0001081316us-gaap:AccumulatedOtherComprehensiveIncomeMemberbhe:PacificorpMember2020-01-012020-09-30PensionPlansDefinedBenefitMembercountry:USbhe:PacificorpMember2021-04-012021-06-300001081316us-gaap:EquityFundsMemberus-gaap:FairValueMeasurementsRecurringMemberbhe:SierraPacificPowerCompanyMemberus-gaap:FairValueInputsLevel1Member2021-12-31
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended SeptemberJune 30, 20212022
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 | | |
| Commission | | Address of principal executive offices | | IRS Employer |
| File Number | | Registrant's telephone number, including area code | | Identification 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 | | |
| | | | |
| 333-90553 | | MIDAMERICAN FUNDING, LLC | | 47-0819200 |
| | (An Iowa Limited Liability Company) | | |
| | 666 Grand Avenue | | |
| | Des Moines, Iowa 50309-2580 | | |
| | 515-242-4300 | | |
| | | | |
| 333-15387 | | MIDAMERICAN ENERGY COMPANY | | 42-1425214 |
| | (An Iowa Corporation) | | |
| | 666 Grand Avenue | | |
| | Des Moines, Iowa 50309-2580 | | |
| | 515-242-4300 | | |
| | | | |
| 000-52378 | | NEVADA POWER COMPANY | | 88-0420104 |
| | (A Nevada Corporation) | | |
| | 6226 West Sahara Avenue | | |
| | Las Vegas, Nevada 89146 | | |
| | 702-402-5000 | | |
| | | | |
| 000-00508 | | SIERRA PACIFIC POWER COMPANY | | 88-0044418 |
| | (A Nevada Corporation) | | |
| | 6100 Neil Road | | |
| | Reno, Nevada 89511 | | |
| | 775-834-4011 | | |
| | | | |
| 001-37591 | | EASTERN ENERGY GAS HOLDINGS, LLC | | 46-3639580 |
| | (A Virginia Limited Liability Company) | | |
| | 6603 West Broad Street | | |
| | Richmond, Virginia 23230 | | |
| | 804-613-5100 | | |
| | | | |
| | N/A | | |
| | (Former name or former address, if changed from last report) | | |
| | | | | |
| Registrant | Securities registered pursuant to Section 12(b) of the Act: |
| BERKSHIRE HATHAWAY ENERGY COMPANY | None |
| PACIFICORP | None |
| MIDAMERICAN FUNDING, LLC | None |
| MIDAMERICAN ENERGY COMPANY | None |
| NEVADA POWER COMPANY | None |
| SIERRA PACIFIC POWER COMPANY | None |
| EASTERN ENERGY GAS HOLDINGS, LLC | None |
| | | | | |
| Registrant | Name of exchange on which registered: |
| BERKSHIRE HATHAWAY ENERGY COMPANY | None |
| PACIFICORP | None |
| MIDAMERICAN FUNDING, LLC | None |
| MIDAMERICAN ENERGY COMPANY | None |
| NEVADA POWER COMPANY | None |
| SIERRA PACIFIC POWER COMPANY | None |
| EASTERN ENERGY GAS HOLDINGS, LLC | None |
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.
| | | | | | | | |
| Registrant | Yes | No |
| 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.
| | | | | | | | | | | | | | | | | |
| Registrant | Large accelerated filer | Accelerated filer | Non-accelerated filer | Smaller reporting company | Emerging 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 NovemberAugust 4, 2021, 76,368,8742022, 75,627,913 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 NovemberAugust 4, 2021,2022, 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 NovemberAugust 4, 2021.2022.
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 NovemberAugust 4, 2021,2022, 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 NovemberAugust 4, 2021,2022, 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 NovemberAugust 4, 2021,2022, 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 NovemberAugust 4, 2021.2022.
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
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.
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| Berkshire Hathaway Energy Company and Related Entities |
| BHE | | Berkshire Hathaway Energy Company |
| Berkshire Hathaway | | Berkshire Hathaway Inc. |
| Berkshire Hathaway Energy or the Company | | Berkshire Hathaway Energy Company and its subsidiaries |
| PacifiCorp | | PacifiCorp and its subsidiaries |
| MidAmerican Funding | | MidAmerican Funding, LLC and its subsidiaries |
| MidAmerican Energy | | MidAmerican Energy Company |
| NV Energy | | NV Energy, Inc. and its subsidiaries |
| Nevada Power | | Nevada Power Company and its subsidiaries |
| Sierra Pacific | | Sierra Pacific Power Company and its subsidiaries |
| Nevada Utilities | | Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries |
| Eastern Energy Gas | | Eastern Energy Gas Holdings, LLC and its subsidiaries |
| Registrants | | Berkshire Hathaway Energy Company, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries and Eastern Energy Gas Holdings, LLC and its subsidiaries |
| Northern Powergrid | | Northern Powergrid Holdings Company and its subsidiaries |
| BHE Pipeline Group | | BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company |
| BHE GT&S | | BHE GT&S, LLC and its subsidiaries |
| Northern Natural Gas | | Northern Natural Gas Company |
| Kern River | | Kern River Gas Transmission Company |
| BHE Transmission | | BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC |
| BHE Canada | | BHE Canada Holdings Corporation and its subsidiaries |
| AltaLink | | AltaLink, L.P. |
| BHE U.S. Transmission | | BHE U.S. Transmission, LLC and its subsidiaries |
| BHE Renewables | | BHE Renewables, LLC and CalEnergy Philippinesits subsidiaries |
| HomeServices | | HomeServices of America, Inc. and its subsidiaries |
| Utilities | | PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries |
Domestic Regulated Businesses | | PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company |
| EGTS | | Eastern Gas Transmission and Storage, Inc. |
GT&S Transaction | | The 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 |
DEI | | Dominion Energy, Inc. |
Questar Pipeline Group | | Dominion Energy Questar Pipeline, LLC and related entities |
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| Certain Industry Terms | | |
| 2017 Tax Reform | | The Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018 |
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| AFUDC | | Allowance for Funds Used During Construction |
| AUC | | Alberta Utilities Commission |
| BART | | Best Available Retrofit Technology |
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COVID-19 | | Coronavirus Disease 2019 |
CPST | | Customer Price Stability Tariff |
CPUC | | California Public Utilities Commission |
| CSAPR | | Cross-State Air Pollution Rule |
| D.C. Circuit | | United States Court of Appeals for the District of Columbia Circuit |
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| Dth | | Decatherm |
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ECAM | | Energy Cost Adjustment Mechanism |
| EPA | | United States Environmental Protection Agency |
| FERC | | Federal Energy Regulatory Commission |
| FIP | | Federal Implementation Plan |
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| GAAP | | Accounting principles generally accepted in the United States of America |
| GEMA | | Gas and Electricity Markets Authority |
GHG | | Greenhouse Gases |
| GTA | | General Tariff Application |
| GWh | | Gigawatt Hour |
IPUC | | Idaho Public Utilities Commission |
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| IRP | | Integrated Resource Plan |
| IUB | | Iowa Utilities Board |
| kV | | Kilovolt |
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| MW | | Megawatt |
| MWh | | Megawatt Hour |
| NAAQS | | National Ambient Air Quality Standards |
NOx | | Nitrogen Oxides |
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| Ofgem | | Office of Gas and Electric Markets |
| OPUC | | Oregon Public Utility Commission |
| PTC | | Production Tax Credit |
| PUCN | | Public Utilities Commission of Nevada |
RAC | | Renewable Adjustment Clause |
REC | | Renewable Energy Credit |
| RFP | | Request for ProposalProposals |
| RPS | | Renewable Portfolio Standards |
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| SCR | | Selective Catalytic Reduction |
| SEC | | United States Securities and Exchange Commission |
| SIP | | State Implementation Plan |
SO2 | | Sulfur Dioxide |
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| UPSC | | Utah Public Service Commission |
WPSC | | Wyoming Public Service Commission |
| WUTC | | Washington Utilities and Transportation Commission |
Forward-Looking Statements
This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:
•general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective Registrant's operations or related industries;
•changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;
•the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner;
•changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;
•performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to the impacts of market conditions, outages and associated repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions;
•the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, extreme temperature events, wind events, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars (including, for example, Russia's invasion of Ukraine in February 2022), terrorism, pandemics, (including potentially in relation to COVID-19), embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;
•the risks and uncertainties associated with wildfires that have occurred, are occurring or may occur in the respective Registrant's service territory, including the wildfires that began in September 2020 in Oregon and California, and any other wildfires for which the cause has yet to be determined; the damage caused by such wildfires; the extent of the respective Registrant's liability in connection with such wildfires (including the risk that the respective Registrant may be found liable for damages regardless of fault); investigations into such wildfires; the outcome of any legal proceedings initiated against the respective Registrant; the risk that the respective Registrant is not able to recover costs from insurance or through rates; and the effect on the respective Registrant's reputation of such wildfires, investigations and proceedings;
•the respective Registrant's ability to reduce wildfire threats and improve safety, including the ability to comply with the targets and metrics set forth in its wildfire mitigation plans; to retain or contract for the workforce necessary to execute its wildfire mitigation plans; the effectiveness of its system hardening; ability to achieve vegetation management targets; and the cost of these programs and the timing and outcome of any proceeding to recover such costs through rates;
•the ability to economically obtain insurance coverage, or any insurance coverage at all, sufficient to cover losses arising from catastrophic events, such as wildfires where the Registrants may be found liable for real and personal property damages regardless of fault;
•a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;
•changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;
•the financial condition, creditworthiness and operational stability of the respective Registrant's significant customers and suppliers;
•changes in business strategy or development plans;
•availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates;
•changes in the respective Registrant's credit ratings;
•risks relating to nuclear generation, including unique operational, closure and decommissioning risks;
•hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;
•the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;
•the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;
•fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;
•increases in employee healthcare costs;
•the impact of investment performance, certain participant elections such as lump sum distributions and changes in interest rates, legislation, healthcare cost trends, mortality, morbidity on pension and other postretirement benefits expense and funding requirements;
•changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and franchising transactions;
•the ability to successfully integrate the portion of the natural gas transmission and storage business acquired from DEI on November 1, 2020, and future acquired operations into a Registrant's business;
•the impact of supply chain disruptions and workforce availability on the respective Registrant's ongoing operations and its ability to timely complete construction projects;
•unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;
•the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;
•the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and
•other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.
Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the SEC, including Part II, Item 1A and other discussions contained in this Form 10-Q. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.
Item 1.Financial Statements
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| Berkshire Hathaway Energy Company and its subsidiaries | | |
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| PacifiCorp and its subsidiaries | | |
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| MidAmerican Energy Company | | |
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| MidAmerican Funding, LLC and its subsidiaries | | |
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| Nevada Power Company and its subsidiaries | | |
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| Sierra Pacific Power Company and its subsidiaries | | |
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| Eastern Energy Gas Holdings, LLC and its subsidiaries | | |
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Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
Berkshire Hathaway Energy Company and its subsidiaries
Consolidated Financial Section
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Berkshire Hathaway Energy Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of SeptemberJune 30, 2021,2022, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and of cash flows for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, 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, 2020,2021, 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, 2021,25, 2022, 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, 2020,2021, 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
NovemberAugust 5, 20212022
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | As of | | As of |
| | | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 2,709 | | | $ | 1,290 | | Cash and cash equivalents | $ | 2,081 | | | $ | 1,096 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 216 | | | 140 | | Restricted cash and cash equivalents | 201 | | | 127 | |
| Trade receivables, net | Trade receivables, net | 2,545 | | | 2,107 | | Trade receivables, net | 2,734 | | | 2,468 | |
| | Income tax receivable | | Income tax receivable | 25 | | | 344 | |
| Inventories | Inventories | 1,129 | | | 1,168 | | Inventories | 1,163 | | | 1,122 | |
| Mortgage loans held for sale | Mortgage loans held for sale | 1,687 | | | 2,001 | | Mortgage loans held for sale | 1,084 | | | 1,263 | |
| | | Regulatory assets | | Regulatory assets | 778 | | | 544 | |
| Other current assets | Other current assets | 2,142 | | | 2,741 | | Other current assets | 1,294 | | | 1,284 | |
| Total current assets | Total current assets | 10,428 | | | 9,447 | | Total current assets | 9,360 | | | 8,248 | |
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| Property, plant and equipment, net | Property, plant and equipment, net | 88,062 | | | 86,128 | | Property, plant and equipment, net | 90,795 | | | 89,816 | |
| Goodwill | Goodwill | 11,572 | | | 11,506 | | Goodwill | 11,559 | | | 11,650 | |
| Regulatory assets | Regulatory assets | 3,372 | | | 3,157 | | Regulatory assets | 3,481 | | | 3,419 | |
| Investments and restricted cash and cash equivalents and investments | 15,218 | | | 14,320 | | |
| Investments and restricted cash, cash equivalents and investments | | Investments and restricted cash, cash equivalents and investments | 16,728 | | | 15,788 | |
| Other assets | Other assets | 2,902 | | | 2,758 | | Other assets | 3,372 | | | 3,144 | |
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| Total assets | Total assets | $ | 131,554 | | | $ | 127,316 | | Total assets | $ | 135,295 | | | $ | 132,065 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | | As of | | As of |
| | | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 1,798 | | | $ | 1,867 | | Accounts payable | $ | 2,290 | | | $ | 2,136 | |
| Accrued interest | Accrued interest | 622 | | | 555 | | Accrued interest | 557 | | | 537 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 670 | | | 582 | | Accrued property, income and other taxes | 789 | | | 606 | |
| Accrued employee expenses | Accrued employee expenses | 556 | | | 383 | | Accrued employee expenses | 457 | | | 372 | |
| Short-term debt | Short-term debt | 1,968 | | | 2,286 | | Short-term debt | 1,948 | | | 2,009 | |
| Current portion of long-term debt | Current portion of long-term debt | 1,179 | | | 1,839 | | Current portion of long-term debt | 2,069 | | | 1,265 | |
| Other current liabilities | Other current liabilities | 2,054 | | | 1,626 | | Other current liabilities | 1,802 | | | 1,837 | |
| Total current liabilities | Total current liabilities | 8,847 | | | 9,138 | | Total current liabilities | 9,912 | | | 8,762 | |
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| BHE senior debt | BHE senior debt | 13,001 | | | 12,997 | | BHE senior debt | 13,594 | | | 13,003 | |
| BHE junior subordinated debentures | BHE junior subordinated debentures | 100 | | | 100 | | BHE junior subordinated debentures | 100 | | | 100 | |
| Subsidiary debt | Subsidiary debt | 35,818 | | | 34,930 | | Subsidiary debt | 35,354 | | | 35,394 | |
| Regulatory liabilities | Regulatory liabilities | 6,958 | | | 7,221 | | Regulatory liabilities | 7,028 | | | 6,960 | |
| Deferred income taxes | Deferred income taxes | 12,910 | | | 11,775 | | Deferred income taxes | 13,394 | | | 12,938 | |
| Other long-term liabilities | Other long-term liabilities | 4,304 | | | 4,178 | | Other long-term liabilities | 4,722 | | | 4,319 | |
| Total liabilities | Total liabilities | 81,938 | | | 80,339 | | Total liabilities | 84,104 | | | 81,476 | |
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| Commitments and contingencies (Note 9) | 0 | | 0 | |
| Commitments and contingencies (Note 8) | | Commitments and contingencies (Note 8) | 0 | | 0 |
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| Equity: | Equity: | | | | Equity: | | | |
| BHE shareholders' equity: | BHE shareholders' equity: | | | | BHE shareholders' equity: | | | |
| Preferred stock - 100 shares authorized, $0.01 par value, 2 and 4 shares issued and outstanding | 2,300 | | | 3,750 | | |
| Preferred stock - 100 shares authorized, $0.01 par value, 1 and 2 shares issued and outstanding | | Preferred stock - 100 shares authorized, $0.01 par value, 1 and 2 shares issued and outstanding | 850 | | | 1,650 | |
| Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding | Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding | — | | | — | | Common stock - 115 shares authorized, no par value, 76 shares issued and outstanding | — | | | — | |
| Additional paid-in capital | Additional paid-in capital | 6,374 | | | 6,377 | | Additional paid-in capital | 6,298 | | | 6,374 | |
| Long-term income tax receivable | Long-term income tax receivable | (658) | | | (658) | | Long-term income tax receivable | (744) | | | (744) | |
| Retained earnings | Retained earnings | 39,199 | | | 35,093 | | Retained earnings | 42,688 | | | 40,754 | |
| Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | (1,523) | | | (1,552) | | Accumulated other comprehensive loss, net | (1,788) | | | (1,340) | |
| Total BHE shareholders' equity | Total BHE shareholders' equity | 45,692 | | | 43,010 | | Total BHE shareholders' equity | 47,304 | | | 46,694 | |
| Noncontrolling interests | Noncontrolling interests | 3,924 | | | 3,967 | | Noncontrolling interests | 3,887 | | | 3,895 | |
| Total equity | Total equity | 49,616 | | | 46,977 | | Total equity | 51,191 | | | 50,589 | |
| | | | | | | | | |
| Total liabilities and equity | Total liabilities and equity | $ | 131,554 | | | $ | 127,316 | | Total liabilities and equity | $ | 135,295 | | | $ | 132,065 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | | | | |
| Energy | Energy | $ | 5,225 | | | $ | 4,451 | | | $ | 14,375 | | | $ | 11,504 | | Energy | $ | 4,940 | | | $ | 4,301 | | | $ | 9,763 | | | $ | 9,150 | |
| Real estate | Real estate | 1,743 | | | 1,742 | | | 4,738 | | | 3,828 | | Real estate | 1,672 | | | 1,763 | | | 2,879 | | | 2,995 | |
| Total operating revenue | Total operating revenue | 6,968 | | | 6,193 | | | 19,113 | | | 15,332 | | Total operating revenue | 6,612 | | | 6,064 | | | 12,642 | | | 12,145 | |
| | | | | | | | | | | | | | | | | |
| Operating expenses: | Operating expenses: | | | | | | | Operating expenses: | | | | | | |
| Energy: | Energy: | | | | | | | Energy: | | | | | | |
| Cost of sales | Cost of sales | 1,385 | | | 1,169 | | | 4,064 | | | 3,095 | | Cost of sales | 1,525 | | | 1,110 | | | 2,985 | | | 2,679 | |
| Operations and maintenance | Operations and maintenance | 1,001 | | | 1,033 | | | 2,972 | | | 2,564 | | Operations and maintenance | 1,081 | | | 1,037 | | | 2,024 | | | 1,971 | |
| Depreciation and amortization | Depreciation and amortization | 946 | | | 789 | | | 2,797 | | | 2,323 | | Depreciation and amortization | 1,045 | | | 936 | | | 2,052 | | | 1,851 | |
| Property and other taxes | Property and other taxes | 194 | | | 152 | | | 593 | | | 456 | | Property and other taxes | 199 | | | 189 | | | 404 | | | 399 | |
| Real estate | Real estate | 1,608 | | | 1,503 | | | 4,312 | | | 3,492 | | Real estate | 1,555 | | | 1,584 | | | 2,734 | | | 2,704 | |
| Total operating expenses | Total operating expenses | 5,134 | | | 4,646 | | | 14,738 | | | 11,930 | | Total operating expenses | 5,405 | | | 4,856 | | | 10,199 | | | 9,604 | |
| | | | | | | | | | | | | | | | | |
| Operating income | Operating income | 1,834 | | | 1,547 | | | 4,375 | | | 3,402 | | Operating income | 1,207 | | | 1,208 | | | 2,443 | | | 2,541 | |
| | | | | | | | | | | | | | | | | |
| Other income (expense): | Other income (expense): | | | | | | | Other income (expense): | | | | | | |
| Interest expense | Interest expense | (531) | | | (504) | | | (1,593) | | | (1,490) | | Interest expense | (550) | | | (532) | | | (1,082) | | | (1,062) | |
| Capitalized interest | Capitalized interest | 18 | | | 24 | | | 46 | | | 60 | | Capitalized interest | 18 | | | 14 | | | 35 | | | 28 | |
| Allowance for equity funds | Allowance for equity funds | 34 | | | 50 | | | 90 | | | 122 | | Allowance for equity funds | 42 | | | 30 | | | 80 | | | 56 | |
| Interest and dividend income | Interest and dividend income | 18 | | | 17 | | | 65 | | | 57 | | Interest and dividend income | 30 | | | 26 | | | 53 | | | 47 | |
| Gains on marketable securities, net | Gains on marketable securities, net | 294 | | | 1,797 | | | 1,142 | | | 2,407 | | Gains on marketable securities, net | 2,528 | | | 1,966 | | | 1,271 | | | 848 | |
| Other, net | Other, net | 8 | | | 36 | | | 64 | | | 61 | | Other, net | (26) | | | 48 | | | (21) | | | 56 | |
| Total other income (expense) | Total other income (expense) | (159) | | | 1,420 | | | (186) | | | 1,217 | | Total other income (expense) | 2,042 | | | 1,552 | | | 336 | | | (27) | |
| | | | | | | | | | | | | | | | | |
| Income before income tax (benefit) expense and equity loss | 1,675 | | | 2,967 | | | 4,189 | | | 4,619 | | |
| Income tax (benefit) expense | (355) | | | 80 | | | (563) | | | (111) | | |
| Income before income tax expense (benefit) and equity loss | | Income before income tax expense (benefit) and equity loss | 3,249 | | | 2,760 | | | 2,779 | | | 2,514 | |
| Income tax expense (benefit) | | Income tax expense (benefit) | 149 | | | 327 | | | (358) | | | (208) | |
| Equity loss | Equity loss | (5) | | | (41) | | | (234) | | | (91) | | Equity loss | (83) | | | (50) | | | (140) | | | (229) | |
| Net income | Net income | 2,025 | | | 2,846 | | | 4,518 | | | 4,639 | | Net income | 3,017 | | | 2,383 | | | 2,997 | | | 2,493 | |
| Net income attributable to noncontrolling interests | Net income attributable to noncontrolling interests | 103 | | | 4 | | | 311 | | | 11 | | Net income attributable to noncontrolling interests | 120 | | | 102 | | | 229 | | | 208 | |
| Net income attributable to BHE shareholders | Net income attributable to BHE shareholders | 1,922 | | | 2,842 | | | 4,207 | | | 4,628 | | Net income attributable to BHE shareholders | 2,897 | | | 2,281 | | | 2,768 | | | 2,285 | |
| Preferred dividends | Preferred dividends | 26 | | | — | | | 101 | | | — | | Preferred dividends | 13 | | | 37 | | | 29 | | | 75 | |
| Earnings on common shares | Earnings on common shares | $ | 1,896 | | | $ | 2,842 | | | $ | 4,106 | | | $ | 4,628 | | Earnings on common shares | $ | 2,884 | | | $ | 2,244 | | | $ | 2,739 | | | $ | 2,210 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
| | | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | | | | | | | | | | | |
| Net income | Net income | $ | 2,025 | | | $ | 2,846 | | | $ | 4,518 | | | $ | 4,639 | | Net income | $ | 3,017 | | | $ | 2,383 | | | $ | 2,997 | | | $ | 2,493 | |
| | | | | | | | | | | | | | | | | |
| Other comprehensive (loss) income, net of tax: | Other comprehensive (loss) income, net of tax: | | Other comprehensive (loss) income, net of tax: | |
| Unrecognized amounts on retirement benefits, net of tax of $7, $(3), $12 and $10 | 22 | | | (6) | | | 44 | | | 38 | | |
| Unrecognized amounts on retirement benefits, net of tax of $9, $1, $12 and $5 | | Unrecognized amounts on retirement benefits, net of tax of $9, $1, $12 and $5 | 25 | | | 15 | | | 40 | | | 22 | |
| Foreign currency translation adjustment | Foreign currency translation adjustment | (218) | | | 244 | | | (59) | | | (195) | | Foreign currency translation adjustment | (481) | | | 68 | | | (591) | | | 159 | |
| Unrealized gains (losses) on cash flow hedges, net of tax of $12, $2, $16 and $(5) | 33 | | | 4 | | | 48 | | | (20) | | |
| Unrealized gains on cash flow hedges, net of tax of $8, $(1), $36 and $4 | | Unrealized gains on cash flow hedges, net of tax of $8, $(1), $36 and $4 | 26 | | | 1 | | | 103 | | | 15 | |
| Total other comprehensive (loss) income, net of tax | Total other comprehensive (loss) income, net of tax | (163) | | | 242 | | | 33 | | | (177) | | Total other comprehensive (loss) income, net of tax | (430) | | | 84 | | | (448) | | | 196 | |
| | | | | | | | | | | | | | | | | |
| Comprehensive income | Comprehensive income | 1,862 | | | 3,088 | | | 4,551 | | | 4,462 | | Comprehensive income | 2,587 | | | 2,467 | | | 2,549 | | | 2,689 | |
| Comprehensive income attributable to noncontrolling interests | Comprehensive income attributable to noncontrolling interests | 103 | | | 4 | | | 315 | | | 11 | | Comprehensive income attributable to noncontrolling interests | 120 | | | 106 | | | 229 | | | 212 | |
| Comprehensive income attributable to BHE shareholders | Comprehensive income attributable to BHE shareholders | $ | 1,759 | | | $ | 3,084 | | | $ | 4,236 | | | $ | 4,451 | | Comprehensive income attributable to BHE shareholders | $ | 2,467 | | | $ | 2,361 | | | $ | 2,320 | | | $ | 2,477 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
| | | | BHE Shareholders' Equity | | | BHE Shareholders' Equity | |
| | | Long-term | | Accumulated | | | | | Long-term | | Accumulated | | |
| | Additional | | Income | | Other | | | Additional | | Income | | Other | |
| | Preferred | | Common | | Paid-in | | Tax | | Retained | | Comprehensive | | Noncontrolling | | Total | | Preferred | | Common | | Paid-in | | Tax | | Retained | | Comprehensive | | Noncontrolling | | Total |
| | | Stock | | Stock | | Capital | | Receivable | | Earnings | | Loss, Net | | Interests | | Equity | | Stock | | Stock | | Capital | | Receivable | | Earnings | | Loss, Net | | Interests | | Equity |
| Balance, June 30, 2020 | $ | — | | | $ | — | | | $ | 6,377 | | | $ | (530) | | | $ | 29,962 | | | $ | (2,125) | | | $ | 101 | | | $ | 33,785 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 35,060 | | | $ | (1,440) | | | $ | 3,962 | | | $ | 47,051 | |
| Net income | Net income | — | | | — | | | — | | | — | | | 2,842 | | | — | | | 3 | | | 2,845 | | Net income | — | | | — | | | — | | | — | | | 2,281 | | | — | | | 102 | | | 2,383 | |
| Other comprehensive income | Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 242 | | | — | | | 242 | | Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 80 | | | 4 | | | 84 | |
| Preferred stock dividend | | Preferred stock dividend | — | | | — | | | — | | | — | | | (37) | | | — | | | — | | | (37) | |
| | Distributions | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (4) | | | (4) | | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (121) | | | (121) | |
| Contributions | | Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 9 | | | 9 | |
| | Other equity transactions | Other equity transactions | — | | | — | | | — | | | — | | | — | | | — | | | 1 | | | 1 | | Other equity transactions | — | | | — | | | — | | | — | | | (1) | | | — | | | (3) | | | (4) | |
| Balance, September 30, 2020 | $ | — | | | $ | — | | | $ | 6,377 | | | $ | (530) | | | $ | 32,804 | | | $ | (1,883) | | | $ | 101 | | | $ | 36,869 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 37,303 | | | $ | (1,360) | | | $ | 3,953 | | | $ | 49,365 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2019 | $ | — | | | $ | — | | | $ | 6,389 | | | $ | (530) | | | $ | 28,296 | | | $ | (1,706) | | | $ | 129 | | | $ | 32,578 | | |
| Balance, December 31, 2020 | | Balance, December 31, 2020 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 35,093 | | | $ | (1,552) | | | $ | 3,967 | | | $ | 46,977 | |
| Net income | Net income | — | | | — | | | — | | | — | | | 4,628 | | | — | | | 10 | | | 4,638 | | Net income | — | | | — | | | — | | | — | | | 2,285 | | | — | | | 208 | | | 2,493 | |
| Other comprehensive loss | — | | | — | | | — | | | — | | | — | | | (177) | | | — | | | (177) | | |
| Common stock purchases | — | | | — | | | (6) | | | — | | | (120) | | | — | | | — | | | (126) | | |
| Other comprehensive income | | Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 192 | | | 4 | | | 196 | |
| Preferred stock dividend | | Preferred stock dividend | — | | | — | | | — | | | — | | | (75) | | | — | | | — | | | (75) | |
| | Distributions | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (11) | | | (11) | | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (234) | | | (234) | |
| Purchase of noncontrolling interest | — | | | — | | | (5) | | | — | | | — | | | — | | | (28) | | | (33) | | |
| Contributions | | Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 9 | | | 9 | |
| | Other equity transactions | Other equity transactions | — | | | — | | | (1) | | | — | | | — | | | — | | | 1 | | | — | | Other equity transactions | — | | | — | | | — | | | — | | | — | | | — | | | (1) | | | (1) | |
| Balance, September 30, 2020 | $ | — | | | $ | — | | | $ | 6,377 | | | $ | (530) | | | $ | 32,804 | | | $ | (1,883) | | | $ | 101 | | | $ | 36,869 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 37,303 | | | $ | (1,360) | | | $ | 3,953 | | | $ | 49,365 | |
| | Balance, June 30, 2021 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 37,303 | | | $ | (1,360) | | | $ | 3,953 | | | $ | 49,365 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 1,650 | | | $ | — | | | $ | 6,374 | | | $ | (744) | | | $ | 40,608 | | | $ | (1,358) | | | $ | 3,894 | | | $ | 50,424 | |
| Net income | Net income | — | | | — | | | — | | | — | | | 1,922 | | | — | | | 103 | | | 2,025 | | Net income | — | | | — | | | — | | | — | | | 2,897 | | | — | | | 120 | | | 3,017 | |
| Other comprehensive loss | Other comprehensive loss | — | | | — | | | — | | | — | | | — | | | (163) | | | — | | | (163) | | Other comprehensive loss | — | | | — | | | — | | | — | | | — | | | (430) | | | — | | | (430) | |
| Preferred stock redemptions | Preferred stock redemptions | (1,450) | | | — | | | — | | | — | | | — | | | — | | | — | | | (1,450) | | Preferred stock redemptions | (800) | | | — | | | — | | | — | | | — | | | — | | | — | | | (800) | |
| Preferred stock dividend | Preferred stock dividend | — | | | — | | | — | | | — | | | (26) | | | — | | | — | | | (26) | | Preferred stock dividend | — | | | — | | | — | | | — | | | (13) | | | — | | | — | | | (13) | |
| Common stock purchases | | Common stock purchases | — | | | — | | | (77) | | | — | | | (793) | | | — | | | — | | | (870) | |
| Distributions | | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (129) | | | (129) | |
| Contributions | | Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 2 | | | 2 | |
| | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (130) | | | (130) | | |
| Other equity transactions | | Other equity transactions | — | | | — | | | 1 | | | — | | | (11) | | | — | | | — | | | (10) | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 850 | | | $ | — | | | $ | 6,298 | | | $ | (744) | | | $ | 42,688 | | | $ | (1,788) | | | $ | 3,887 | | | $ | 51,191 | |
| | | | | | | | | | | | | | | | | |
| 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 | | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 1,650 | | | $ | — | | | $ | 6,374 | | | $ | (744) | | | $ | 40,754 | | | $ | (1,340) | | | $ | 3,895 | | | $ | 50,589 | |
| Net income | Net income | — | | | — | | | — | | | — | | | 4,207 | | | — | | | 311 | | | 4,518 | | Net income | — | | | — | | | — | | | — | | | 2,768 | | | — | | | 229 | | | 2,997 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 29 | | | 4 | | | 33 | | |
| Other comprehensive loss | | Other comprehensive loss | — | | | — | | | — | | | — | | | — | | | (448) | | | — | | | (448) | |
| Preferred stock redemptions | Preferred stock redemptions | (1,450) | | | — | | | — | | | — | | | — | | | — | | | — | | | (1,450) | | Preferred stock redemptions | (800) | | | — | | | — | | | — | | | — | | | — | | | — | | | (800) | |
| Preferred stock dividend | Preferred stock dividend | — | | | — | | | — | | | — | | | (101) | | | — | | | — | | | (101) | | Preferred stock dividend | — | | | — | | | — | | | — | | | (29) | | | — | | | — | | | (29) | |
| | Common stock purchases | | Common stock purchases | — | | | — | | | (77) | | | — | | | (793) | | | — | | | — | | | (870) | |
| Distributions | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (364) | | | (364) | | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (245) | | | (245) | |
| Contributions | Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 9 | | | 9 | | Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 2 | | | 2 | |
| Purchase of noncontrolling interest | — | | | — | | | (3) | | | — | | | — | | | — | | | — | | | (3) | | |
| | Other equity transactions | Other equity transactions | — | | | — | | | — | | | — | | | — | | | — | | | (3) | | | (3) | | Other equity transactions | — | | | — | | | 1 | | | — | | | (12) | | | — | | | 6 | | | (5) | |
| Balance, September 30, 2021 | $ | 2,300 | | | $ | — | | | $ | 6,374 | | | $ | (658) | | | $ | 39,199 | | | $ | (1,523) | | | $ | 3,924 | | | $ | 49,616 | | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 850 | | | $ | — | | | $ | 6,298 | | | $ | (744) | | | $ | 42,688 | | | $ | (1,788) | | | $ | 3,887 | | | $ | 51,191 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions) | | | | Nine-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2022 | | 2021 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 4,518 | | | $ | 4,639 | | Net income | $ | 2,997 | | | $ | 2,493 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | Adjustments to reconcile net income to net cash flows from operating activities: | | Adjustments to reconcile net income to net cash flows from operating activities: | |
| Gains on marketable securities, net | Gains on marketable securities, net | (1,142) | | | (2,407) | | Gains on marketable securities, net | (1,271) | | | (848) | |
| Depreciation and amortization | Depreciation and amortization | 2,834 | | | 2,357 | | Depreciation and amortization | 2,081 | | | 1,874 | |
| Allowance for equity funds | Allowance for equity funds | (90) | | | (122) | | Allowance for equity funds | (80) | | | (56) | |
| Equity loss, net of distributions | Equity loss, net of distributions | 346 | | | 146 | | Equity loss, net of distributions | 202 | | | 313 | |
| Changes in regulatory assets and liabilities | Changes in regulatory assets and liabilities | (518) | | | (87) | | Changes in regulatory assets and liabilities | (226) | | | (199) | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 661 | | | 791 | | Deferred income taxes and investment tax credits, net | 385 | | | 613 | |
| Other, net | Other, net | (88) | | | (6) | | Other, net | 37 | | | (26) | |
| Changes in other operating assets and liabilities, net of effects from acquisitions: | Changes in other operating assets and liabilities, net of effects from acquisitions: | | Changes in other operating assets and liabilities, net of effects from acquisitions: | |
| Trade receivables and other assets | Trade receivables and other assets | (13) | | | (1,668) | | Trade receivables and other assets | (317) | | | (254) | |
| Derivative collateral, net | Derivative collateral, net | 115 | | | 53 | | Derivative collateral, net | 189 | | | 92 | |
| Pension and other postretirement benefit plans | Pension and other postretirement benefit plans | (37) | | | (69) | | Pension and other postretirement benefit plans | (21) | | | (33) | |
| Accrued property, income and other taxes, net | Accrued property, income and other taxes, net | (29) | | | 97 | | Accrued property, income and other taxes, net | 489 | | | 76 | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 427 | | | 796 | | Accounts payable and other liabilities | 682 | | | 187 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 6,984 | | | 4,520 | | Net cash flows from operating activities | 5,147 | | | 4,232 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | | | Cash flows from investing activities: | | | |
| Capital expenditures | Capital expenditures | (4,594) | | | (4,607) | | Capital expenditures | (3,382) | | | (2,848) | |
| Acquisitions, net of cash acquired | (64) | | | — | | |
| | Purchases of marketable securities | Purchases of marketable securities | (243) | | | (322) | | Purchases of marketable securities | (281) | | | (185) | |
| Proceeds from sales of marketable securities | Proceeds from sales of marketable securities | 222 | | | 308 | | Proceeds from sales of marketable securities | 257 | | | 163 | |
| Proceeds from other investments | 1,296 | | | 13 | | |
| | Equity method investments | Equity method investments | (54) | | | (2,062) | | Equity method investments | (28) | | | (52) | |
| Other, net | Other, net | (91) | | | 37 | | Other, net | (18) | | | (53) | |
| Net cash flows from investing activities | Net cash flows from investing activities | (3,528) | | | (6,633) | | Net cash flows from investing activities | (3,452) | | | (2,975) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | | | Cash flows from financing activities: | | | |
| | Preferred stock redemptions | Preferred stock redemptions | (1,450) | | | — | | Preferred stock redemptions | (800) | | | — | |
| Preferred dividends | (86) | | | — | | |
| Common stock purchases | Common stock purchases | — | | | (126) | | Common stock purchases | (870) | | | — | |
| Proceeds from BHE senior debt | Proceeds from BHE senior debt | — | | | 3,231 | | Proceeds from BHE senior debt | 987 | | | — | |
| Repayments of BHE senior debt | Repayments of BHE senior debt | (450) | | | (350) | | Repayments of BHE senior debt | — | | | (450) | |
| Preferred dividends | | Preferred dividends | (33) | | | (75) | |
| Proceeds from subsidiary debt | Proceeds from subsidiary debt | 2,014 | | | 2,648 | | Proceeds from subsidiary debt | 1,201 | | | 539 | |
| Repayments of subsidiary debt | Repayments of subsidiary debt | (1,271) | | | (1,558) | | Repayments of subsidiary debt | (542) | | | (1,210) | |
| Net repayments of short-term debt | (316) | | | (815) | | |
| Purchase of noncontrolling interest | — | | | (33) | | |
| Net (repayments of) proceeds from short-term debt | | Net (repayments of) proceeds from short-term debt | (54) | | | 245 | |
| | Distributions to noncontrolling interests | Distributions to noncontrolling interests | (366) | | | (13) | | Distributions to noncontrolling interests | (246) | | | (234) | |
| Contributions from noncontrolling interests | 9 | | | 5 | | |
| | Other, net | Other, net | (44) | | | (52) | | Other, net | (248) | | | (19) | |
| Net cash flows from financing activities | Net cash flows from financing activities | (1,960) | | | 2,937 | | Net cash flows from financing activities | (605) | | | (1,204) | |
| | Effect of exchange rate changes | Effect of exchange rate changes | 1 | | | 4 | | Effect of exchange rate changes | (33) | | | 2 | |
| | Net change in cash and cash equivalents and restricted cash and cash equivalents | Net change in cash and cash equivalents and restricted cash and cash equivalents | 1,497 | | | 828 | | Net change in cash and cash equivalents and restricted cash and cash equivalents | 1,057 | | | 55 | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 1,445 | | | 1,268 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 1,244 | | | 1,445 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 2,942 | | | $ | 2,096 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 2,301 | | | $ | 1,500 | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The Company'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 and its subsidiaries ("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 and its subsidiaries ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation and its subsidiaries ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC)LLC and its subsidiaries), BHE Renewables (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines)its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns 4 utility companies in the United StatesU.S. 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,U.S., an electric transmission business in Canada, interests in electric transmission businesses in the United States,U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United StatesU.S. and 1 of the largest residential real estate brokerage franchise networks in the United States.U.S.
