would result in a net decrease of $4 million, or 0.2%, in base rates effective January 1, 2022. Requested recovery of $7 million for the capital-related cost is offset by $7 million related to forecast PTCs and $4 million in net power cost savings with actual PTCs and net power cost savings to be trued-up in the Energy Balancing Account. A hearing has been scheduled beginning November 2021.

In August 2021, PacifiCorp filed an application with the UPSC for approval of its Electric Vehicle Infrastructure Program, as provided for by Utah House Bill 396 ("HB 396"), Electric Vehicle Charging Infrastructure Amendments. The filing details how PacifiCorp proposes to invest the $50 million authorized by HB 396 to support the development of electric vehicle infrastructure in Utah. The application also requests approval of a surcharge to collect $5 million per year for 10 years. The proposed surcharge would replace the existing Sustainable Transportation and Energy Plan cost adjustment that will expire on December 31, 2021. PacifiCorp's request would result in a decrease of $5 million, or 0.2%, compared to current rates effective January 1, 2022.

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-powered generating facilities, new wind-powered generating facilities and certain other new investments that had not been placed in service at the time of the filing. Additional compliance filings have been made to include investments in rates concurrent with when they were placed in service. In January 2021, the OPUC approved the second compliance filing to add the remainder of the Ekola Flats wind-powered generating facility to rates, resulting in a rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2021, the OPUC approved the third compliance filing to add the Foote Creek repowered wind-powered generating facility and the Pryor Mountain new wind-powered generating facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021. In July 2021, a deferral for resources not placed in service by June 30, 2021 was filed for consideration in a future rate proceeding.

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

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 was held in July 2021. In September 2021, the WPSC approved PacifiCorp's application to defer depreciation expense incurred from January 1, 2021 through June 30, 2021, subject to certain offsetting cost savings during the relevant period. The WPSC will address recovery of the deferred costs in a future general rate case.

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. In May 2021, the WPSC approved a $7 million base revenue requirement increase that includes the Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs and rate design proposals to be offset by returning the remaining 2017 Tax Reform benefits to customers over the next three years. The WPSC also approved revisions to the ECAM to adjust the sharing band from 70/30 to 80/20 and to include PTCs within the mechanism. PacifiCorp's proposals for extended recovery of the depreciation of certain coal-fueled generation units and use of remaining 2017 Tax Reform benefits to buy down certain plant balances were denied. The WPSC decision results in an overall net decrease of 3.5% with a rate effective date of July 1, 2021. A final written order was issued in July 2021.

In April 2021, PacifiCorp filed its annual ECAM and REC and Sulfur Dioxide Revenue Adjustment Mechanism 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 requested an interim rate effective July 1, 2021, which was approved by the WPSC in June 2021. PacifiCorp filed an all-party stipulation in October 2021. A hearing on the stipulation was held in November 2021.
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Washington

In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. The proposed $13 million, or 3.7%, rate increase has a requested effective date of January 1, 2022. In November 2021, PacifiCorp reached a proposed settlement with most of the parties, which includes an agreement to adjust the PTC rate in base rates and apply a production factor and to include a net power cost update as part of the compliance filing. A hearing in this matter is scheduled for January 2022 with rates becoming effective after an order is issued.

Idaho

In March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $14 million for deferred costs in 2020, a 1.1% decrease compared to current rates. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, changes in 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. In May 2021, PacifiCorp updated the requested recovery to correct for certain load related data reflected in the initial application, and the IPUC approved recovery of $10 million for deferred costs, a 2.5% decrease compared to current rates, effective June 1, 2021.

In May 2021, PacifiCorp filed a general rate case with the IPUC requesting a $19 million, or 7.0%, revenue requirement increase effective January 1, 2022. This is the first general rate case PacifiCorp has filed in Idaho since 2011. The rate case includes recovery of Energy Vision 2020 investments, the Pryor Mountain wind-powered generating facility, repowered Foote Creek, new investment in transmission, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested recovery of the decommissioning and closure costs associated with the early retirement of Cholla Unit 4. PacifiCorp filed an all-party settlement with the IPUC in October 2021, resolving all issues in the case. The settlement provides an $8 million, or 2.9%, overall increase, which will be offset in part by a refund of deferred income tax savings over two years, resulting in a net increase of $4 million, or 1.4%. A hearing on the settlement has been scheduled for November 2021 for rates to be effective January 1, 2022.

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 for which it received approval in July 2021.

In August 2020, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application includes a $7 million, or 6.7% decrease in energy costs, which is largely attributed to PTCs for new and repowered Energy Vision 2020 resources, and an increase of $1 million, or 0.8%, to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. In March 2021, the CPUC approved the rate change related to GHG allowances and in November 2021, approved updated rates for energy costs as filed.

In August 2021, PacifiCorp filed an application with the CPUC to address California energy costs and GHG allowance costs. The application includes a $5 million rate decrease associated with lower energy costs, partially offset by an increase of $3 million to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. PacifiCorp's application would result in a rate decrease of $2 million, or 1.9%, effective January 1, 2022. As of November 2021, the CPUC has not set a procedural schedule for this application.

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. In July 2021, PacifiCorp filed its answer to the FERC's show cause order denying the alleged violation of certain NERC reliability standards. The FERC Office of Enforcement staff replied in September 2021. A decision by the FERC is pending.
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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 customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the nine-month period ended September 30, 2021.

Renewable Subscription Program

In December 2020, MidAmerican Energy filed with the IUB a proposed Renewable Subscription Program ("RSP") tariff. As proposed, the program would provide qualified industrial customers with the opportunity to meet their future energy growth above baseline levels with renewable energy from specific MidAmerican Energy wind-powered generation additions and 100 MWs of planned solar generation for 20 years at fixed prices based on the cost of such facilities. Under the program, MidAmerican Energy would own the facilities, retain PTCs and other tax benefits associated with the facilities and include all revenues and costs from the program in its Iowa-jurisdictional results of operation, but renewable attributes from the project would be specifically assigned to subscribing customers. In June 2021, the IUB rejected the proposed RSP tariff. In a separate docket, the IUB ordered the exclusion from MidAmerican Energy's energy adjustment clause all PTCs and energy benefits associated with projects addressed in the RSP, resulting in MidAmerican Energy retaining such benefits.

NV Energy (Nevada Power and Sierra Pacific)

Price Stability Tariff

In November 2018, the Nevada Utilities made filings with the PUCN to implement the CPST. The Nevada Utilities have designed the CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of 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 Deferred Energy Accounting Adjustment. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available 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 with the PUCN. The enrollment period for the tariff has ended with no customers having enrolled. A final order has not been issued but because no customers have enrolled the order may be dismissed or withdrawn and the tariff will not go into effect. A final order is expected in 2021.

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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 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. A hearing related to the application for approval of the first amendment to the 2020 natural disaster protection plan was held in June 2021. The Nevada Utilities filed a partial party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial party stipulation and other intervenors filed legal briefs. The partial party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate for cost recovery. In July 2021, a hearing was held regarding the recovery of the 2020 costs held in a regulatory asset account and the cost recovery mechanism. In September 2021, the PUCN issued an order, approving the recovery of the 2020 costs with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management costs were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate for operating costs and a service territory specific rate for capital costs. In September 2021, the Nevada Utilities and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. The PUCN will reexamine the record and issue a modified order or reaffirm its original order with the outcome expected in the fourth quarter of 2021.

Senate Bill 448 ("SB 448")

SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission development, renewable energy and storage within the state of Nevada and requires the Nevada Utilities to submit a plan to accelerate transportation electrification in the state and file a plan for certain high-voltage transmission infrastructure projects. SB 448 requires the Nevada Utilities to amend its most recently filed resource plan to include a plan for certain high-voltage transmission infrastructure construction projects that will be placed into service not later than December 31, 2028 and requires the IRP to include at least one scenario of low carbon dioxide emissions that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. SB 448 also requires the Nevada Utilities, on or before September 1, 2021, to file a plan to invest in certain transportation electrification programs during the period beginning January 1, 2022, and ending on December 31, 2024, and establishes requirements for the contents of the transportation electrification investment plan for that period. It also establishes requirements for the review and the acceptance or modification of the transportation electrification investment plan by the PUCN. In September 2021, the Nevada Utilities filed an application for the approval of their Economic Recovery Transportation Electrification Plan to accelerate transportation electrification in the state of Nevada. In addition, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of their Transmission Infrastructure for a Clean Energy Economy Plan that sets forth a plan for the construction of certain high-voltage transmission infrastructure. The PUCN opened rulemakings to address the regulations in SB 448.

ON Line Temporary Rider ("ONTR")

In October 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR and corresponding updates to its electric rate tariffs to authorize recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being accumulated as a result of the ON Line cost reallocation and the on-going reallocated revenue requirement. Sierra Pacific's application would, if approved by the PUCN as filed, result in a one-time rate increase of $28 million to be collected over a nine-month period starting on April 1, 2022.

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Northern Powergrid Distribution Companies

In December 2020, GEMA, through Ofgem, published its final determinations for transmission and gas distribution networks in Great Britain. Regarding the allowed return on capital, Ofgem determined a cost of equity of 4.55% (plus inflation calculated using the United Kingdom's consumer price index including owner occupiers' housing costs ("CPIH")). In March 2021, all the transmission and gas distribution networks lodged appeals with the Competition and Markets Authority against Ofgem's determination for the cost of equity. In August 2021, the Competition and Markets Authority published a provisional determination that proposed to uphold the 4.55% cost of equity, which was confirmed in their final determination in October 2021. 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.

In December 2020, GEMA published its decision on the methodology it will use to set the next electricity distribution price control, ED2, and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution, and that the financial aspects in respect of electricity distribution would broadly follow the transmission and gas distribution methodology, setting a 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.

In July 2021, Northern Powergrid submitted and published its draft business plan for April 2023 to March 2028. If adopted, this plan would involve annual capital and operating expenditures of £642 million, an increase relative to the £471 million average annual capital and operating expenditures expected over the current price control period (April 2015 to March 2023). A final business plan submission for 2023-2028 will be submitted in December 2021, ahead of GEMA's draft and final determinations which are expected around June and December 2022, respectively. A new price control can be implemented by GEMA without the consent of the licensee but, if a licensee disagrees with the decision, it can appeal the matter to the United Kingdom's Competition and Markets Authority. In general terms, an appeal may also be sought by another licensee whose interests are materially affected by the decision, a trade association that represents a licensee and Citizens Advice, as the representative of consumers whose interests are materially affected by the decision.