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of SeptemberJune 30, 20212022 and for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020.2021. The results of operations for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 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, 20202021 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-monthsix-month period ended SeptemberJune 30, 2021.
(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.
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 equipment | | 9,264 | |
Goodwill | | 1,741 | |
Regulatory assets | | 108 | |
Deferred income taxes | | 284 | |
Other long-term assets | | 1,424 | |
Total assets | | 13,403 | |
| | |
Current liabilities, including current portion of long-term debt of $1,200 | | 1,616 | |
Long-term debt, less current portion | | 4,415 | |
Regulatory liabilities | | 650 | |
Other long-term liabilities | | 292 | |
Total liabilities | | 6,973 | |
Noncontrolling interest | | 3,916 | |
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.
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 | | | | As of |
| | | Depreciable | | September 30, | | December 31, | | Depreciable | | June 30, | | December 31, |
| | Life | | 2021 | | 2020 | | Life | | 2022 | | 2021 |
| Regulated assets: | Regulated assets: | | | | | | Regulated assets: | | | | | |
| Utility generation, transmission and distribution systems | Utility generation, transmission and distribution systems | 5-80 years | | $ | 89,026 | | | $ | 86,730 | | Utility generation, transmission and distribution systems | 5-80 years | | $ | 90,810 | | | $ | 90,223 | |
| Interstate natural gas pipeline assets | Interstate natural gas pipeline assets | 3-80 years | | 17,044 | | | 16,667 | | Interstate natural gas pipeline assets | 3-80 years | | 17,547 | | | 17,423 | |
| | | | 106,070 | | | 103,397 | | | | 108,357 | | | 107,646 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (32,444) | | | (30,662) | | Accumulated depreciation and amortization | | (33,618) | | | (32,680) | |
| Regulated assets, net | Regulated assets, net | | 73,626 | | | 72,735 | | Regulated assets, net | | 74,739 | | | 74,966 | |
| | | | | | | | | | | |
| Nonregulated assets: | Nonregulated assets: | | | | | Nonregulated assets: | | | | |
| Independent power plants | Independent power plants | 5-30 years | | 7,058 | | | 7,012 | | Independent power plants | 2-50 years | | 8,073 | | | 7,665 | |
| Cove Point LNG facility | | Cove Point LNG facility | 40 years | | 3,373 | | | 3,364 | |
| Other assets | Other assets | 3-40 years | | 5,951 | | | 5,659 | | Other assets | 2-30 years | | 3,042 | | | 2,666 | |
| | | | 13,009 | | | 12,671 | | | | 14,488 | | | 13,695 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (2,916) | | | (2,586) | | Accumulated depreciation and amortization | | (3,206) | | | (3,041) | |
| Nonregulated assets, net | Nonregulated assets, net | | 10,093 | | | 10,085 | | Nonregulated assets, net | | 11,282 | | | 10,654 | |
| | | | | | | | | | | |
| Net operating assets | Net operating assets | | 83,719 | | | 82,820 | | Net operating assets | | 86,021 | | | 85,620 | |
| Construction work-in-progress | Construction work-in-progress | | 4,343 | | | 3,308 | | Construction work-in-progress | | 4,774 | | | 4,196 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 88,062 | | | $ | 86,128 | | Property, plant and equipment, net | | $ | 90,795 | | | $ | 89,816 | |
Construction work-in-progress includes $3.9$4.4 billion as of SeptemberJune 30, 20212022 and $3.2$3.8 billion as of December 31, 2020,2021, related to the construction of regulated assets.
(43) 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 | | As of |
| | | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Investments: | Investments: | | | | Investments: | | | |
| BYD Company Limited common stock | BYD Company Limited common stock | $ | 7,023 | | | $ | 5,897 | | BYD Company Limited common stock | $ | 9,003 | | | $ | 7,693 | |
| Rabbi trusts | Rabbi trusts | 473 | | | 440 | | Rabbi trusts | 429 | | | 492 | |
| Other | Other | 295 | | | 263 | | Other | 328 | | | 305 | |
| Total investments | Total investments | 7,791 | | | 6,600 | | Total investments | 9,760 | | | 8,490 | |
| | | | | | | | | |
| Equity method investments: | Equity method investments: | | Equity method investments: | |
| BHE Renewables tax equity investments | BHE Renewables tax equity investments | 5,253 | | | 5,626 | | BHE Renewables tax equity investments | 4,680 | | | 4,931 | |
| Iroquois Gas Transmission System, L.P. | Iroquois Gas Transmission System, L.P. | 583 | | | 580 | | Iroquois Gas Transmission System, L.P. | 742 | | | 735 | |
| Electric Transmission Texas, LLC | Electric Transmission Texas, LLC | 578 | | | 594 | | Electric Transmission Texas, LLC | 606 | | | 595 | |
| JAX LNG, LLC | 87 | | | 75 | | |
| Bridger Coal Company | 60 | | | 74 | | |
| | Other | Other | 163 | | | 118 | | Other | 302 | | | 293 | |
| Total equity method investments | Total equity method investments | 6,724 | | | 7,067 | | Total equity method investments | 6,330 | | | 6,554 | |
| | Restricted cash and cash equivalents and investments: | | | | |
| Restricted cash, cash equivalents and investments: | | Restricted cash, cash equivalents and investments: | | | |
| Quad Cities Station nuclear decommissioning trust funds | Quad Cities Station nuclear decommissioning trust funds | 727 | | | 676 | | Quad Cities Station nuclear decommissioning trust funds | 658 | | | 768 | |
| Other restricted cash and cash equivalents | Other restricted cash and cash equivalents | 233 | | | 155 | | Other restricted cash and cash equivalents | 220 | | | 148 | |
| Total restricted cash and cash equivalents and investments | 960 | | | 831 | | |
| Total restricted cash, cash equivalents and investments | | Total restricted cash, cash equivalents and investments | 878 | | | 916 | |
| | | | | | | | | |
| Total investments and restricted cash and cash equivalents and investments | $ | 15,475 | | | $ | 14,498 | | |
| Total investments and restricted cash, cash equivalents and investments | | Total investments and restricted cash, cash equivalents and investments | $ | 16,968 | | | $ | 15,960 | |
| | Reflected as: | Reflected as: | | Reflected as: | |
| Current assets | Current assets | $ | 257 | | | $ | 178 | | Current assets | $ | 240 | | | $ | 172 | |
| Noncurrent assets | Noncurrent assets | 15,218 | | | 14,320 | | Noncurrent assets | 16,728 | | | 15,788 | |
| Total investments and restricted cash and cash equivalents and investments | $ | 15,475 | | | $ | 14,498 | | |
| Total investments and restricted cash, cash equivalents and investments | | Total investments and restricted cash, cash equivalents and investments | $ | 16,968 | | | $ | 15,960 | |
Investments
Gains on marketable securities, net recognized during the period consists of the following (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| 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 | — | | | 3 | | | 1 | | | 4 | |
| Gains on marketable securities, net | $ | 294 | | | $ | 1,797 | | | $ | 1,142 | | | $ | 2,407 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Six-Month Periods |
| Ended June 30, | | Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| Unrealized gains recognized on marketable securities still held at the reporting date | $ | 2,527 | | | $ | 1,966 | | | $ | 1,270 | | | $ | 847 | |
| Net gains recognized on marketable securities sold during the period | 1 | | | — | | | 1 | | | 1 | |
| Gains on marketable securities, net | $ | 2,528 | | | $ | 1,966 | | | $ | 1,271 | | | $ | 848 | |
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 StatesU.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents 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 | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash and cash equivalents | Cash and cash equivalents | $ | 2,709 | | | $ | 1,290 | | Cash and cash equivalents | $ | 2,081 | | | $ | 1,096 | |
| Restricted cash and cash equivalents | Restricted cash and cash equivalents | 216 | | | 140 | | Restricted cash and cash equivalents | 201 | | | 127 | |
| Investments and restricted cash and cash equivalents and investments | 17 | | | 15 | | |
| Investments and restricted cash, cash equivalents and investments | | Investments and restricted cash, cash equivalents and investments | 19 | | | 21 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 2,942 | | | $ | 1,445 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 2,301 | | | $ | 1,244 | |
(54) 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 $450June 2022, Sierra Pacific purchased $60 million of its 2.95%variable-rate tax-exempt Gas & Water Facilities Refunding Revenue Bonds, Series First Mortgage Bonds that was originally2016B, due February 2022.2036, as required by the bond indenture. Sierra Pacific is holding this bond and can re-offer it at a future date.
In September 2021, HomeServices entered into a $150May 2022, Sierra Pacific issued $250 million unsecured amortizing term loanof 4.71% General and Refunding Mortgage bonds, Series W, due September 2026.2052. The net proceeds were used to fundrepay the repayment ofoutstanding $200 million unsecured loan with NV Energy, Inc., repay amounts outstanding under 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.
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 2021revolving credit facility and for general corporate purposes.
In April 2022, BHE issued $1 billion of its 4.6% Senior Notes due 2053 and used the net proceeds for general corporate purposes, which included repaying a portion of BHE's outstanding commercial paper obligations and redeeming a portion of its 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.
In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.
In April 2022, Northern Powergrid (Northeast) plc issued £350 million of its 3.25% bonds due 2052 and used the net proceeds for general corporate purposes.
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate ("SOFR") or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. In May 2022, Nevada Power drew the remaining $100 million available under the facility at an initial interest rate of 1.24%. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility 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 2021,2022, BHE amended and restated its existing $3.5 billion unsecured credit facility expiring in June 2022 with one remaining one-year extension option.2024. The amendment extended the expiration date to June 20242025 and increasedamended pricing from the available maturity extension optionsLondon Interbank Offered Rate ("LIBOR") to an unlimited number, subject to lender consent.SOFR.
In June 2021,2022, PacifiCorp terminated, upon lender consent,amended and restated its existing $600 million$1.2 billion 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.2024. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 20242025 and increased the available maturity extension optionsamended pricing from LIBOR to an unlimited number, subject to lender consent.SOFR.
In June 2021,2022, MidAmerican Energy amended and restated its existing $900 million$1.5 billion unsecured credit facility expiring in June 2022.2024. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 20242025 and increased the available maturity extension optionsamended pricing from LIBOR 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.SOFR.
In June 2021,2022, 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.2024. The amendments extended the expiration date to June 20242025 and increased the available maturity extension optionsamended pricing from LIBOR to an unlimited number, subject to lender consent.SOFR.
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.
(65) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax (benefit) expensebenefit is as follows:
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | | | | | | | | | | | |
| Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| Income tax credits | Income tax credits | (31) | | | (20) | | | (29) | | | (23) | | Income tax credits | (13) | | | (13) | | | (28) | | | (27) | |
| State income tax, net of federal income tax impacts | State income tax, net of federal income tax impacts | (4) | | | 3 | | | — | | | 2 | | State income tax, net of federal income tax impacts | (1) | | | 4 | | | — | | | 2 | |
| Income tax effect of foreign income | Income tax effect of foreign income | (1) | | | 1 | | | 2 | | | — | | Income tax effect of foreign income | — | | | 3 | | | (1) | | | 3 | |
| Effects of ratemaking | Effects of ratemaking | (6) | | | (2) | | | (5) | | | (2) | | Effects of ratemaking | (1) | | | (2) | | | (2) | | | (4) | |
| Equity income | Equity income | — | | | — | | | (1) | | | — | | Equity income | (1) | | | — | | | (1) | | | (2) | |
| Noncontrolling interest | Noncontrolling interest | (1) | | | — | | | (2) | | | — | | Noncontrolling interest | (1) | | | (1) | | | (2) | | | (2) | |
| Other, net | Other, net | 1 | | | — | | | 1 | | | — | | Other, net | 1 | | | — | | | — | | | 1 | |
| Effective income tax rate | Effective income tax rate | (21) | % | | 3 | % | | (13) | % | | (2) | % | Effective income tax rate | 5 | % | | 12 | % | | (13) | % | | (8) | % |
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-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 totaled $734 million and 2020 totaled $1.2 billion and $1.0 billion,$678 million, respectively.
Income tax effect on foreign income includes, among other items, a deferred income tax charge of $109 million recognized in June 2021 upon the enactment of an increase in the United Kingdom's corporate income tax rate from 19% to 25% effective April 1, 2023, 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 2020.2023.
The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United StatesU.S. federal and Iowa state income tax returns and the majority of the Company's United StatesU.S. federal income tax is remitted to or received from Berkshire Hathaway. For the nine-month periods ended September 30, 2021 and 2020, theThe Company received net cash payments for federal income taxes from Berkshire Hathaway for the six-month periods ended June 30, 2022 and 2021 totaling $1.3 billion$1,249 million and $1.0 billion,$943 million, respectively.
(76) Employee Benefit Plans
Domestic Operations
Net periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):
| | | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Pension: | Pension: | | | | | | | | Pension: | | | | | | | |
| Service cost | Service cost | $ | 7 | | | $ | 4 | | | $ | 22 | | | $ | 11 | | Service cost | $ | 6 | | | $ | 8 | | | $ | 13 | | | $ | 15 | |
| Interest cost | Interest cost | 21 | | | 23 | | | 59 | | | 69 | | Interest cost | 19 | | | 18 | | | 38 | | | 38 | |
| Expected return on plan assets | Expected return on plan assets | (32) | | | (35) | | | (101) | | | (105) | | Expected return on plan assets | (27) | | | (36) | | | (54) | | | (69) | |
| Settlement | Settlement | 4 | | | — | | | 4 | | | — | | Settlement | — | | | — | | | 2 | | | — | |
| Net amortization | Net amortization | 6 | | | 8 | | | 19 | | | 25 | | Net amortization | 5 | | | 7 | | | 9 | | | 13 | |
| Net periodic benefit cost | $ | 6 | | | $ | — | | | $ | 3 | | | $ | — | | |
| Net periodic benefit cost (credit) | | Net periodic benefit cost (credit) | $ | 3 | | | $ | (3) | | | $ | 8 | | | $ | (3) | |
| | Other postretirement: | Other postretirement: | | Other postretirement: | |
| Service cost | Service cost | $ | 2 | | | $ | 1 | | | $ | 8 | | | $ | 5 | | Service cost | $ | 4 | | | $ | 4 | | | $ | 6 | | | $ | 6 | |
| Interest cost | Interest cost | 4 | | | 6 | | | 14 | | | 16 | | Interest cost | 5 | | | 5 | | | 10 | | | 10 | |
| Expected return on plan assets | Expected return on plan assets | (5) | | | (9) | | | (16) | | | (25) | | Expected return on plan assets | (7) | | | (6) | | | (14) | | | (11) | |
| Net amortization | Net amortization | — | | | (1) | | | (2) | | | (5) | | Net amortization | (1) | | | (1) | | | (1) | | | (2) | |
| Net periodic benefit cost (credit) | $ | 1 | | | $ | (3) | | | $ | 4 | | | $ | (9) | | |
| Net periodic benefit cost | | Net periodic benefit cost | $ | 1 | | | $ | 2 | | | $ | 1 | | | $ | 3 | |
Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $13$5 million, respectively, during 2021.2022. As of SeptemberJune 30, 2021, $92022, $7 million and $10$5 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
Foreign Operations
Net periodic benefit credit for the United Kingdom pension plan included the following components (in millions):
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | | | | | | | | | | | |
| Service cost | Service cost | $ | 4 | | | $ | 4 | | | $ | 12 | | | $ | 12 | | Service cost | $ | 3 | | | $ | 4 | | | $ | 7 | | | $ | 8 | |
| Interest cost | Interest cost | 8 | | | 10 | | | 23 | | | 30 | | Interest cost | 9 | | | 7 | | | 19 | | | 15 | |
| Expected return on plan assets | Expected return on plan assets | (28) | | | (26) | | | (84) | | | (76) | | Expected return on plan assets | (23) | | | (28) | | | (48) | | | (56) | |
| | Net amortization | Net amortization | 14 | | | 11 | | | 42 | | | 32 | | Net amortization | 6 | | | 14 | | | 12 | | | 28 | |
| Net periodic benefit credit | Net periodic benefit credit | $ | (2) | | | $ | (1) | | | $ | (7) | | | $ | (2) | | Net periodic benefit credit | $ | (5) | | | $ | (3) | | | $ | (10) | | | $ | (5) | |
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£12 million during 2021.2022. As of SeptemberJune 30, 2021, £172022, £6 million, or $24$8 million, of contributions had been made to the United Kingdom pension plan.
(87) 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 | | | Input Levels for Fair Value Measurements | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total | | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
| As of September 30, 2021 | | | | | | | | | | | |
| As of June 30, 2022: | | As of June 30, 2022: | | | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | | $ | 15 | | | $ | 436 | | | $ | 88 | | | $ | (49) | | | $ | 490 | | Commodity derivatives | | $ | 11 | | | $ | 660 | | | $ | 77 | | | $ | (164) | | | $ | 584 | |
| Foreign currency exchange rate derivatives | | — | | | 8 | | | — | | | — | | | 8 | | |
| | Interest rate derivatives | Interest rate derivatives | | — | | | 12 | | | 30 | | | — | | | 42 | | Interest rate derivatives | | 16 | | | 45 | | | 24 | | | — | | | 85 | |
| Mortgage loans held for sale | Mortgage loans held for sale | | — | | | 1,687 | | | — | | | — | | | 1,687 | | Mortgage loans held for sale | | — | | | 1,084 | | | — | | | — | | | 1,084 | |
| Money market mutual funds | Money market mutual funds | | 2,017 | | | — | | | — | | | — | | | 2,017 | | Money market mutual funds | | 1,492 | | | — | | | — | | | — | | | 1,492 | |
| Debt securities: | Debt securities: | | Debt securities: | |
| United States government obligations | | 228 | | | — | | | — | | | — | | | 228 | | |
| U.S. government obligations | | U.S. government obligations | | 220 | | | — | | | — | | | — | | | 220 | |
| International government obligations | International government obligations | | — | | | 2 | | | — | | | — | | | 2 | | International government obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Corporate obligations | Corporate obligations | | — | | | 86 | | | — | | | — | | | 86 | | Corporate obligations | | — | | | 75 | | | — | | | — | | | 75 | |
| Municipal obligations | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
| Agency, asset and mortgage-backed obligations | Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | | Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Equity securities: | Equity securities: | | Equity securities: | |
| United States companies | | 398 | | | — | | | — | | | — | | | 398 | | |
| U.S. companies | | U.S. companies | | 348 | | | — | | | — | | | — | | | 348 | |
| International companies | International companies | | 7,031 | | | — | | | — | | | — | | | 7,031 | | International companies | | 9,011 | | | — | | | — | | | — | | | 9,011 | |
| Investment funds | Investment funds | | 264 | | | — | | | — | | | — | | | 264 | | Investment funds | | 258 | | | — | | | — | | | — | | | 258 | |
| | | | $ | 9,953 | | | $ | 2,235 | | | $ | 118 | | | $ | (49) | | | $ | 12,257 | | | | $ | 11,356 | | | $ | 1,869 | | | $ | 101 | | | $ | (164) | | | $ | 13,162 | |
| Liabilities: | Liabilities: | | | | | | | | | | | Liabilities: | | | | | | | | | | |
| Commodity derivatives | Commodity derivatives | | $ | (2) | | | $ | (134) | | | $ | (56) | | | $ | 80 | | | $ | (112) | | Commodity derivatives | | $ | (14) | | | $ | (211) | | | $ | (255) | | | $ | 77 | | | $ | (403) | |
| Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | — | | | (4) | | | — | | | — | | | (4) | | Foreign currency exchange rate derivatives | | — | | | (19) | | | — | | | — | | | (19) | |
| Interest rate derivatives | Interest rate derivatives | | (1) | | | (11) | | | (2) | | | — | | | (14) | | Interest rate derivatives | | — | | | (6) | | | (3) | | | — | | | (9) | |
| | $ | (3) | | | $ | (149) | | | $ | (58) | | | $ | 80 | | | $ | (130) | | | $ | (14) | | | $ | (236) | | | $ | (258) | | | $ | 77 | | | $ | (431) | |
| | | Input Levels for Fair Value Measurements | | | Input Levels for Fair Value Measurements | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total | | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
| As of December 31, 2020 | | | | | | | | | | | |
| As of December 31, 2021: | | As of December 31, 2021: | | | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | | $ | 1 | | | $ | 73 | | | $ | 135 | | | $ | (21) | | | $ | 188 | | Commodity derivatives | | $ | 5 | | | $ | 271 | | | $ | 73 | | | $ | (47) | | | $ | 302 | |
| Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | — | | | 20 | | | — | | | — | | | 20 | | Foreign currency exchange rate derivatives | | — | | | 3 | | | — | | | — | | | 3 | |
| Interest rate derivatives | Interest rate derivatives | | — | | | — | | | 62 | | | — | | | 62 | | Interest rate derivatives | | 1 | | | 3 | | | 20 | | | — | | | 24 | |
| Mortgage loans held for sale | Mortgage loans held for sale | | — | | | 2,001 | | | — | | | — | | | 2,001 | | Mortgage loans held for sale | | — | | | 1,263 | | | — | | | — | | | 1,263 | |
| Money market mutual funds | Money market mutual funds | | 873 | | | — | | | — | | | — | | | 873 | | Money market mutual funds | | 554 | | | — | | | — | | | — | | | 554 | |
| Debt securities: | Debt securities: | | Debt securities: | |
| United States government obligations | | 200 | | | — | | | — | | | — | | | 200 | | |
| U.S. government obligations | | U.S. government obligations | | 232 | | | — | | | — | | | — | | | 232 | |
| International government obligations | International government obligations | | — | | | 5 | | | — | | | — | | | 5 | | International government obligations | | — | | | 2 | | | — | | | — | | | 2 | |
| Corporate obligations | Corporate obligations | | — | | | 73 | | | — | | | — | | | 73 | | Corporate obligations | | — | | | 90 | | | — | | | — | | | 90 | |
| Municipal obligations | Municipal obligations | | — | | | 2 | | | — | | | — | | | 2 | | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
| Agency, asset and mortgage-backed obligations | Agency, asset and mortgage-backed obligations | | — | | | 6 | | | — | | | — | | | 6 | | Agency, asset and mortgage-backed obligations | | — | | | 2 | | | — | | | — | | | 2 | |
| Equity securities: | Equity securities: | | Equity securities: | |
| United States companies | | 381 | | | — | | | — | | | — | | | 381 | | |
| U.S. companies | | U.S. companies | | 428 | | | — | | | — | | | — | | | 428 | |
| International companies | International companies | | 5,906 | | | — | | | — | | | — | | | 5,906 | | International companies | | 7,703 | | | — | | | — | | | — | | | 7,703 | |
| Investment funds | Investment funds | | 201 | | | — | | | — | | | — | | | 201 | | Investment funds | | 237 | | | — | | | — | | | — | | | 237 | |
| | | | $ | 7,562 | | | $ | 2,180 | | | $ | 197 | | | $ | (21) | | | $ | 9,918 | | | | $ | 9,160 | | | $ | 1,637 | | | $ | 93 | | | $ | (47) | | | $ | 10,843 | |
| Liabilities: | Liabilities: | | | | | | | | | | | Liabilities: | | | | | | | | | | |
| Commodity derivatives | Commodity derivatives | | $ | (1) | | | $ | (90) | | | $ | (19) | | | $ | 56 | | | $ | (54) | | Commodity derivatives | | $ | (2) | | | $ | (113) | | | $ | (224) | | | $ | 73 | | | $ | (266) | |
| Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | — | | | (2) | | | — | | | — | | | (2) | | Foreign currency exchange rate derivatives | | — | | | (3) | | | — | | | — | | | (3) | |
| Interest rate derivatives | Interest rate derivatives | | (5) | | | (60) | | | — | | | — | | | (65) | | Interest rate derivatives | | — | | | (7) | | | (1) | | | — | | | (8) | |
| | $ | (6) | | | $ | (152) | | | $ | (19) | | | $ | 56 | | | $ | (121) | | | $ | (2) | | | $ | (123) | | | $ | (225) | | | $ | 73 | | | $ | (277) | |
(1)Represents netting under master netting arrangements and a net cash collateral payable of $87 million and receivable of $31 million and $35$26 million as of SeptemberJune 30, 20212022 and December 31, 2020,2021, 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 the underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.
The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
The following table reconciles the beginning and ending balances of the Company's financial assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):. Transfers out of Level 3 occur primarily due to increased price observability.
| | | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | Interest | | | Interest | | | Interest | | | Interest |
| | | Commodity | | Rate | | Commodity | | Rate | | Commodity | | Rate | | Commodity | | Rate |
| | Derivatives | | Derivatives | | Derivatives | | Derivatives | | Derivatives | | Derivatives | | Derivatives | | Derivatives |
| 2021: | | | | | | | | |
| 2022: | | 2022: | | | | | | | |
| Beginning balance | Beginning balance | $ | 105 | | | $ | 41 | | | $ | 116 | | | $ | 62 | | Beginning balance | $ | (239) | | | $ | 13 | | | $ | (151) | | | $ | 19 | |
Changes included in earnings(1) | Changes included in earnings(1) | (18) | | | (13) | | | (34) | | | (34) | | Changes included in earnings(1) | (26) | | | 8 | | | (82) | | | 2 | |
| Changes in fair value recognized in OCI | Changes in fair value recognized in OCI | (6) | | | — | | | (13) | | | — | | Changes in fair value recognized in OCI | 5 | | | — | | | 10 | | | — | |
| Changes in fair value recognized in net regulatory assets | Changes in fair value recognized in net regulatory assets | 12 | | | — | | | 21 | | | — | | Changes in fair value recognized in net regulatory assets | 1 | | | — | | | (59) | | | — | |
| | Purchases | Purchases | 1 | | | — | | | 2 | | | — | | Purchases | 1 | | | — | | | 1 | | | — | |
| | Settlements | Settlements | (62) | | | — | | | (60) | | | — | | Settlements | 11 | | | — | | | 34 | | | — | |
| Transfers out of Level 3 into Level 2 | | Transfers out of Level 3 into Level 2 | 69 | | | — | | | 69 | | | — | |
| | Ending balance | Ending balance | $ | 32 | | | $ | 28 | | | $ | 32 | | | $ | 28 | | Ending balance | $ | (178) | | | $ | 21 | | | $ | (178) | | | $ | 21 | |
| | | Three-Month Periods | | Nine-Month Periods | |
| | Ended September 30, | | Ended September 30, | |
| | | Interest | | | Interest | |
| | Commodity | | Rate | | Commodity | | Rate | |
| | Derivatives | | Derivatives | | Derivatives | | Derivatives | |
| 2020: | | | | | | | | |
| 2021: | | 2021: | |
| Beginning balance | Beginning balance | $ | 44 | | | $ | 78 | | | $ | 97 | | | $ | 14 | | Beginning balance | $ | 124 | | | $ | 41 | | | $ | 116 | | | $ | 62 | |
Changes included in earnings(1) | Changes included in earnings(1) | (7) | | | 10 | | | (11) | | | 74 | | Changes included in earnings(1) | (10) | | | — | | | (16) | | | (21) | |
| | Changes in fair value recognized in OCI | | Changes in fair value recognized in OCI | (6) | | | — | | | (7) | | | — | |
| Changes in fair value recognized in net regulatory assets | Changes in fair value recognized in net regulatory assets | 20 | | | — | | | (36) | | | — | | Changes in fair value recognized in net regulatory assets | (7) | | | — | | | 9 | | | — | |
| Purchases | Purchases | 1 | | | — | | | 4 | | | — | | Purchases | 1 | | | — | | | 1 | | | — | |
| | Settlements | Settlements | 38 | | | — | | | 42 | | | — | | Settlements | 3 | | | — | | | 2 | | | — | |
| | Ending balance | Ending balance | $ | 96 | | | $ | 88 | | | $ | 96 | | | $ | 88 | | Ending balance | $ | 105 | | | $ | 41 | | | $ | 105 | | | $ | 41 | |
(1)Changes included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.
The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of September 30, 2021 | | As of December 31, 2020 |
| | Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | | |
| Long-term debt | $ | 50,098 | | | $ | 57,902 | | | $ | 49,866 | | | $ | 60,633 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of June 30, 2022 | | As of December 31, 2021 |
| | Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | | |
| Long-term debt | $ | 51,117 | | | $ | 48,636 | | | $ | 49,762 | | | $ | 57,189 | |
(9)8) Commitments and Contingencies
Construction Commitments
During the nine-monthsix-month period ended SeptemberJune 30, 2021, MidAmerican Energy2022, PacifiCorp entered into firma procurement and construction commitments totaling $405services agreement for $849 million through the remainder of 2021 and 2022 related to the repowering and construction of wind-powered generating facilities and2024 for the construction of solar-powered generating facilities.a key Energy Gateway Transmission segment extending between the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah.
EasementsFuel Contracts
During the nine-monthsix-month period ended SeptemberJune 30, 2021, MidAmerican Energy2022, PacifiCorp entered into non-cancelable easements with minimum payment commitmentscertain coal supply and transportation agreements totaling $87approximately $200 million through 2061 for land in Iowa on which some of its wind- and solar-powered generating facilities will be located.2024.
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, privatereal and publicpersonal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires").California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. 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.
SeveralMultiple 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. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. 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 real and personal property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.
As of SeptemberDuring the three-month period ended June 30, 2021,2022, PacifiCorp has accrued $136$64 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probableresulting in an overall loss accrual net of being incurred.expected insurance recoveries of $200 million as of June 30, 2022 compared to $136 million as of December 31, 2021. These accruals include estimatedPacifiCorp's estimate of losses for fire suppression costs, real and personal property damage,damages, natural resource damages and noneconomic damages such as personal injury damages and loss of life damages.damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to natural resource damages, is not currently available. 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 variation in those types of properties and lack of specific claims for all potential claimants.available details. 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. PacifiCorp's receivable for expected insurance recoveries was $277 million as of June 30, 2022.
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 conditionally approved the required property transfer.transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending. In February 2022, the FERC staff issued a draft environmental impact statement for the project, concluding that dam removal is the preferred alternative. A final environmental impact statement is expected later in 2022.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.