BHE Pipeline Group

BHE GT&S

In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022 subject to refund and the outcome of hearing procedures. This matter is pending.

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.

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BHE Transmission

AltaLink

Tariff Refund Application

In January 2021, driven by the pandemic and economic shutdown that 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 consisted of a proposed refund to customers of C$150 million of previously collected future income taxes and C$200 million of surplus accumulated depreciation.

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

In April 2021, the AUC confirmed its approval of AltaLink's customer tariff refund as provided in the decision issued in March 2021 and detailed its reasons for the decision. Specifically, the AUC found that the exceptional circumstances faced by Alberta customers in 2021 brought to bear an unprecedented need for rate relief that has not existed previously. These exceptional circumstances included the current economic downturn due to COVID-19, the collapse in the world price of oil and the resulting significant negative impact to Albertans and businesses. As a result, immediate and temporary relief was warranted.

2019-2021 General Tariff Application

In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposed to provide 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.

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.

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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 by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year over year increase of approximately 2% in 2022 and 2023 revenue requirements. In addition, similar to the C$80 million refund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further similar tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively.

In September 2021, AltaLink provided responses to information requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates. The amended application requested the approval of transmission tariffs of C$820 million and C$843 million for 2022 and 2023, respectively. Oral argument and reply argument were completed in a hearing in October 2021. A decision from the AUC is expected in January 2022.

2022 Generic Cost of Capital Proceeding

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

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

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

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

In August 2021, the AUC denied the Utilities Consumer Advocate's application for review and variance of its decision that extended the approved 2020 and 2021 return on equity of 8.5% and equity ratio of 37% to 2022. In September 2021, the Alberta Court of Appeal heard the Utilities Consumer Advocate's permission to appeal application. In October 2021, the Alberta Court of Appeal issued its judgement dismissing the Utilities Consumer Advocate's application for leave to appeal the AUC decision setting final rates for 2022.

2019 Deferral Accounts Reconciliation Application

In October 2020, AltaLink filed its application with the AUC, which includes 10 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 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. In May 2021, the AUC issued its decision approving the compliance filing application as filed.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other 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 goals of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius and reaching a global peak of greenhouse gas emissions as soon as possible to achieve climate neutrality by mid-century; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021, President Biden announced new climate goals to cut GHG 50%-52% economy-wide by 2030 compared to 2005 levels and to reach 100% carbon pollution-free electricity by 2035. Additional details on how the United States will implement these goals is anticipated to be released through fall 2021.
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Regional and State Activities

Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant and include:
On July 27, 2021, the governor of Oregon signed House Bill 2021, which requires utilities to reduce GHG emissions to meet certain clean energy targets. The bill sets a baseline of the average of 2010, 2011, and 2012 emissions and requires utilities to meet the following reductions from that baseline: 80% by 2030, 90% by 2035 and 100% by 2040. No earlier than January 1, 2022, PacifiCorp must file a clean energy plan with the OPUC showing how it will meet the clean energy targets.
On May 17, 2021, the state of Washington passed the Climate Commitment Act (Senate Bill 5126), which creates an economy-wide cap-and-trade program to reduce GHG emissions. Under the Climate Commitment Act, the Washington Department of Ecology must establish progressively declining annual allowance budgets for emissions of GHG beginning January 1, 2023. PacifiCorp is subject to the Climate Commitment Act as an importer and generator of electricity in Washington.

Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which 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 are described below.

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. The 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. 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.
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New Source Performance Standards for Methane Emissions

In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. The rule was immediately challenged by environmental and tribal groups, as wells as numerous states. In January 2021, the D.C. Circuit lifted an administrative stay and allowed the rule to take effect, finding that groups challenging the rule had not met the standard for a long-term stay. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution has the effect of reinstating the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA released proposed rules in response to Executive Order 13990. The November 2021 proposed rule would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposal would expand and strengthen emissions reduction requirements for new, modified and reconstructed oil and natural gas sources, and would require states to reduce methane emissions from existing sources nationwide. The EPA intends to issue a supplemental proposal in 2022 and to finalize the rule by the end of 2022. Until the rule is finalized, the relevant Registrants cannot determine the full impacts of the proposed rule.

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 or 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.

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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.

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

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. The EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a FIP requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval at the end of 2019. In January 2020, the 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.
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Water Quality Standards

In April 2014, the EPA and the United States Army Corps of Engineers ("Corps of Engineers") issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule came as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but was appealed in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule, which was finalized September 12, 2019. On January 22, 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extension of the compliance deadline. On December 11, 2018, the EPA and the Corps of Engineers proposed a revised definition of "waters of the United States" that is intended to further clarify jurisdictional questions, eliminate case-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in Rapanos v. United States. On January 23, 2020, the EPA and the Corps of Engineers signed the final rule narrowing the federal government's permitting authority under the Clean Water Act. The new Navigable Waters Protection Rule, redefines what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction. Under the new rule, the Clean Water Act is considered to cover territorial seas and traditional navigable waters; tributaries that flow into jurisdictional waters; wetlands that are directly adjacent to jurisdictional waters; and lakes, ponds and impoundments of jurisdictional waters. On June 9, 2021, the EPA and the Corps of Engineers announced their intention to again revise the definition of "waters of the United States." After reviewing the Navigable Waters Protection Rule in accordance with Executive Order 13990, the agencies determined that the rule significantly reduced clean water protections. The agencies announced their intention to restore the clean water protections that were in place prior to the implementation of the "waters of the United States" rule in 2015. On August 30, 2021, the United States District Court for the District of Arizona vacated the Navigable Waters Protection Rule and the agencies quickly announced that they would no longer implement the rule nationwide. As a result, the agencies are relying on the pre-2015 regulatory definition of "waters of the United States" until they promulgate a new definition. Projects that are already permitted under the Navigable Waters Protection Rule and those that received an approved jurisdictional determination in reliance on the rule may continue to rely on those authorizations until they expire. Until the agencies take final action to update the definition of "waters of the United States," impacts to the relevant Registrants cannot be determined.

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.

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PacifiCorp and its subsidiaries
Consolidated Financial Section

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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 September 30, 2021, the related consolidated statements of operations and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 2021 and 2020, and of cash flows for the nine-month periods ended September 30, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of 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
November 5, 2021

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

 As of
 September 30,December 31,
20212020
ASSETS
Current assets:
Cash and cash equivalents$893 $13 
Trade receivables, net732 703 
Other receivables, net41 48 
Inventories465 482 
Derivative contracts153 27 
Regulatory assets70 116 
Prepaid expenses89 79 
Other current assets24 55 
Total current assets2,467 1,523 
 
Property, plant and equipment, net22,748 22,430 
Regulatory assets1,326 1,279 
Other assets530 470 
 
Total assets$27,071 $25,702 

The accompanying notes are an integral part of these consolidated financial statements.
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PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

 As of
 September 30,December 31,
20212020
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable$624 $772 
Accrued interest115 127 
Accrued property, income and other taxes159 80 
Accrued employee expenses117 84 
Short-term debt— 93 
Current portion of long-term debt574 420 
Regulatory liabilities112 115 
Other current liabilities241 174 
Total current liabilities1,942 1,865 
 
Long-term debt8,625 8,192 
Regulatory liabilities2,759 2,727 
Deferred income taxes2,781 2,627 
Other long-term liabilities1,064 1,118 
Total liabilities17,171 16,529 
 
Commitments and contingencies (Note 9)00
 
Shareholders' equity:
Preferred stock
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding— — 
Additional paid-in capital4,479 4,479 
Retained earnings5,437 4,711 
Accumulated other comprehensive loss, net(18)(19)
Total shareholders' equity9,900 9,173 
 
Total liabilities and shareholders' equity$27,071 $25,702 

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

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

 Three-Month PeriodsNine-Month Periods
 Ended September 30,Ended September 30,
 2021202020212020
 
Operating revenue$1,491 $1,479 $4,031 $3,829 
   
Operating expenses:
Cost of fuel and energy505 499 1,370 1,299 
Operations and maintenance267 332 781 829 
Depreciation and amortization272 234 811 696 
Property and other taxes54 53 158 154 
Total operating expenses1,098 1,118 3,120 2,978 
   
Operating income393 361 911 851 
   
Other income (expense):  
Interest expense(110)(107)(322)(319)
Allowance for borrowed funds14 18 36 
Allowance for equity funds13 29 38 73 
Interest and dividend income18 
Other, net(5)
Total other income (expense)(89)(57)(243)(193)
   
Income before income tax (benefit) expense304 304 668 658 
Income tax (benefit) expense(28)18 (58)30 
Net income$332 $286 $726 $628 

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

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

 Accumulated 
   Additional OtherTotal
PreferredCommonPaid-inRetainedComprehensiveShareholders'
 StockStockCapitalEarningsLoss, NetEquity
 
Balance, June 30, 2020$$— $4,479 $4,314 $(15)$8,780 
Net income— — — 286 — 286 
Balance, September 30, 2020$$— $4,479 $4,600 $(15)$9,066 
Balance, December 31, 2019$$— $4,479 $3,972 $(16)$8,437 
Net income— — — 628 — 628 
Other comprehensive income— — — — 
Balance, September 30, 2020$$— $4,479 $4,600 $(15)$9,066 
       
Balance, June 30, 2021$$— $4,479 $5,105 $(19)$9,567 
Net income— — — 332 — 332 
Other comprehensive income— — — — 
Balance, September 30, 2021$$— $4,479 $5,437 $(18)$9,900 
Balance, December 31, 2020$$— $4,479 $4,711 $(19)$9,173 
Net income— — — 726 — 726 
Other comprehensive income— — — — 
Balance, September 30, 2021$$— $4,479 $5,437 $(18)$9,900 

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

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

 Nine-Month Periods
 Ended September 30,
 20212020
Cash flows from operating activities: 
Net income$726  $628 
Adjustments to reconcile net income to net cash flows from operating activities: 
Depreciation and amortization811  696 
Allowance for equity funds(38)(73)
Changes in regulatory assets and liabilities(185) (17)
Deferred income taxes and amortization of investment tax credits33  (48)
Other, net— 
Changes in other operating assets and liabilities:  
Trade receivables, other receivables and other assets(1) (150)
Inventories17  (97)
Derivative collateral, net19  22 
Prepaid expenses(11)(4)
Accrued property, income and other taxes, net96 84 
Accounts payable and other liabilities77  248 
Net cash flows from operating activities1,544  1,291 
   
Cash flows from investing activities:  
Capital expenditures(1,157) (1,618)
Other, net 31 
Net cash flows from investing activities(1,150) (1,587)
   
Cash flows from financing activities:  
Proceeds from long-term debt984 987 
Repayments of long-term debt(400)— 
Repayments of short-term debt(93)(130)
Other, net(5)— 
Net cash flows from financing activities486  857 
   
Net change in cash and cash equivalents and restricted cash and cash equivalents880  561 
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$899  $597 
 
The accompanying notes are an integral part of these consolidated financial statements.