(10)(9) 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 1312 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three-Month Period Ended September 30, 2021 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
| Customer Revenue: | | | | | | | | | | | | | | | | | | |
| Regulated: | | | | | | | | | | | | | | | | | | |
| Retail electric | | $ | 1,352 | | | $ | 736 | | | $ | 1,008 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,096 | |
| Retail gas | | — | | | 84 | | | 16 | | | — | | | — | | | — | | | — | | | — | | | 100 | |
| Wholesale | | 58 | | | 113 | | | 19 | | | — | | | 14 | | | — | | | — | | | (1) | | | 203 | |
Transmission and
distribution | | 55 | | | 15 | | | 35 | | | 241 | | | — | | | 175 | | | — | | | — | | | 521 | |
| Interstate pipeline | | — | | | — | | | — | | | — | | | 514 | | | — | | | — | | | (28) | | | 486 | |
| Other | | 26 | | | — | | | — | | | — | | | (2) | | | — | | | — | | | — | | | 24 | |
| Total Regulated | | 1,491 | | | 948 | | | 1,078 | | | 241 | | | 526 | | | 175 | | | — | | | (29) | | | 4,430 | |
| Nonregulated | | — | | | 2 | | | — | | | 8 | | | 257 | | | 12 | | | 288 | | | 141 | | | 708 | |
| Total Customer Revenue | | 1,491 | | | 950 | | | 1,078 | | | 249 | | | 783 | | | 187 | | | 288 | | | 112 | | | 5,138 | |
| Other revenue | | — | | | 16 | | | 7 | | | 28 | | | 2 | | | (2) | | | 28 | | | 8 | | | 87 | |
| Total | | $ | 1,491 | | | $ | 966 | | | $ | 1,085 | | | $ | 277 | | | $ | 785 | | | $ | 185 | | | $ | 316 | | | $ | 120 | | | $ | 5,225 | |
| | | For the Nine-Month Period Ended September 30, 2021 | | For the Three-Month Period Ended June 30, 2022 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total | | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
| Customer Revenue: | Customer Revenue: | | | | | | | | | | | | | | | | | | | Customer Revenue: | | | | | | | | | | | | | | | | | | |
| Regulated: | Regulated: | | Regulated: | |
| Retail electric | Retail electric | | $ | 3,685 | | | $ | 1,704 | | | $ | 2,227 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 7,615 | | Retail electric | | $ | 1,167 | | | $ | 594 | | | $ | 831 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 2,591 | |
| Retail gas | Retail gas | | — | | | 633 | | | 74 | | | — | | | — | | | — | | | — | | | — | | | 707 | | Retail gas | | — | | | 136 | | | 28 | | | — | | | — | | | — | | | — | | | — | | | 164 | |
| Wholesale | Wholesale | | 124 | | | 307 | | | 44 | | | — | | | 31 | | | — | | | — | | | (2) | | | 504 | | Wholesale | | 55 | | | 119 | | | 15 | | | — | | | — | | | — | | | — | | | (2) | | | 187 | |
Transmission and
distribution | Transmission and
distribution | | 117 | | | 45 | | | 78 | | | 747 | | | — | | | 525 | | | — | | | — | | | 1,512 | | Transmission and
distribution | | 45 | | | 13 | | | 18 | | | 274 | | | — | | | 172 | | | — | | | — | | | 522 | |
| Interstate pipeline | Interstate pipeline | | — | | | — | | | — | | | — | | | 1,787 | | | — | | | — | | | (94) | | | 1,693 | | Interstate pipeline | | — | | | — | | | — | | | — | | | 524 | | | — | | | — | | | (27) | | | 497 | |
| Other | Other | | 80 | | | — | | | 1 | | | — | | | (1) | | | — | | | — | | | — | | | 80 | | Other | | 28 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 28 | |
| Total Regulated | Total Regulated | | 4,006 | | | 2,689 | | | 2,424 | | | 747 | | | 1,817 | | | 525 | | | — | | | (97) | | | 12,111 | | Total Regulated | | 1,295 | | | 862 | | | 892 | | | 274 | | | 524 | | | 172 | | | — | | | (30) | | | 3,989 | |
| Nonregulated | Nonregulated | | — | | | 13 | | | 1 | | | 26 | | | 726 | | | 27 | | | 693 | | | 452 | | | 1,938 | | Nonregulated | | — | | | — | | | 1 | | | 42 | | | 285 | | | 15 | | | 262 | | | 151 | | | 756 | |
| Total Customer Revenue | Total Customer Revenue | | 4,006 | | | 2,702 | | | 2,425 | | | 773 | | | 2,543 | | | 552 | | | 693 | | | 355 | | | 14,049 | | Total Customer Revenue | | 1,295 | | | 862 | | | 893 | | | 316 | | | 809 | | | 187 | | | 262 | | | 121 | | | 4,745 | |
| Other revenue | Other revenue | | 25 | | | 24 | | | 18 | | | 84 | | | 41 | | | (5) | | | 80 | | | 59 | | | 326 | | Other revenue | | 19 | | | 35 | | | 6 | | | 29 | | | 47 | | | (4) | | | 32 | | | 31 | | | 195 | |
| Total | Total | | $ | 4,031 | | | $ | 2,726 | | | $ | 2,443 | | | $ | 857 | | | $ | 2,584 | | | $ | 547 | | | $ | 773 | | | $ | 414 | | | $ | 14,375 | | Total | | $ | 1,314 | | | $ | 897 | | | $ | 899 | | | $ | 345 | | | $ | 856 | | | $ | 183 | | | $ | 294 | | | $ | 152 | | | $ | 4,940 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Six-Month Period Ended June 30, 2022 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
| Customer Revenue: | | | | | | | | | | | | | | | | | | |
| Regulated: | | | | | | | | | | | | | | | | | | |
| Retail electric | | $ | 2,352 | | | $ | 1,066 | | | $ | 1,430 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 4,847 | |
| Retail gas | | — | | | 473 | | | 79 | | | — | | | — | | | — | | | — | | | — | | | 552 | |
| Wholesale | | 110 | | | 280 | | | 35 | | | — | | | — | | | — | | | — | | | (2) | | | 423 | |
Transmission and
distribution | | 77 | | | 28 | | | 35 | | | 543 | | | — | | | 348 | | | — | | | — | | | 1,031 | |
| Interstate pipeline | | — | | | — | | | — | | | — | | | 1,269 | | | — | | | — | | | (68) | | | 1,201 | |
| Other | | 48 | | | — | | | 1 | | | — | | | 1 | | | — | | | — | | | — | | | 50 | |
| Total Regulated | | 2,587 | | | 1,847 | | | 1,580 | | | 543 | | | 1,270 | | | 348 | | | — | | | (71) | | | 8,104 | |
| Nonregulated | | — | | | 2 | | | 1 | | | 57 | | | 563 | | | 22 | | | 431 | | | 284 | | | 1,360 | |
| Total Customer Revenue | | 2,587 | | | 1,849 | | | 1,581 | | | 600 | | | 1,833 | | | 370 | | | 431 | | | 213 | | | 9,464 | |
| Other revenue | | 24 | | | 53 | | | 11 | | | 60 | | | 58 | | | (4) | | | 30 | | | 67 | | | 299 | |
| Total | | $ | 2,611 | | | $ | 1,902 | | | $ | 1,592 | | | $ | 660 | | | $ | 1,891 | | | $ | 366 | | | $ | 461 | | | $ | 280 | | | $ | 9,763 | |
| | | For the Three-Month Period Ended September 30, 2020 | | For the Three-Month Period Ended June 30, 2021 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total | | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
| Customer Revenue: | Customer Revenue: | | | | | | | | | | | | | | | | | | | Customer Revenue: | | | | | | | | | | | | | | | | | | |
| Regulated: | Regulated: | | Regulated: | |
| Retail electric | Retail electric | | $ | 1,344 | | | $ | 661 | | | $ | 977 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 2,981 | | Retail electric | | $ | 1,188 | | | $ | 516 | | | $ | 708 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 2,411 | |
| Retail gas | Retail gas | | — | | | 70 | | | 14 | | | — | | | — | | | — | | | — | | | — | | | 84 | | Retail gas | | — | | | 89 | | | 20 | | | — | | | — | | | — | | | — | | | — | | | 109 | |
| Wholesale | Wholesale | | 59 | | | 56 | | | 14 | | | — | | | — | | | — | | | — | | | 1 | | | 130 | | Wholesale | | 30 | | | 69 | | | 10 | | | — | | | — | | | — | | | — | | | (1) | | | 108 | |
Transmission and
distribution | Transmission and
distribution | | 33 | | | 15 | | | 30 | | | 208 | | | — | | | 169 | | | — | | | — | | | 455 | | Transmission and
distribution | | 37 | | | 15 | | | 22 | | | 243 | | | — | | | 178 | | | — | | | — | | | 495 | |
| Interstate pipeline | Interstate pipeline | | — | | | — | | | — | | | — | | | 264 | | | — | | | — | | | (29) | | | 235 | | Interstate pipeline | | — | | | — | | | — | | | — | | | 458 | | | — | | | — | | | (25) | | | 433 | |
| Other | Other | | 42 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 42 | | Other | | 31 | | | — | | | 1 | | | — | | | (1) | | | — | | | — | | | — | | | 31 | |
| Total Regulated | Total Regulated | | 1,478 | | | 802 | | | 1,035 | | | 208 | | | 264 | | | 169 | | | — | | | (29) | | | 3,927 | | Total Regulated | | 1,286 | | | 689 | | | 761 | | | 243 | | | 457 | | | 178 | | | — | | | (27) | | | 3,587 | |
| Nonregulated | Nonregulated | | — | | | 4 | | | (1) | | | 6 | | | — | | | 6 | | | 270 | | | 145 | | | 430 | | Nonregulated | | — | | | 1 | | | 1 | | | 8 | | | 232 | | | 7 | | | 239 | | | 124 | | | 612 | |
| Total Customer Revenue | Total Customer Revenue | | 1,478 | | | 806 | | | 1,034 | | | 214 | | | 264 | | | 175 | | | 270 | | | 116 | | | 4,357 | | Total Customer Revenue | | 1,286 | | | 690 | | | 762 | | | 251 | | | 689 | | | 185 | | | 239 | | | 97 | | | 4,199 | |
| Other revenue | Other revenue | | 1 | | | 6 | | | 8 | | | 32 | | | — | | | — | | | 39 | | | 8 | | | 94 | | Other revenue | | 12 | | | 3 | | | 5 | | | 29 | | | 17 | | | (3) | | | 28 | | | 11 | | | 102 | |
| Total | Total | | $ | 1,479 | | | $ | 812 | | | $ | 1,042 | | | $ | 246 | | | $ | 264 | | | $ | 175 | | | $ | 309 | | | $ | 124 | | | $ | 4,451 | | Total | | $ | 1,298 | | | $ | 693 | | | $ | 767 | | | $ | 280 | | | $ | 706 | | | $ | 182 | | | $ | 267 | | | $ | 108 | | | $ | 4,301 | |
| | | For the Nine-Month Period Ended September 30, 2020 | | For the Six-Month Period Ended June 30, 2021 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total | | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
| Customer Revenue: | Customer Revenue: | | | | | | | | | | | | | | | | | | | Customer Revenue: | | | | | | | | | | | | | | | | | | |
| Regulated: | Regulated: | | Regulated: | |
| Retail electric | Retail electric | | $ | 3,532 | | | $ | 1,539 | | | $ | 2,144 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 7,214 | | Retail electric | | $ | 2,333 | | | $ | 968 | | | $ | 1,219 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 4,519 | |
| Retail gas | Retail gas | | — | | | 341 | | | 81 | | | — | | | — | | | — | | | — | | | — | | | 422 | | Retail gas | | — | | | 549 | | | 58 | | | — | | | — | | | — | | | — | | | — | | | 607 | |
| Wholesale | Wholesale | | 76 | | | 157 | | | 34 | | | — | | | — | | | — | | | — | | | (1) | | | 266 | | Wholesale | | 66 | | | 194 | | | 25 | | | — | | | 17 | | | — | | | — | | | (1) | | | 301 | |
Transmission and
distribution | Transmission and
distribution | | 79 | | | 48 | | | 75 | | | 632 | | | — | | | 502 | | | — | | | — | | | 1,336 | | Transmission and
distribution | | 62 | | | 30 | | | 43 | | | 506 | | | — | | | 350 | | | — | | | — | | | 991 | |
| Interstate pipeline | Interstate pipeline | | — | | | — | | | — | | | — | | | 885 | | | — | | | — | | | (103) | | | 782 | | Interstate pipeline | | — | | | — | | | — | | | — | | | 1,273 | | | — | | | — | | | (66) | | | 1,207 | |
| Other | Other | | 88 | | | — | | | 1 | | | — | | | — | | | — | | | — | | | — | | | 89 | | Other | | 54 | | | — | | | 1 | | | — | | | 1 | | | — | | | — | | | — | | | 56 | |
| Total Regulated | Total Regulated | | 3,775 | | | 2,085 | | | 2,335 | | | 632 | | | 885 | | | 502 | | | — | | | (105) | | | 10,109 | | Total Regulated | | 2,515 | | | 1,741 | | | 1,346 | | | 506 | | | 1,291 | | | 350 | | | — | | | (68) | | | 7,681 | |
| Nonregulated | Nonregulated | | — | | | 13 | | | 1 | | | 18 | | | — | | | 14 | | | 641 | | | 394 | | | 1,081 | | Nonregulated | | — | | | 11 | | | 1 | | | 18 | | | 469 | | | 15 | | | 405 | | | 311 | | | 1,230 | |
| Total Customer Revenue | Total Customer Revenue | | 3,775 | | | 2,098 | | | 2,336 | | | 650 | | | 885 | | | 516 | | | 641 | | | 289 | | | 11,190 | | Total Customer Revenue | | 2,515 | | | 1,752 | | | 1,347 | | | 524 | | | 1,760 | | | 365 | | | 405 | | | 243 | | | 8,911 | |
| Other revenue | Other revenue | | 54 | | | 16 | | | 23 | | | 83 | | | 5 | | | — | | | 90 | | | 43 | | | 314 | | Other revenue | | 25 | | | 8 | | | 11 | | | 56 | | | 39 | | | (3) | | | 52 | | | 51 | | | 239 | |
| Total | Total | | $ | 3,829 | | | $ | 2,114 | | | $ | 2,359 | | | $ | 733 | | | $ | 890 | | | $ | 516 | | | $ | 731 | | | $ | 332 | | | $ | 11,504 | | Total | | $ | 2,540 | | | $ | 1,760 | | | $ | 1,358 | | | $ | 580 | | | $ | 1,799 | | | $ | 362 | | | $ | 457 | | | $ | 294 | | | $ | 9,150 | |
(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 | | HomeServices |
| | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Customer Revenue: | Customer Revenue: | | | | | | | | Customer Revenue: | | | | | | | |
| Brokerage | Brokerage | $ | 1,563 | | | $ | 1,449 | | | $ | 4,154 | | | $ | 3,183 | | Brokerage | $ | 1,544 | | | $ | 1,569 | | | $ | 2,636 | | | $ | 2,591 | |
| Franchise | Franchise | 23 | | | 23 | | | 65 | | | 54 | | Franchise | 17 | | | 24 | | | 37 | | | 42 | |
| Total Customer Revenue | Total Customer Revenue | 1,586 | | | 1,472 | | | 4,219 | | | 3,237 | | Total Customer Revenue | 1,561 | | | 1,593 | | | 2,673 | | | 2,633 | |
| Mortgage and other revenue | Mortgage and other revenue | 157 | | | 270 | | | 519 | | | 591 | | Mortgage and other revenue | 111 | | | 170 | | | 206 | | | 362 | |
| Total | Total | $ | 1,743 | | | $ | 1,742 | | | $ | 4,738 | | | $ | 3,828 | | Total | $ | 1,672 | | | $ | 1,763 | | | $ | 2,879 | | | $ | 2,995 | |
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 SeptemberJune 30, 2021,2022, by reportable segment (in millions):
| | | Performance obligations expected to be satisfied: | | | Performance obligations expected to be satisfied: | |
| | Less than 12 months | | More than 12 months | | Total | | Less than 12 months | | More than 12 months | | Total |
| BHE Pipeline Group | BHE Pipeline Group | $ | 2,586 | | | $ | 21,377 | | | $ | 23,963 | | BHE Pipeline Group | $ | 3,324 | | | $ | 21,878 | | | $ | 25,202 | |
| BHE Transmission | BHE Transmission | 175 | | | — | | | 175 | | BHE Transmission | 695 | | | 348 | | | 1,043 | |
| Total | Total | $ | 2,761 | | | $ | 21,377 | | | $ | 24,138 | | Total | $ | 4,019 | | | $ | 22,226 | | | $ | 26,245 | |
(11) (10) BHE Shareholders' Equity
On July 22, 2021,In May 2022, BHE redeemed at par 1,450,003800,006 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $1.45 billion,$800 million, plus an additional amount equal to the accrued dividends on the pro rata shares redeemed.
In June 2022, BHE purchased 740,961 shares of its common stock held by Mr. Gregory E. Abel, BHE's Chair, for $870 million. The purchase was pursuant to the terms of BHE's Shareholders Agreement.
(1211) Components of Accumulated Other Comprehensive Income (Loss),Loss, Net
The following table shows the change in accumulated other comprehensive income (loss)loss by each component of other comprehensive income (loss), net of applicable income tax (in millions):
| | | Unrecognized | | Foreign | | Unrealized | | AOCI | | Unrecognized | | Foreign | | Unrealized | | AOCI |
| | Amounts on | | Currency | | (Losses) Gains | | Attributable | | Amounts on | | Currency | | (Losses) Gains | | Attributable |
| | Retirement | | Translation | | on Cash | | Noncontrolling | | To BHE | | Retirement | | Translation | | on Cash | | Noncontrolling | | To BHE |
| | Benefits | | Adjustment | | Flow Hedges | | Interests | | Shareholders, Net | | Benefits | | Adjustment | | Flow Hedges | | Interests | | Shareholders, Net |
| | Balance, December 31, 2019 | | $ | (417) | | | $ | (1,296) | | | $ | 7 | | | $ | — | | | $ | (1,706) | | |
| Other comprehensive income (loss) | | 38 | | | (195) | | | (20) | | | — | | | (177) | | |
| Balance, September 30, 2020 | | $ | (379) | | | $ | (1,491) | | | $ | (13) | | | $ | — | | | $ | (1,883) | | |
| | Balance, December 31, 2020 | Balance, December 31, 2020 | | $ | (492) | | | $ | (1,062) | | | $ | (8) | | | $ | 10 | | | $ | (1,552) | | Balance, December 31, 2020 | | $ | (492) | | | $ | (1,062) | | | $ | (8) | | | $ | 10 | | | $ | (1,552) | |
| Other comprehensive income (loss) | Other comprehensive income (loss) | | 44 | | | (59) | | | 48 | | | (4) | | | 29 | | Other comprehensive income (loss) | | 22 | | | 159 | | | 15 | | | (4) | | | 192 | |
| Balance, September 30, 2021 | | $ | (448) | | | $ | (1,121) | | | $ | 40 | | | $ | 6 | | | $ | (1,523) | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | | $ | (470) | | | $ | (903) | | | $ | 7 | | | $ | 6 | | | $ | (1,360) | |
| | Balance, December 31, 2021 | | Balance, December 31, 2021 | | $ | (318) | | | $ | (1,086) | | | $ | 59 | | | $ | 5 | | | $ | (1,340) | |
| Other comprehensive income (loss) | | Other comprehensive income (loss) | | 40 | | | (591) | | | 103 | | | — | | | (448) | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | | $ | (278) | | | $ | (1,677) | | | $ | 162 | | | $ | 5 | | | $ | (1,788) | |
(1312) Segment Information
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, and BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines.Canada. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
| | | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | | | | |
| PacifiCorp | PacifiCorp | $ | 1,491 | | | $ | 1,479 | | | $ | 4,031 | | | $ | 3,829 | | PacifiCorp | $ | 1,314 | | | $ | 1,298 | | | $ | 2,611 | | | $ | 2,540 | |
| MidAmerican Funding | MidAmerican Funding | 966 | | | 812 | | | 2,726 | | | 2,114 | | MidAmerican Funding | 897 | | | 693 | | | 1,902 | | | 1,760 | |
| NV Energy | NV Energy | 1,085 | | | 1,042 | | | 2,443 | | | 2,359 | | NV Energy | 899 | | | 767 | | | 1,592 | | | 1,358 | |
| Northern Powergrid | Northern Powergrid | 277 | | | 246 | | | 857 | | | 733 | | Northern Powergrid | 345 | | | 280 | | | 660 | | | 580 | |
| BHE Pipeline Group | BHE Pipeline Group | 785 | | | 264 | | | 2,584 | | | 890 | | BHE Pipeline Group | 856 | | | 706 | | | 1,891 | | | 1,799 | |
| BHE Transmission | BHE Transmission | 185 | | | 175 | | | 547 | | | 516 | | BHE Transmission | 183 | | | 182 | | | 366 | | | 362 | |
| BHE Renewables | BHE Renewables | 316 | | | 309 | | | 773 | | | 731 | | BHE Renewables | 294 | | | 267 | | | 461 | | | 457 | |
| HomeServices | HomeServices | 1,743 | | | 1,742 | | | 4,738 | | | 3,828 | | HomeServices | 1,672 | | | 1,763 | | | 2,879 | | | 2,995 | |
BHE and Other(1) | BHE and Other(1) | 120 | | | 124 | | | 414 | | | 332 | | BHE and Other(1) | 152 | | | 108 | | | 280 | | | 294 | |
| Total operating revenue | Total operating revenue | $ | 6,968 | | | $ | 6,193 | | | $ | 19,113 | | | $ | 15,332 | | Total operating revenue | $ | 6,612 | | | $ | 6,064 | | | $ | 12,642 | | | $ | 12,145 | |
| | | | Depreciation and amortization: | Depreciation and amortization: | | Depreciation and amortization: | |
| PacifiCorp | PacifiCorp | $ | 272 | | | $ | 234 | | | $ | 811 | | | $ | 696 | | PacifiCorp | $ | 279 | | | $ | 275 | | | $ | 559 | | | $ | 539 | |
| MidAmerican Funding | MidAmerican Funding | 218 | | | 179 | | | 634 | | | 530 | | MidAmerican Funding | 277 | | | 209 | | | 527 | | | 416 | |
| NV Energy | NV Energy | 138 | | | 128 | | | 411 | | | 377 | | NV Energy | 139 | | | 137 | | | 279 | | | 273 | |
| Northern Powergrid | Northern Powergrid | 73 | | | 69 | | | 217 | | | 195 | | Northern Powergrid | 100 | | | 73 | | | 180 | | | 144 | |
| BHE Pipeline Group | BHE Pipeline Group | 124 | | | 45 | | | 363 | | | 134 | | BHE Pipeline Group | 125 | | | 121 | | | 256 | | | 239 | |
| BHE Transmission | BHE Transmission | 59 | | | 61 | | | 177 | | | 176 | | BHE Transmission | 60 | | | 60 | | | 118 | | | 118 | |
| BHE Renewables | BHE Renewables | 61 | | | 72 | | | 182 | | | 214 | | BHE Renewables | 66 | | | 61 | | | 131 | | | 121 | |
| HomeServices | HomeServices | 14 | | | 11 | | | 37 | | | 34 | | HomeServices | 14 | | | 12 | | | 29 | | | 23 | |
BHE and Other(1) | BHE and Other(1) | 1 | | | 1 | | | 2 | | | 1 | | BHE and Other(1) | (1) | | | (1) | | | 2 | | | 1 | |
| Total depreciation and amortization | Total depreciation and amortization | $ | 960 | | | $ | 800 | | | $ | 2,834 | | | $ | 2,357 | | Total depreciation and amortization | $ | 1,059 | | | $ | 947 | | | $ | 2,081 | | | $ | 1,874 | |
| | | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating income: | Operating income: | | | | | | | | Operating income: | | | | | | | |
| PacifiCorp | PacifiCorp | $ | 394 | | | $ | 361 | | | $ | 911 | | | $ | 851 | | PacifiCorp | $ | 158 | | | $ | 283 | | | $ | 374 | | | $ | 517 | |
| MidAmerican Funding | MidAmerican Funding | 287 | | | 232 | | | 438 | | | 444 | | MidAmerican Funding | 90 | | | 103 | | | 190 | | | 151 | |
| NV Energy | NV Energy | 348 | | | 347 | | | 563 | | | 587 | | NV Energy | 140 | | | 145 | | | 202 | | | 215 | |
| Northern Powergrid | Northern Powergrid | 126 | | | 106 | | | 403 | | | 327 | | Northern Powergrid | 110 | | | 126 | | | 269 | | | 277 | |
| BHE Pipeline Group | BHE Pipeline Group | 303 | | | 101 | | | 1,166 | | | 442 | | BHE Pipeline Group | 352 | | | 245 | | | 890 | | | 863 | |
| BHE Transmission | BHE Transmission | 90 | | | 79 | | | 256 | | | 236 | | BHE Transmission | 84 | | | 85 | | | 167 | | | 166 | |
| BHE Renewables | BHE Renewables | 149 | | | 143 | | | 279 | | | 244 | | BHE Renewables | 134 | | | 97 | | | 132 | | | 130 | |
| HomeServices | HomeServices | 135 | | | 239 | | | 426 | | | 336 | | HomeServices | 117 | | | 179 | | | 145 | | | 291 | |
BHE and Other(1) | BHE and Other(1) | 2 | | | (61) | | | (67) | | | (65) | | BHE and Other(1) | 22 | | | (55) | | | 74 | | | (69) | |
| Total operating income | Total operating income | 1,834 | | | 1,547 | | | 4,375 | | | 3,402 | | Total operating income | 1,207 | | | 1,208 | | | 2,443 | | | 2,541 | |
| Interest expense | Interest expense | (531) | | | (504) | | | (1,593) | | | (1,490) | | Interest expense | (550) | | | (532) | | | (1,082) | | | (1,062) | |
| Capitalized interest | Capitalized interest | 18 | | | 24 | | | 46 | | | 60 | | Capitalized interest | 18 | | | 14 | | | 35 | | | 28 | |
| Allowance for equity funds | Allowance for equity funds | 34 | | | 50 | | | 90 | | | 122 | | Allowance for equity funds | 42 | | | 30 | | | 80 | | | 56 | |
| Interest and dividend income | Interest and dividend income | 18 | | | 17 | | | 65 | | | 57 | | Interest and dividend income | 30 | | | 26 | | | 53 | | | 47 | |
| Gains on marketable securities, net | Gains on marketable securities, net | 294 | | | 1,797 | | | 1,142 | | | 2,407 | | Gains on marketable securities, net | 2,528 | | | 1,966 | | | 1,271 | | | 848 | |
| Other, net | Other, net | 8 | | | 36 | | | 64 | | | 61 | | Other, net | (26) | | | 48 | | | (21) | | | 56 | |
| Total income before income tax (benefit) expense and equity loss | $ | 1,675 | | | $ | 2,967 | | | $ | 4,189 | | | $ | 4,619 | | |
| Total income before income tax expense (benefit) and equity loss | | Total income before income tax expense (benefit) and equity loss | $ | 3,249 | | | $ | 2,760 | | | $ | 2,779 | | | $ | 2,514 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | | | |
| Interest expense: | | | | | | | |
| PacifiCorp | $ | 110 | | | $ | 107 | | | $ | 322 | | | $ | 319 | |
| MidAmerican Funding | 81 | | | 79 | | | 237 | | | 238 | |
| NV Energy | 51 | | | 56 | | | 154 | | | 171 | |
| Northern Powergrid | 33 | | | 34 | | | 98 | | | 97 | |
| BHE Pipeline Group | 33 | | | 15 | | | 111 | | | 44 | |
| BHE Transmission | 39 | | | 38 | | | 117 | | | 111 | |
| BHE Renewables | 39 | | | 41 | | | 119 | | | 125 | |
| HomeServices | 1 | | | 1 | | | 3 | | | 9 | |
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 Funding | 373 | | | 337 | | | 728 | | | 695 | |
| NV Energy | 282 | | | 249 | | | 416 | | | 367 | |
| Northern Powergrid | 83 | | | 26 | | | 162 | | | 172 | |
| BHE Pipeline Group | 144 | | | 78 | | | 627 | | | 321 | |
| BHE Transmission | 65 | | | 58 | | | 184 | | | 173 | |
| BHE Renewables | 163 | | | 162 | | | 360 | | | 395 | |
| HomeServices | 102 | | | 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 | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | | | |
| Interest expense: | | | | | | | |
| PacifiCorp | $ | 107 | | | $ | 105 | | | $ | 213 | | | $ | 212 | |
| MidAmerican Funding | 83 | | | 78 | | | 165 | | | 156 | |
| NV Energy | 52 | | | 51 | | | 103 | | | 103 | |
| Northern Powergrid | 34 | | | 32 | | | 66 | | | 65 | |
| BHE Pipeline Group | 36 | | | 40 | | | 73 | | | 78 | |
| BHE Transmission | 38 | | | 40 | | | 76 | | | 78 | |
| BHE Renewables | 45 | | | 40 | | | 86 | | | 80 | |
| HomeServices | 2 | | | 1 | | | 3 | | | 2 | |
BHE and Other(1) | 153 | | | 145 | | | 297 | | | 288 | |
| Total interest expense | $ | 550 | | | $ | 532 | | | $ | 1,082 | | | $ | 1,062 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Earnings on common shares: | | | | | | | |
| PacifiCorp | $ | 83 | | | $ | 226 | | | $ | 213 | | | $ | 395 | |
| MidAmerican Funding | 204 | | | 211 | | | 445 | | | 355 | |
| NV Energy | 93 | | | 100 | | | 122 | | | 134 | |
| Northern Powergrid | 71 | | | (25) | | | 182 | | | 79 | |
| BHE Pipeline Group | 199 | | | 100 | | | 521 | | | 483 | |
| BHE Transmission | 62 | | | 60 | | | 124 | | | 119 | |
| BHE Renewables | 249 | | | 181 | | | 353 | | | 197 | |
| HomeServices | 84 | | | 135 | | | 105 | | | 219 | |
BHE and Other(1) | 1,839 | | | 1,256 | | | 674 | | | 229 | |
| Total earnings on common shares | $ | 2,884 | | | $ | 2,244 | | | $ | 2,739 | | | $ | 2,210 | |
| | | | | | | |
| | | | As of | | As of |
| | | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Assets: | Assets: | | | | Assets: | | | |
| PacifiCorp | PacifiCorp | $ | 28,230 | | | $ | 26,862 | | PacifiCorp | $ | 28,596 | | | $ | 27,615 | |
| MidAmerican Funding | MidAmerican Funding | 25,038 | | | 23,530 | | MidAmerican Funding | 25,733 | | | 25,352 | |
| NV Energy | NV Energy | 15,105 | | | 14,501 | | NV Energy | 15,905 | | | 15,239 | |
| Northern Powergrid | Northern Powergrid | 9,043 | | | 8,782 | | Northern Powergrid | 9,343 | | | 9,326 | |
| BHE Pipeline Group | BHE Pipeline Group | 19,993 | | | 19,541 | | BHE Pipeline Group | 20,691 | | | 20,434 | |
| BHE Transmission | BHE Transmission | 9,383 | | | 9,208 | | BHE Transmission | 9,441 | | | 9,476 | |
| BHE Renewables | BHE Renewables | 11,766 | | | 12,004 | | BHE Renewables | 11,853 | | | 11,829 | |
| HomeServices | HomeServices | 5,065 | | | 4,955 | | HomeServices | 4,115 | | | 4,574 | |
BHE and Other(1) | BHE and Other(1) | 7,931 | | | 7,933 | | BHE and Other(1) | 9,618 | | | 8,220 | |
| Total assets | Total assets | $ | 131,554 | | | $ | 127,316 | | Total assets | $ | 135,295 | | | $ | 132,065 | |
(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
| | | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue by country: | Operating revenue by country: | | | | | | | | Operating revenue by country: | | | | | | | |
| United States | $ | 6,499 | | | $ | 5,773 | | | $ | 17,700 | | | $ | 14,086 | | |
| U.S. | | U.S. | $ | 6,087 | | | $ | 5,604 | | | $ | 11,621 | | | $ | 11,201 | |
| United Kingdom | United Kingdom | 277 | | | 246 | | | 857 | | | 733 | | United Kingdom | 345 | | | 280 | | | 660 | | | 580 | |
| Canada | Canada | 180 | | | 174 | | | 537 | | | 512 | | Canada | 180 | | | 180 | | | 361 | | | 357 | |
| Philippines and other | 12 | | | — | | | 19 | | | 1 | | |
| Other | | Other | — | | | — | | | — | | | 7 | |
| Total operating revenue by country | Total operating revenue by country | $ | 6,968 | | | $ | 6,193 | | | $ | 19,113 | | | $ | 15,332 | | Total operating revenue by country | $ | 6,612 | | | $ | 6,064 | | | $ | 12,642 | | | $ | 12,145 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Income before income tax (benefit) expense and equity loss by country: | | | | | | | |
| United States | $ | 1,511 | | | $ | 2,839 | | | $ | 3,699 | | | $ | 4,220 | |
| United Kingdom | 107 | | | 82 | | | 343 | | | 250 | |
| Canada | 49 | | | 44 | | | 134 | | | 130 | |
| Philippines and other | 8 | | | 2 | | | 13 | | | 19 | |
| Total income before income tax (benefit) expense and equity loss by country | $ | 1,675 | | | $ | 2,967 | | | $ | 4,189 | | | $ | 4,619 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Income before income tax expense (benefit) and equity loss by country: | | | | | | | |
| U.S. | $ | 3,117 | | | $ | 2,611 | | | $ | 2,463 | | | $ | 2,188 | |
| United Kingdom | 87 | | | 104 | | | 226 | | | 236 | |
| Canada | 46 | | | 46 | | | 92 | | | 85 | |
| Other | (1) | | | (1) | | | (2) | | | 5 | |
| Total income before income tax expense (benefit) and equity loss by country | $ | 3,249 | | | $ | 2,760 | | | $ | 2,779 | | | $ | 2,514 | |
The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-monthsix-month period ended SeptemberJune 30, 20212022 (in millions):
| | | BHE Pipeline Group | | | | | BHE Pipeline Group | | | |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Transmission | | BHE Renewables | | HomeServices | | | | | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Transmission | | BHE Renewables | | HomeServices | | | |
| | BHE Pipeline Group | | Total | | BHE Pipeline Group | | Total |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 1,000 | | | $ | 1,803 | | | $ | 1,551 | | | $ | 95 | | | $ | 1,457 | | | $ | 11,506 | | |
| December 31, 2021 | | December 31, 2021 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 992 | | | $ | 1,814 | | | $ | 1,563 | | | $ | 95 | | | $ | 1,586 | | | | $ | 11,650 | |
| Acquisitions | Acquisitions | — | | | — | | | — | | | — | | | 11 | | | — | | | — | | | 59 | | | | 70 | | Acquisitions | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 8 | | | | 8 | |
| Foreign currency translation | Foreign currency translation | — | | | — | | | — | | | (10) | | | — | | | 6 | | | — | | | — | | | | (4) | | Foreign currency translation | — | | | — | | | — | | | (70) | | | — | | | (29) | | | — | | | — | | | | (99) | |
| | September 30, 2021 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 990 | | | $ | 1,814 | | | $ | 1,557 | | | $ | 95 | | | $ | 1,516 | | | | $ | 11,572 | | |
| June 30, 2022 | | June 30, 2022 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 922 | | | $ | 1,814 | | | $ | 1,534 | | | $ | 95 | | | $ | 1,594 | | | | $ | 11,559 | |
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.
BHE is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway. As of August 4, 2022, Berkshire Hathaway and family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, beneficially owned 92% and 8%, respectively, of BHE's common stock.
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 StatesU.S. 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,U.S., an electric transmission business in Canada, interests in electric transmission businesses in the United States,U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United StatesU.S. and one of the largest residential real estate brokerage franchise networks in the United States.U.S. 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.
Results of Operations for the ThirdSecond Quarter and First NineSix Months of 20212022 and 20202021
Overview
Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Operating revenue: | Operating revenue: | | | | | | | | | | | | Operating revenue: | | | | | | | | | | | |
| PacifiCorp | PacifiCorp | $ | 1,491 | | | $ | 1,479 | | | $ | 12 | | | 1 | % | | $ | 4,031 | | | $ | 3,829 | | | $ | 202 | | | 5 | % | PacifiCorp | $ | 1,314 | | | $ | 1,298 | | | $ | 16 | | | 1 | % | | $ | 2,611 | | | $ | 2,540 | | | $ | 71 | | | 3 | % |
| MidAmerican Funding | MidAmerican Funding | 966 | | | 812 | | | 154 | | | 19 | | | 2,726 | | | 2,114 | | | 612 | | | 29 | | MidAmerican Funding | 897 | | | 693 | | | 204 | | | 29 | | | 1,902 | | | 1,760 | | | 142 | | | 8 | |
| NV Energy | NV Energy | 1,085 | | | 1,042 | | | 43 | | | 4 | | | 2,443 | | | 2,359 | | | 84 | | | 4 | | NV Energy | 899 | | | 767 | | | 132 | | | 17 | | | 1,592 | | | 1,358 | | | 234 | | | 17 | |
| Northern Powergrid | Northern Powergrid | 277 | | | 246 | | | 31 | | | 13 | | | 857 | | | 733 | | | 124 | | | 17 | | Northern Powergrid | 345 | | | 280 | | | 65 | | | 23 | | | 660 | | | 580 | | | 80 | | | 14 | |
| BHE Pipeline Group | BHE Pipeline Group | 785 | | | 264 | | | 521 | | | * | | 2,584 | | | 890 | | | 1,694 | | | * | BHE Pipeline Group | 856 | | | 706 | | | 150 | | | 21 | | | 1,891 | | | 1,799 | | | 92 | | | 5 |
| BHE Transmission | BHE Transmission | 185 | | | 175 | | | 10 | | | 6 | | | 547 | | | 516 | | | 31 | | | 6 | | BHE Transmission | 183 | | | 182 | | | 1 | | | 1 | | | 366 | | | 362 | | | 4 | | | 1 | |
| BHE Renewables | BHE Renewables | 316 | | | 309 | | | 7 | | | 2 | | | 773 | | | 731 | | | 42 | | | 6 | | BHE Renewables | 294 | | | 267 | | | 27 | | | 10 | | | 461 | | | 457 | | | 4 | | | 1 | |
| HomeServices | HomeServices | 1,743 | | | 1,742 | | | 1 | | | — | | | 4,738 | | | 3,828 | | | 910 | | | 24 | | HomeServices | 1,672 | | | 1,763 | | | (91) | | | (5) | | | 2,879 | | | 2,995 | | | (116) | | | (4) | |
| BHE and Other | BHE and Other | 120 | | | 124 | | | (4) | | | (3) | | | 414 | | | 332 | | | 82 | | | 25 | | BHE and Other | 152 | | | 108 | | | 44 | | | 41 | | | 280 | | | 294 | | | (14) | | | (5) | |
| Total operating revenue | Total operating revenue | $ | 6,968 | | | $ | 6,193 | | | $ | 775 | | | 13 | % | | $ | 19,113 | | | $ | 15,332 | | | $ | 3,781 | | | 25 | % | Total operating revenue | $ | 6,612 | | | $ | 6,064 | | | $ | 548 | | | 9 | % | | $ | 12,642 | | | $ | 12,145 | | | $ | 497 | | | 4 | % |
| | Earnings on common shares: | Earnings on common shares: | | Earnings on common shares: | |
| PacifiCorp | PacifiCorp | $ | 333 | | | $ | 286 | | | $ | 47 | | | 16 | % | | $ | 728 | | | $ | 629 | | | $ | 99 | | | 16 | % | PacifiCorp | $ | 83 | | | $ | 226 | | | $ | (143) | | | (63) | % | | $ | 213 | | | $ | 395 | | | $ | (182) | | | (46) | % |
| MidAmerican Funding | MidAmerican Funding | 373 | | | 337 | | | 36 | | | 11 | | | 728 | | | 695 | | | 33 | | | 5 | | MidAmerican Funding | 204 | | | 211 | | | (7) | | | (3) | | | 445 | | | 355 | | | 90 | | | 25 | |
| NV Energy | NV Energy | 282 | | | 249�� | | | 33 | | | 13 | | | 416 | | | 367 | | | 49 | | | 13 | | NV Energy | 93 | | | 100 | | | (7) | | | (7) | | | 122 | | | 134 | | | (12) | | | (9) | |
| Northern Powergrid | Northern Powergrid | 83 | | | 26 | | | 57 | | | * | | 162 | | | 172 | | | (10) | | | (6) | | Northern Powergrid | 71 | | | (25) | | | 96 | | | * | | 182 | | | 79 | | | 103 | | | * |
| BHE Pipeline Group | BHE Pipeline Group | 144 | | | 78 | | | 66 | | | 85 | | | 627 | | | 321 | | | 306 | | | 95 | | BHE Pipeline Group | 199 | | | 100 | | | 99 | | | 99 | | | 521 | | | 483 | | | 38 | | | 8 | |
| BHE Transmission | BHE Transmission | 65 | | | 58 | | | 7 | | | 12 | | | 184 | | | 173 | | | 11 | | | 6 | | BHE Transmission | 62 | | | 60 | | | 2 | | | 3 | | | 124 | | | 119 | | | 5 | | | 4 | |
BHE Renewables(1) | BHE Renewables(1) | 163 | | | 162 | | | 1 | | | 1 | | | 360 | | | 395 | | | (35) | | | (9) | | BHE Renewables(1) | 249 | | | 181 | | | 68 | | | 38 | | 353 | | | 197 | | | 156 | | | 79 | |
| HomeServices | HomeServices | 102 | | | 177 | | | (75) | | | (42) | | | 321 | | | 246 | | | 75 | | | 30 | HomeServices | 84 | | | 135 | | | (51) | | | (38) | | | 105 | | | 219 | | | (114) | | | (52) | |
| BHE and Other | BHE and Other | 351 | | | 1,469 | | | (1,118) | | | (76) | | | 580 | | | 1,630 | | | (1,050) | | | (64) | | BHE and Other | 1,839 | | | 1,256 | | | 583 | | | 46 | | | 674 | | | 229 | | | 445 | | | * |
| Total earnings on common shares | Total earnings on common shares | $ | 1,896 | | | $ | 2,842 | | | $ | (946) | | | (33) | % | | $ | 4,106 | | | $ | 4,628 | | | $ | (522) | | | (11) | % | Total earnings on common shares | $ | 2,884 | | | $ | 2,244 | | | $ | 640 | | | 29 | % | | $ | 2,739 | | | $ | 2,210 | | | $ | 529 | | | 24 | % |
(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
* Not meaningful
Earnings on common shares decreased $946increased $640 million for the thirdsecond quarter of 20212022 compared to 2020.2021. The thirdsecond quarter of 20212022 included a pre-tax unrealized gain of $296$2,557 million ($2532,020 million after-tax) compared to a pre-tax unrealized gain in the thirdsecond quarter of 20202021 of $1,787$1,954 million ($1,2991,420 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 thirdsecond quarter of 20212022 was $1,643$864 million, an increase of $100$40 million, or 6%5%, compared to adjusted earnings on common shares in the thirdsecond quarter of 20202021 of $1,543$824 million.
Earnings on common shares decreased $522increased $529 million for the first ninesix months of 20212022 compared to 2020.2021. The first ninesix months of 20212022 included a pre-tax unrealized gain of $1,126$1,310 million ($8551,035 million after-tax) compared to a pre-tax unrealized gain in the first ninesix months of 20202021 of $2,402$830 million ($1,746602 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 ninesix months of 20212022 was $3,251$1,704 million, an increase of $369$96 million, or 13%6%, compared to adjusted earnings on commoncommons shares in the first ninesix months of 20202021 of $2,882$1,608 million.
The decreasesincreases in earnings on common shares for the thirdsecond quarter and for the first ninesix months of 20212022 compared to 20202021 were primarily due to the following:
•The Utilities' earnings increased $116decreased $157 million for the thirdsecond quarter and $181$104 million for the first ninesix months of 20212022 compared to 2020,2021, reflecting higher operations and maintenance expense, higher depreciation and amortization expense and unfavorable investment earnings, partially offset by higher electric utility margin and a favorable income tax expense,benefit from higher PTCs recognized and the impacts of ratemaking, and lower operations and maintenance expense, partially offset by higher depreciation and amortization expense.recognized. Electric retail customer volumes increased 4.8%1.3% for the first ninesix months of 20212022 compared to 2020,2021, 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$96 million for the thirdsecond quarter and decreased $10$103 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to a deferred income tax charges ($35 million in third quarter 2020 andcharge of $109 million in second quarter 2021) related to a June 2021 enacted increasesincrease in the United Kingdom corporate income tax rate and higher distribution revenue;from 19% to 25% effective April 1, 2023;
•BHE Pipeline Group's earnings increased $66$99 million for the thirdsecond quarter and $306$38 million for the first ninesix months of 20212022 compared to 2020,2021, largely due to $74 million and $247 million, respectively, of incrementalhigher earnings fromat BHE GT&S acquired in November 2020.from favorable state unitary income tax adjustments, the impacts of the EGTS general rate case and lower operations and maintenance expense. In addition, earnings for the first ninesix months increaseddecreased from the effects of higher margins on natural gas sales and higher transportation revenue in the first quarter of 2021 at Northern Natural Gas largely due to the favorable impacts offrom the February 2021 polar vortex weather event;
•BHE Renewables' earnings decreased $35increased $68 million for the second quarter and $156 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to lowerhigher operating revenue from owned renewable energy projects and higher earnings from tax equity investment earningsinvestments, with the first six months being positively impacted by the unfavorable impacts in the first quarter of 2021 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;event;
•HomeServices' earnings decreased $75$51 million for the thirdsecond quarter and increased $75$114 million for the first ninesix months of 20212022 compared to 2020, primarily due to2021, reflecting lower earnings from mortgage services duemainly from a decrease in funded volumes and lower earnings from brokerage and settlement services largely attributable 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;units at existing companies; and
•BHE and Other's earnings decreased $1,118increased $583 million for the thirdsecond quarter and $1,050$445 million for the first ninesix months of 20212022 compared to 2020,2021, mainly due to $1,046$600 million and $891$433 million, respectively, of unfavorablefavorable changes in the after-tax unrealized position of the Company's investment in BYD Company Limited and lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway, in October 2020.partially offset by lower federal income tax credits recognized on a consolidated basis.
Reportable Segment Results
PacifiCorp
Operating revenue increased $12$16 million for the thirdsecond quarter of 20212022 compared to 2020,2021, 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$30 million, partially offset by price impactslower retail revenue 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.$14 million. Wholesale and other revenue increased primarily due to higher average wholesale prices and higher wheeling revenue. Retail revenue and REC sales,decreased primarily due to lower retail volumes of $42 million, partially offset by $27price impacts of $28 million from higher average retail rates primarily due to tariff changes. Retail customer volumes decreased 3.3%, primarily due to the Oregon RAC settlement (offsetunfavorable impact of weather and lower customer usage, partially offset by an increase in depreciation expense) recognized in 2020.the average number of customers.
Earnings increased $47decreased $143 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to lowerhigher operations and maintenance expense of $65$120 million, favorablean unfavorable income tax expense, frombenefit and unfavorable changes in the impactscash surrender value of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, andcorporate-owned life insurance policies, partially offset by higher utility margin of $6 million, partially offset bymillion. Operations and maintenance expense increased mainly due to an increase in the loss accruals associated with the September 2020 wildfires, net of estimated insurance recoveries, and higher depreciationgeneral and amortization expense of $38 million and lower allowances for equity and borrowed funds used during construction of $24 million.plant maintenance costs. Utility margin increased primarily due to lower purchased power costs and the higher wholesale and other revenue, partially offset by higher thermal generation costs, the lower retail revenue and lower deferred net power costs in accordance with established adjustment mechanismsmechanisms. The unfavorable income tax benefit was largely due to lower PTCs recognized of $22 million 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 impactseffects of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.ratemaking of $18 million.
Operating revenue increased $202$71 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to higher retail revenue of $152 million and higher wholesale and other revenue of $50$45 million and higher retail revenue of $26 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 average wholesale prices and higher wheeling revenue. Retail revenue wholesale volumes and REC sales,increased primarily due to price impacts of $43 million from higher average retail rates largely due to tariff changes, partially offset by $34 million fromlower retail volumes of $17 million. Retail customer volumes decreased 0.7%, primarily due to the Oregon RAC settlement (offsetunfavorable impact of weather and lower customer usage, partially offset by an increase in depreciation expense) recognized in 2020.the average number of customers.
Earnings increased $99decreased $182 million for the first ninesix months of 20212022 compared to 2020,2021, 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$138 million, partially offset byan unfavorable income tax benefit, higher depreciation and amortization expense of $115$20 million, mainly from additional assets placed in-service, and lower allowances for equityunfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by higher utility margin of $20 million. Operations and borrowed funds used during constructionmaintenance expense increased mainly due to an increase in loss accruals related to the September 2020 wildfires, net of $53 million.estimated insurance recoveries, and higher general and plant maintenance costs. Utility margin increased primarily due to the higher retail, wholesale and wheelingother 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 primarilycosts. The unfavorable income tax benefit was largely due to 2020 costs associated withlower PTCs recognized of $27 million and 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 impactseffects of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.ratemaking of $27 million.
MidAmerican Funding
Operating revenue increased $154$204 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to higher electric operating revenue of $126$139 million and higher natural gas operating revenue of $30$65 million. Electric operating revenue increased due to higher retail revenue of $67$77 million and higher wholesale and other revenue of $59$62 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $43$59 million (largely(fully offset in expense, primarily cost of sales) and higher customer volumes of $24$11 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$59 million. Electric retail customer volumes increased 3.3% due to higher customer usage and higher wholesale volumesthe favorable impact of $17 million.weather. Natural gas operating revenue increased due to higher purchased gas adjustment recoveries of $63 million (fully offset in cost of sales), primarily from 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).sold.
Earnings increased $36decreased $7 million for the thirdsecond quarter of 20212022 compared to 2020,2021, 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$68 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies, higher operations and maintenance expense of $16 million and higher interest expense of $5 million, partially offset by higher electric utility margin of $68 million, a favorable income tax benefit and higher allowances for equity and borrowed funds used during construction of $9 million. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service. 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 primarilyThe favorable income tax benefit was largely due to additional assets placed in-service as well ashigher PTCs recognized of $39 million from higher wind-powered generation, partially offset by the impactseffects of certain regulatory mechanisms.ratemaking.
Operating revenue increased $612$142 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to higher electric operating revenue of $202 million, partially offset by lower natural gas operating revenue of $344 million and higher electric operating revenue of $268$51 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$105 million and higher retail revenue of $97 million. Electric wholesale and other revenue increased mainly due to higher average wholesale per-unit prices of $78 million and higher wholesale volumes of $28 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $91$63 million (largely(fully offset in expense, primarily cost of sales) and higher customer volumes of $28 million. Electric retail customer volumes increased 4.4% due to higher customer usage and the favorable impact of weather. Natural gas operating revenue decreased due to lower purchased gas adjustment recoveries of $71 million (fully offset in cost of sales), higher customer volumesprimarily from a lower average per-unit cost of $59 million and pricenatural gas sold driven largely by the February 2021 polar vortex weather event, partially offset by the impacts of $7certain regulatory recovery mechanisms of $5 million, from changes in sales mix. Electric retail customer volumes increased 6.5% due to increased usagethe impacts of certain industrial customerstax reform of $5 million and the favorable impact of weather. Electric wholesale and other revenue increased due to higher wholesale volumesweather of $64 million and higher average wholesale per-unit prices of $42$5 million.
Earnings increased $33$90 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to higher electric utility margin of $117$157 million, and a favorable income tax benefit, higher natural gas utility margin of $20 million and higher allowances for equity and borrowed funds used during construction of $20 million, partially offset by higher depreciation and amortization expense of $104$111 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies, higher operations and maintenance expense of $18$15 million, higher interest expense of $9 million and lower allowances for equity and borrowed fundsnonregulated utility margin of $12$8 million. Electric utility margin increased primarily due to the higher retailwholesale and wholesaleretail revenues, partially offset by higher thermal generation and purchased power costs. OperationsThe favorable income tax benefit was mainly due to higher PTCs recognized of $91 million from higher wind-powered generation, partially offset by the effects of ratemaking. Depreciation and maintenanceamortization 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 facilitiesmechanisms and additional assets placed in-service, partially offset by the impacts of ratemaking.in-service.
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$132 million for the thirdsecond quarter of 20212022 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$123 million partially offset by lowerand higher natural gas operating revenue of $8 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (offset(fully offset in cost of sales) of $153$121 million and higher retail customer volumes,regulatory-related revenue deferrals of $11 million, partially offset by unfavorable price impacts from changes in sales mix andof $12 million. Electric retail customer volumes increased 0.4%, primarily due to 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 favorableunfavorable impact of weather. Natural gas operating revenue decreasedincreased primarily due to a lowerhigher average per-unit cost of natural gas sold (offset(fully offset in cost of sales).
Earnings increased $49decreased $7 million for the first nine monthssecond quarter of 20212022 compared to 2020, primarily2021, mainly 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 favorableunfavorable changes in the cash surrender value of corporate-owned life insurance policies, higher depreciation and amortization expense of $3 million, primarily from additional plant placed in-service, and higher operations and maintenance expense of $2 million, primarily from an unfavorable change in earnings sharing at the Nevada Utilities, partially offset by lowerhigher interest and dividend income of $9 million, primarily from carrying charges on regulatory balances.
Operating revenue increased $234 million for the first six months of 2022 compared to 2021, primarily due to higher electric utility marginoperating revenue of $61$213 million and higher natural gas operating revenue of $21 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of $209 million, higher regulatory-related revenue deferrals of $8 million and higher transmission and wholesale revenue of $5 million, partially offset by unfavorable price impacts from changes in sales mix of $7 million. Electric retail customer volumes increased 2.0%, primarily due to an increase in the average number of customers and higher customer usage, partially offset by the unfavorable impact of weather. Natural gas operating revenue increased primarily due to a higher average per-unit cost of natural gas sold (fully offset in cost of sales).
Earnings decreased $12 million for the first six months of 2022 compared to 2021, mainly due to unfavorable changes in the cash surrender value of corporate-owned life insurance policies, higher operations and maintenance expense of $8 million, primarily from an unfavorable change in earnings sharing at the Nevada Utilities and increased plant operations and maintenance expenses, and higher depreciation and amortization expense of $34 million. Electric utility margin decreased$6 million, primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decision in 2020,from additional plant placed in-service, partially offset by higher retail customer volumes, price impactsinterest and dividend income of $14 million, primarily from changes in sales mix and an increase in the average number of customers. Operations and maintenance expense decreased primarily due to lowercarrying charges on 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.balances.
Northern Powergrid
Operating revenue increased $31$65 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to $17 million from the weaker United States dollar and higher distribution revenue of $17$60 million mainlyand revenue from 4.1%a gas project that commenced commercial operation in March 2022 totaling $40 million, partially offset by $40 million from the stronger U.S. dollar. Distribution revenue increased due to the recovery of Supplier of Last Resort payments totaling $45 million (fully offset in cost of sales) and higher tariff rates of $25 million, partially offset by a 4.0% decline in units distributed of $10 million and increased tariff rates of $8$9 million.
Earnings increased $57$96 million for the thirdsecond quarter of 20212022 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.
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 and the higher distribution tariff rates, partially offset by higher distribution-related operating and depreciation expenses of $27 million, including higher storm-related costs, $9 million from the stronger U.S. dollar and the decline in units distributed.
Operating revenue increased $80 million for the first six months of 2022 compared to 2021, primarily due to higher distribution revenue of $70 million and revenue from a gas project that commenced commercial operation in March 2022 totaling $50 million, partially offset by $45 million from the stronger U.S. dollar. Distribution revenue increased due to the recovery of Supplier of Last Resort payments totaling $45 million (fully offset in cost of sales) and higher tariff rates of $39 million, partially offset by a 3.3% decline in units distributed of $12 million.
Earnings increased $103 million for the first six months of 2022 compared to 2021, primarily due to a deferred income tax charge in July 2020 of $35$109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate not decreasing from 19% to 17%25% effective April 1, 2020, as had previously been announced,2023 and $11the higher distribution tariff rates, partially offset by higher distribution-related operating and depreciation expenses of $27 million, including higher storm-related costs, the decline in units distributed and $8 million from the weaker United Statesstronger U.S. dollar.
BHE Pipeline Group
Operating revenue increased $521$150 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to $516higher non-regulated revenue of $58 million (largely offset in cost of incremental revenuesales) at BHE GT&S acquiredfrom favorable pricing, an increase in November 2020,regulated gas transportation and storage services rates due to an agreement in principle for EGTS' general rate case of $25 million, higher LNG variable revenue of $25 million at Cove Point, higher transportation revenue of $23 million at Kern River largely due to higher rates, partially offset by lower transportation revenue of $19$17 million at Northern Natural Gas primarily due to lower volumes.higher volumes and rates and higher gas sales of $9 million (largely offset in cost of sales) related to system balancing activities at Northern Natural Gas.
Earnings increased $66$99 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to $74higher earnings of $90 million of incremental earnings at BHE GT&S largely due to favorable state unitary income tax adjustments, the impacts of the EGTS general rate case, lower operations and maintenance expense, favorable valuations of system gas and higher earnings of $16 million at Kern Rivermargin from the higher transportation revenue, partially offset by lower earnings of $25 million at Northern Natural Gas, primarily due to the lower transportation revenue.non-regulated activities.
Operating revenue increased $1,694$92 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to $1,563higher non-regulated revenue of $69 million (largely offset in cost of incremental revenuesales) at BHE GT&S from favorable pricing, higher LNG variable revenue of $38 million at Cove Point and an increase in regulated gas transportation and storage services rates due to an agreement in principle for EGTS' general rate case of $25 million, partially offset by lower gas sales of $32 million related to system balancing activities at Northern Natural Gas, lower gas sales of $17 million at EGTS used for operational and system balancing purposes and lower transportation revenue of $3 million at Northern Natural Gas. The variances in gas sales and transportation revenue at Northern Natural Gas included favorable impacts recognized in the first quarter of 2021 of $77 million and higher transportation revenue of $49 million, at Northern Natural Gas, each due to the favorable impacts ofrespectively, from the February 2021 polar vortex weather event, higherevent. Excluding this item, gas sales at Northern Natural Gas of $33increased $45 million (largely offset in cost of sales) and higher transportation revenue of $25increased $46 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.volumes and rates.
Earnings increased $306$38 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to $247higher earnings of $99 million of incremental earnings at BHE GT&S, higherpartially offset by lower earnings of $39$60 million at Northern Natural GasGas. Earnings at BHE GT&S increased mainly due to favorable state unitary income tax adjustments, the impacts of the EGTS general rate case, lower operations and maintenance expense, favorable property tax assessments, increased earnings of $18 million at Kern RiverCove Point and higher margin from the higher transportation revenue.non-regulated activities. Earnings at Northern Natural Gas' improved performance was primarily due toGas decreased as the higher gross margin on gas sales and higher transportation revenue each due toin the favorable impactsfirst quarter of 2021 from the February 2021 polar vortex weather event were partially offset by the lowerfavorable transportation revenue due primarily to lower volumes.higher volumes and rates.
BHE Transmission
Operating revenue increased $10$1 million for the thirdsecond quarter and $4 million for the first six months of 20212022 compared to 2020,2021, primarily due to $10higher non-regulated revenue and higher revenue at AltaLink from recovery of higher costs, partially offset by $7 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.weaker U.S. dollar.
Earnings increased $7$2 million for the thirdsecond quarter of 2021 compared to 2020, primarily due to higher earnings from the Montana-Alberta Tie-Line.
Operating revenue increased $31and $5 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to $40the higher non-regulated revenue and improved equity earnings at Electric Transmission Texas, LLC, partially offset by $2 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.weaker U.S. dollar.
BHE Renewables
Operating revenue increased $7$27 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to higher hydro, natural gaswind, geothermal and solar revenues of $51 million from higher generation and favorable market conditions,pricing, partially offset by an unfavorable changechanges in the valuation of a power purchase agreement of $8certain derivative contracts totaling $14 million and lower geothermalnatural gas revenues of $13 million from lower generation.
Earnings increased $1$68 million for the thirdsecond quarter 2021of 2022 compared to 2020,2021, primarily due to higher wind earnings of $6$58 million mainlyand higher geothermal earnings of $11 million, largely due to the higher operating revenue and lower maintenance costs. Wind earnings increased primarily due to higher earnings from owned projects of $31 million, largely from the higher operating revenue and favorable production tax credits offset by the unfavorable derivative contract valuations, and higher earnings from tax equity investments of $27 million, mainly from higher production tax credits 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.performance.
Operating revenue increased $42$4 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to higher natural gas, hydrowind, geothermal and solar revenues of $77 million from favorable market conditions and higher generation and pricing, partially offset by an unfavorable changechanges in the valuation of a power purchase agreementcertain derivative contracts totaling $57 million, lower natural gas revenues of $22 million.$10 million from lower generation and lower hydro revenues of $6 million due to the transfer of the Casecnan generating facility to the Philippine National Irrigation Administration in December 2021.
Earnings decreased $35increased $156 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to lowerhigher wind earnings of $56$150 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$10 million, mainly due to the higher generationoperating revenue, and higher geothermal earnings of $9 million, largely due to the higher operating revenue and lower depreciation expense, and highermaintenance costs, partially offset by lower hydro earnings of $5$10 million from higher generation. Tax equity investment earnings decreased due to unfavorable resultsthe Casecnan generating facility transfer. Wind earnings increased primarily due to higher earnings from existing tax equity investments of $123 million, primarily due tomainly as a result of the unfavorable impacts in the first quarter of 2021 from the February 2021 polar vortex weather event partiallyand higher production tax credits offset by $79 million ofunfavorable performance, and higher earnings from owned projects reaching commercial operation.of $27 million, largely from the higher operating revenue and favorable production tax credits offset by the unfavorable derivative contract valuations.
HomeServices
Operating revenue increased $1decreased $91 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to higher brokerage revenue of $117 million, partially offset by lower mortgage revenue of $112$63 million from a 27%29% decrease in funded volume. The increase in brokerage revenue wasvolume due to $67a decline in refinance activity and lower brokerage and settlement services revenue of $26 million from acquired companies and a 5% increasedecrease in closed transaction volume at existing companies, resulting from an increase in average sales price offset by fewer closed units.volumes.
Earnings decreased $75$51 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to lower earnings from mortgagebrokerage and settlement services of $76$33 million, largely attributable to the decrease in closed units at existing companies, and lower earnings from mortgage services of $22 million from the decrease in funded volume.
Operating revenue increased $910decreased $116 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to lower mortgage revenue of $160 million from a 34% decrease in funded volume due to a decline in refinance activity, partially offset by higher brokerage revenue of $933$67 million from a 34%3% increase in closed transaction volume. The increase in brokerage volume resulting from increaseswas due to acquisitions and a 10% increase in closed units and average sales price partiallyat existing companies offset by lower mortgage revenue of $71 million from a decrease in refinance activity.15% fewer closed units at existing companies.
Earnings increased $75decreased $114 million for the first ninesix months of 20212022 compared to 2020,2021, 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$71 million largely attributableand lower earnings from brokerage and settlement services of $49 million due to the decrease in refinance activityclosed units at existing companies. Earnings from mortgage services were lower primarily due to the decrease in funded volumes, partially offset by an unfavorable 2020 contingent earn-out remeasurement.favorable operating expense variances.
BHE and Other
Operating revenue decreased $4increased $44 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to lowerhigher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from lowerfavorable pricing and higher electricity volumes offset by favorable pricing.lower natural gas volumes.
Earnings decreased $1,118increased $583 million for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to the $1,046$600 million unfavorablefavorable comparative change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $86lower corporate costs and $25 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 andpartially offset by $41 million of lower federal income tax credits recognized on a consolidated basis, unfavorable changes in the cash surrender value of corporate-owned life insurance policies partially offset by lower other corporate costs and higher earningsBHE corporate interest expense from an April 2022 debt issuance.
Operating revenue decreased $14 million for the first six months of $18 million2022 compared to 2021, primarily due to lower electricity sales revenue 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 tofrom unfavorable pricing offset by higher electricity andvolumes, partially offset by higher natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes.
Earnings decreased $1,050increased $445 million for the first ninesix months of 20212022 compared to 2020,2021, primarily due to the $891$433 million unfavorablefavorable comparative change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $101lower corporate costs, $46 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock $44 millionissued to certain subsidiaries of lower federal income tax credits recognized on a consolidated basis, higher BHE corporate interest expense from debt issuances in MarchBerkshire Hathaway and October 2020 and higher other corporate costs, partially offset by higher earnings of $30$45 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts, and favorablepartially offset by $95 million of lower federal income tax credits recognized on a consolidated basis, unfavorable changes in the cash surrender value of corporate-owned life insurance policies.policies and higher BHE corporate interest expense from an April 2022 debt issuance.
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, 20202021 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of SeptemberJune 30, 2021,2022, the Company's total net liquidity was as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | BHE Pipeline | |
| | MidAmerican | | NV | | Northern | | BHE | | | MidAmerican | | NV | | Northern | | BHE | | Group and | |
| | BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | Other | | Total | | BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Other | | Total |
| | Cash and cash equivalents | Cash and cash equivalents | $ | 300 | | | $ | 893 | | | $ | 542 | | | $ | 99 | | | $ | 14 | | | $ | 72 | | | $ | 789 | | | $ | 2,709 | | Cash and cash equivalents | $ | 61 | | | $ | 390 | | | $ | 497 | | | $ | 83 | | | $ | 327 | | | $ | 60 | | | $ | 294 | | | $ | 369 | | | $ | 2,081 | |
| Credit facilities(1) | Credit facilities(1) | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 204 | | | 848 | | | 3,450 | | | 11,361 | | Credit facilities(1) | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 259 | | | 835 | | | 3,400 | | | — | | | 11,353 | |
| Less: | Less: | | Less: | |
| Short-term debt | Short-term debt | — | | | — | | | — | | | (127) | | | (68) | | | (230) | | | (1,543) | | | (1,968) | | Short-term debt | (385) | | | — | | | — | | | — | | | (15) | | | (378) | | | (1,170) | | | — | | | (1,948) | |
| Tax-exempt bond support and letters of credit | Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (1) | | | — | | | (589) | | Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (1) | | | — | | | — | | | (589) | |
| Net credit facilities | Net credit facilities | 3,500 | | | 982 | | | 1,139 | | | 523 | | | 136 | | | 617 | | | 1,907 | | | 8,804 | | Net credit facilities | 3,115 | | | 982 | | | 1,139 | | | 650 | | | 244 | | | 456 | | | 2,230 | | | — | | | 8,816 | |
| | Total net liquidity | Total net liquidity | $ | 3,800 | | | $ | 1,875 | | | $ | 1,681 | | | $ | 622 | | | $ | 150 | | | $ | 689 | | | $ | 2,696 | | | $ | 11,513 | | Total net liquidity | $ | 3,176 | | | $ | 1,372 | | | $ | 1,636 | | | $ | 733 | | | $ | 571 | | | $ | 516 | | | $ | 2,524 | | | $ | 369 | | | $ | 10,897 | |
| Credit facilities: | Credit facilities: | | | | | | | | | | | | | | | | Credit facilities: | | | | | | | | | | | | | | | | | |
| Maturity dates | Maturity dates | 2024 | | 2024 | | 2022, 2024 | | 2024 | | 2023 | | 2022, 2025 | | 2022, 2026 | | Maturity dates | 2025 | | 2025 | | 2023, 2025 | | 2025 | | 2024, 2026 | | 2023, 2026 | | 2022, 2023, 2026 | |
|
(1)Includes $15 million drawn uncommittedon a capital expenditure credit facilities totaling $1 millionfacility at Northern Powergrid Holdings.
Operating Activities
Net cash flows from operating activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $7.0$5.1 billion and $4.5$4.2 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 selected and assumptions usedmade for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 20202021 were $(3.5) billion and $(6.6)$(3.0) billion, respectively. The change was primarily due to lower fundinghigher capital expenditures of tax equity investments and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement.$534 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-monthsix-month period ended SeptemberJune 30, 20212022 was $(2.0) billion.$(605) million. Sources of cash totaled $2,188 million and consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and proceeds from BHE senior debt issuances totaling $987 million. Uses of cash totaled $4.0 billion$2,793 million and consisted mainly of purchases of common stock totaling $870 million, preferred stock redemptions totaling $1.5 billion,of $800 million, repayments of subsidiary debt totaling $1.3 billion, repayments of BHE senior debt totaling $450$542 million, distributions to noncontrolling interests of $366$246 million and net repayments of short-term debt totaling $316$54 million. Sources of cash totaled $2.0 billion and consisted of proceeds from subsidiary debt issuances.
For a discussiondiscussions of recent financing and BHE shareholders' equity transactions, refer to Note 5Notes 4 and 10 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-monthsix-month period ended SeptemberJune 30, 20202021 was $2.9$(1.2) billion. Sources of cash totaled $5.9 billion$784 million and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.6 billion.$539 million and net proceeds from short-term debt of $245 million. Uses of cash totaled $2.9$2.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.6$1.2 billion, net repayments of short-term debt totaling $815 million, repayments of BHE senior debt totaling $350$450 million and common stock repurchases totaling $126 million.
Debt Repurchases
The Company may from timedistributions 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 sharesnoncontrolling interests 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$234 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.
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 Periods | | Annual | | Six-Month Periods | | Annual |
| | Ended September 30, | | Forecast | | Ended June 30, | | Forecast |
| | 2020 | | 2021 | | 2021 | | 2021 | | 2022 | | 2022 |
| Capital expenditures by business: | Capital expenditures by business: | | | | | | Capital expenditures by business: | | | | | |
| PacifiCorp | PacifiCorp | $ | 1,618 | | | $ | 1,157 | | | $ | 1,558 | | PacifiCorp | $ | 819 | | | $ | 894 | | | $ | 2,279 | |
| MidAmerican Funding | MidAmerican Funding | 1,341 | | | 1,266 | | | 1,943 | | MidAmerican Funding | 720 | | | 862 | | | 1,913 | |
| NV Energy | NV Energy | 509 | | | 519 | | | 829 | | NV Energy | 365 | | | 541 | | | 1,228 | |
| Northern Powergrid | Northern Powergrid | 492 | | | 564 | | | 748 | | Northern Powergrid | 369 | | | 450 | | | 776 | |
| BHE Pipeline Group | BHE Pipeline Group | 428 | | | 684 | | | 1,262 | | BHE Pipeline Group | 308 | | | 457 | | | 1,252 | |
| BHE Transmission | BHE Transmission | 276 | | | 234 | | | 268 | | BHE Transmission | 156 | | | 95 | | | 210 | |
| BHE Renewables | BHE Renewables | 46 | | | 129 | | | 166 | | BHE Renewables | 80 | | | 60 | | | 185 | |
| HomeServices | HomeServices | 21 | | | 29 | | | 42 | | HomeServices | 18 | | | 20 | | | 55 | |
BHE and Other(1) | BHE and Other(1) | (124) | | | 12 | | | 27 | | BHE and Other(1) | 13 | | | 3 | | | 16 | |
| Total | Total | $ | 4,607 | | | $ | 4,594 | | | $ | 6,843 | | Total | $ | 2,848 | | | $ | 3,382 | | | $ | 7,914 | |
| | | | Capital expenditures by type: | Capital expenditures by type: | | Capital expenditures by type: | |
| Wind generation | Wind generation | $ | 1,388 | | | $ | 872 | | | $ | 1,122 | | Wind generation | $ | 483 | | | $ | 300 | | | $ | 886 | |
| Electric distribution | Electric distribution | 1,182 | | | 1,217 | | | 1,745 | | Electric distribution | 817 | | | 815 | | | 1,763 | |
| Electric transmission | Electric transmission | 745 | | | 539 | | | 845 | | Electric transmission | 339 | | | 620 | | | 1,773 | |
| Natural gas transmission and storage | Natural gas transmission and storage | 385 | | | 647 | | | 1,097 | | Natural gas transmission and storage | 308 | | | 336 | | | 976 | |
| Solar generation | Solar generation | 2 | | | 104 | | | 218 | | Solar generation | 67 | | | 100 | | | 230 | |
| Other | Other | 905 | | | 1,215 | | | 1,816 | | Other | 834 | | | 1,211 | | | 2,286 | |
| Total | Total | $ | 4,607 | | | $ | 4,594 | | | $ | 6,843 | | Total | $ | 2,848 | | | $ | 3,382 | | | $ | 7,914 | |
(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$5 million and $676$172 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $73$106 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.2022.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $274$214 million and $25$82 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, respectively. Planned spending for the repowering of wind-powered generating facilities totals $101$314 million for the remainder of 2021.2022. 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 892593 MWs of current repowering projects not in-service as of SeptemberJune 30, 2021, 5912022, 292 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.
◦Construction of wind-powered generating facilities at PacifiCorp totaling $99$4 million and $705$79 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, respectively. Construction includes 674516 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in service in2021. Planned spending for the first nine monthsconstruction of 2021.additional wind-powered generating facilities totals $24 million for the remainder of 2022. The energy production for thesefrom the new wind-powered generating facilities placed in-service by the end of 2024 is expected to qualify for 100%60% of the federal PTCs available for 10 years once the equipment is placed in-service. Similar to PacifiCorp's 2019 IRP,
◦Planned acquisition and repowering of two wind-powered generating facilities by PacifiCorp totaling $7 million and $2 million (excluding the 2021 IRP identified over 1,800 MWssale of new wind-powered generating resources thatwind turbines) for the six-month periods ended June 30, 2022 and 2021, respectively. In 2021, PacifiCorp sold wind turbines previously acquired from a third party to BHE Wind, LLC, an indirect wholly owned subsidiary of BHE, for $6 million. The repowered facilities are expected to come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of ownedplaced in-service in 2023 and contracted resources.2024. Planned spending for the construction of additional wind-poweredacquiring and repowering generating facilities totals $17$14 million for the remainder of 2021.2022.
◦Repowering of wind-powered generating facilities at PacifiCorpBHE Renewables totaling $9 million and $99$45 million for the nine-month periodssix-month period ended SeptemberJune 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.2022. Planned spending for the repowering of wind-powered generating facilities totals $7$43 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 2021.2022.
•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 the following:
◦PacifiCorp's 140-miletransmission investment primarily reflects planned costs for the 416-mile, 500-kV Aeolus-Bridger/Anticlinehigh-voltage transmission line which is a major segment of PacifiCorp'sbetween the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these segments totaled $296 million and $35 million for the six-month periods ended June 30, 2022 and 2021, respectively. Planned spending for these Energy Gateway Transmission expansion program,segments to be placed in-service in November 2020,2024-2026 totals $614 million for the remainder of 2022.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations. Expenditures for the expansion program and AltaLink's directly assignedother growth projects fromtotaled $60 million and $41 million for the Alberta Electric System Operator. six-month periods ended June 30, 2022 and 2021, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026-2028 and other growth projects totals $109 million for the remainder of 2022.
◦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 planspending for the constructionfollowing:
◦Construction of solar-powered generating facilities at MidAmerican Energy totaling 141 MWs of small- and utility-scale solar generation, duringwith total spend of $77 million and $63 million for the six-month periods ended June 30, 2022 and 2021, respectively and planned spending of which 61 MWs are expected to be placed in-service in 2021.$63 million for the remainder of 2022.
◦Construction of a solar-powered generating facility at Nevada Power's solar generation investmentPower totaling $23 million and $5 million for the six-month periods ended June 30, 2022 and 2021, respectively and planned spending of $67 million for the remainder of 2022. Construction includes expenditures for a 150 MWs150-MW solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage known as the Dry Lake generating facility.that will be developed in Clark County, Nevada. Commercial operation 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.
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 ObligationsMaterial Cash Requirements
As of SeptemberJune 30, 2021,2022, there have been no material changes outside the normal course of business in contractual obligationscash requirements from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 20202021, other than those disclosed in Notes 4 and 8 of the recent financing transactions and renewable tax equity investments previously discussed.Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Quad Cities Generating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, ("which was a subsidiary of Exelon Generation")Corporation prior to February 1, 2022), 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")ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon GenerationConstellation Energy 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,Constellation Energy, 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 capacity 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 requestRequests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms waswere filed onin October 5, 2021 and remains pending.denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Constellation Energy is strenuously opposing these appeals.
Assuming the continued effectiveness of the Illinois zero emission standard, Exelon GenerationConstellation Energy 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, 20202021 and new regulatory matters occurring in 2021.2022.
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,March 2022, PacifiCorp filed a general rate case and in December 2020, the OPUC approved a netrequesting an overall rate decreasechange of approximately $24$82 million, or 1.8%6.6%, to become effective January 1, 2021, accepting2023, that includes cost increases associated with the implementation of 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 responsewildfire mitigation and vegetation management plans. Parties 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 placedcase filed testimony in service at the time of the filing. Additional compliance filings have been made to include investmentsJune 2022. PacifiCorp filed reply testimony 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 aJuly 2022 supporting an overall rate increase of approximately $7$94 million or 0.5%, effective January 12, 2021. In April 2021,but proposing that the OPUC approvedrequest be capped at PacifiCorp's original request. A hearing in 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.
In July 2021, in accordance with the OPUC's December 2020 general rate case will be held in September 2022 with an 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 approvedexpected in the last general rate case.
WyomingDecember 2022.
In September 2018,May 2022, PacifiCorp filed an application for depreciationits 2021 power cost adjustment mechanism ("PCAM"), which is the first time since the mechanism has been in place that a rate changes withchange has been warranted. After consideration of the WPSC based on PacifiCorp's 2018 depreciation rate study,mechanism's deadband, sharing band and earnings test, PacifiCorp is requesting the ratesrecovery of $52 million, or a 4.2% increase, to 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 associated2023. This request is 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 byrate change sought in 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,July 2022, PacifiCorp filed an application requesting approval of an automatic adjustment clause with 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 revisionbalancing account to the ECAM to eliminate the sharing band and requested authorization to discontinue operations and recover costs associated with the early retirementimplementing PacifiCorp's wildfire protection plan in Oregon. Oregon Senate Bill 762 provides for utilities to timely recover these costs through an automatic adjustment clause. The filing requests a rate increase 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$20 million, or 1.3%1.6%, and reflectedto recover incremental costs in 2022. While PacifiCorp requested 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.August 24, 2022, the OPUC has suspended the filing for further review.
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.
Washington
In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. The proposedPacifiCorp requested a $13 million, or 3.7%, rate increase has a requestedwith an 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 was held in this matter is scheduled for January 2022 and the WUTC issued an order approving the settlement in March 2022. A compliance filing reflecting a $43 million, or 12.2%, increase was filed in April 2022 with rates becoming effective after an order is issued.
IdahoMay 1, 2022.