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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 September 30, 2021 and for the three- and nine-month periods ended September 30, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 2021 and 2020. The results of operations for the three- and nine-month periods ended September 30, 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 nine-month period ended September 30, 2021.

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

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
As of
September 30,December 31,
20212020
Cash and cash equivalents$893 $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$899 $19 

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(3)    Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
  As of
 September 30,December 31,
Depreciable Life20212020
Utility Plant: 
Generation15 - 59 years$13,635 $12,861 
Transmission60 - 90 years7,833 7,632 
Distribution20 - 75 years7,889 7,660 
Intangible plant(1)
5 - 75 years1,083 1,054 
Other5 - 60 years1,535 1,510 
Utility plant in service31,975 30,717 
Accumulated depreciation and amortization (10,370)(9,838)
Utility plant in service, net 21,605 20,879 
Other non-regulated, net of accumulated depreciation and amortization14 - 95 years
Plant, net21,614 20,888 
Construction work-in-progress 1,134 1,542 
Property, plant and equipment, net $22,748 $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 $38 million for the three-month period ended September 30, 2021 as compared to the three-month period ended September 30, 2020, and $120 million for the nine-month period ended September 30, 2021 compared to the nine-month period ended September 30, 2020 based on historical property, plant and equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.

(4)    Recent Financing Transactions

Long-term Debt

In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.

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

Credit Facilities

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

Common Shareholder's Equity

In October 2021, PacifiCorp declared a common stock dividend of $150 million, payable in November 2021, to PPW Holdings LLC.
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(5)    Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax (benefit) expense is as follows:
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Federal statutory income tax rate21 %21 %21 %21 %
State income tax, net of federal income tax benefit
Federal income tax credits(20)(15)(20)(12)
Effects of ratemaking(13)(4)(14)(8)
Other(1)— 
Effective income tax rate(9)%%(9)%%

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

Effects of ratemaking for the three- and nine-month periods ended September 30, 2021, and 2020 is primarily attributable to activity associated with excess deferred income taxes. Excess deferred income tax amortization, net of deferrals, was $89 million for the nine-month period ended September 30, 2021, including the use of $3 million to amortize certain regulatory asset balances in Wyoming, as compared to $41 million for the nine-month period ended September 30, 2020, including the use of $30 million to accelerate depreciation of certain retired equipment in Oregon. Excess deferred income tax amortization, net of deferrals, was $41 million for the three-month period ended September 30, 2021, as compared to $6 million for the three-month period ended September 30, 2020.

Berkshire Hathaway includes BHE and its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the nine-month period ended September 30, 2021 PacifiCorp received net cash payments for federal and state income tax from BHE totaling $109 million. For the nine-month period ended September 30, 2020 PacifiCorp made net cash payments for federal and state income tax to BHE totaling $79 million.

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(6)    Employee Benefit Plans

Net periodic benefit cost (credit) for the pension and other postretirement benefit plans included the following components (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Pension:
Service cost$— $— $— $— 
Interest cost22 27 
Expected return on plan assets(12)(14)(39)(42)
Settlement— — 
Net amortization15 13 
Net periodic benefit cost (credit)$$(1)$$(2)
Other postretirement:
Service cost$— $— $$
Interest cost
Expected return on plan assets(2)(3)(6)(10)
Net amortization— — 
Net periodic benefit (credit) cost$— $(1)$$(2)

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 September 30, 2021, $3 million of contributions had been made to the pension plans.

The amount of lump sum pension distributions in 2021 resulted in a July 31, 2021 remeasurement of the pension plan assets and projected benefit obligation. As a result of the remeasurement, PacifiCorp recognized a settlement loss of $4 million, net of regulatory deferrals. Additionally, the pension plan's underfunded status and regulatory asset each decreased by $84 million.

(7)    Risk Management and Hedging Activities

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

PacifiCorp has established a risk management process that is designed to identify, manage and report each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to 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 8 for additional information on derivative contracts.
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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 September 30, 2021
Not designated as hedging contracts(1):
Commodity assets$159 $40 $$$204 
Commodity liabilities— — (46)(9)(55)
Total159 40 (42)(8)149 
     
Total derivatives159 40 (42)(8)149 
Cash collateral (payable) receivable(6)— 11 — 
Total derivatives - net basis$153 $40 $(31)$(8)$154 
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 receivable— — 15 24 
Total derivatives - net basis$27 $$(7)$(19)$

(1)PacifiCorp's commodity derivatives are generally included in rates. As of September 30, 2021 a regulatory liability of $149 million was recorded related to the net derivative asset of $149 million. As of December 31, 2020 a regulatory asset of $17 million was recorded related to the net derivative liability of $17 million.

The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Beginning balance$(102)$68 $17 $62 
Changes in fair value(128)(49)(247)(21)
Net gains (losses) reclassified to operating revenue— (5)14 
Net gains (losses) reclassified to cost of fuel and energy81 (11)86 (46)
Ending balance$(149)$$(149)$

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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 ofSeptember 30,December 31,
Measure20212020
Electricity sales, netMegawatt hours— (1)
Natural gas purchasesDecatherms101 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 September 30, 2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $54 million and $51 million as of September 30, 2021 and December 31, 2020, respectively, for which PacifiCorp had posted collateral of $11 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 September 30, 2021 and December 31, 2020, PacifiCorp would have been required to post $36 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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(8)    Fair Value Measurements

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

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

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

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

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 September 30, 2021    
Assets:    
Commodity derivatives$— $204 $— $(11)$193 
Money market mutual funds876 — — — 876 
Investment funds31 — — — 31 
 $907 $204 $— $(11)$1,100 
Liabilities - Commodity derivatives$— $(55)$— $16 $(39)
As of December 31, 2020
Assets:
Commodity derivatives$— $36 $— $(3)$33 
Money market mutual funds— — — 
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 $5 million and $24 million as of September 30, 2021 and December 31, 2020, respectively.

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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 7 for further discussion regarding PacifiCorp's risk management and hedging activities.

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

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 September 30, 2021As of December 31, 2020
 CarryingFairCarryingFair
 ValueValueValueValue
     
Long-term debt$9,199 $11,005 $8,612 $10,995 

(9)    Commitments and Contingencies

Legal Matters

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

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    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 "2020 Wildfires"). The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. 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 September 30, 2021, PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.

Environmental Laws and Regulations

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.

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In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application by January 16, 2021, to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC and the States as co-licensees. The transfer will be effective after PacifiCorp secures property transfer approvals from its state public utility commissions and 30 days following the issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions approved the property transfer. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah.

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.

(10)    Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
Three-Month PeriodsNine-Month Periods
Ended September 30,Ended September 30,
2021202020212020
Customer Revenue:
Retail:
Residential$530 $519 $1,442 $1,363 
Commercial428 418 1,180 1,122 
Industrial296 293 849 838 
Other retail98 114 214 209 
Total retail1,352 1,344 3,685 3,532 
Wholesale
58 59 124 76 
Transmission55 33 117 79 
Other Customer Revenue26 42 80 88 
Total Customer Revenue1,491 1,478 4,006 3,775 
Other revenue— 25 54 
Total operating revenue$1,491 $1,479 $4,031 $3,829 

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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 Third Quarter and First Nine Months of 2021 and 2020

Overview

Net income for the third quarter of 2021 was $332 million, an increase of $46 million, or 16%, compared to 2020. Net income increased primarily due to lower operations and maintenance expense of $65 million, primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires, lower income tax expense of $46 million primarily due to the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and higher utility margin of $6 million, partially offset by higher depreciation and amortization expense of $38 million, including the impacts of the depreciation study for which rates became effective January 2021, and lower allowances for equity and borrowed funds used during construction of $24 million. Utility margin increased primarily due to higher retail and wheeling revenue, higher deferred net power costs in accordance with established adjustment mechanisms, lower purchased electricity volumes and higher REC revenue, partially offset by higher purchased electricity prices, thermal generation costs, and wheeling expenses. Retail customer volumes increased 2.1%, primarily due to an increase in the average number of customers and higher customer usage. Energy generated increased 9% for the third quarter 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 4% and purchased electricity volumes decreased 16%.

Net income for the first nine months of 2021 was $726 million, an increase of $98 million, or 16%, compared to 2020. Net income increased primarily due to higher utility margin of $131 million, lower income tax expense of $118 million (excluding prior year impacts of the Oregon RAC settlement offset in depreciation expense), primarily from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, lower operations and maintenance expense of $48 million, primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires, partially offset by higher depreciation and amortization expense of $115 million, including the impacts of the depreciation study for which rates became effective January 2021, and lower allowances for equity and borrowed funds used during construction of $53 million. Utility margin increased primarily due to the higher retail, wholesale, and wheeling revenue, higher deferred net power costs in accordance with established adjustment mechanisms, lower purchased electricity volumes and higher REC revenue, partially offset by higher purchased electricity prices, thermal generation costs and wheeling expenses. Retail customer volumes increased 4.4%, primarily due to higher customer usage, an increase in the average number of customers, and favorable impacts of weather. Energy generated increased 14% for the first nine months of 2021 compared to 2020 primarily due to higher coal-fueled, wind-powered, and natural gas-fueled generation, partially offset by lower hydroelectric generation. Wholesale electricity sales volumes increased 20% and purchased electricity volumes decreased 16%.

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.