In March 2021,June 2022, PacifiCorp filed its annual ECAM application with2021 PCAM and the IPUCnew tracking mechanism for PTCs approved in the 2021 general rate case. For the 2021 PCAM, PacifiCorp is requesting recovery of $14$26 million, for deferred costs in 2020,or a 1.1% decrease compared to6.5% increase. PacifiCorp proposed that the 2021 PCAM be amortized over two years, rather than the one-year period required under the current rates. This filing includesterms of the PCAM. For the new 2021 PTC tracker, PacifiCorp is seeking recovery of $3 million, or an 0.8% increase. Should the difference in actual net power costsWUTC approve the proposal to extend the base level in rates, an adder for recoveryamortization period of the Lake Side 2 resource, changes in PTCs, RECs, and a resource tracking mechanism2021 PCAM from one to match costs withtwo years, 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 $19combined annual increase would be $16 million, or 7.0%4.0%, 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, 2022.2023.
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,May 2022, PacifiCorp filed a general rate case requesting an application with the CPUC to address California energy costs and GHG allowance costs. The application includes a $7overall rate change of $28 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%25.7%, to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program.become effective January 1, 2023. 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 includesJune 2022, 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 applicationproposed procedural schedule was developed that 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.decision in August 2023.
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.
MidAmerican Energy
Natural Gas Purchased for ResaleSouth Dakota
In February 2021, severe cold weather overMay 2022, MidAmerican Energy filed a request with the central United States caused disruptionsSouth Dakota Public Utilities Commission ("SDPUC") for an increase in its South Dakota retail natural gas supply fromrates, which would increase revenue by $7 million annually. If approved, the southern partrequested rates would increase retail customers' bills by an average 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, 2021.6.4%.
Renewable Subscription ProgramWind PRIME
In December 2020,January 2022, MidAmerican Energy filed an application with the IUB a proposed Renewable Subscription Program ("RSP") tariff. As proposed, the program would provide qualified industrial customersfor advance ratemaking principles for Wind PRIME. If approved, MidAmerican Energy expects to proceed with Wind PRIME, which consists of up to 2,042 MWs of new wind generation and up to 50 MWs of solar generation. If all of Wind PRIME generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind generation and nearly 200 MWs of solar generation. Wind PRIME is projected to allow MidAmerican Energy to generate renewable energy greater than or equal to all of its Iowa retail customers' annual energy needs. MidAmerican Energy secured sufficient safe harbor equipment necessary to remain eligible for 60% PTCs under current tax law. Procedural hearings with the opportunityIUB are scheduled 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 programbegin 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.October 2022.
NV Energy (Nevada Power and Sierra Pacific)
Price Stability TariffRegulatory Rate Review
In November 2018, the Nevada Utilities made filingsJune 2022, Sierra Pacific filed a regulatory rate review with the PUCN that requested an annual revenue increase of $88 million, or 9.7%. In addition, a filing was made 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 isrevise depreciation rates based on renewable resources. The CPST provides for an energy rate that would replacea study, 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 participateresults of which are reflected 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 finalproposed revenue requirement. An order is expected in 2021.
Natural Disaster Protection Plan
The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. Intervenors have filed a petition for judicial review with the District Court in November 2020. In December 2020, the PUCN issued a second modified final order approving the natural disaster protection plan, as modified, and reopened its investigation and rulemaking on Senate Bill 329 to address rate design issues raised by intervenors. The comment period for the reopened investigation and rulemaking ended in early February 2021 and an order is expected in 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 PUCNend of 2022 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 wasif 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 towould 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.effective January 1, 2023.
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 inwithin the state of Nevada. In addition,September 2021, 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.infrastructure, Greenlink North among others, that will be placed into service no later than December 31, 2028, and requires the IRP to include at least one scenario that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. 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. The plan establishes requirements for the contents of the transportation electrification investment as well as requirements for review, cost recovery and monitoring. The plan covers an initial period beginning January 1, 2022 and ending on December 31, 2024. In November 2021, the PUCN issued an order granting the application and accepting the Economic Recovery Transportation Electrification Plan with some modifications. The PUCN opened rulemakings to address theother regulations inthat resulted from SB 448. In February 2022, the PUCN adopted regulations regarding the Economic Development Electric Rate Rider Program to revise the discounted electric rates to ease the economic burden on small businesses who take advantage of the discounted rates under the tariff. The remaining two SB 448 rulemakings are ongoing.
ON Line Temporary Rider ("ONTR")
In October 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR andwith 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 andas well as the related on-going reallocated revenue requirement. Sierra Pacific's application would have, if approved by the PUCN as filed, resultresulted in a one-time rate increase of $28 million to be collected over a nine-month period starting on April 1, 2022. In March 2022, the PUCN issued an order directing Sierra Pacific to recover $14 million of the ON Line regulatory asset as a one-time rate increase collectable over a nine-month period effective April 1, 2022, with the expected remaining balance at December 31, 2022 to be included in rate base in the 2022 regulatory rate review for inclusion in the rates set in that case.
Merger Application
In March 2022, the Nevada Utilities filed a joint application with the PUCN for authorization to merge Sierra Pacific with and into Nevada Power, with Nevada Power being the surviving entity. If approved by the PUCN as filed, Nevada Power will have two distinct electric service territories in northern and southern Nevada each with their own rates and one natural gas service territory in the Reno and Sparks area. An order is expected in 2022.
Northern Powergrid Distribution Companies
In December 2020, GEMA, through Ofgem, publishedis undertaking 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 aspectsscheduled review of the proposals are capableelectricity distribution price control to put in place a new price control at the end of application at Northern Powergrid's nextthe current period that ends March 2023. The new price control ("ED2"), which will begin inrun for five years from April 2023.
2023 to March 2028. In December 2020 and March 2021, 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.ED2. This confirmed that Ofgem will applymaintain many aspects of the proposals fromcurrent price control and that the changes being made will generally follow the template that was set by the price controls implemented in April 2021 for transmission and gas distribution price controlsin Great Britain. Specific changes include new service standard incentives and mechanisms to electricity distribution,adjust cost allowances in specific circumstances, while others will be discontinued, and thatpartially updating the financial aspectsallowed return on equity within the period for changes in respect of electricity distributionthe interest rate on government bonds.
In December 2021, Northern Powergrid published and filed its business plan with Ofgem, setting out its detailed approach for 2023-2028 including the cost allowances this approach would broadly follow the transmission and gas distribution methodology, setting a working assumption for arequire. In June 2022, Ofgem published its draft determinations, which included an allowed cost of equity at 4.65% (plus CPIH), ahead of 4.75% plus inflation (calculated using the final determinations in late 2022.United Kingdom's consumer price index including owner occupiers' housing costs). When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, thethis working assumption for ED2 is approximately 150 basistwo percentage points lower than the current cost of equity.
In July 2021, Northern Powergrid submittedequity for electricity distribution. Ofgem's proposals also set out cost allowances 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 whichassociated expectations. Final values from Ofgem 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.in late 2022.
BHE Pipeline Group
BHE GT&S
In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS")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 matterIn June 2022, the parties reached an agreement in principle and the litigation procedural schedule was ordered held in abeyance for 90 days to enable the parties to finalize a settlement. The settlement is pending.expected to be filed by September 30, 2022. As of June 30, 2022, EGTS' provision for rate refund for April 2022 through June 2022 totaled $35 million and was included in other current liabilities on the Consolidated Balance Sheet.
Northern Natural Gas
In January 2020, pursuant to the terms of a previous settlement, Cove PointJuly 2022, Northern Natural Gas filed a general rate case for its FERC-jurisdictional services, withthat proposed rates to be effective March 1, 2020. Cove Point proposed an overall annual cost-of-service of $182 million.$1.3 billion. This is an increase of $323 million above the cost of service filed in its 2019 rate case of $1.0 billion. Depreciation on increased rate base and an increase in depreciation and negative salvage rates account for $115 million of the $323 million increase in the filed cost of service. Northern Natural Gas has requested increases in various rates, including transportation reservation rates ranging from approximately 45% in the Field Area to 120% in the Market Area to be implemented, subject to refund, on August 1, 2022. In February 2020,July 2022, the FERC approved suspendingissued an order that suspended the changes in rates proposed for five months following the proposed effective date, until AugustJanuary 1, 2020,2023, 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 agreementrefund and the rate refunds to customers were processed in late April.
BHE Transmission
AltaLink
Tariff Refund Application
In January 2021, driven by the pandemic and economic shutdown that 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.
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 yearyear-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 fromIn November 2021, the AUC is expected inapproved the 2022 interim refundable transmission tariff at C$57 million per month effective January 2022.
In January 2022, the AUC issued its decision with respect to AltaLink's 2022-2023 GTA. AltaLink's 2022-2023 GTA reflected its continued commitment to provide rate stability to customers by maintaining flat tariffs and providing additional tariff relief measures, including a proposed tariff refund of C$60 million of accumulated depreciation in each of 2022 and 2023. The AUC did not approve AltaLink's proposed refund due to an anticipated improvement in general economic conditions in Alberta. In March 2022, AltaLink filed a review and variance application requesting the AUC to review and vary its decision to deny AltaLink's proposed C$120 million refund of accumulated depreciation surplus, given material changes in circumstances since the decision was issued in January 2022. In May 2022, the AUC issued a decision with respect to AltaLink's application to review and vary its proposed $120 million refund of accumulated depreciation surplus. The AUC found that a material decline in Alberta's economic circumstances is not sufficient evidence to warrant the refund. In May 2022, the AUC approved AltaLink's revised total 2022 and 2023 revenue requirementof C$879 million and C$883 million, respectively, allowing AltaLink to fully deliver on its flat-for-five commitment to customers.
2023 Generic Cost of Capital Proceeding
In December 2020,January 2022, the AUC initiated the 20222023 generic cost of capital proceeding. ThisThe proceeding consideredwill be conducted in two stages. The first stage will determine the return on equitycost of capital parameters for 2023 and deemed equity ratios for 2022 and one or more additional test years. Duethe second stage will consider returning 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 genericestablish cost of capital proceedingadjustments, commencing 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.
2024. In March 2021,2022, the AUC issued its decision with respect to setting the return on equity and deemed equity ratios for AltaLink. The AUC approved an equity returnfirst stage of 8.5% and an equity ratiothe 2023 GCOC proceeding by approving the extension of 37% forthe 2022 based on continuing economic and market uncertainties, the unsettled nature of capital markets, and the need for certainty and stability for Alberta customers.
In April 2021, the Utilities Consumer Advocate filed an application with the Alberta Court of Appeal requesting permission to appeal the AUC's decision that set the return on equity of 8.5% and deemed equity ratio of 37% on a final basis for 2022.2023, recognizing lingering uncertainty and continued volatility of financial markets due to the COVID-19 pandemic. In the appeal, the Utilities Consumer Advocate alleged thatJune 2022, the AUC erred by failinginitiated the second stage to fulfill its statutory obligation of establishingexplore a fair return and by failingformula-based approach to apply procedural fairness. The Utilities Consumer Advocate additionally filed an application withdetermine 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%for 2024 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.future test periods.
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, 2020,2021, and new environmental matters occurring in 2021.2022.
Climate Change
Affordable Clean Energy Rule
In December 2015, an international agreement was negotiated by 195 nationsJune 2014, the EPA released proposed regulations to create a universal framework for coordinated action on climate change in what isaddress greenhouse gas emissions from existing fossil-fueled generating facilities, referred to as the Paris Agreement.Clean Power Plan, under Section 111(d) of the Clean Air Act. The Paris Agreement reaffirmsEPA's proposal calculated state-specific emission rate targets to be achieved based on the goals"best system of limiting global temperature increase well below 2 degrees Celsius,emission reduction." In August 2015, the final Clean Power Plan was released, which established the best system of emission reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the United States Supreme Court in February 2016 while urging effortslitigation proceeded. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule. In the Affordable Clean Energy rule, the EPA determined that the best system of emission reduction for existing coal-fueled generating facilities is limited to limitactions that can be taken at a point source facility, specifically heat rate improvements, and identified a set of candidate technologies and measures that could improve heat rates. Measures taken to meet the increasestandards of performance must be achieved at the source itself. The Affordable Clean Energy rule was challenged by environmental and health groups in the D.C. Circuit. On January 19, 2021, the D.C. Circuit vacated and remanded the Affordable Clean Energy rule to 1.5 degrees Celsiusthe EPA, finding that the rule "rested critically on a mistaken reading of the Clean Air Act" that limited the best system of emission reduction to actions taken at a facility. In October 2021, the United States Supreme Court agreed to hear an appeal of that decision. Arguments in the case were held February 28, 2022, and reaching a global peakon June 30, 2022, the United States Supreme Court issued its decision regarding the scope of the EPA's authority to regulate 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 achievingunder 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.Clean Air Act. The United States completed its withdrawalSupreme Court held that the "generation shifting" approach in the Clean Power Plan exceeded the powers granted to the EPA by Congress, although the court did not address whether the EPA may only adopt measures applied at the individual source as it did in the Affordable Clean Energy rule. A key area where the EPA went astray was using the Clean Power Plan to give states the option to promulgate regulations that would encourage "generation shifting," or moving away from higher-polluting power sources like coal to lower-polluting sources like natural gas or renewables. The United States Supreme Court found that type of regulation, which would impact larger economic forces beyond the Paris Agreement on November 4, 2020. President Biden accepted the termsfence lines of individual generating facilities, is not permitted under Section 111(d) of the climate agreement January 20, 2021, and theClean Air Act. 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 howSupreme Court reversed the United States will implement these goals is anticipated to be released through fall 2021.
Regional and State Activities
Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant and include:
•On July 27, 2021, the governor of Oregon signed House Bill 2021, which requires utilities to reduce GHG emissions to meet certain clean energy targets. The bill sets a baselineD.C. Circuit's vacatur of the average of 2010, 2011,Affordable Clean Energy rule and 2012 emissionsremanded the case for further proceedings. The ruling has no immediate impact on the Registrants, as there is no Section 111(d) rule currently in effect. The Biden administration plans to propose by March 2023 its own rule to replace the Clean Power Plan 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.Affordable Clean Energy rule.
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.
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.
The Sierra Club filed a lawsuit againstOn June 4, 2018, the EPA in August 2013 with respectpublished final ozone designations for much of the U.S. Relevant to the one-hour SO2 standardsRegistrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and its failurethe Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to make certain attainment designations in a timely manner. In Marchmeet the 2015 standard three years from the United States District CourtAugust 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the Northern District2015 ozone standards for contravening the Clean Air Act. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of California ("Northern Districtinterstate ozone plans of California") accepted as an enforceable order an agreement betweendozens of states. Relevant to the Registrants, the EPA must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan, Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directedWisconsin. On February 22, 2022, the EPA published a series of proposed decisions to complete designations in three phases:disapprove the first phase by July 2, 2016;SIPs for interstate ozone transport of 19 states. Relevant to the second phaseRegistrants, these states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's SIP after re-analyzing the state's data. The EPA must finalize the proposed rules by December 31, 2017; and15, 2022. In addition, the final phaseEPA must, by December 31, 2020. The first phase15, 2022, approve or disapprove the interstate plans of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard;Arizona, California, Nevada 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 inWyoming. On 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, 2021,15, 2022, the EPA issued the last of its final designationsrule approving Iowa's SIP as meeting the good neighbor provisions for the 2010 primary SO22015 ozone standard. IncludedOn May 24, 2022, the EPA disapproved the Utah and Wyoming interstate ozone SIPs. Until the EPA takes final action consistent with this decree, additional impacts to the relevant Registrants cannot be determined.
Separately, on March 28, 2022, the EPA proposed determinations as to whether certain areas have achieved levels of ground-level ozone pollution that meet the 2008 and 2015 ozone NAAQS. Relevant to the Registrants, the Southern Wasatch Front in this round was designationUtah and Yuma, Arizona are proposed to have met the 2015 ozone standard; and the Cincinnati area of Converse County, WyomingOhio and Kentucky and the Northern Wasatch Front in Utah are proposed to have not met the 2015 ozone, will be reclassified as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No furtherModerate Non-Attainment, and will have until August 3, 2024 to meet the standard. Until the EPA takes final action by PacifiCorp is required.on the proposal and the affected states submit any required SIPs, the relevant Registrants cannot determine the impacts of the proposed rule.
Cross-State Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States,U.S., 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, the EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. The 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 StatesU.S. 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 Statesstates 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,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 plantsgenerating facilities in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update rule.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 plantsgenerating facilities 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 Rule largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule. In June 2021, a new lawsuit was filed that challenges the Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court. Until litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.
In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. The rule focuses on reductions of NOx, precursors to ozone formation and covers 26 states. Relevant to the Registrants, four states are included in the cross-state program for the first time - California, Nevada, Utah and Wyoming. Iowa is not included in the proposal. In a separate but related action in February 2022, the EPA proposed to approve the good neighbor provisions of Iowa's SIP addressing ozone transport and the 2015 ozone standard. The EPA proposes to retain emissions allowance trading for generating facilities. Beginning in 2023, emissions budgets would be set at the level of reductions achievable through immediately available measures such as consistently operating existing emissions controls. Starting in 2026, emissions budgets would be set at levels achievable by the installation of SCR controls at certain generating facilities. The proposal also includes additional industries beyond the power sector for the first time, with a focus on the top NOx emitting stationary source categories. These include natural gas pipeline compressor stations, pulp and paper mills, cement production, iron and steel boilers and furnaces, glass furnaces, chemical manufacturing and petroleum and coal product manufacturing. These sources will not have access to trading and will instead be subject to rate-based limits that are assigned for each source category. The EPA accepted comments on the proposal through June 21, 2022. Until the EPA takes final action consistent with this decree, impacts to the relevant Registrants cannot be determined.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2 and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2 and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR equipment 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 equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install SCR equipment 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 generating facility federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington generating facilities. The proposed approval withdraws the FIP requirements to install SCR equipment 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 generating facilities. 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. After review of the rule by the Biden administration, the EPA determined it would defend the rule, and briefing in the case is ongoing. A date for oral arguments has not been scheduled. The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for the regional haze second planning period on April 6, 2022. The public comment period is anticipated to begin in early May 2022. The proposed plan sets mass-based emissions limits for PacifiCorp's Hunter and Huntington generating facilities to ensure reasonable visibility progress for the second planning period. The division proposes to add existing SO2 emission limits for all five Hunter and Huntington units as enforceable regional haze controls. The division also proposes new enforceable mass-based NOx emission limits for both generating facilities based on actual emissions. The state is on track to submit a final implementation plan to the EPA in August 2022.
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 StatesU.S. Department of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to install SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement.
The stateEPA did not proceed with final approval of Utah issuedthe settlement agreement for Wyodak and is currently engaged with Wyoming and PacifiCorp concerning alternative paths for resolution. On February 5, 2019, PacifiCorp submitted a regional haze SIPreasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of SO2,SCR, to be replaced with a permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. In May 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NOx and particulate matterSO2 emission limits on the four Jim Bridger units and submitted a regional haze SIP revision to the EPA. The revised SIP would grant approval of PacifiCorp's Jim Bridger reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency suspension order under Section 110(g) of the Clean Air Act, allowing the operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA proposed to reject the SIP revisions. The EPA took comment on the proposal through February 17, 2022. On February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp under Sections 201 and 209(a) of the Wyoming Environmental Quality Act, resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree and as forecasted in PacifiCorp's 2021 IRP, PacifiCorp must convert both units to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. In addition, PacifiCorp must propose an RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and 4. Wyoming issued its proposed implementation plan for second planning period reasonable progress on February 18, 2022 and accepted comments through March 23, 2022. The EPA and PacifiCorp executed an administrative order on consent June 9, 2022, covering compliance for Jim Bridger Units 1 and 2 under the regional haze rule. The federal order contains the same emission and operating limits as the Wyoming consent decree and adds federal approval of the compliance pathway outlined in the state consent decree, including revision of the SIP to include conversion of Jim Bridger Units 1 and 2 to natural gas. The order includes a one-year deadline to complete the SIP revision. The proposed SIP revision reflecting these agreements is currently being evaluated under parallel processes by the state of Wyoming and the EPA. The Wyoming Department of Environmental Quality submitted the Jim Bridger Units 1 and 2 proposed SIP revision to federal land managers for a 60-day consultation on June 7, 2022. The federal land managers must complete review and provide comments by August 8, 2022. For the second round of regional haze planning, Wyoming determined that no controls will be necessary on Hunterany Wyoming resources to make reasonable progress. It is estimated that the state will submit a final state-approved implementation plan to the EPA in August 2022.
In February 2022, NV Energy received 30-day notice letters from the Nevada Division of Environmental Protection regarding the reopening and revision of the Valmy and Tracy Generating Station's Title V air quality operating permits to add federally enforceable retirement dates of December 31, 2028 for Valmy Units 1 and 2 and Huntington Units 1 and 2. In December 2012,31, 2031 for Tracy Unit 4. The enforceable retirement dates will implement Nevada's SIP for the EPA approved the SO2 portion of the Utah regional haze SIPsecond planning period. The revised permits were received in March and disapproved the NOx and particulate matter portions. Subsequently, the UtahApril 2022. The Nevada Division of Air Quality completed an alternative BART analysis for Hunter Units 1Environmental Protection accepted public comment on its SIP through July 25, 2022, and 2 and Huntington Units 1 and 2. In January 2016,is on track to submit the EPA published two alternative proposals to either approve the Utahfinal 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.August 2022.
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, 2020.2021. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2020.2021.
PacifiCorp and its subsidiaries
Consolidated Financial Section
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
PacifiCorp
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of SeptemberJune 30, 2021,2022, 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-monththree-month and six-month periods ended SeptemberJune 30, 2022 and 2021, and 2020,of cash flows for the six-month periods ended June 30, 2022 and 2021, 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, 2020,2021, 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, 2021,25, 2022, 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, 2020,2021, 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
NovemberAugust 5, 20212022
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | As of | | | As of |
| | | | September 30, | | December 31, | | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | | $ | 893 | | | $ | 13 | | Cash and cash equivalents | | $ | 390 | | | $ | 179 | |
| Trade receivables, net | Trade receivables, net | | 732 | | | 703 | | Trade receivables, net | | 730 | | | 725 | |
| Other receivables, net | Other receivables, net | | 41 | | | 48 | | Other receivables, net | | 49 | | | 52 | |
| Inventories | Inventories | | 465 | | | 482 | | Inventories | | 490 | | | 474 | |
| Derivative contracts | Derivative contracts | | 153 | | | 27 | | Derivative contracts | | 127 | | | 76 | |
| | Regulatory assets | Regulatory assets | | 70 | | | 116 | | Regulatory assets | | 150 | | | 65 | |
| Prepaid expenses | | 89 | | | 79 | | |
| | Other current assets | Other current assets | | 24 | | | 55 | | Other current assets | | 83 | | | 150 | |
| Total current assets | Total current assets | | 2,467 | | | 1,523 | | Total current assets | | 2,019 | | | 1,721 | |
| | | | | |
| Property, plant and equipment, net | Property, plant and equipment, net | | 22,748 | | | 22,430 | | Property, plant and equipment, net | | 23,414 | | | 22,914 | |
| Regulatory assets | Regulatory assets | | 1,326 | | | 1,279 | | Regulatory assets | | 1,257 | | | 1,287 | |
| Other assets | Other assets | | 530 | | | 470 | | Other assets | | 750 | | | 534 | |
| | | | | | | | | | | |
| Total assets | Total assets | | $ | 27,071 | | | $ | 25,702 | | Total assets | | $ | 27,440 | | | $ | 26,456 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | | | As of | | | As of |
| | | | September 30, | | December 31, | | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| LIABILITIES AND SHAREHOLDERS' EQUITY | LIABILITIES AND SHAREHOLDERS' EQUITY | LIABILITIES AND SHAREHOLDERS' EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | | $ | 624 | | | $ | 772 | | Accounts payable | | $ | 848 | | | $ | 680 | |
| Accrued interest | Accrued interest | | 115 | | | 127 | | Accrued interest | | 122 | | | 121 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | | 159 | | | 80 | | Accrued property, income and other taxes | | 189 | | | 78 | |
| | Accrued employee expenses | Accrued employee expenses | | 117 | | | 84 | | Accrued employee expenses | | 117 | | | 89 | |
| Short-term debt | | — | | | 93 | | |
| | Current portion of long-term debt | Current portion of long-term debt | | 574 | | | 420 | | Current portion of long-term debt | | 455 | | | 155 | |
| Regulatory liabilities | Regulatory liabilities | | 112 | | | 115 | | Regulatory liabilities | | 115 | | | 118 | |
| Other current liabilities | Other current liabilities | | 241 | | | 174 | | Other current liabilities | | 195 | | | 219 | |
| Total current liabilities | Total current liabilities | | 1,942 | | | 1,865 | | Total current liabilities | | 2,041 | | | 1,460 | |
| | | | | |
| Long-term debt | Long-term debt | | 8,625 | | | 8,192 | | Long-term debt | | 8,268 | | | 8,575 | |
| Regulatory liabilities | Regulatory liabilities | | 2,759 | | | 2,727 | | Regulatory liabilities | | 2,833 | | | 2,650 | |
| Deferred income taxes | Deferred income taxes | | 2,781 | | | 2,627 | | Deferred income taxes | | 2,908 | | | 2,847 | |
| Other long-term liabilities | Other long-term liabilities | | 1,064 | | | 1,118 | | Other long-term liabilities | | 1,364 | | | 1,011 | |
| Total liabilities | Total liabilities | | 17,171 | | | 16,529 | | Total liabilities | | 17,414 | | | 16,543 | |
| | | | | | | | | | | |
| Commitments and contingencies (Note 9) | Commitments and contingencies (Note 9) | | 0 | | 0 | Commitments and contingencies (Note 9) | | 0 | | 0 |
| | | | | |
| Shareholders' equity: | Shareholders' equity: | | Shareholders' equity: | |
| Preferred stock | Preferred stock | | 2 | | | 2 | | Preferred stock | | 2 | | | 2 | |
| Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | | — | | | — | | Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | | — | | | — | |
| Additional paid-in capital | Additional paid-in capital | | 4,479 | | | 4,479 | | Additional paid-in capital | | 4,479 | | | 4,479 | |
| Retained earnings | Retained earnings | | 5,437 | | | 4,711 | | Retained earnings | | 5,561 | | | 5,449 | |
| Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | | (18) | | | (19) | | Accumulated other comprehensive loss, net | | (16) | | | (17) | |
| Total shareholders' equity | Total shareholders' equity | | 9,900 | | | 9,173 | | Total shareholders' equity | | 10,026 | | | 9,913 | |
| | | | | | | | | | | |
| Total liabilities and shareholders' equity | Total liabilities and shareholders' equity | | $ | 27,071 | | | $ | 25,702 | | Total liabilities and shareholders' equity | | $ | 27,440 | | | $ | 26,456 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | | | | | | | | | | | |
| Operating revenue | Operating revenue | $ | 1,491 | | | $ | 1,479 | | | $ | 4,031 | | | $ | 3,829 | | Operating revenue | $ | 1,314 | | | $ | 1,298 | | | $ | 2,611 | | | $ | 2,540 | |
| | | | | | | | | | | | | | | | | |
| Operating expenses: | Operating expenses: | | Operating expenses: | |
| Cost of fuel and energy | Cost of fuel and energy | 505 | | | 499 | | | 1,370 | | | 1,299 | | Cost of fuel and energy | 451 | | | 441 | | | 916 | | | 865 | |
| Operations and maintenance | Operations and maintenance | 267 | | | 332 | | | 781 | | | 829 | | Operations and maintenance | 375 | | | 255 | | | 652 | | | 514 | |
| Depreciation and amortization | Depreciation and amortization | 272 | | | 234 | | | 811 | | | 696 | | Depreciation and amortization | 279 | | | 275 | | | 559 | | | 539 | |
| Property and other taxes | Property and other taxes | 54 | | | 53 | | | 158 | | | 154 | | Property and other taxes | 51 | | | 43 | | | 110 | | | 104 | |
| Total operating expenses | Total operating expenses | 1,098 | | | 1,118 | | | 3,120 | | | 2,978 | | Total operating expenses | 1,156 | | | 1,014 | | | 2,237 | | | 2,022 | |
| | | | | | | | | | | | | | | | | |
| Operating income | Operating income | 393 | | | 361 | | | 911 | | | 851 | | Operating income | 158 | | | 284 | | | 374 | | | 518 | |
| | | | | | | | | | | | | | | | | |
| Other income (expense): | Other income (expense): | | | | Other income (expense): | | | |
| Interest expense | Interest expense | (110) | | | (107) | | | (322) | | | (319) | | Interest expense | (107) | | | (105) | | | (213) | | | (212) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 6 | | | 14 | | | 18 | | | 36 | | Allowance for borrowed funds | 6 | | | 6 | | | 12 | | | 12 | |
| Allowance for equity funds | Allowance for equity funds | 13 | | | 29 | | | 38 | | | 73 | | Allowance for equity funds | 15 | | | 12 | | | 28 | | | 25 | |
| Interest and dividend income | Interest and dividend income | 7 | | | 2 | | | 18 | | | 8 | | Interest and dividend income | 7 | | | 5 | | | 14 | | | 11 | |
| Other, net | Other, net | (5) | | | 5 | | | 5 | | | 9 | | Other, net | (5) | | | 4 | | | (9) | | | 10 | |
| Total other income (expense) | Total other income (expense) | (89) | | | (57) | | | (243) | | | (193) | | Total other income (expense) | (84) | | | (78) | | | (168) | | | (154) | |
| | | | | | | | | | | | | | | | | |
| Income before income tax (benefit) expense | 304 | | | 304 | | | 668 | | | 658 | | |
| Income tax (benefit) expense | (28) | | | 18 | | | (58) | | | 30 | | |
| Income before income tax benefit | | Income before income tax benefit | 74 | | | 206 | | | 206 | | | 364 | |
| Income tax benefit | | Income tax benefit | (8) | | | (19) | | | (6) | | | (30) | |
| Net income | Net income | $ | 332 | | | $ | 286 | | | $ | 726 | | | $ | 628 | | Net income | $ | 82 | | | $ | 225 | | | $ | 212 | | | $ | 394 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)
(Amounts in millions)
| | | | | Accumulated | | | | | Accumulated | | |
| | | | | | | | Additional | | | | Other | | Total | | | | | | | Additional | | | | Other | | Total |
| | Preferred | | Common | | Paid-in | | Retained | | Comprehensive | | Shareholders' | | Preferred | | Common | | Paid-in | | Retained | | Comprehensive | | Shareholders' |
| | | | Stock | | Stock | | Capital | | Earnings | | Loss, Net | | Equity | | | Stock | | Stock | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance, June 30, 2020 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,314 | | | $ | (15) | | | $ | 8,780 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,880 | | | $ | (19) | | | $ | 9,342 | |
| Net income | Net income | | — | | | — | | | — | | | 286 | | | — | | | 286 | | Net income | | — | | | — | | | — | | | 225 | | | — | | | 225 | |
| | Balance, September 30, 2020 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,600 | | | $ | (15) | | | $ | 9,066 | | |
| | Balance, December 31, 2019 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 3,972 | | | $ | (16) | | | $ | 8,437 | | |
| Net income | | — | | | — | | | — | | | 628 | | | — | | | 628 | | |
| Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | | |
| | Balance, September 30, 2020 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,600 | | | $ | (15) | | | $ | 9,066 | | |
| | | | | | | | | | | | | | |
| Balance, June 30, 2021 | Balance, June 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,105 | | | $ | (19) | | | $ | 9,567 | | Balance, June 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,105 | | | $ | (19) | | | $ | 9,567 | |
| Net income | | — | | | — | | | — | | | 332 | | | — | | | 332 | | |
| Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | | |
| | Balance, September 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,437 | | | $ | (18) | | | $ | 9,900 | | |
| | Balance, December 31, 2020 | Balance, December 31, 2020 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,711 | | | $ | (19) | | | $ | 9,173 | | Balance, December 31, 2020 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,711 | | | $ | (19) | | | $ | 9,173 | |
| Net income | Net income | | — | | | — | | | — | | | 726 | | | — | | | 726 | | Net income | | — | | | — | | | — | | | 394 | | | — | | | 394 | |
| | Balance, June 30, 2021 | | Balance, June 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,105 | | | $ | (19) | | | $ | 9,567 | |
| | | | | | | | | | | | | | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,579 | | | $ | (16) | | | $ | 10,044 | |
| Net income | | Net income | | — | | | — | | | — | | | 82 | | | — | | | 82 | |
| | Common stock dividends declared | | Common stock dividends declared | | — | | | — | | | — | | | (100) | | | — | | | (100) | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,561 | | | $ | (16) | | | $ | 10,026 | |
| | Balance, December 31, 2021 | | Balance, December 31, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,449 | | | $ | (17) | | | $ | 9,913 | |
| Net income | | Net income | | — | | | — | | | — | | | 212 | | | — | | | 212 | |
| Other comprehensive income | Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | | Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| | Balance, September 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,437 | | | $ | (18) | | | $ | 9,900 | | |
| Common stock dividends declared | | Common stock dividends declared | | — | | | — | | | — | | | (100) | | | — | | | (100) | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,561 | | | $ | (16) | | | $ | 10,026 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | Nine-Month Periods | | Six-Month Periods |
| | | Ended September 30, | | Ended June 30, |
| | | 2021 | | 2020 | | 2022 | | 2021 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 726 | | | $ | 628 | | Net income | $ | 212 | | | $ | 394 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | Adjustments to reconcile net income to net cash flows from operating activities: | | | | Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| Depreciation and amortization | Depreciation and amortization | 811 | | | 696 | | Depreciation and amortization | 559 | | | 539 | |
| Allowance for equity funds | Allowance for equity funds | (38) | | | (73) | | Allowance for equity funds | (28) | | | (25) | |
| Changes in regulatory assets and liabilities | Changes in regulatory assets and liabilities | (185) | | | (17) | | Changes in regulatory assets and liabilities | (76) | | | (98) | |
| Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 33 | | | (48) | | Deferred income taxes and amortization of investment tax credits | 29 | | | 22 | |
| Other, net | Other, net | — | | | 2 | | Other, net | 12 | | | (1) | |
| Changes in other operating assets and liabilities: | Changes in other operating assets and liabilities: | | | | Changes in other operating assets and liabilities: | | | |
| Trade receivables, other receivables and other assets | Trade receivables, other receivables and other assets | (1) | | | (150) | | Trade receivables, other receivables and other assets | (142) | | | (10) | |
| Inventories | Inventories | 17 | | | (97) | | Inventories | (16) | | | 8 | |
| Derivative collateral, net | Derivative collateral, net | 19 | | | 22 | | Derivative collateral, net | 69 | | | 35 | |
| Prepaid expenses | (11) | | | (4) | | |
| | Accrued property, income and other taxes, net | Accrued property, income and other taxes, net | 96 | | | 84 | | Accrued property, income and other taxes, net | 152 | | | 79 | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 77 | | | 248 | | Accounts payable and other liabilities | 442 | | | 103 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 1,544 | | | 1,291 | | Net cash flows from operating activities | 1,213 | | | 1,046 | |
| | | | | | | | | |
| Cash flows from investing activities: | Cash flows from investing activities: | | | | Cash flows from investing activities: | | | |
| Capital expenditures | Capital expenditures | (1,157) | | | (1,618) | | Capital expenditures | (894) | | | (819) | |
| Other, net | Other, net | 7 | | | 31 | | Other, net | 6 | | | — | |
| Net cash flows from investing activities | Net cash flows from investing activities | (1,150) | | | (1,587) | | Net cash flows from investing activities | (888) | | | (819) | |
| | | | | | | | | |
| Cash flows from financing activities: | Cash flows from financing activities: | | | | Cash flows from financing activities: | | | |
| Proceeds from long-term debt | 984 | | | 987 | | |
| | Repayments of long-term debt | Repayments of long-term debt | (400) | | | — | | Repayments of long-term debt | (9) | | | (400) | |
| Repayments of short-term debt | (93) | | | (130) | | |
| Net proceeds from short-term debt | | Net proceeds from short-term debt | — | | | 208 | |
| | Dividends paid | | Dividends paid | (100) | | | — | |
| Other, net | Other, net | (5) | | | — | | Other, net | (2) | | | (4) | |
| Net cash flows from financing activities | Net cash flows from financing activities | 486 | | | 857 | | Net cash flows from financing activities | (111) | | | (196) | |
| | | | | | | | | |
| Net change in cash and cash equivalents and restricted cash and cash equivalents | Net change in cash and cash equivalents and restricted cash and cash equivalents | 880 | | | 561 | | Net change in cash and cash equivalents and restricted cash and cash equivalents | 214 | | | 31 | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 19 | | | 36 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 186 | | | 19 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 899 | | | $ | 597 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 400 | | | $ | 50 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United StatesU.S. 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 SeptemberJune 30, 20212022 and for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020.2021. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020.2021. The results of operations for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 20202021 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, 20202021 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-monthsix-month period ended SeptemberJune 30, 2021.2022, other than the updates associated with PacifiCorp's estimates of loss contingencies related to the Oregon and California 2020 wildfires (the "2020 Wildfires") as discussed in Note 9.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United StatesU.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing vendor retention, custodialnuclear decommissioning and nuclear decommissioningcustodial 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 | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash and cash equivalents | Cash and cash equivalents | $ | 893 | | | $ | 13 | | Cash and cash equivalents | $ | 390 | | | $ | 179 | |
| Restricted cash included in other current assets | 4 | | | 4 | | |
| Restricted cash and cash equivalents included in other current assets | | Restricted cash and cash equivalents included in other current assets | 7 | | | 4 | |
| Restricted cash included in other assets | Restricted cash included in other assets | 2 | | | 2 | | Restricted cash included in other assets | 3 | | | 3 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 899 | | | $ | 19 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 400 | | | $ | 186 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | | As of |
| | | | September 30, | | December 31, |
| Depreciable Life | | 2021 | | 2020 |
| Utility Plant: | | | | | |
| Generation | 15 - 59 years | | $ | 13,635 | | | $ | 12,861 | |
| Transmission | 60 - 90 years | | 7,833 | | | 7,632 | |
| Distribution | 20 - 75 years | | 7,889 | | | 7,660 | |
Intangible plant(1) | 5 - 75 years | | 1,083 | | | 1,054 | |
| Other | 5 - 60 years | | 1,535 | | | 1,510 | |
| Utility plant in service | | | 31,975 | | | 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 amortization | 14 - 95 years | | 9 | | | 9 | |
| Plant, net | | | 21,614 | | | 20,888 | |
| Construction work-in-progress | | | 1,134 | | | 1,542 | |
| Property, plant and equipment, net | | | $ | 22,748 | | | $ | 22,430 | |
| | | | | | | | | | | | | | | | | |
| | | | As of |
| | | | June 30, | | December 31, |
| Depreciable Life | | 2022 | | 2021 |
| Utility Plant: | | | | | |
| Generation | 15 - 59 years | | $ | 13,770 | | | $ | 13,679 | |
| Transmission | 60 - 90 years | | 7,952 | | | 7,894 | |
| Distribution | 20 - 75 years | | 8,211 | | | 8,044 | |
Intangible plant(1) | 5 - 75 years | | 1,114 | | | 1,106 | |
| Other | 5 - 60 years | | 1,584 | | | 1,539 | |
| Utility plant in-service | | | 32,631 | | | 32,262 | |
| Accumulated depreciation and amortization | | | (10,874) | | | (10,507) | |
| Utility plant in-service, net | | | 21,757 | | | 21,755 | |
| Other non-regulated, net of accumulated depreciation and amortization | 14 - 95 years | | 18 | | | 18 | |
| Plant, net | | | 21,775 | | | 21,773 | |
| Construction work-in-progress | | | 1,639 | | | 1,141 | |
| Property, plant and equipment, net | | | $ | 23,414 | | | $ | 22,914 | |
(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 2021,2022, PacifiCorp terminated, upon lender consent,amended and restated its existing $600 million$1.2 billion 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.2024. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 20242025 and increasedamended pricing from the available maturity extension optionsLondon Interbank Offered Rate to an unlimited number, subject to lender consent.the Secured Overnight Financing Rate.