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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):
Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin:
Operating revenue$1,491 $1,479 $12 %$4,031 $3,829 $202 %
Cost of fuel and energy505 499 1,370 1,299 71 
Utility margin986 980 2,661 2,530 131 
Operations and maintenance267 332 (65)(20)781 829 (48)(6)
Depreciation and amortization272 234 38 16 811 696 115 17 
Property and other taxes54 53 158 154 
Operating income$393 $361 $32 %$911 $851 $60 %
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Utility Margin

A comparison of key operating results related to utility margin is as follows:
Third QuarterFirst Nine Months
20212020Change20212020Change
Utility margin (in millions):
Operating revenue$1,491 $1,479 $12 %$4,031 $3,829 $202 %
Cost of fuel and energy505 499 1,370 1,299 71 
Utility margin$986 $980 $%$2,661 $2,530 $131 %
Sales (GWhs):
Residential4,732 4,622 110 %13,396 12,699 697 %
Commercial5,078 4,799 279 14,181 13,157 1,024 
Industrial, irrigation and other5,375 5,446 (71)(1)14,976 14,907 69 — 
Total retail15,185 14,867 318 42,553 40,763 1,790 
Wholesale1,093 1,053 40 3,928 3,266 662 20 
Total sales16,278 15,920 358 %46,481 44,029 2,452 %
Average number of retail customers
 (in thousands)
2,006 1,971 35 %1,998 1,963 35 %
Average revenue per MWh:
Retail$88.91 $90.25 $(1.34)(1)%$86.53 $86.60 $(0.07)— %
Wholesale$53.45 $57.54 $(4.09)(7)%$37.23 $38.58 $(1.35)(3)%
Heating degree days196 194 %6,111 6,132 (21)— %
Cooling degree days1,681 1,658 23 %2,427 2,097 330 16 %
Sources of energy (GWhs)(1):
Coal9,011 8,576 435 %24,157 22,001 2,156 10 %
Natural gas3,886 3,638 248 10,174 8,881 1,293 15 
Hydroelectric(2)
380 414 (34)(8)1,981 2,351 (370)(16)
Wind and other(2)
1,323 720 603 84 4,534 2,696 1,838 68 
Total energy generated14,600 13,348 1,252 40,846 35,929 4,917 14 
Energy purchased3,058 3,621 (563)(16)9,407 11,245 (1,838)(16)
Total17,658 16,969 689 %50,253 47,174 3,079 %
Average cost of energy per MWh:
Energy generated(3)
$18.39 $18.65 $(0.26)(1)%$17.98 $17.95 $0.03 — %
Energy purchased$88.48 $53.28 $35.20 66 %$67.10 $45.85 $21.25 46 %

(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 September 30, 2021 compared to Quarter Ended September 30, 2020

Utility margin increased $6 million, or 1%, for the third quarter of 2021 compared to 2020 primarily due to:
$103 million of higher deferred net power costs in accordance with established adjustment mechanisms;
$12 million of favorable wheeling activities;
$8 million increase in retail revenue primarily due to higher customer volumes, partially offset by lower rates driven by certain general rate case orders. Retail customer volumes increased 2.1%, primarily due to an increase in the average number of customers, and higher customer usage, partially offset by the unfavorable impact of weather; and
$6 million of higher REC, fly ash and by-product revenues.
The increases above were partially offset by:
$80 million of higher purchased electricity costs from higher average market prices, partially offset by lower volumes;
$27 million of lower other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense) in the prior year;
$13 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes; and
$7 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.
Operations and maintenance decreased $65 million, or 20%, for the third quarter of 2021 compared to 2020 primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires and lower thermal plant maintenance expense, including overhauls, partially offset by higher wind plant and distribution maintenance.

Depreciation and amortization increased $38 million, or 16%, for the third quarter of 2021 compared to 2020 primarily due to the impacts of a depreciation study effective January 1, 2021 of approximately $38 million and higher plant in-service balances, partially offset by prior year accelerated depreciation of $27 million (offset in other revenue) due to the prior year Oregon RAC settlement.

Allowance for borrowed and equity funds decreased $24 million, or 56%, for the third quarter of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances.

Other, net decreased $10 million for the third quarter of 2021 compared to 2020 primarily due to the July 2021 pension settlement loss and market movements related to corporate-owned life insurance policies.

Income tax (benefit) expense decreased $46 million to a benefit of $28 million for the third quarter of 2021 compared to expense of $18 million for the third quarter of 2020. The effective tax rate was (9)% for 2021 and 6% for 2020. The effective tax rate decreased primarily as a result of higher effects of ratemaking associated with excess deferred income tax amortization in the current year and increased PTCs from PacifiCorp's new wind-powered generating facilities.

First Nine Months of 2021 compared to First Nine Months of 2020

Utility margin increased $131 million, or 5%, for the first nine months of 2021 compared to 2020 primarily due to:
$152 million increase in retail revenue primarily due to higher customer volumes, partially offset by lower rates driven by certain general rate case orders. Retail customer volumes increased 4.4%, primarily due to higher customer usage, an increase in the average number of customers, and the favorable impact of weather;
$151 million of higher deferred net power costs in accordance with established adjustment mechanisms;
$21 million of favorable wheeling activities;
$20 million of higher wholesale revenue due to higher wholesale volumes, partially offset by lower average wholesale market prices; and
$18 million of higher REC, fly ash and by-product revenues.
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The increases above were partially offset by:
$117 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes;
$58 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes;
$34 million of lower other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense) in the prior year; and
$33 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.
Operations and maintenance decreased $48 million, or 6%, for the first nine months of 2021 compared to 2020 primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires, lower thermal plant maintenance expense, including overhauls, and lower employee expenses, partially offset by higher wind plant and distribution maintenance and higher vegetation management costs.