Common Shareholder'sShareholders' Equity
In October 2021,May 2022, PacifiCorp declared a common stock dividend of $150$100 million, payablepaid in November 2021,June 2022, to PPW Holdings LLC.
(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) expensebenefit is as follows:
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| State income tax, net of federal income tax benefit | State income tax, net of federal income tax benefit | 4 | | | 3 | | | 4 | | | 3 | | State income tax, net of federal income tax benefit | 4 | | | 4 | | | 3 | | | 4 | |
| Federal income tax credits | Federal income tax credits | (20) | | | (15) | | | (20) | | | (12) | | Federal income tax credits | (25) | | | (19) | | | (21) | | | (19) | |
Effects of ratemaking | Effects of ratemaking | (13) | | | (4) | | | (14) | | | (8) | | Effects of ratemaking | (13) | | | (15) | | | (11) | | | (14) | |
| | Valuation allowance | | Valuation allowance | — | | | — | | | 4 | | | — | |
| Other | Other | (1) | | | 1 | | | — | | | 1 | | Other | 2 | | | — | | | 1 | | | — | |
| Effective income tax rate | Effective income tax rate | (9) | % | | 6 | % | | (9) | % | | 5 | % | Effective income tax rate | (11) | % | | (9) | % | | (3) | % | | (8) | % |
(1)Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
Income tax credits relate primarily to production tax credits ("PTC"PTCs") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods endedJune 30, 2022 and 2021 totaled $18 million and $40 million, respectively. PTCs for the six-month periods ended June 30, 2022 and 2021 totaled $44 million and $71 million, respectively.
Effects of ratemaking forFor the three- and nine-month periodssix-month period ended SeptemberJune 30, 2021, and 2020 is primarily attributable2022 PacifiCorp recorded a valuation allowance related to activity associated with excess deferred income taxes. Excess deferred income tax amortization,state 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 endedSeptember 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.operating loss carryforwards.
Berkshire Hathaway includes BHE and its subsidiaries in its United StatesU.S. 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 periodsix-month periods ended SeptemberJune 30, 2022 and 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$150 million and state income tax to BHE totaling $79 million.$93 million, respectively.
(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 Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Pension: | Pension: | | | | | | | | Pension: | | | | | | | |
| Service cost | Service cost | $ | — | | | $ | — | | | $ | — | | | $ | — | | Service cost | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Interest cost | Interest cost | 8 | | | 9 | | | 22 | | | 27 | | Interest cost | 7 | | | 7 | | | 14 | | | 14 | |
| Expected return on plan assets | Expected return on plan assets | (12) | | | (14) | | | (39) | | | (42) | | Expected return on plan assets | (11) | | | (14) | | | (21) | | | (27) | |
| Settlement | 4 | | | — | | | 4 | | | — | | |
| | Net amortization | Net amortization | 5 | | | 4 | | | 15 | | | 13 | | Net amortization | 4 | | | 5 | | | 8 | | | 10 | |
| Net periodic benefit cost (credit) | Net periodic benefit cost (credit) | $ | 5 | | | $ | (1) | | | $ | 2 | | | $ | (2) | | Net periodic benefit cost (credit) | $ | — | | | $ | (2) | | | $ | 1 | | | $ | (3) | |
| | Other postretirement: | Other postretirement: | | Other postretirement: | |
| Service cost | Service cost | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | | Service cost | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 1 | |
| Interest cost | Interest cost | 1 | | | 2 | | | 5 | | | 7 | | Interest cost | 2 | | | 2 | | | 4 | | | 4 | |
| Expected return on plan assets | Expected return on plan assets | (2) | | | (3) | | | (6) | | | (10) | | Expected return on plan assets | (3) | | | (2) | | | (5) | | | (4) | |
| Net amortization | Net amortization | 1 | | | — | | | 1 | | | — | | Net amortization | — | | | — | | | — | | | — | |
| Net periodic benefit (credit) cost | $ | — | | | $ | (1) | | | $ | 1 | | | $ | (2) | | |
| Net periodic benefit cost (credit) | | Net periodic benefit cost (credit) | $ | — | | | $ | 1 | | | $ | — | | | $ | 1 | |
Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the 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 2021.2022. As of SeptemberJune 30, 2021, $32022, $2 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, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. 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.
The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
| As of September 30, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
| Commodity assets | $ | 159 | | | $ | 40 | | | $ | 4 | | | $ | 1 | | | $ | 204 | |
| Commodity liabilities | — | | | — | | | (46) | | | (9) | | | (55) | |
| Total | 159 | | | 40 | | | (42) | | | (8) | | | 149 | |
| | | | | | | | | |
| Total derivatives | 159 | | | 40 | | | (42) | | | (8) | | | 149 | |
| Cash collateral (payable) receivable | (6) | | | — | | | 11 | | | — | | | 5 | |
| Total derivatives - net basis | $ | 153 | | | $ | 40 | | | $ | (31) | | | $ | (8) | | | $ | 154 | |
| | | | | | | | | |
| As of December 31, 2020 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
| Commodity assets | $ | 29 | | | $ | 6 | | | $ | 1 | | | $ | — | | | $ | 36 | |
| Commodity liabilities | (2) | | | — | | | (23) | | | (28) | | | (53) | |
| Total | 27 | | | 6 | | | (22) | | | (28) | | | (17) | |
| | | | | | | | | | |
| Total derivatives | 27 | | | 6 | | | (22) | | | (28) | | | (17) | |
| Cash collateral receivable | — | | | — | | | 15 | | | 9 | | | 24 | |
| Total derivatives - net basis | $ | 27 | | | $ | 6 | | | $ | (7) | | | $ | (19) | | | $ | 7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative | | | | | | | | |
| Contracts - | | | | Other | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
| As of June 30, 2022 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
| Commodity assets | $ | 183 | | | $ | 80 | | | $ | 9 | | | $ | — | | | $ | 272 | |
| Commodity liabilities | (1) | | | — | | | (44) | | | (4) | | | (49) | |
| Total | 182 | | | 80 | | | (35) | | | (4) | | | 223 | |
| | | | | | | | | |
| Total derivatives | 182 | | | 80 | | | (35) | | | (4) | | | 223 | |
| Cash collateral payable | (55) | | | (9) | | | — | | | — | | | (64) | |
| Total derivatives - net basis | $ | 127 | | | $ | 71 | | | $ | (35) | | | $ | (4) | | | $ | 159 | |
| | | | | | | | | |
| As of December 31, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
| Commodity assets | $ | 81 | | | $ | 21 | | | $ | 2 | | | $ | — | | | $ | 104 | |
| Commodity liabilities | (5) | | | (1) | | | (38) | | | (7) | | | (51) | |
| Total | 76 | | | 20 | | | (36) | | | (7) | | | 53 | |
| | | | | | | | | | |
| Total derivatives | 76 | | | 20 | | | (36) | | | (7) | | | 53 | |
| Cash collateral receivable | — | | | — | | | 5 | | | — | | | 5 | |
| Total derivatives - net basis | $ | 76 | | | $ | 20 | | | $ | (31) | | | $ | (7) | | | $ | 58 | |
(1)PacifiCorp's commodity derivatives are generally included in rates. As of SeptemberJune 30, 20212022 a regulatory liability of $149$223 million was recorded related to the net derivative asset of $149$223 million. As of December 31, 20202021 a regulatory assetliability of $17$53 million was recorded related to the net derivative liabilityasset of $17$53 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 Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
| Beginning balance | $ | (102) | | | $ | 68 | | | $ | 17 | | | $ | 62 | |
| Changes in fair value | (128) | | | (49) | | | (247) | | | (21) | |
| Net gains (losses) reclassified to operating revenue | — | | | 1 | | | (5) | | | 14 | |
| Net gains (losses) reclassified to cost of fuel and energy | 81 | | | (11) | | | 86 | | | (46) | |
| Ending balance | $ | (149) | | | $ | 9 | | | $ | (149) | | | $ | 9 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Six-Month Periods |
| Ended June 30, | | Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | |
| Beginning balance | $ | (195) | | | $ | — | | | $ | (53) | | | $ | 17 | |
| Changes in fair value recognized in regulatory assets | (49) | | | (102) | | | (217) | | | (119) | |
| Net losses reclassified to operating revenue | (8) | | | (5) | | | (11) | | | (5) | |
| Net gains reclassified to energy costs | 29 | | | 5 | | | 58 | | | 5 | |
| Ending balance | $ | (223) | | | $ | (102) | | | $ | (223) | | | $ | (102) | |
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
| | | Unit of | | September 30, | | December 31, | | Unit of | | June 30, | | December 31, |
| | Measure | | 2021 | | 2020 | | Measure | | 2022 | | 2021 |
| | Electricity sales, net | Megawatt hours | | — | | | (1) | | |
| Electricity purchases, net | | Electricity purchases, net | Megawatt hours | | 2 | | | 2 | |
| Natural gas purchases | Natural gas purchases | Decatherms | | 101 | | | 100 | | Natural gas purchases | Decatherms | | 105 | | | 106 | |
|
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 SeptemberJune 30, 2021,2022, 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$47 million and $51$37 million as of SeptemberJune 30, 20212022 and December 31, 2020,2021, respectively, for which PacifiCorp had posted collateral of $11$— million and $24$5 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 SeptemberJune 30, 20212022 and December 31, 2020,2021, PacifiCorp would have been required to post $36$33 million and $25$23 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(8) Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.
The following table presents PacifiCorp's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
| As of September 30, 2021 | | | | | | | | | |
| Assets: | | | | | | | | | |
| Commodity derivatives | $ | — | | | $ | 204 | | | $ | — | | | $ | (11) | | | $ | 193 | |
| Money market mutual funds | 876 | | | — | | | — | | | — | | | 876 | |
| Investment funds | 31 | | | — | | | — | | | — | | | 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 | 6 | | | — | | | — | | | — | | | 6 | |
| Investment funds | 25 | | | — | | | — | | | — | | | 25 | |
| $ | 31 | | | $ | 36 | | | $ | — | | | $ | (3) | | | $ | 64 | |
| | | | | | | | | |
| Liabilities - Commodity derivatives | $ | — | | | $ | (53) | | | $ | — | | | $ | 27 | | | $ | (26) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
| As of June 30, 2022: | | | | | | | | | |
| Assets: | | | | | | | | | |
| Commodity derivatives | $ | — | | | $ | 272 | | | $ | — | | | $ | (74) | | | $ | 198 | |
| Money market mutual funds | 374 | | | — | | | — | | | — | | | 374 | |
| Investment funds | 26 | | | — | | | — | | | — | | | 26 | |
| | $ | 400 | | | $ | 272 | | | $ | — | | | $ | (74) | | | $ | 598 | |
| | | | | | | | | |
| Liabilities - Commodity derivatives | $ | — | | | $ | (49) | | | $ | — | | | $ | 10 | | | $ | (39) | |
| | | | | | | | | |
| As of December 31, 2021: | | | | | | | | | |
| Assets: | | | | | | | | | |
| Commodity derivatives | $ | — | | | $ | 104 | | | $ | — | | | $ | (8) | | | $ | 96 | |
| Money market mutual funds | 181 | | | — | | | — | | | — | | | 181 | |
| Investment funds | 27 | | | — | | | — | | | — | | | 27 | |
| $ | 208 | | | $ | 104 | | | $ | — | | | $ | (8) | | | $ | 304 | |
| | | | | | | | | |
| Liabilities - Commodity derivatives | $ | — | | | $ | (51) | | | $ | — | | | $ | 13 | | | $ | (38) | |
(1)Represents netting under master netting arrangements and a net cash collateral payable of $64 million and a net cash collateral receivable of $5 million and $24 million as of SeptemberJune 30, 20212022 and December 31, 2020,2021, 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 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, 2021 | | As of December 31, 2020 |
| | | Carrying | | Fair | | Carrying | | Fair |
| | | Value | | Value | | Value | | Value |
| | | | | | | | | |
| Long-term debt | | $ | 9,199 | | | $ | 11,005 | | | $ | 8,612 | | | $ | 10,995 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | As of June 30, 2022 | | As of December 31, 2021 |
| | | Carrying | | Fair | | Carrying | | Fair |
| | | Value | | Value | | Value | | Value |
| | | | | | | | | |
| Long-term debt | | $ | 8,723 | | | $ | 8,555 | | | $ | 8,730 | | | $ | 10,374 | |
(9) Commitments and Contingencies
Construction Commitments
During the six-month period ended June 30, 2022, PacifiCorp entered into a procurement and construction services agreement for $849 million through 2024 for the construction of a key Energy Gateway Transmission segment extending between the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah.
Fuel Contracts
During the six-month period ended June 30, 2022, PacifiCorp entered into certain coal supply and transportation agreements totaling approximately $200 million through 2024.
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
California and Oregon 2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, privatereal and publicpersonal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires").California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. 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.
SeveralMultiple 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. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. 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 real and personal property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.
AsDuring the three-month period ended June 30, 2022, PacifiCorp accrued $64 million 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 probableresulting in an overall loss accrual net of being incurred.expected insurance recoveries of $200 million as of June 30, 2022 compared to $136 million as of December 31, 2021. These accruals include estimatedPacifiCorp's estimate of losses for fire suppression costs, real and personal property damage,damages, natural resource damages and noneconomic damages such as personal injury damages and loss of life damages.damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to natural resource damages, is not currently available. 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 variation in those types of properties and lack of specific claims for all potential claimants.available details. 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. PacifiCorp's receivable for expected insurance recoveries was $277 million as of June 30, 2022.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application by January 16, 2021, to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC 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 conditionally approved the required property transfer.transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending. In February 2022, the FERC staff issued a draft environmental impact statement for the project, concluding that dam removal is the preferred alternative. A final environmental impact statement is expected later in 2022.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale or transfer of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.
(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 Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Customer Revenue: | Customer Revenue: | | | | | | | | Customer Revenue: | | | | | | | |
| Retail: | Retail: | | Retail: | |
| Residential | Residential | $ | 530 | | | $ | 519 | | | $ | 1,442 | | | $ | 1,363 | | Residential | $ | 417 | | | $ | 429 | | | $ | 922 | | | $ | 912 | |
| Commercial | Commercial | 428 | | | 418 | | | 1,180 | | | 1,122 | | Commercial | 393 | | | 393 | | | 763 | | | 752 | |
| Industrial | Industrial | 296 | | | 293 | | | 849 | | | 838 | | Industrial | 277 | | | 282 | | | 550 | | | 553 | |
| Other retail | Other retail | 98 | | | 114 | | | 214 | | | 209 | | Other retail | 80 | | | 84 | | | 117 | | | 116 | |
| Total retail | Total retail | 1,352 | | | 1,344 | | | 3,685 | | | 3,532 | | Total retail | 1,167 | | | 1,188 | | | 2,352 | | | 2,333 | |
Wholesale | Wholesale | 58 | | | 59 | | | 124 | | | 76 | | Wholesale | 55 | | | 30 | | | 110 | | | 66 | |
| Transmission | Transmission | 55 | | | 33 | | | 117 | | | 79 | | Transmission | 45 | | | 37 | | | 77 | | | 62 | |
| Other Customer Revenue | Other Customer Revenue | 26 | | | 42 | | | 80 | | | 88 | | Other Customer Revenue | 28 | | | 31 | | | 48 | | | 54 | |
| Total Customer Revenue | Total Customer Revenue | 1,491 | | | 1,478 | | | 4,006 | | | 3,775 | | Total Customer Revenue | 1,295 | | | 1,286 | | | 2,587 | | | 2,515 | |
| Other revenue | Other revenue | — | | | 1 | | | 25 | | | 54 | | Other revenue | 19 | | | 12 | | | 24 | | | 25 | |
| Total operating revenue | Total operating revenue | $ | 1,491 | | | $ | 1,479 | | | $ | 4,031 | | | $ | 3,829 | | Total operating revenue | $ | 1,314 | | | $ | 1,298 | | | $ | 2,611 | | | $ | 2,540 | |
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 ThirdSecond Quarter and First NineSix Months of 20212022 and 20202021
Overview
Net income for the thirdsecond quarter of 20212022 was $332$82 million, an increasea decrease of $46$143 million, or 16%64%, compared to 2020.2021. Net income increaseddecreased primarily due to lowerhigher operations and maintenance expense of $65$120 million, primarily due to prior year costs associated with the Klamath Hydroelectric Projectand estimated losses in the prior year associated with wildfires, lower income tax expensebenefit of $46$11 million, primarily due to the impactshigher property and other taxes of ratemaking$8 million and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and higher utility marginother expense of $6 million, partially offset by higher depreciationutility margin of $6 million. Operations and amortizationmaintenance expense increased primarily due to an increase in the loss accruals associated with the September 2020 wildfires, net of $38 million, including the impacts of the depreciation study for which rates became effective January 2021,estimated insurance recoveries, and lower allowances for equityhigher general and borrowed funds used during construction of $24 million.plant maintenance costs. Utility margin increased primarily due to lower purchased electricity prices, higher retail rates, higher average wholesale market prices and wheeling revenue,lower thermal generation volumes, partially offset by higher natural gas-fueled generation prices, lower retail volumes, higher purchased electricity volumes and lower 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.mechanisms. Retail customer volumes increased 2.1%decreased 3.3%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers and higher customer usage.customers. Energy generated increased 9%decreased 7% for the thirdsecond quarter of 20212022 compared to 20202021 primarily due to higher wind-powered,lower coal-fueled and natural gas-fueled generation, partially offset by lowerhigher wind-powered and hydroelectric generation. Wholesale electricity sales volumes increased 4%were essentially flat and purchased electricity volumes decreased 16%increased 12%.
Net income for the first ninesix months of 20212022 was $726$212 million, an increasea decrease of $98$182 million, or 16%46%, compared to 2020. Net income increased2021 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$138 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 bylower income tax benefit of $24 million, higher depreciation and amortization expense of $115$20 million includingand higher other expense of $14 million, partially offset by higher utility margin of $20 million. Operations and maintenance expense increased mainly due to an increase in loss accruals related to the impactsSeptember 2020 wildfires, net of the depreciation study for which rates became effective January 2021,estimated insurance recoveries, and lower allowances for equityhigher general and borrowed funds used during construction of $53 million.plant maintenance costs. 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 prices, higher retail rates, higher average wholesale market prices, lower thermal generation volumes, and higher RECwheeling revenue, partially offset by higher natural gas-fueled generation prices, higher purchased electricity prices, thermal generation costsvolumes and wheeling expenses.lower retail volumes. Retail customer volumes increased 4.4%decreased 0.7%, primarily due to higherthe unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers, and favorable impacts of weather.customers. Energy generated increased 14%decreased 4% for the first ninesix months of 20212022 compared to 20202021 primarily due to higherlower coal-fueled wind-powered, and natural gas-fueled generation, partially offset by lowerhigher wind-powered and hydroelectric generation. Wholesale electricity sales volumes increased 20%decreased 1% and purchased electricity volumes decreased 16%increased 9%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
PacifiCorp's cost of fuel and energy is generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin: | Utility margin: | | | | | | | | | | | | Utility margin: | | | | | | | | | | | |
| Operating revenue | Operating revenue | $ | 1,491 | | | $ | 1,479 | | | $ | 12 | | | 1 | % | | $ | 4,031 | | | $ | 3,829 | | | $ | 202 | | | 5 | % | Operating revenue | $ | 1,314 | | | $ | 1,298 | | | $ | 16 | | | 1 | % | | $ | 2,611 | | | $ | 2,540 | | | $ | 71 | | | 3 | % |
| Cost of fuel and energy | Cost of fuel and energy | 505 | | | 499 | | | 6 | | | 1 | | | 1,370 | | | 1,299 | | | 71 | | | 5 | | Cost of fuel and energy | 451 | | | 441 | | | 10 | | | 2 | | | 916 | | | 865 | | | 51 | | | 6 | |
| Utility margin | Utility margin | 986 | | | 980 | | | 6 | | | 1 | | | 2,661 | | | 2,530 | | | 131 | | | 5 | | Utility margin | 863 | | | 857 | | | 6 | | | 1 | | | 1,695 | | | 1,675 | | | 20 | | | 1 | |
| Operations and maintenance | Operations and maintenance | 267 | | | 332 | | | (65) | | | (20) | | | 781 | | | 829 | | | (48) | | | (6) | | Operations and maintenance | 375 | | | 255 | | | 120 | | | 47 | | | 652 | | | 514 | | | 138 | | | 27 | |
| Depreciation and amortization | Depreciation and amortization | 272 | | | 234 | | | 38 | | | 16 | | | 811 | | | 696 | | | 115 | | | 17 | | Depreciation and amortization | 279 | | | 275 | | | 4 | | | 1 | | | 559 | | | 539 | | | 20 | | | 4 | |
| Property and other taxes | Property and other taxes | 54 | | | 53 | | | 1 | | | 2 | | | 158 | | | 154 | | | 4 | | | 3 | | Property and other taxes | 51 | | | 43 | | | 8 | | | 19 | | | 110 | | | 104 | | | 6 | | | 6 | |
| Operating income | Operating income | $ | 393 | | | $ | 361 | | | $ | 32 | | | 9 | % | | $ | 911 | | | $ | 851 | | | $ | 60 | | | 7 | % | Operating income | $ | 158 | | | $ | 284 | | | $ | (126) | | | (44) | % | | $ | 374 | | | $ | 518 | | | $ | (144) | | | (28) | % |
Utility Margin
A comparison of key operating results related to utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
| Utility margin (in millions): | | | | | | | | | | | | | | | |
| Operating revenue | $ | 1,491 | | | $ | 1,479 | | | $ | 12 | | | 1 | % | | $ | 4,031 | | | $ | 3,829 | | | $ | 202 | | | 5 | % |
| Cost of fuel and energy | 505 | | | 499 | | | 6 | | | 1 | | | 1,370 | | | 1,299 | | | 71 | | | 5 | |
| Utility margin | $ | 986 | | | $ | 980 | | | $ | 6 | | | 1 | % | | $ | 2,661 | | | $ | 2,530 | | | $ | 131 | | | 5 | % |
| | | | | | | | | | | | | | | |
| Sales (GWhs): | | | | | | | | | | | | | | | |
| Residential | 4,732 | | | 4,622 | | | 110 | | | 2 | % | | 13,396 | | | 12,699 | | | 697 | | | 5 | % |
| Commercial | 5,078 | | | 4,799 | | | 279 | | | 6 | | | 14,181 | | | 13,157 | | | 1,024 | | | 8 | |
| Industrial, irrigation and other | 5,375 | | | 5,446 | | | (71) | | | (1) | | | 14,976 | | | 14,907 | | | 69 | | | — | |
| Total retail | 15,185 | | | 14,867 | | | 318 | | | 2 | | | 42,553 | | | 40,763 | | | 1,790 | | | 4 | |
| Wholesale | 1,093 | | | 1,053 | | | 40 | | | 4 | | | 3,928 | | | 3,266 | | | 662 | | | 20 | |
| Total sales | 16,278 | | | 15,920 | | | 358 | | | 2 | % | | 46,481 | | | 44,029 | | | 2,452 | | | 6 | % |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Average number of retail customers
(in thousands) | 2,006 | | | 1,971 | | | 35 | | | 2 | % | | 1,998 | | | 1,963 | | | 35 | | | 2 | % |
| | | | | | | | | | | | | | | |
| 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 days | 196 | | | 194 | | | 2 | | | 1 | % | | 6,111 | | | 6,132 | | | (21) | | | — | % |
| | | | | | | | | | | | | | | |
| Cooling degree days | 1,681 | | | 1,658 | | | 23 | | | 1 | % | | 2,427 | | | 2,097 | | | 330 | | | 16 | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
| Coal | 9,011 | | | 8,576 | | | 435 | | | 5 | % | | 24,157 | | | 22,001 | | | 2,156 | | | 10 | % |
| Natural gas | 3,886 | | | 3,638 | | | 248 | | | 7 | | | 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 generated | 14,600 | | | 13,348 | | | 1,252 | | | 9 | | | 40,846 | | | 35,929 | | | 4,917 | | | 14 | |
| Energy purchased | 3,058 | | | 3,621 | | | (563) | | | (16) | | | 9,407 | | | 11,245 | | | (1,838) | | | (16) | |
| Total | 17,658 | | | 16,969 | | | 689 | | | 4 | % | | 50,253 | | | 47,174 | | | 3,079 | | | 7 | % |
| | | | | | | | | | | | | | | |
| 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 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter | | First Six Months |
| 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin (in millions): | | | | | | | | | | | | | | | |
| Operating revenue | $ | 1,314 | | | $ | 1,298 | | | $ | 16 | | | 1 | % | | $ | 2,611 | | | $ | 2,540 | | | $ | 71 | | | 3 | % |
| Cost of fuel and energy | 451 | | | 441 | | | 10 | | | 2 | | | 916 | | | 865 | | | 51 | | | 6 | |
| Utility margin | $ | 863 | | | $ | 857 | | | $ | 6 | | | 1 | % | | $ | 1,695 | | | $ | 1,675 | | | $ | 20 | | | 1 | % |
| | | | | | | | | | | | | | | |
| Sales (GWhs): | | | | | | | | | | | | | | | |
| Residential | 3,854 | | | 4,032 | | | (178) | | | (4) | % | | 8,618 | | | 8,664 | | | (46) | | | (1) | % |
| Commercial | 4,633 | | | 4,633 | | | — | | | — | | | 9,183 | | | 9,103 | | | 80 | | | 1 | |
| Industrial, irrigation and other | 4,849 | | | 5,127 | | | (278) | | | (5) | | | 9,372 | | | 9,601 | | | (229) | | | (2) | |
| Total retail | 13,336 | | | 13,792 | | | (456) | | | (3) | | | 27,173 | | | 27,368 | | | (195) | | | (1) | |
| Wholesale | 1,245 | | | 1,244 | | | 1 | | | — | | | 2,798 | | | 2,835 | | | (37) | | | (1) | |
| Total sales | 14,581 | | | 15,036 | | | (455) | | | (3) | % | | 29,971 | | | 30,203 | | | (232) | | | (1) | % |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Average number of retail customers
(in thousands) | 2,033 | | | 1,998 | | | 35 | | | 2 | % | | 2,029 | | | 1,994 | | | 35 | | | 2 | % |
| | | | | | | | | | | | | | | |
| Average revenue per MWh: | | | | | | | | | | | | | | | |
| Retail | $ | 88.14 | | | $ | 86.26 | | | $ | 1.88 | | | 2 | % | | $ | 86.77 | | | $ | 85.21 | | | $ | 1.56 | | | 2 | % |
| Wholesale | $ | 51.53 | | | $ | 31.08 | | | $ | 20.45 | | | 66 | % | | $ | 44.64 | | | $ | 30.97 | | | $ | 13.67 | | | 44 | % |
| | | | | | | | | | | | | | | |
| Heating degree days | 1,736 | | | 1,228 | | | 508 | | | 41 | % | | 6,481 | | | 5,915 | | | 566 | | | 10 | % |
| | | | | | | | | | | | | | | |
| Cooling degree days | 406 | | | 746 | | | (340) | | | (46) | % | | 411 | | | 746 | | | (335) | | | (45) | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
| Coal | 6,260 | | | 7,502 | | | (1,242) | | | (17) | % | | 13,171 | | | 15,146 | | | (1,975) | | | (13) | % |
| Natural gas | 2,747 | | | 3,223 | | | (476) | | | (15) | | | 5,862 | | | 6,288 | | | (426) | | | (7) | |
Wind(2) | 1,817 | | | 1,383 | | | 434 | | | 31 | | | 4,209 | | | 3,121 | | | 1,088 | | | 35 | |
Hydroelectric and other(2) | 1,033 | | | 703 | | | 330 | | | 47 | | | 2,017 | | | 1,691 | | | 326 | | | 19 | |
| Total energy generated | 11,857 | | | 12,811 | | | (954) | | | (7) | | | 25,259 | | | 26,246 | | | (987) | | | (4) | |
| Energy purchased | 3,717 | | | 3,321 | | | 396 | | | 12 | | | 6,940 | | | 6,349 | | | 591 | | | 9 | |
| Total | 15,574 | | | 16,132 | | | (558) | | | (3) | % | | 32,199 | | | 32,595 | | | (396) | | | (1) | % |
| | | | | | | | | | | | | | | |
| Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 21.90 | | | $ | 17.84 | | | $ | 4.06 | | | 23 | % | | $ | 20.27 | | | $ | 17.75 | | | $ | 2.52 | | | 14 | % |
| Energy purchased | $ | 48.92 | | | $ | 65.62 | | | $ | (16.70) | | | (25) | % | | $ | 51.97 | | | $ | 56.80 | | | $ | (4.83) | | | (9) | % |
(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 RECsRenewable Energy Credits or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
Quarter Ended SeptemberJune 30, 20212022 compared to Quarter Ended SeptemberJune 30, 20202021
Utility margin increased $6 million, or 1%, for the thirdsecond quarter of 20212022 compared to 20202021 primarily due to:
•$10336 million of lower purchased electricity costs from lower average market prices, partially offset by higher purchased volumes;
•$25 million increase in wholesale revenue primarily due to higher average market prices;
•$22 million of lower coal-fueled generation costs primarily due to lower volumes; and
•$7 million of favorable wheeling activities.
The increases above were partially offset by:
•$54 million of higher natural gas-fueled generation costs due to higher average prices, partially offset by lower volumes;
•$14 million decrease in retail revenue due to lower volumes, partially offset by higher average prices. Retail customer volumes decreased 3.3%, primarily due to the unfavorable impacts of weather, mainly in Utah, Idaho and Oregon and a decrease in customer usage, mainly in Utah and Oregon, partially offset by an increase in the average number of customers across the service territory, mainly in Utah and Oregon; and
•$13 million of lower deferred net power costs in accordance with established adjustment mechanisms;mechanisms.
Operations and maintenance increased $120 million, or 47%, for the second quarter of 2022 compared to 2021 primarily due to a $64 million increase in the loss accruals associated with the September 2020 wildfires net of estimated insurance recoveries, $27 million of higher general and plant maintenance costs, higher insurance premiums due to cost increases related to wildfire coverage and higher labor and employee expenses.
Depreciation and amortization increased $4 million, or 1%, for the second quarter of 2022 compared to 2021 primarily due to prior year deferrals in Idaho associated with the increase in depreciation expense resulting from the implementation of the 2018 depreciation study compounded by amortization of those deferrals in the current quarter and higher plant in-service balances in the current quarter, partially offset by lower depreciation associated with Oregon's accelerated depreciation of coal units due to an update to the Oregon allocation factor applied in computing the incremental depreciation.
Property and other taxes increased $8 million, or 19%, for the second quarter of 2022 compared to 2021 primarily due to higher assessed property values in Utah and Wyoming.
Other, net decreased $9 million for the second quarter of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies associated with PacifiCorp's supplemental executive retirement plan.
Income tax benefit decreased $11 million, or 58% for the second quarter of 2022 compared to 2021. The effective tax rate was (11)% for the second quarter of 2022 and (9)% for the second quarter of 2021. The effective tax rate decreased primarily due to the relative impact on a percentage basis of PTCs on the lower pre-tax book income in the second quarter of 2022 compared to that of 2021, which results in a higher benefit related to PTCs in the second quarter of 2022.
First Six Months of 2022 compared to First Six Months Ended 2021
Utility margin increased $20 million, or 1%, for the first six months of 2022 compared to 2021 primarily due to:
•$1237 million of favorable wheeling activities;increase in wholesale revenue due to higher average market prices, partially offset by lower volumes;
•$834 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices;
•$26 million increase in retail revenue primarily due to higher customer volumes,average prices, partially offset by lower rates driven by certain general rate case orders.volumes. Retail customer volumes increased 2.1%decreased 0.7%, primarily due to the unfavorable impacts of weather, mainly in Utah, Oregon and Idaho and a decrease in customer usage primarily in Utah, partially offset by an increase in the average number of customers across the service territory, mainly in Utah and higher customer usage, partially offset by the unfavorable impactOregon;
•$24 million of weather;lower purchased electricity costs due to lower average market prices; and
•$615 million of higher REC, fly ash and by-product revenues.favorable wheeling activities.
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.
The increases above were partially offset by:
•$117 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes;
•$5824 million of higher natural gas-fueled generationpurchased electricity costs due to higher average prices and higher volumes;
•$345 million of lower other revenue due to impacts of the Oregon RAC settlement (offsetdeferred net power costs in depreciation expense) in the prior year;accordance with established adjustment mechanisms; and
•$335 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.wind-based ancillary revenue.
Operations and maintenance decreased $48increased $138 million, or 6%27%, for the first ninesix months of 20212022 compared to 20202021 primarily due to prior year costsa $64 million increase in the loss accruals associated with the Klamath Hydroelectric ProjectSeptember 2020 wildfires net of estimated insurance recoveries, $37 million of higher general and estimated losses in the prior year associated with wildfires, lower thermal plant maintenance expense, including overhauls, and lower employee expenses, partially offset bycosts, higher wind plant and distribution maintenanceinsurance premiums due to cost increases related to wildfire coverage and higher vegetation management costs.bad debt expense.
Depreciation and amortization increased $115$20 million, or 17%,4% for the first ninesix months of 20212022 compared to 20202021 primarily due to prior year deferrals in Idaho associated with the impactsincrease in depreciation expense resulting from the implementation of athe 2018 depreciation study effective January 1, 2021compounded by amortization of approximately $120 million,those deferrals in the current year and higher plant in-service balances in the current year, partially offset by a $71 million decreaselower depreciation associated with Oregon's accelerated depreciation of coal units due to an update to the prior year Oregon RAC settlement ($3 millionallocation factor applied in computing 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)).incremental depreciation.
Allowance for borrowedProperty and equity fundsother taxes decreased $53increased $6 million, or 49%,6% for the first ninesix months of 20212022 compared to 20202021 primarily due to higher assessed property values in Utah and Wyoming.
Other, net decreased $19 million for the first six months of 2022 compared to 2021 primarily due to lower qualified construction work-in-progress balances and allowance for borrowed and equity funds rates.cash surrender value of corporate-owned life insurance policies associated with PacifiCorp's supplemental executive retirement plan.
Income tax (benefit) expensebenefit decreased $88$24 million, to a benefit of $58 millionor 80% for the first ninesix months of 20212022 compared to expense of $30 million the first ninesix months of 2020.2021. The effective tax rate was (9)(3)% for 2021the first six months of 2022 and 5%(8)% for 2020.the first six months of 2021. The effective tax rate decreasedincreased primarily asdue to 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 amortizationvaluation allowance PacifiCorp recorded in the current year.first quarter of 2022 against state net operating loss carryforwards.
Liquidity and Capital Resources
As of SeptemberJune 30, 2021,2022, PacifiCorp's total net liquidity was as follows (in millions):
| | | | | | | | |
| Cash and cash equivalents | | $ | 893390 | |
| | | |
| Credit facilities | | 1,200 | |
| Less: | | |
| | |
| Tax-exempt bond support | | (218) | |
| Net credit facilities | | 982 | |
| | | |
| Total net liquidity | | $ | 1,8751,372 | |
| | | |
| Credit facilities: | | |
| Maturity dates | | 20242025 | |
Operating Activities
Net cash flows from operating activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $1,544$1,213 million and $1,291$1,046 million, respectively. The change was primarily due to timing of operating payables, higher collections from retail customers and highertransmission deposits, cash received for income taxes and collateral received from counterparties, partially offset by higher fuel and 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.
Investing Activities
Net cash flows from investing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $(1,150)$(888) million and $(1,587)$(819) million, respectively. The change is primarily due to a decreasean increase 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.$75 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-monthsix-month period ended SeptemberJune 30, 2022 were $(111) million. Uses of cash consisted primarily of $100 million for common stock dividends paid to PPW Holdings LLC and $9 million for the repayment of long-term debt.
Net cash flows from financing activities for the six-month period ended June 30, 2021 were $486$(196) million. Sources of cash consisted of net proceeds$208 million from the issuanceborrowing of long-term debt of $984 million.short-term debt. 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 SeptemberJune 30, 2022 and December 31, 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 currently has regulatory authority from the OPUC and the IPUCIdaho Public Utilities Commission 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. PacifiCorp must make a notice filing with the WUTC prior to any future issuance.
Common Shareholder'sShareholders' Equity
In October 2021,May 2022, PacifiCorp declared a common stock dividend of $150$100 million, payablepaid in November 2021,June 2022, to PPW Holdings LLC.
Future Uses of Cash
PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to 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 Periods | | Annual | | Six-Month Periods | | Annual |
| | Ended September 30, | | Forecast | | Ended June 30, | | Forecast |
| | 2020 | | 2021 | | 2021 | | 2021 | | 2022 | | 2022 |
| | Wind generation | Wind generation | $ | 807 | | | $ | 110 | | | $ | 138 | | Wind generation | $ | 82 | | | $ | 14 | | | $ | 66 | |
| Electric distribution | Electric distribution | 360 | | | 461 | | | 637 | | Electric distribution | 326 | | | 303 | | | 682 | |
| Electric transmission | Electric transmission | 300 | | | 212 | | | 316 | | Electric transmission | 136 | | | 405 | | | 1,185 | |
| Other | Other | 151 | | | 374 | | | 467 | | Other | 275 | | | 172 | | | 346 | |
| Total | Total | $ | 1,618 | | | $ | 1,157 | | | $ | 1,558 | | Total | $ | 819 | | | $ | 894 | | | $ | 2,279 | |
PacifiCorp's 2019 and 2021 IRP identified a roadmap for a significant increase in renewable resourceand carbon free generation resources, coal to natural gas conversion of certain coal-fueled units, energy storage and associated transmission. PacifiCorp's 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to be online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp has included an estimate for these new generation resources and associated transmission in its forecast capital expenditures for 20212022 through 2023.2024. These estimates mayare likely to change as a result of the RFP process. PacifiCorp's historical and forecast capital expenditures include the following:
•Wind generation includes both growth projects and operating expenditures. Growth projects include:
◦Construction of wind-powered generating facilities at PacifiCorp totaling $99$4 million and $705$79 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, respectively. Construction includes 674516 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$24 million for the remainder of 2021.2022.
◦RepoweringPlanned acquisition and repowering of two wind-powered generating facilities atby PacifiCorp totaling $9$7 million and $99$2 million (excluding the 2021 sale of wind turbines) for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021, and 2020, respectively. Certain repowering projectsIn 2021, PacifiCorp sold wind turbines previously acquired from a third party to BHE Wind, LLC, an indirect wholly owned subsidiary of BHE, for existing facilities were placed in service in 2019, 2020 and in the first nine months of 2021.$6 million. The energy production from these existing repowered facilities isare expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service.be placed in-service in 2023 and 2024. Planned spending for theacquiring and repowering of wind-powered generating facilities totals $7$14 million for the remainder of 2021.2022.
•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$59 million and $21$117 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, respectively. Planned electric distribution spending for wildfire mitigation and wildfire and storm damage restoration totals $51$97 million for the remainder of 2021 and relates2022. Remaining investments relate to expenditures for new connections and distribution.distribution operations.
•Electric transmission includes both growth projects and operating expenditures. Transmission investment through 2020 primarily reflects planned costs for the 140-mile416-mile, 500-kV Aeolus-Bridger/Anticlinehigh-voltage transmission line a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020.between the Aeolus substation near Medicine Bow, Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these segments totaled $296 million and $35 million for the six-month periods ended June 30, 2022 and 2021, respectively. Planned spending for additionalthese Energy Gateway Transmission segments to be placed in servicein-service in 2024-2026 totals $46$614 million in 2021.for the remainder of 2022.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $69$77 million and $53$47 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, respectively. Planned information technology spending totals $47$87 million for the remainder of 2021 and relates2022. Remaining investments relate 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. PacifiCorp files its IRP biennially with the state commissions in each of the six states where PacifiCorp operates. Five states indicate whether the IRP meets the state commission's IRP standards and guidelines, a process referred to as "acknowledgment" in some states. Acknowledgement by a state commission does not address cost recovery or prudency of resources ultimately selected.
In September 2021, PacifiCorp filed its 2021 IRP with its state commissions. Thecommissions and subsequently filed its 2021 IRP includes investmentsUpdate in March and April 2022. In March 2022, the OPUC acknowledged PacifiCorp's 2021 IRP and its preferred portfolio. In June 2022, the UPSC issued an order declining to acknowledge the 2021 IRP due to its determination that PacifiCorp did not meet the commission's IRP guidelines by excluding new renewable energy resources, new battery storage resources and expanded transmission investments. New renewable energynatural gas-fueled resources in its modeling of the 2021 IRP's preferred portfolio, as well as the commission's view that PacifiCorp did not provide ample time for public input and information exchange during the development of the IRP. The UPSC did approve the 2022 All Source RFP ("2022AS RFP") to procure resources identified in the 2021 IRP. Reviews of the 2021 IRP include more than 1,800 MW of new wind-powered generation, over 2,100 MW of new solar-powered generationby the Wyoming Public Service Commission, the WUTC 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.the Idaho Public Utilities Commission are ongoing.
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.
PacifiCorpA draft of PacifiCorp's 2022AS RFP was filed for approval with the WUTC in December 2021, and with the UPSC and the OPUC in January 2022. The draft 2022AS RFP was approved by the WUTC in March 2022 and by the UPSC and the OPUC in April 2022. The 2022AS RFP was issued the 2020 All Source RFP to the market in July 2020. The 2020 All Source RFP soughtApril 2022. PacifiCorp-owned 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 winningare due late November 2022 and market 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.are due February 2023.
Contractual ObligationsMaterial Cash Requirements
As of SeptemberJune 30, 2021,2022, there have been no material changes outside the normal course of business in contractual obligationscash requirements from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2020.2021, other than those disclosed in Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Regulatory Matters
PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, pension and other postretirement benefits, income taxes and revenue recognition-unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2020.2021. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2020.2021.
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of 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 SeptemberJune 30, 2021,2022, the related statements of operations and changes in shareholder's equity for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and of cash flows for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, 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, 2020,2021, 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, 2021,25, 2022, 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, 2020,2021, 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
NovemberAugust 5, 20212022
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 541 | | | $ | 38 | | Cash and cash equivalents | $ | 495 | | | $ | 232 | |
| Trade receivables, net | Trade receivables, net | 555 | | | 234 | | Trade receivables, net | 525 | | | 526 | |
| | Income tax receivable | | Income tax receivable | 19 | | | 79 | |
| Inventories | Inventories | 244 | | | 278 | | Inventories | 226 | | | 234 | |
| Other current assets | Other current assets | 142 | | | 73 | | Other current assets | 186 | | | 123 | |
| Total current assets | Total current assets | 1,482 | | | 623 | | Total current assets | 1,451 | | | 1,194 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 19,773 | | | 19,279 | | Property, plant and equipment, net | 20,504 | | | 20,301 | |
| Regulatory assets | Regulatory assets | 479 | | | 392 | | Regulatory assets | 509 | | | 473 | |
| Investments and restricted investments | Investments and restricted investments | 975 | | | 911 | | Investments and restricted investments | 893 | | | 1,026 | |
| Other assets | Other assets | 235 | | | 232 | | Other assets | 278 | | | 263 | |
| | Total assets | Total assets | $ | 22,944 | | | $ | 21,437 | | Total assets | $ | 23,635 | | | $ | 23,257 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 347 | | | $ | 408 | | Accounts payable | $ | 415 | | | $ | 531 | |
| Accrued interest | Accrued interest | 89 | | | 78 | | Accrued interest | 84 | | | 84 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 242 | | | 161 | | Accrued property, income and other taxes | 206 | | | 158 | |
| | Current portion of long-term debt | | Current portion of long-term debt | 64 | | | — | |
| Other current liabilities | Other current liabilities | 226 | | | 183 | | Other current liabilities | 181 | | | 145 | |
| Total current liabilities | Total current liabilities | 904 | | | 830 | | Total current liabilities | 950 | | | 918 | |
| | Long-term debt | Long-term debt | 7,716 | | | 7,210 | | Long-term debt | 7,661 | | | 7,721 | |
| Regulatory liabilities | Regulatory liabilities | 943 | | | 1,111 | | Regulatory liabilities | 1,026 | | | 1,080 | |
| Deferred income taxes | Deferred income taxes | 3,407 | | | 3,054 | | Deferred income taxes | 3,413 | | | 3,389 | |
| Asset retirement obligations | Asset retirement obligations | 677 | | | 709 | | Asset retirement obligations | 698 | | | 714 | |
| Other long-term liabilities | Other long-term liabilities | 495 | | | 458 | | Other long-term liabilities | 476 | | | 475 | |
| Total liabilities | Total liabilities | 14,142 | | | 13,372 | | Total liabilities | 14,224 | | | 14,297 | |
| | Commitments and contingencies (Note 9) | 0 | | 0 | |
| Commitments and contingencies (Note 8) | | Commitments and contingencies (Note 8) | 0 | | 0 |
| | Shareholder's equity: | Shareholder's equity: | | Shareholder's equity: | |
| Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | — | | | — | | Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | — | | | — | |
| Additional paid-in capital | Additional paid-in capital | 561 | | | 561 | | Additional paid-in capital | 561 | | | 561 | |
| Retained earnings | Retained earnings | 8,241 | | | 7,504 | | Retained earnings | 8,850 | | | 8,399 | |
| | Total shareholder's equity | Total shareholder's equity | 8,802 | | | 8,065 | | Total shareholder's equity | 9,411 | | | 8,960 | |
| | Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 22,944 | | | $ | 21,437 | | Total liabilities and shareholder's equity | $ | 23,635 | | | $ | 23,257 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| Operating revenue: | | | | | | | |
| Regulated electric | $ | 854 | | | $ | 728 | | | $ | 1,985 | | | $ | 1,717 | |
| Regulated natural gas and other | 112 | | | 84 | | | 741 | | | 389 | |
| Total operating revenue | 966 | | | 812 | | | 2,726 | | | 2,106 | |
| | | | | | | |
| Operating expenses: | | | | | | | |
| Cost of fuel and energy | 163 | | | 115 | | | 417 | | | 266 | |
| Cost of natural gas purchased for resale and other | 64 | | | 40 | | | 553 | | | 210 | |
| Operations and maintenance | 200 | | | 212 | | | 577 | | | 559 | |
| Depreciation and amortization | 218 | | | 180 | | | 634 | | | 531 | |
| Property and other taxes | 34 | | | 33 | | | 107 | | | 102 | |
| Total operating expenses | 679 | | | 580 | | | 2,288 | | | 1,668 | |
| | | | | | | |
| Operating income | 287 | | | 232 | | | 438 | | | 438 | |
| | | | | | | |
| Other income (expense): | | | | | | | |
| Interest expense | (76) | | | (74) | | | (224) | | | (224) | |
| Allowance for borrowed funds | 4 | | | 5 | | | 8 | | | 12 | |
| Allowance for equity funds | 11 | | | 16 | | | 25 | | | 33 | |
| Other, net | 8 | | | 14 | | | 34 | | | 30 | |
| Total other income (expense) | (53) | | | (39) | | | (157) | | | (149) | |
| | | | | | | |
| Income before income tax benefit | 234 | | | 193 | | | 281 | | | 289 | |
| Income tax benefit | (143) | | | (147) | | | (456) | | | (411) | |
| | | | | | | |
| Net income | $ | 377 | | | $ | 340 | | | $ | 737 | | | $ | 700 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Six-Month Periods |
| Ended June 30, | | Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue: | | | | | | | |
| Regulated electric | $ | 725 | | | $ | 586 | | | $ | 1,333 | | | $ | 1,131 | |
| Regulated natural gas and other | 172 | | | 107 | | | 569 | | | 629 | |
| Total operating revenue | 897 | | | 693 | | | 1,902 | | | 1,760 | |
| | | | | | | |
| Operating expenses: | | | | | | | |
| Cost of fuel and energy | 174 | | | 103 | | | 299 | | | 254 | |
| Cost of natural gas purchased for resale and other | 120 | | | 57 | | | 418 | | | 489 | |
| Operations and maintenance | 200 | | | 184 | | | 392 | | | 377 | |
| Depreciation and amortization | 277 | | | 209 | | | 527 | | | 416 | |
| Property and other taxes | 36 | | | 37 | | | 76 | | | 73 | |
| Total operating expenses | 807 | | | 590 | | | 1,712 | | | 1,609 | |
| | | | | | | |
| Operating income | 90 | | | 103 | | | 190 | | | 151 | |
| | | | | | | |
| Other income (expense): | | | | | | | |
| Interest expense | (78) | | | (74) | | | (156) | | | (148) | |
| Allowance for borrowed funds | 5 | | | 2 | | | 9 | | | 4 | |
| Allowance for equity funds | 14 | | | 8 | | | 29 | | | 14 | |
| Other, net | (12) | | | 15 | | | (15) | | | 26 | |
| Total other income (expense) | (71) | | | (49) | | | (133) | | | (104) | |
| | | | | | | |
| Income before income tax benefit | 19 | | | 54 | | | 57 | | | 47 | |
| Income tax benefit | (188) | | | (159) | | | (394) | | | (313) | |
| | | | | | | |
| Net income | $ | 207 | | | $ | 213 | | | $ | 451 | | | $ | 360 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions)
| | | Common Stock | | Additional Paid-in Capital | | Retained
Earnings | | Total Shareholder's
Equity | | Common Stock | | Additional Paid-in Capital | | Retained
Earnings | | Total Shareholder's
Equity |
| | Balance, June 30, 2020 | $ | — | | | $ | 561 | | | $ | 7,039 | | | $ | 7,600 | | |
| Net income | — | | | — | | | 340 | | | 340 | | |
| | Balance, September 30, 2020 | $ | — | | | $ | 561 | | | $ | 7,379 | | | $ | 7,940 | | |
| | Balance, December 31, 2019 | $ | — | | | $ | 561 | | | $ | 6,679 | | | $ | 7,240 | | |
| Net income | — | | | — | | | 700 | | | 700 | | |
| | Balance, September 30, 2020 | $ | — | | | $ | 561 | | | $ | 7,379 | | | $ | 7,940 | | |
| | Balance, June 30, 2021 | $ | — | | | $ | 561 | | | $ | 7,865 | | | $ | 8,426 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | $ | — | | | $ | 561 | | | $ | 7,651 | | | $ | 8,212 | |
| Net income | Net income | — | | | — | | | 377 | | | 377 | | Net income | — | | | — | | | 213 | | | 213 | |
| Other equity transactions | Other equity transactions | — | | | — | | | (1) | | | (1) | | Other equity transactions | — | | | — | | | 1 | | | 1 | |
| Balance, September 30, 2021 | $ | — | | | $ | 561 | | | $ | 8,241 | | | $ | 8,802 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | — | | | $ | 561 | | | $ | 7,865 | | | $ | 8,426 | |
| | Balance, December 31, 2020 | Balance, December 31, 2020 | $ | — | | | $ | 561 | | | $ | 7,504 | | | $ | 8,065 | | Balance, December 31, 2020 | $ | — | | | $ | 561 | | | $ | 7,504 | | | $ | 8,065 | |
| Net income | Net income | — | | | — | | | 737 | | | 737 | | Net income | — | | | — | | | 360 | | | 360 | |
| Other equity transactions | | Other equity transactions | — | | | — | | | 1 | | | 1 | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | — | | | $ | 561 | | | $ | 7,865 | | | $ | 8,426 | |
| | Balance, September 30, 2021 | $ | — | | | $ | 561 | | | $ | 8,241 | | | $ | 8,802 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | — | | | $ | 561 | | | $ | 8,643 | | | $ | 9,204 | |
| Net income | | Net income | — | | | — | | | 207 | | | 207 | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | — | | | $ | 561 | | | $ | 8,850 | | | $ | 9,411 | |
| | Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | — | | | $ | 561 | | | $ | 8,399 | | | $ | 8,960 | |
| Net income | | Net income | — | | | — | | | 451 | | | 451 | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | — | | | $ | 561 | | | $ | 8,850 | | | $ | 9,411 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | Nine-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 737 | | | $ | 700 | | Net income | $ | 451 | | | $ | 360 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | Adjustments to reconcile net income to net cash flows from operating activities: | | Adjustments to reconcile net income to net cash flows from operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 634 | | | 531 | | Depreciation and amortization | 527 | | | 416 | |
| Amortization of utility plant to other operating expenses | Amortization of utility plant to other operating expenses | 26 | | | 25 | | Amortization of utility plant to other operating expenses | 19 | | | 17�� | |
| Allowance for equity funds | Allowance for equity funds | (25) | | | (33) | | Allowance for equity funds | (29) | | | (14) | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 121 | | | 76 | | Deferred income taxes and investment tax credits, net | 58 | | | 196 | |
| Settlements of asset retirement obligations | Settlements of asset retirement obligations | (51) | | | (55) | | Settlements of asset retirement obligations | (28) | | | (19) | |
| Other, net | Other, net | 42 | | | (1) | | Other, net | 33 | | | 11 | |
| Changes in other operating assets and liabilities: | Changes in other operating assets and liabilities: | | Changes in other operating assets and liabilities: | |
| Trade receivables and other assets | Trade receivables and other assets | (331) | | | (15) | | Trade receivables and other assets | 2 | | | (275) | |
| Inventories | Inventories | 34 | | | (40) | | Inventories | 8 | | | 41 | |
| | Pension and other postretirement benefit plans | 2 | | | (17) | | |
| | Accrued property, income and other taxes, net | Accrued property, income and other taxes, net | 80 | | | (10) | | Accrued property, income and other taxes, net | 94 | | | 56 | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 21 | | | 48 | | Accounts payable and other liabilities | (10) | | | (68) | |
| Net cash flows from operating activities | Net cash flows from operating activities | 1,290 | | | 1,209 | | Net cash flows from operating activities | 1,125 | | | 721 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (1,266) | | | (1,341) | | Capital expenditures | (862) | | | (720) | |
| Purchases of marketable securities | Purchases of marketable securities | (166) | | | (251) | | Purchases of marketable securities | (214) | | | (109) | |
| Proceeds from sales of marketable securities | Proceeds from sales of marketable securities | 163 | | | 244 | | Proceeds from sales of marketable securities | 210 | | | 105 | |
| Other, net | Other, net | (7) | | | 9 | | Other, net | 6 | | | (2) | |
| Net cash flows from investing activities | Net cash flows from investing activities | (1,276) | | | (1,339) | | Net cash flows from investing activities | (860) | | | (726) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| | Proceeds from long-term debt | 492 | | | — | | |
| Repayments of long-term debt | (1) | | | — | | |
| | | Other, net | Other, net | (2) | | | (1) | | Other, net | (1) | | | (2) | |
| Net cash flows from financing activities | Net cash flows from financing activities | 489 | | | (1) | | Net cash flows from financing activities | (1) | | | (2) | |
| | Net change in cash and cash equivalents and restricted cash and cash equivalents | Net change in cash and cash equivalents and restricted cash and cash equivalents | 503 | | | (131) | | Net change in cash and cash equivalents and restricted cash and cash equivalents | 264 | | | (7) | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 45 | | | 330 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 239 | | | 45 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 548 | | | $ | 199 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 503 | | | $ | 38 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
(1) General
MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct, wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of SeptemberJune 30, 2021,2022, and for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2021 and 2020.2021. The results of operations for the three- and nine-monthsix-month periods ended SeptemberJune 30, 2021,2022, are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2020,2021, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's assumptions regarding significant accounting estimates and policies during the nine-monthsix-month period ended SeptemberJune 30, 2021.2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United StatesU.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | Cash and cash equivalents | Cash and cash equivalents | $ | 541 | | | $ | 38 | | Cash and cash equivalents | $ | 495 | | | $ | 232 | |
| Restricted cash and cash equivalents in other current assets | Restricted cash and cash equivalents in other current assets | 7 | | | 7 | | Restricted cash and cash equivalents in other current assets | 8 | | | 7 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 548 | | | $ | 45 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 503 | | | $ | 239 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | Depreciable Life | | 2021 | | 2020 | | Depreciable Life | | 2022 | | 2021 |
| Utility plant in service, net: | | | | | | |
| Utility plant in-service, net: | | Utility plant in-service, net: | | | | | |
| Generation | Generation | 20-70 years | | $ | 17,162 | | | $ | 16,980 | | Generation | 20-70 years | | $ | 17,737 | | | $ | 17,397 | |
| Transmission | Transmission | 52-75 years | | 2,415 | | | 2,365 | | Transmission | 52-75 years | | 2,583 | | | 2,474 | |
| Electric distribution | Electric distribution | 20-75 years | | 4,522 | | | 4,369 | | Electric distribution | 20-75 years | | 4,725 | | | 4,661 | |
| Natural gas distribution | Natural gas distribution | 29-75 years | | 2,011 | | | 1,955 | | Natural gas distribution | 29-75 years | | 2,049 | | | 2,039 | |
| Utility plant in service | | 26,110 | | | 25,669 | | |
| Utility plant in-service | | Utility plant in-service | | 27,094 | | | 26,571 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (7,444) | | | (6,902) | | Accumulated depreciation and amortization | | (7,658) | | | (7,376) | |
| Utility plant in service, net | | 18,666 | | | 18,767 | | |
| Utility plant in-service, net | | Utility plant in-service, net | | 19,436 | | | 19,195 | |
| Nonregulated property, net: | Nonregulated property, net: | | | | | Nonregulated property, net: | | | | |
| Nonregulated property gross | 20-50 years | | 7 | | | 7 | | |
| Nonregulated property, gross | | Nonregulated property, gross | 20-50 years | | 7 | | | 7 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (1) | | | (1) | | Accumulated depreciation and amortization | | (1) | | | (1) | |
| Nonregulated property, net | Nonregulated property, net | | 6 | | | 6 | | Nonregulated property, net | | 6 | | | 6 | |
| | 18,672 | | | 18,773 | | | 19,442 | | | 19,201 | |
| Construction work-in-progress | Construction work-in-progress | | 1,101 | | | 506 | | Construction work-in-progress | | 1,062 | | | 1,100 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 19,773 | | | $ | 19,279 | | Property, plant and equipment, net | | $ | 20,504 | | | $ | 20,301 | |
(4) Regulatory Matters
Natural Gas Purchased for Resale
In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. These increased costs are reflected in cost of natural gas purchased for resale and other on the Statement of Operations and their recovery through the Purchased Gas Adjustment Clause is reflected in regulated natural gas and other revenue.
To mitigate the impact to MidAmerican Energy's customers, the Iowa Utilities Board ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the nine-month period ended September 30, 2021.
(5) Recent Financing Transactions
Long-Term Debt
In July 2021, MidAmerican Energy issued $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Energy used the net proceeds to finance a portion of the capital expenditures, disbursed during the period from July 22, 2019 to September 27, 2019, with respect to investments in its 2,000-megawatt Wind XI project, its 592-megawatt Wind XII project, its 207-megawatt Wind XII Expansion project and the repowering of certain of its existing wind-powered generating facilities, which were previously financed with MidAmerican Energy's general funds.
Credit Facilities
In June 2021,2022, MidAmerican Energy amended and restated its existing $900 million$1.5 billion unsecured credit facility expiring in June 2022.2024. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 20242025 and increasedamended pricing from the available maturity extension optionsLondon Interbank Offered Rate 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.Secured Overnight Financing Rate.
(6)(5) Income Taxes
A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| Income tax credits | Income tax credits | (44) | | | (55) | | | (143) | | | (122) | | Income tax credits | (973) | | | (271) | | | (682) | | | (634) | |
| State income tax, net of federal income tax impacts | State income tax, net of federal income tax impacts | (26) | | | (27) | | | (27) | | | (29) | | State income tax, net of federal income tax impacts | (26) | | | (31) | | | (23) | | | (32) | |
| Effects of ratemaking | Effects of ratemaking | (12) | | | (15) | | | (13) | | | (13) | | Effects of ratemaking | (11) | | | (15) | | | (9) | | | (21) | |
| Other, net | Other, net | — | | | — | | | — | | | 1 | | Other, net | — | | | 2 | | | 2 | | | — | |
| Effective income tax rate | Effective income tax rate | (61) | % | | (76) | % | | (162) | % | | (142) | % | Effective income tax rate | (989) | % | | (294) | % | | (691) | % | | (666) | % |
Income tax credits relate primarily to production tax credits ("PTCs") from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. MidAmerican Energy recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 totaled $103$388 million and $105 million, respectively, and for the nine-month periods ended September 30, 2021 and 2020 totaled $400 million and $352$297 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its United StatesU.S. federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date. MidAmerican Energy received net cash payments for income tax from BHE totaling $677$541 million and $500$558 million for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021, and 2020, respectively.
(7)(6) Employee Benefit Plans
MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.
Net periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Pension: | Pension: | | | | | | | | Pension: | | | | | | | |
| Service cost | Service cost | $ | 5 | | | $ | 2 | | | $ | 15 | | | $ | 4 | | Service cost | $ | 4 | | | $ | 5 | | | $ | 9 | | | $ | 10 | |
| Interest cost | Interest cost | 6 | | | 7 | | | 17 | | | 19 | | Interest cost | 5 | | | 5 | | | 10 | | | 11 | |
| Expected return on plan assets | Expected return on plan assets | (9) | | | (10) | | | (28) | | | (30) | | Expected return on plan assets | (7) | | | (10) | | | (14) | | | (19) | |
| Settlement | | Settlement | — | | | — | | | 2 | | | — | |
| Net amortization | Net amortization | — | | | — | | | 1 | | | 1 | | Net amortization | 1 | | | 1 | | | 1 | | | 1 | |
| Net periodic benefit cost (credit) | $ | 2 | | | $ | (1) | | | $ | 5 | | | $ | (6) | | |
| Net periodic benefit cost | | Net periodic benefit cost | $ | 3 | | | $ | 1 | | | $ | 8 | | | $ | 3 | |
| | Other postretirement: | Other postretirement: | | Other postretirement: | |
| Service cost | Service cost | $ | 2 | | | $ | 1 | | | $ | 6 | | | $ | 3 | | Service cost | $ | 2 | | | $ | 2 | | | $ | 4 | | | $ | 4 | |
| Interest cost | Interest cost | 2 | | | 2 | | | 6 | | | 5 | | Interest cost | 2 | | | 2 | | | 4 | | | 4 | |
| Expected return on plan assets | Expected return on plan assets | (2) | | | (4) | | | (7) | | | (10) | | Expected return on plan assets | (3) | | | (3) | | | (7) | | | (5) | |
| Net amortization | Net amortization | (1) | | | (1) | | | (3) | | | (4) | | Net amortization | (1) | | | (1) | | | (1) | | | (2) | |
| Net periodic benefit cost (credit) | $ | 1 | | | $ | (2) | | | $ | 2 | | | $ | (6) | | |
| Net periodic benefit cost | | Net periodic benefit cost | $ | — | | | $ | — | | | $ | — | | | $ | 1 | |
Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and $12$3 million, respectively, during 2021.2022. As of SeptemberJune 30, 2021, $52022, $4 million and $9$2 million of contributions had been made to the pension and other postretirement benefit plans, respectively.
(8)
(7) Fair Value Measurements
The carrying value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.
The following table presents MidAmerican Energy's financial assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
| As of September 30, 2021: | | | | | | | | | | |
| Assets: | | | | | | | | | | |
| Commodity derivatives | | $ | 1 | | | $ | 70 | | | $ | 4 | | | $ | (7) | | | $ | 68 | |
| Money market mutual funds | | 543 | | | — | | | — | | | — | | | 543 | |
| Debt securities: | | | | | | | | | | |
| United States government obligations | | 228 | | | — | | | — | | | — | | | 228 | |
| International government obligations | | — | | | 2 | | | — | | | — | | | 2 | |
| Corporate obligations | | — | | | 86 | | | — | | | — | | | 86 | |
| Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
| Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Equity securities: | | | | | | | | | | |
| United States companies | | 398 | | | — | | | — | | | — | | | 398 | |
| International companies | | 8 | | | — | | | — | | | — | | | 8 | |
| Investment funds | | 23 | | | — | | | — | | | — | | | 23 | |
| | $ | 1,201 | | | $ | 162 | | | $ | 4 | | | $ | (7) | | | $ | 1,360 | |
| | | | | | | | | | |
| Liabilities - commodity derivatives | | $ | (2) | | | $ | (5) | | | $ | (4) | | | $ | 7 | | | $ | (4) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
| As of June 30, 2022: | | | | | | | | | | |
| Assets: | | | | | | | | | | |
| Commodity derivatives | | $ | 1 | | | $ | 66 | | | $ | 28 | | | $ | (22) | | | $ | 73 | |
| Money market mutual funds | | 498 | | | — | | | — | | | — | | | 498 | |
| Debt securities: | | | | | | | | | | |
| U.S. government obligations | | 220 | | | — | | | — | | | — | | | 220 | |
| International government obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Corporate obligations | | — | | | 75 | | | — | | | — | | | 75 | |
| Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
| Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Equity securities: | | | | | | | | | | |
| U.S. companies | | 348 | | | — | | | — | | | — | | | 348 | |
| International companies | | 8 | | | — | | | — | | | — | | | 8 | |
| Investment funds | | 21 | | | — | | | — | | | — | | | 21 | |
| | $ | 1,096 | | | $ | 146 | | | $ | 28 | | | $ | (22) | | | $ | 1,248 | |
| | | | | | | | | | |
| Liabilities - commodity derivatives | | $ | (1) | | | $ | (10) | | | $ | (2) | | | $ | 7 | | | $ | (6) | |
| | | Input Levels for Fair Value Measurements | | | Input Levels for Fair Value Measurements | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total | | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
| As of December 31, 2020: | | | | | | | | | | | |
| As of December 31, 2021: | | As of December 31, 2021: | | | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | | $ | — | | | $ | 4 | | | $ | 5 | | | $ | (5) | | | $ | 4 | | Commodity derivatives | | $ | — | | | $ | 32 | | | $ | 3 | | | $ | (7) | | | $ | 28 | |
| Money market mutual funds | Money market mutual funds | | 41 | | | — | | | — | | | — | | | 41 | | Money market mutual funds | | 228 | | | — | | | — | | | — | | | 228 | |
| Debt securities: | Debt securities: | | Debt securities: | |
| United States government obligations | | 200 | | | — | | | — | | | — | | | 200 | | |
| U.S. government obligations | | U.S. government obligations | | 232 | | | — | | | — | | | — | | | 232 | |
| International government obligations | International government obligations | | — | | | 5 | | | — | | | — | | | 5 | | International government obligations | | — | | | 2 | | | — | | | — | | | 2 | |
| Corporate obligations | Corporate obligations | | — | | | 73 | | | — | | | — | | | 73 | | Corporate obligations | | — | | | 90 | | | — | | | — | | | 90 | |
| Municipal obligations | Municipal obligations | | — | | | 2 | | | — | | | — | | | 2 | | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
| Agency, asset and mortgage-backed obligations | Agency, asset and mortgage-backed obligations | | — | | | 6 | | | — | | | — | | | 6 | | Agency, asset and mortgage-backed obligations | | — | | | 2 | | | — | | | — | | | 2 | |
| Equity securities: | Equity securities: | | Equity securities: | |
| United States companies | | 381 | | | — | | | — | | | — | | | 381 | | |
| U.S. companies | | U.S. companies | | 428 | | | — | | | — | | | — | | | 428 | |
| International companies | International companies | | 9 | | | — | | | — | | | — | | | 9 | | International companies | | 10 | | | — | | | — | | | — | | | 10 | |
| Investment funds | Investment funds | | 17 | | | — | | | — | | | — | | | 17 | | Investment funds | | 18 | | | — | | | — | | | — | | | 18 | |
| | $ | 648 | | | $ | 90 | | | $ | 5 | | | $ | (5) | | | $ | 738 | | | $ | 916 | | | $ | 129 | | | $ | 3 | | | $ | (7) | | | $ | 1,041 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | | $ | — | | | $ | (4) | | | $ | (3) | | | $ | 5 | | | $ | (2) | | Liabilities - commodity derivatives | | $ | — | | | $ | (6) | | | $ | (8) | | | $ | 12 | | | $ | (2) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivablepayable of $—$15 million as of SeptemberJune 30, 20212022 and a net cash collateral receivable of $5 million as of December 31, 2020, respectively.2021.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
The following table reconciles the beginning and ending balances of MidAmerican Energy's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Six-Month Periods |
| Ended June 30, | | Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | |
| Beginning balance | $ | 4 | | | $ | 1 | | | $ | (5) | | | $ | 2 | |
| Changes in fair value recognized in regulatory assets | 31 | | | — | | | 44 | | | — | |
| Settlements | (9) | | | (2) | | | (13) | | | (3) | |
| Ending balance | $ | 26 | | | $ | (1) | | | $ | 26 | | | $ | (1) | |
MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | As of December 31, 2020 |
| Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value |
| | | | | | | |
| Long-term debt | $ | 7,716 | | | $ | 9,101 | | | $ | 7,210 | | | $ | 9,130 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2022 | | As of December 31, 2021 |
| Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value |
| | | | | | | |
| Long-term debt | $ | 7,725 | | | $ | 7,376 | | | $ | 7,721 | | | $ | 9,037 | |
(9)(8) 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
MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Transmission Rates
MidAmerican Energy's wholesale transmission rates are set annually using Federal Energy Regulatory Commission ("FERC")-approved formula rates subject to true-up for actual cost of service. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the approved base return on equity ("ROE") effective January 2015. Prior to September 2016, the rates in effect were based on a 12.38% ROE. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the 12.38% ROE no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively. In September 2016, the FERC issued an order for the first complaint, which reduces the base ROE to 10.32% and required refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. In November 2019, the FERC issued an order addressing the second complaint and issues on appeal in the first complaint. The order established a ROE of 9.88% (10.38% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 forward. In May 2020, the FERC issued an order on rehearing of the November 2019 order. The May 2020 order affirmed the FERC's prior decision to dismiss the second complaint and established an ROE of 10.02% (10.52% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 to the date of the May 2020 order. These orders continue to be subject to judicial appeal. MidAmerican Energy cannot predict the ultimate outcome of these matters and, as of SeptemberJune 30, 2021,2022, has accrued a $9an $8 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.