Depreciation and amortization increased $115 million, or 17%, for the first nine months of 2021 compared to 2020 primarily due to the impacts of a depreciation study effective January 1, 2021 of approximately $120 million, and higher plant in-service balances, partially offset by a $71 million decrease due to the prior year Oregon RAC settlement ($3 million in the first quarter of 2021 (fully offset in other revenue) compared to $74 million in 2020 ($34 million offset in other revenue and $40 million offset in income tax expense)).

Allowance for borrowed and equity funds decreased $53 million, or 49%, for the first nine months of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances and allowance for borrowed and equity funds rates.

Income tax (benefit) expense decreased $88 million to a benefit of $58 million for the first nine months of 2021 compared to expense of $30 million the first nine months of 2020. The effective tax rate was (9)% for 2021 and 5% for 2020. The effective tax rate decreased primarily as a result of increased PTCs from PacifiCorp's new wind-powered generating facilities and as a result of higher effects of ratemaking associated with excess deferred income tax amortization in the current year.

Liquidity and Capital Resources

As of September 30, 2021, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents$893 
 
Credit facilities1,200 
Less:
Tax-exempt bond support(218)
Net credit facilities982 
 
Total net liquidity$1,875 
 
Credit facilities:
Maturity dates2024 
Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020 were $1,544 million and $1,291 million, respectively. The change was primarily due to higher collections from retail customers and higher cash received for income taxes, partially offset by higher wholesale purchases.

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

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Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020 were $(1,150) million and $(1,587) million, respectively. The change is primarily due to a decrease in capital expenditures of $461 million, partially offset by 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 nine-month period ended September 30, 2021 were $486 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $984 million. Uses of cash consisted substantially of $400 million for the repayment of long-term debt and $93 million for the repayment of short-term debt.

Net cash flows from financing activities for the nine-month period ended September 30, 2020 were $857 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $987 million. Uses of cash consisted of $130 million for the repayment of short-term debt.

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of September 30, 2021, PacifiCorp had no short-term debt outstanding. As of December 31, 2020, PacifiCorp had $93 million of short-term debt outstanding at a weighted average interest rate of 0.16%.    

Long-term Debt

In November 2021, PacifiCorp exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.95% Series First Mortgage Bonds that was originally due February 2022.

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

Debt Authorizations

Following the July 2021 long-term debt issuance, PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $2 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.

Common Shareholder's Equity

In October 2021, PacifiCorp declared a common stock dividend of $150 million, payable in November 2021, to PPW Holdings LLC.

Future Uses of Cash

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

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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):
Nine-Month PeriodsAnnual
Ended September 30,Forecast
202020212021
Wind generation$807 $110 $138 
Electric distribution360 461 637 
Electric transmission300 212 316 
Other151 374 467 
Total$1,618 $1,157 $1,558 

PacifiCorp's 2019 and 2021 IRP identified a significant increase in renewable resource generation and associated transmission. PacifiCorp has included an estimate for these new resources and associated transmission in its forecast capital expenditures for 2021 through 2023. These estimates may 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 $99 million and $705 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in service in the first nine months of 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. Planned spending for the construction of additional wind-powered generating facilities totals $17 million for the remainder of 2021.
Repowering of wind-powered generating facilities at PacifiCorp totaling $9 million and $99 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first nine months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned spending for the repowering of wind-powered generating facilities totals $7 million for the remainder of 2021.
Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes planned spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled $144 million and $21 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned electric distribution spending totals $51 million for the remainder of 2021 and relates to expenditures for new connections and distribution.

Electric transmission includes both growth projects and operating expenditures. Transmission investment through 2020 primarily reflects costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020. Planned spending for additional Energy Gateway Transmission segments to be placed in service in 2024-2026 totals $46 million in 2021.

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Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $69 million and $53 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned information technology spending totals $47 million for the remainder of 2021 and relates to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.

Energy Supply Planning

As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations.

In September 2021, PacifiCorp filed its 2021 IRP with its state commissions. The IRP includes investments in new renewable energy resources, new battery storage resources and expanded transmission investments. New renewable energy resources in the IRP include more than 1,800 MW of new wind-powered generation, over 2,100 MW of new solar-powered generation and nearly 700 MW of new battery storage capacity by 2025. The IRP also outlines PacifiCorp's plan to retire or convert to natural gas all coal-fueled resources by 2042.

Requests for Proposals

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

PacifiCorp issued the 2020 All Source RFP to the market in July 2020. The 2020 All Source RFP sought bids for resources capable of coming online by the end of 2024 up to the level of resources identified in PacifiCorp's 2019 IRP. An initial shortlist was identified in October 2020. The final shortlist of winning bids was submitted to OPUC in June 2021. PacifiCorp will initiate negotiations with shortlisted bids that include approximately 1,792 MWs of new wind capacity, 1,306 MWs of solar capacity and 697 MWs of battery storage to its portfolio by 2024. PacifiCorp expects that 590 MWs of the 1,792 MWs of new wind capacity will be owned with the remainder of the wind, solar and battery storage capacity being contracted resources.

Contractual Obligations

As of September 30, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2020.

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.

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

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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 September 30, 2021, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2021 and 2020, and of cash flows for the nine-month periods ended September 30, 2021 and 2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 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
November 5, 2021

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