(10)(9) Revenue from Contracts with Customers
The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 1110 (in millions):
| | | For the Three-Month Period Ended September 30, 2021 | | For the Nine-Month Period Ended September 30, 2021 | | For the Three-Month Period Ended June 30, 2022 | | For the Six-Month Period Ended June 30, 2022 |
| | Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total |
| Customer Revenue: | Customer Revenue: | | | | | | | | | | | | | | | | Customer Revenue: | | | | | | | | | | | | | | | |
| Retail: | Retail: | | Retail: | |
| Residential | Residential | $ | 255 | | | $ | 52 | | | $ | — | | | $ | 307 | | | $ | 586 | | | $ | 419 | | | $ | — | | | $ | 1,005 | | Residential | $ | 185 | | | $ | 87 | | | $ | — | | | $ | 272 | | | $ | 353 | | | $ | 312 | | | $ | — | | | $ | 665 | |
| Commercial | Commercial | 107 | | | 17 | | | — | | | 124 | | | 258 | | | 164 | | | — | | | 422 | | Commercial | 91 | | | 31 | | | — | | | 122 | | | 165 | | | 119 | | | — | | | 284 | |
| Industrial | Industrial | 321 | | | 5 | | | — | | | 326 | | | 741 | | | 20 | | | — | | | 761 | | Industrial | 277 | | | 9 | | | — | | | 286 | | | 475 | | | 18 | | | — | | | 493 | |
| Natural gas transportation services | Natural gas transportation services | — | | | 9 | | | — | | | 9 | | | — | | | 28 | | | — | | | 28 | | Natural gas transportation services | — | | | 9 | | | — | | | 9 | | | — | | | 23 | | | — | | | 23 | |
Other retail(1) | Other retail(1) | 53 | | | 1 | | | — | | | 54 | | | 119 | | | 2 | | | — | | | 121 | | Other retail(1) | 41 | | | — | | | — | | | 41 | | | 73 | | | 1 | | | — | | | 74 | |
| Total retail | Total retail | 736 | | | 84 | | | — | | | 820 | | | 1,704 | | | 633 | | | — | | | 2,337 | | Total retail | 594 | | | 136 | | | — | | | 730 | | | 1,066 | | | 473 | | | — | | | 1,539 | |
| Wholesale | Wholesale | 88 | | | 25 | | | — | | | 113 | | | 214 | | | 93 | | | — | | | 307 | | Wholesale | 84 | | | 34 | | | — | | | 118 | | | 188 | | | 92 | | | — | | | 280 | |
| Multi-value transmission projects | Multi-value transmission projects | 15 | | | — | | | — | | | 15 | | | 45 | | | — | | | — | | | 45 | | Multi-value transmission projects | 13 | | | — | | | — | | | 13 | | | 28 | | | — | | | — | | | 28 | |
| Other Customer Revenue | Other Customer Revenue | — | | | — | | | 2 | | | 2 | | | — | | | — | | | 13 | | | 13 | | Other Customer Revenue | — | | | — | | | 1 | | | 1 | | | — | | | — | | | 2 | | | 2 | |
| Total Customer Revenue | Total Customer Revenue | 839 | | | 109 | | | 2 | | | 950 | | | 1,963 | | | 726 | | | 13 | | | 2,702 | | Total Customer Revenue | 691 | | | 170 | | | 1 | | | 862 | | | 1,282 | | | 565 | | | 2 | | | 1,849 | |
| Other revenue | Other revenue | 15 | | | 1 | | | — | | | 16 | | | 22 | | | 2 | | | — | | | 24 | | Other revenue | 34 | | | 1 | | | — | | | 35 | | | 51 | | | 2 | | | — | | | 53 | |
| Total operating revenue | Total operating revenue | $ | 854 | | | $ | 110 | | | $ | 2 | | | $ | 966 | | | $ | 1,985 | | | $ | 728 | | | $ | 13 | | | $ | 2,726 | | Total operating revenue | $ | 725 | | | $ | 171 | | | $ | 1 | | | $ | 897 | | | $ | 1,333 | | | $ | 567 | | | $ | 2 | | | $ | 1,902 | |
| | | For the Three-Month Period Ended September 30, 2020 | | For the Nine-Month Period Ended September 30, 2020 | | For the Three-Month Period Ended June 30, 2021 | | For the Six-Month Period Ended June 30, 2021 |
| | Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total |
| Customer Revenue: | Customer Revenue: | | | | | | | | | | | | | | | | Customer Revenue: | | | | | | | | | | | | | | | |
| Retail: | Retail: | | Retail: | |
| Residential | Residential | $ | 241 | | | $ | 46 | | | $ | — | | | $ | 287 | | | $ | 555 | | | $ | 233 | | | $ | — | | | $ | 788 | | Residential | $ | 170 | | | $ | 59 | | | $ | — | | | $ | 229 | | | $ | 331 | | | $ | 367 | | | $ | — | | | $ | 698 | |
| Commercial | Commercial | 99 | | | 13 | | | — | | | 112 | | | 242 | | | 71 | | | — | | | 313 | | Commercial | 80 | | | 18 | | | — | | | 98 | | | 151 | | | 147 | | | — | | | 298 | |
| Industrial | Industrial | 280 | | | 2 | | | — | | | 282 | | | 640 | | | 9 | | | — | | | 649 | | Industrial | 230 | | | 3 | | | — | | | 233 | | | 420 | | | 15 | | | — | | | 435 | |
| Natural gas transportation services | Natural gas transportation services | — | | | 8 | | | — | | | 8 | | | — | | | 26 | | | — | | | 26 | | Natural gas transportation services | — | | | 9 | | | — | | | 9 | | | — | | | 19 | | | — | | | 19 | |
Other retail(1) | Other retail(1) | 42 | | | 1 | | | — | | | 43 | | | 103 | | | 2 | | | — | | | 105 | | Other retail(1) | 36 | | | — | | | — | | | 36 | | | 66 | | | 1 | | | — | | | 67 | |
| Total retail | Total retail | 662 | | | 70 | | | — | | | 732 | | | 1,540 | | | 341 | | | — | | | 1,881 | | Total retail | 516 | | | 89 | | | — | | | 605 | | | 968 | | | 549 | | | — | | | 1,517 | |
| Wholesale | Wholesale | 46 | | | 10 | | | — | | | 56 | | | 116 | | | 41 | | | — | | | 157 | | Wholesale | 52 | | | 17 | | | — | | | 69 | | | 126 | | | 68 | | | — | | | 194 | |
| Multi-value transmission projects | Multi-value transmission projects | 14 | | | — | | | — | | | 14 | | | 47 | | | — | | | — | | | 47 | | Multi-value transmission projects | 15 | | | — | | | — | | | 15 | | | 30 | | | — | | | — | | | 30 | |
| Other Customer Revenue | Other Customer Revenue | — | | | — | | | 4 | | | 4 | | | — | | | — | | | 5 | | | 5 | | Other Customer Revenue | — | | | — | | | 1 | | | 1 | | | — | | | — | | | 11 | | | 11 | |
| Total Customer Revenue | Total Customer Revenue | 722 | | | 80 | | | 4 | | | 806 | | | 1,703 | | | 382 | | | 5 | | | 2,090 | | Total Customer Revenue | 583 | | | 106 | | | 1 | | | 690 | | | 1,124 | | | 617 | | | 11 | | | 1,752 | |
| Other revenue | Other revenue | 6 | | | — | | | — | | | 6 | | | 14 | | | 2 | | | — | | | 16 | | Other revenue | 3 | | | — | | | — | | | 3 | | | 7 | | | 1 | | | — | | | 8 | |
| Total operating revenue | Total operating revenue | $ | 728 | | | $ | 80 | | | $ | 4 | | | $ | 812 | | | $ | 1,717 | | | $ | 384 | | | $ | 5 | | | $ | 2,106 | | Total operating revenue | $ | 586 | | | $ | 106 | | | $ | 1 | | | $ | 693 | | | $ | 1,131 | | | $ | 618 | | | $ | 11 | | | $ | 1,760 | |
(1) Other retail includes provisions for rate refunds, for which any actual refunds will be reflected in the applicable customer classes upon resolution of the related regulatory proceeding.
(11)(10) Segment Information
MidAmerican Energy has identified 2 reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost.
The following tables provide information on a reportable segment basis (in millions):
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | | | | |
| Regulated electric | Regulated electric | $ | 854 | | | $ | 728 | | | $ | 1,985 | | | $ | 1,717 | | Regulated electric | $ | 725 | | | $ | 586 | | | $ | 1,333 | | | $ | 1,131 | |
| Regulated natural gas | Regulated natural gas | 110 | | | 80 | | | 728 | | | 384 | | Regulated natural gas | 171 | | | 106 | | | 567 | | | 618 | |
| Other | Other | 2 | | | 4 | | | 13 | | | 5 | | Other | 1 | | | 1 | | | 2 | | | 11 | |
| Total operating revenue | Total operating revenue | $ | 966 | | | $ | 812 | | | $ | 2,726 | | | $ | 2,106 | | Total operating revenue | $ | 897 | | | $ | 693 | | | $ | 1,902 | | | $ | 1,760 | |
| | Operating income: | Operating income: | | Operating income: | |
| Regulated electric | Regulated electric | $ | 289 | | | $ | 238 | | | $ | 401 | | | $ | 398 | | Regulated electric | $ | 87 | | | $ | 103 | | | $ | 138 | | | $ | 112 | |
| Regulated natural gas | Regulated natural gas | (2) | | | (6) | | | 37 | | | 40 | | Regulated natural gas | 3 | | | — | | | 52 | | | 39 | |
| | Total operating income | Total operating income | 287 | | | 232 | | | 438 | | | 438 | | Total operating income | 90 | | | 103 | | | 190 | | | 151 | |
| Interest expense | Interest expense | (76) | | | (74) | | | (224) | | | (224) | | Interest expense | (78) | | | (74) | | | (156) | | | (148) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 4 | | | 5 | | | 8 | | | 12 | | Allowance for borrowed funds | 5 | | | 2 | | | 9 | | | 4 | |
| Allowance for equity funds | Allowance for equity funds | 11 | | | 16 | | | 25 | | | 33 | | Allowance for equity funds | 14 | | | 8 | | | 29 | | | 14 | |
| Other, net | Other, net | 8 | | | 14 | | | 34 | | | 30 | | Other, net | (12) | | | 15 | | | (15) | | | 26 | |
| Income before income tax benefit | Income before income tax benefit | $ | 234 | | | $ | 193 | | | $ | 281 | | | $ | 289 | | Income before income tax benefit | $ | 19 | | | $ | 54 | | | $ | 57 | | | $ | 47 | |
| | | As of | | As of |
| | September 30,
2021 | | December 31,
2020 | | June 30,
2022 | | December 31,
2021 |
| Assets: | Assets: | | | | Assets: | | | |
| Regulated electric | Regulated electric | $ | 21,063 | | | $ | 19,892 | | Regulated electric | $ | 21,967 | | | $ | 21,385 | |
| Regulated natural gas | Regulated natural gas | 1,874 | | | 1,544 | | Regulated natural gas | 1,667 | | | 1,871 | |
| Other | Other | 7 | | | 1 | | Other | 1 | | | 1 | |
| Total assets | Total assets | $ | 22,944 | | | $ | 21,437 | | Total assets | $ | 23,635 | | | $ | 23,257 | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers and Member of
MidAmerican Funding, LLC
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of SeptemberJune 30, 2021,2022, the related consolidated statements of operations and changes in member's equity for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and of cash flows for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2020,2021, and the related consolidated statements of operations, changes in member's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021,25, 2022, 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, 2020,2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB and with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
NovemberAugust 5, 20212022
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 542 | | | $ | 39 | | Cash and cash equivalents | $ | 497 | | | $ | 233 | |
| Trade receivables, net | Trade receivables, net | 555 | | | 234 | | Trade receivables, net | 525 | | | 526 | |
| | Income tax receivable | | Income tax receivable | 20 | | | 80 | |
| Inventories | Inventories | 244 | | | 278 | | Inventories | 226 | | | 234 | |
| Other current assets | Other current assets | 143 | | | 74 | | Other current assets | 187 | | | 123 | |
| Total current assets | Total current assets | 1,484 | | | 625 | | Total current assets | 1,455 | | | 1,196 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 19,774 | | | 19,279 | | Property, plant and equipment, net | 20,505 | | | 20,302 | |
| Goodwill | Goodwill | 1,270 | | | 1,270 | | Goodwill | 1,270 | | | 1,270 | |
| Regulatory assets | Regulatory assets | 479 | | | 392 | | Regulatory assets | 509 | | | 473 | |
| Investments and restricted investments | Investments and restricted investments | 977 | | | 913 | | Investments and restricted investments | 895 | | | 1,028 | |
| Other assets | Other assets | 234 | | | 232 | | Other assets | 277 | | | 262 | |
| | Total assets | Total assets | $ | 24,218 | | | $ | 22,711 | | Total assets | $ | 24,911 | | | $ | 24,531 | |
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| LIABILITIES AND MEMBER'S EQUITY | LIABILITIES AND MEMBER'S EQUITY | LIABILITIES AND MEMBER'S EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 347 | | | $ | 408 | | Accounts payable | $ | 415 | | | $ | 531 | |
| Accrued interest | Accrued interest | 90 | | | 83 | | Accrued interest | 89 | | | 89 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 242 | | | 161 | | Accrued property, income and other taxes | 206 | | | 158 | |
| Note payable to affiliate | Note payable to affiliate | 190 | | | 177 | | Note payable to affiliate | 197 | | | 189 | |
| | Current portion of long-term debt | | Current portion of long-term debt | 64 | | | — | |
| Other current liabilities | Other current liabilities | 226 | | | 183 | | Other current liabilities | 181 | | | 146 | |
| Total current liabilities | Total current liabilities | 1,095 | | | 1,012 | | Total current liabilities | 1,152 | | | 1,113 | |
| | Long-term debt | Long-term debt | 7,956 | | | 7,450 | | Long-term debt | 7,901 | | | 7,961 | |
| Regulatory liabilities | Regulatory liabilities | 943 | | | 1,111 | | Regulatory liabilities | 1,026 | | | 1,080 | |
| Deferred income taxes | Deferred income taxes | 3,405 | | | 3,052 | | Deferred income taxes | 3,411 | | | 3,387 | |
| Asset retirement obligations | Asset retirement obligations | 677 | | | 709 | | Asset retirement obligations | 698 | | | 714 | |
| Other long-term liabilities | Other long-term liabilities | 495 | | | 458 | | Other long-term liabilities | 477 | | | 475 | |
| Total liabilities | Total liabilities | 14,571 | | | 13,792 | | Total liabilities | 14,665 | | | 14,730 | |
| | Commitments and contingencies (Note 9) | 0 | | 0 | |
| Commitments and contingencies (Note 8) | | Commitments and contingencies (Note 8) | 0 | | 0 |
| | Member's equity: | Member's equity: | | Member's equity: | |
| Paid-in capital | Paid-in capital | 1,679 | | | 1,679 | | Paid-in capital | 1,679 | | | 1,679 | |
| Retained earnings | Retained earnings | 7,968 | | | 7,240 | | Retained earnings | 8,567 | | | 8,122 | |
| | Total member's equity | Total member's equity | 9,647 | | | 8,919 | | Total member's equity | 10,246 | | | 9,801 | |
| | Total liabilities and member's equity | Total liabilities and member's equity | $ | 24,218 | | | $ | 22,711 | | Total liabilities and member's equity | $ | 24,911 | | | $ | 24,531 | |
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | | | | |
| Regulated electric | Regulated electric | $ | 854 | | | $ | 728 | | | $ | 1,985 | | | $ | 1,717 | | Regulated electric | $ | 725 | | | $ | 586 | | | $ | 1,333 | | | $ | 1,131 | |
| Regulated natural gas and other | Regulated natural gas and other | 112 | | | 84 | | | 741 | | | 397 | | Regulated natural gas and other | 172 | | | 107 | | | 569 | | | 629 | |
| Total operating revenue | Total operating revenue | 966 | | | 812 | | | 2,726 | | | 2,114 | | Total operating revenue | 897 | | | 693 | | | 1,902 | | | 1,760 | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | |
| Cost of fuel and energy | Cost of fuel and energy | 163 | | | 115 | | | 417 | | | 266 | | Cost of fuel and energy | 174 | | | 103 | | | 299 | | | 254 | |
| Cost of natural gas purchased for resale and other | Cost of natural gas purchased for resale and other | 64 | | | 40 | | | 553 | | | 211 | | Cost of natural gas purchased for resale and other | 120 | | | 57 | | | 418 | | | 489 | |
| Operations and maintenance | Operations and maintenance | 200 | | | 212 | | | 577 | | | 560 | | Operations and maintenance | 200 | | | 184 | | | 392 | | | 377 | |
| Depreciation and amortization | Depreciation and amortization | 218 | | | 180 | | | 634 | | | 531 | | Depreciation and amortization | 277 | | | 209 | | | 527 | | | 416 | |
| Property and other taxes | Property and other taxes | 34 | | | 33 | | | 107 | | | 102 | | Property and other taxes | 36 | | | 37 | | | 76 | | | 73 | |
| Total operating expenses | Total operating expenses | 679 | | | 580 | | | 2,288 | | | 1,670 | | Total operating expenses | 807 | | | 590 | | | 1,712 | | | 1,609 | |
| | Operating income | Operating income | 287 | | | 232 | | | 438 | | | 444 | | Operating income | 90 | | | 103 | | | 190 | | | 151 | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | |
| Interest expense | Interest expense | (81) | | | (79) | | | (237) | | | (238) | | Interest expense | (83) | | | (78) | | | (165) | | | (156) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 4 | | | 5 | | | 8 | | | 12 | | Allowance for borrowed funds | 5 | | | 2 | | | 9 | | | 4 | |
| Allowance for equity funds | Allowance for equity funds | 11 | | | 16 | | | 25 | | | 33 | | Allowance for equity funds | 14 | | | 8 | | | 29 | | | 14 | |
| Other, net | Other, net | 8 | | | 15 | | | 34 | | | 30 | | Other, net | (10) | | | 16 | | | (14) | | | 26 | |
| Total other income (expense) | Total other income (expense) | (58) | | | (43) | | | (170) | | | (163) | | Total other income (expense) | (74) | | | (52) | | | (141) | | | (112) | |
| | Income before income tax benefit | Income before income tax benefit | 229 | | | 189 | | | 268 | | | 281 | | Income before income tax benefit | 16 | | | 51 | | | 49 | | | 39 | |
| Income tax benefit | Income tax benefit | (144) | | | (148) | | | (460) | | | (414) | | Income tax benefit | (188) | | | (160) | | | (396) | | | (316) | |
| | Net income | Net income | $ | 373 | | | $ | 337 | | | $ | 728 | | | $ | 695 | | Net income | $ | 204 | | | $ | 211 | | | $ | 445 | | | $ | 355 | |
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)
(Amounts in millions)
| | | Paid-in
Capital | | Retained
Earnings | | Total Member's
Equity | | Paid-in
Capital | | Retained
Earnings | | Total Member's
Equity |
| | Balance, June 30, 2020 | $ | 1,679 | | | $ | 6,780 | | | $ | 8,459 | | |
| Net income | — | | | 337 | | | 337 | | |
| | Balance, September 30, 2020 | $ | 1,679 | | | $ | 7,117 | | | $ | 8,796 | | |
| | Balance, December 31, 2019 | $ | 1,679 | | | $ | 6,422 | | | $ | 8,101 | | |
| Net income | — | | | 695 | | | 695 | | |
| | Balance, September 30, 2020 | $ | 1,679 | | | $ | 7,117 | | | $ | 8,796 | | |
| | Balance, June 30, 2021 | $ | 1,679 | | | $ | 7,594 | | | $ | 9,273 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | $ | 1,679 | | | $ | 7,384 | | | $ | 9,063 | |
| Net income | Net income | — | | | 373 | | | 373 | | Net income | — | | | 211 | | | 211 | |
| Other equity transactions | Other equity transactions | — | | | 1 | | | 1 | | Other equity transactions | — | | | (1) | | | (1) | |
| Balance, September 30, 2021 | $ | 1,679 | | | $ | 7,968 | | | $ | 9,647 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | 1,679 | | | $ | 7,594 | | | $ | 9,273 | |
| | Balance, December 31, 2020 | Balance, December 31, 2020 | $ | 1,679 | | | $ | 7,240 | | | $ | 8,919 | | Balance, December 31, 2020 | $ | 1,679 | | | $ | 7,240 | | | $ | 8,919 | |
| Net income | Net income | — | | | 728 | | | 728 | | Net income | — | | | 355 | | | 355 | |
| Other equity transactions | | Other equity transactions | — | | | (1) | | | (1) | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | $ | 1,679 | | | $ | 7,594 | | | $ | 9,273 | |
| | Balance, September 30, 2021 | $ | 1,679 | | | $ | 7,968 | | | $ | 9,647 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 1,679 | | | $ | 8,363 | | | $ | 10,042 | |
| Net income | | Net income | — | | | 204 | | | 204 | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 1,679 | | | $ | 8,567 | | | $ | 10,246 | |
| | Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 1,679 | | | $ | 8,122 | | | $ | 9,801 | |
| Net income | | Net income | — | | | 445 | | | 445 | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | $ | 1,679 | | | $ | 8,567 | | | $ | 10,246 | |
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | Nine-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 728 | | | $ | 695 | | Net income | $ | 445 | | | $ | 355 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | Adjustments to reconcile net income to net cash flows from operating activities: | | Adjustments to reconcile net income to net cash flows from operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 634 | | | 531 | | Depreciation and amortization | 527 | | | 416 | |
| Amortization of utility plant to other operating expenses | Amortization of utility plant to other operating expenses | 26 | | | 25 | | Amortization of utility plant to other operating expenses | 19 | | | 17 | |
| Allowance for equity funds | Allowance for equity funds | (25) | | | (33) | | Allowance for equity funds | (29) | | | (14) | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 121 | | | 79 | | Deferred income taxes and investment tax credits, net | 58 | | | 195 | |
| | Settlements of asset retirement obligations | Settlements of asset retirement obligations | (51) | | | (55) | | Settlements of asset retirement obligations | (28) | | | (19) | |
| Other, net | Other, net | 42 | | | (1) | | Other, net | 32 | | | 11 | |
| Changes in other operating assets and liabilities: | Changes in other operating assets and liabilities: | | Changes in other operating assets and liabilities: | |
| Trade receivables and other assets | Trade receivables and other assets | (331) | | | (16) | | Trade receivables and other assets | 1 | | | (275) | |
| Inventories | Inventories | 34 | | | (40) | | Inventories | 8 | | | 41 | |
| | Pension and other postretirement benefit plans | 2 | | | (17) | | |
| | Accrued property, income and other taxes, net | Accrued property, income and other taxes, net | 80 | | | (13) | | Accrued property, income and other taxes, net | 95 | | | 56 | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 16 | | | 44 | | Accounts payable and other liabilities | (10) | | | (68) | |
| Net cash flows from operating activities | Net cash flows from operating activities | 1,276 | | | 1,199 | | Net cash flows from operating activities | 1,118 | | | 715 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (1,266) | | | (1,341) | | Capital expenditures | (862) | | | (721) | |
| Purchases of marketable securities | Purchases of marketable securities | (166) | | | (251) | | Purchases of marketable securities | (214) | | | (109) | |
| Proceeds from sales of marketable securities | Proceeds from sales of marketable securities | 163 | | | 244 | | Proceeds from sales of marketable securities | 210 | | | 105 | |
| | Other, net | Other, net | (7) | | | 10 | | Other, net | 6 | | | (1) | |
| Net cash flows from investing activities | Net cash flows from investing activities | (1,276) | | | (1,338) | | Net cash flows from investing activities | (860) | | | (726) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| | Proceeds from long-term debt | 492 | | | — | | |
| Repayments of long-term debt | (1) | | | — | | |
| | Net change in note payable to affiliate | Net change in note payable to affiliate | 13 | | | 13 | | Net change in note payable to affiliate | 8 | | | 6 | |
| | Other, net | Other, net | (1) | | | (1) | | Other, net | (1) | | | (2) | |
| Net cash flows from financing activities | Net cash flows from financing activities | 503 | | | 12 | | Net cash flows from financing activities | 7 | | | 4 | |
| | Net change in cash and cash equivalents and restricted cash and cash equivalents | Net change in cash and cash equivalents and restricted cash and cash equivalents | 503 | | | (127) | | Net change in cash and cash equivalents and restricted cash and cash equivalents | 265 | | | (7) | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 46 | | | 331 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 240 | | | 46 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 549 | | | $ | 204 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 505 | | | $ | 39 | |
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct, wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct, wholly owned nonregulated subsidiary is Midwest Capital Group, Inc.
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of SeptemberJune 30, 2021,2022, and for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 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 2020.2021. The results of operations for the three- and nine-monthsix-month periods ended SeptemberJune 30, 2021,2022, are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2020,2021, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's assumptions regarding significant accounting estimates and policies during the nine-monthsix-month period ended SeptemberJune 30, 2021.2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United StatesU.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of 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 | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | Cash and cash equivalents | Cash and cash equivalents | $ | 542 | | | $ | 39 | | Cash and cash equivalents | $ | 497 | | | $ | 233 | |
| Restricted cash and cash equivalents in other current assets | Restricted cash and cash equivalents in other current assets | 7 | | | 7 | | Restricted cash and cash equivalents in other current assets | 8 | | | 7 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 549 | | | $ | 46 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 505 | | | $ | 240 | |
(3) Property, Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.
(4) Regulatory MattersRecent Financing Transactions
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
(5) Recent Financing Transactions
Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.
(6) Income Taxes
A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit is as follows:
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| Income tax credits | Income tax credits | (45) | | | (56) | | | (150) | | | (126) | | Income tax credits | (1,150) | | | (286) | | | (793) | | | (764) | |
| State income tax, net of federal income tax impacts | State income tax, net of federal income tax impacts | (27) | | | (27) | | | (29) | | | (30) | | State income tax, net of federal income tax impacts | (38) | | | (33) | | | (29) | | | (41) | |
| Effects of ratemaking | Effects of ratemaking | (12) | | | (16) | | | (14) | | | (13) | | Effects of ratemaking | (12) | | | (16) | | | (10) | | | (26) | |
| Other, net | Other, net | — | | | — | | | — | | | 1 | | Other, net | 4 | | | — | | | 3 | | | — | |
| Effective income tax rate | Effective income tax rate | (63) | % | | (78) | % | | (172) | % | | (147) | % | Effective income tax rate | (1,175) | % | | (314) | % | | (808) | % | | (810) | % |
Income tax credits relate primarily to production tax credits ("PTCs") from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. MidAmerican Funding recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 totaled $103$388 million and $105 million, respectively, and for the nine-month periods ended September 30, 2021 and 2020 totaled $400 million and $352$297 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its United StatesU.S. federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or received from BHE. The timing of MidAmerican Funding's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date. MidAmerican Funding received net cash payments for income tax from BHE totaling $681$544 million and $504$560 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021. respectively.
(7)(6) Employee Benefit Plans
Refer to Note 76 of MidAmerican Energy's Notes to Financial Statements.
(8)(7) Fair Value Measurements
Refer to Note 87 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | As of December 31, 2020 |
| Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value |
| | | | | | | |
| Long-term debt | $ | 7,956 | | | $ | 9,417 | | | $ | 7,450 | | | $ | 9,466 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2022 | | As of December 31, 2021 |
| Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value |
| | | | | | | |
| Long-term debt | $ | 7,965 | | | $ | 7,646 | | | $ | 7,961 | | | $ | 9,350 | |
(9)(8) Commitments and Contingencies
MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.
(9) Revenue from Contracts with Customers
Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.
(10) Revenue from Contracts with Customers
Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $— million for the three-month periods ended September 30, 2021 and 2020, respectively, and $— million and $8 million for the nine-month periods ended September 30, 2021 and 2020, respectively.
(11)(10) Segment Information
MidAmerican Funding has identified 2 reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the financial results and assets of nonregulated operations, MHC and MidAmerican Funding.
The following tables provide information on a reportable segment basis (in millions):
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | | | | |
| Regulated electric | Regulated electric | $ | 854 | | | $ | 728 | | | $ | 1,985 | | | $ | 1,717 | | Regulated electric | $ | 725 | | | $ | 586 | | | $ | 1,333 | | | $ | 1,131 | |
| Regulated natural gas | Regulated natural gas | 110 | | | 80 | | | 728 | | | 384 | | Regulated natural gas | 171 | | | 106 | | | 567 | | | 618 | |
| Other | Other | 2 | | | 4 | | | 13 | | | 13 | | Other | 1 | | | 1 | | | 2 | | | 11 | |
| Total operating revenue | Total operating revenue | $ | 966 | | | $ | 812 | | | $ | 2,726 | | | $ | 2,114 | | Total operating revenue | $ | 897 | | | $ | 693 | | | $ | 1,902 | | | $ | 1,760 | |
| | Operating income: | Operating income: | | Operating income: | |
| Regulated electric | Regulated electric | $ | 289 | | | $ | 238 | | | $ | 401 | | | $ | 398 | | Regulated electric | $ | 87 | | | $ | 103 | | | $ | 138 | | | $ | 112 | |
| Regulated natural gas | Regulated natural gas | (2) | | | (6) | | | 37 | | | 40 | | Regulated natural gas | 3 | | | — | | | 52 | | | 39 | |
| Other | — | | | — | | | — | | | 6 | | |
| | Total operating income | Total operating income | 287 | | | 232 | | | 438 | | | 444 | | Total operating income | 90 | | | 103 | | | 190 | | | 151 | |
| Interest expense | Interest expense | (81) | | | (79) | | | (237) | | | (238) | | Interest expense | (83) | | | (78) | | | (165) | | | (156) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 4 | | | 5 | | | 8 | | | 12 | | Allowance for borrowed funds | 5 | | | 2 | | | 9 | | | 4 | |
| Allowance for equity funds | Allowance for equity funds | 11 | | | 16 | | | 25 | | | 33 | | Allowance for equity funds | 14 | | | 8 | | | 29 | | | 14 | |
| Other, net | Other, net | 8 | | | 15 | | | 34 | | | 30 | | Other, net | (10) | | | 16 | | | (14) | | | 26 | |
| Income before income tax benefit | Income before income tax benefit | $ | 229 | | | $ | 189 | | | $ | 268 | | | $ | 281 | | Income before income tax benefit | $ | 16 | | | $ | 51 | | | $ | 49 | | | $ | 39 | |
| | | As of | | As of |
| | September 30,
2021 | | December 31,
2020 | | June 30,
2022 | | December 31,
2021 |
Assets(1): | Assets(1): | | | | Assets(1): | | | |
| Regulated electric | Regulated electric | $ | 22,254 | | | $ | 21,083 | | Regulated electric | $ | 23,158 | | | $ | 22,576 | |
| Regulated natural gas | Regulated natural gas | 1,953 | | | 1,623 | | Regulated natural gas | 1,746 | | | 1,950 | |
| Other | Other | 11 | | | 5 | | Other | 7 | | | 5 | |
| Total assets | Total assets | $ | 24,218 | | | $ | 22,711 | | Total assets | $ | 24,911 | | | $ | 24,531 | |
| | | | | |
| (1) | Assets by reportable segment reflect the assignment of goodwill to applicable reporting units. |
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with MidAmerican Funding's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.
Results of Operations for the ThirdSecond Quarter and First NineSix Months of 20212022 and 20202021
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the thirdsecond quarter of 20212022 was $377$207 million, an increasea decrease of $37$6 million, or 11%3%, compared to 20202021, primarily due to higher depreciation and amortization expense of $68 million, unfavorable other, net of $27 million, higher operations and maintenance expense of $16 million and higher interest expense of $4 million, offset by higher electric utility margin of $78$68 million, lower operationshigher income tax benefit of $29 million, higher allowances for equity and maintenance expensesborrowed funds of $12$9 million due to storm restoration costs in 2020 and higher natural gas utility margin of $6 million, partially offset by higher depreciation and amortization expense of $38 million, lower allowance for equity funds used during construction of $5 million due to lower construction work-in-progress balances, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and lower income tax benefit$2 million. Electric retail customer volumes increased 3% primarily due to higher pretax income. Electric utility margincustomer usage and the favorable impact of weather. Wholesale electricity sales volumes increased 7% due to higher wholesale utility margin primarily reflecting higherfavorable market prices and higherconditions. Natural gas retail utility margin mainly from higher volumes. Depreciation and amortization expensecustomer volumes increased 21% due to additional assets placed in-service and the favorable impact of regulatory mechanisms.weather.
MidAmerican Energy's net income for the first ninesix months of 20212022 was $737$451 million, an increase of $37$91 million, or 5%25%, compared to 2020,2021, primarily due to higher electric utility margin of $117$157 million, a favorablehigher income tax benefit of $45$81 million, higher natural gas utility margin of $20 million and favorable changes in the cash surrender valuehigher allowances for equity and borrowed funds of corporate-owned life insurance policies, partially$20 million, offset by higher depreciation and amortization expense of $103$111 million, unfavorable other, net of $41 million, higher operations and maintenance expenses, including increased costs associated with additional wind-powered generating facilities placed in-serviceexpense of $15 million, higher interest expense of $8 million, lower nonregulated utility margins of $8 million and higher natural gas distribution costs, partially offset by lower electric distribution costs due to storm restoration costs in 2020property and lower allowances for equity and borrowed fundsother taxes of $12$3 million. Electric utility marginretail customer volumes increased 4% primarily due to higher retail utility margin, primarily from highercustomer usage and the favorable impact of weather. Wholesale electricity sales volumes and higher recoveries through bill riders (offset in operations and maintenance and income tax benefit), and higher wholesale utility margin from higher wholesale volumes. The favorable income tax benefit wasincreased 20% due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service. Depreciation and amortization expensefavorable market conditions. Natural gas retail customer volumes increased 11% due to additional assets placed in-service and the favorable impact of regulatory mechanisms.
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 for the third quarter and 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.weather.
MidAmerican Funding -
MidAmerican Funding's net income for the thirdsecond quarter of 20212022 was $373$204 million, an increasea decrease of $36$7 million, or 11%3%, compared to 2020.2021. MidAmerican Funding's net income for the first ninesix months of 20212022 was $728$445 million, an increase of $33$90 million, or 5%25%, compared to 2020.2021. The variances in net income were primarily due to the changes in MidAmerican Energy's earnings discussed above.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.
MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's expense included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Electric utility margin: | Electric utility margin: | | | | | | | | | | | | | Electric utility margin: | | | | | | | | | | | | |
| Operating revenue | Operating revenue | | $ | 854 | | | $ | 728 | | | $ | 126 | | 17 | % | | $ | 1,985 | | | $ | 1,717 | | | $ | 268 | | 16 | % | Operating revenue | | $ | 725 | | | $ | 586 | | | $ | 139 | | 24 | % | | $ | 1,333 | | | $ | 1,131 | | | $ | 202 | | 18 | % |
| Cost of fuel and energy | Cost of fuel and energy | | 163 | | | 115 | | | 48 | | 42 | | | 417 | | | 266 | | | 151 | | 57 | | Cost of fuel and energy | | 174 | | | 103 | | | 71 | | 69 | | | 299 | | | 254 | | | 45 | | 18 | |
| Electric utility margin | Electric utility margin | | 691 | | | 613 | | | 78 | | 13 | % | | 1,568 | | | 1,451 | | | 117 | | 8 | % | Electric utility margin | | 551 | | | 483 | | | 68 | | 14 | % | | 1,034 | | | 877 | | | 157 | | 18 | % |
| | Natural gas utility margin: | Natural gas utility margin: | | Natural gas utility margin: | |
| Operating revenue | Operating revenue | | 110 | | | 80 | | | 30 | | 38 | % | | 728 | | | 384 | | | 344 | | * | Operating revenue | | 171 | | | 106 | | | 65 | | 61 | % | | 567 | | | 618 | | | (51) | | (8) | % |
| Natural gas purchased for resale | Natural gas purchased for resale | | 63 | | | 39 | | | 24 | | 62 | | | 552 | | | 209 | | | 343 | | * | Natural gas purchased for resale | | 120 | | | 57 | | | 63 | | * | | 418 | | | 489 | | | (71) | | (15) | |
| Natural gas utility margin | Natural gas utility margin | | 47 | | | 41 | | | 6 | | 15 | % | | 176 | | | 175 | | | 1 | | 1 | % | Natural gas utility margin | | 51 | | | 49 | | | 2 | | 4 | % | | 149 | | | 129 | | | 20 | | 16 | % |
| | Utility margin | Utility margin | | 738 | | | 654 | | | 84 | | 13 | % | | 1,744 | | | 1,626 | | | 118 | | 7 | % | Utility margin | | 602 | | | 532 | | | 70 | | 13 | % | | 1,183 | | | 1,006 | | | 177 | | 18 | % |
| | Other operating revenue | Other operating revenue | | 2 | | | 4 | | | (2) | | (50) | % | | 13 | | | 5 | | | 8 | | * | Other operating revenue | | 1 | | | 1 | | | — | | — | % | | 2 | | | 11 | | | (9) | | (82) | % |
| Other cost of sales | | 1 | | | 1 | | | — | | — | | | 1 | | | 1 | | | — | | * | |
| | Operations and maintenance | Operations and maintenance | | 200 | | | 212 | | | (12) | | (6) | | | 577 | | | 559 | | | 18 | | 3 | | Operations and maintenance | | 200 | | | 184 | | | 16 | | 9 | | | 392 | | | 377 | | | 15 | | 4 | |
| Depreciation and amortization | Depreciation and amortization | | 218 | | | 180 | | | 38 | | 21 | | | 634 | | | 531 | | | 103 | | 19 | | Depreciation and amortization | | 277 | | | 209 | | | 68 | | 33 | | | 527 | | | 416 | | | 111 | | 27 | |
| Property and other taxes | Property and other taxes | | 34 | | | 33 | | | 1 | | 3 | | | 107 | | | 102 | | | 5 | | 5 | | Property and other taxes | | 36 | | | 37 | | | (1) | | (3) | | | 76 | | | 73 | | | 3 | | 4 | |
| | Operating income | Operating income | | $ | 287 | | | $ | 232 | | | $ | 55 | | 24 | % | | $ | 438 | | | $ | 438 | | | $ | — | | — | % | Operating income | | $ | 90 | | | $ | 103 | | | $ | (13) | | (13) | % | | $ | 190 | | | $ | 151 | | | $ | 39 | | 26 | % |
* Not meaningful.
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | Utility margin (in millions): | | | | | | | | | | | |
| Operating revenue | Operating revenue | $ | 854 | | | $ | 728 | | | $ | 126 | | | 17 | % | | $ | 1,985 | | | $ | 1,717 | | | $ | 268 | | | 16 | % | Operating revenue | $ | 725 | | | $ | 586 | | | $ | 139 | | | 24 | % | | $ | 1,333 | | | $ | 1,131 | | | $ | 202 | | | 18 | % |
| Cost of fuel and energy | Cost of fuel and energy | 163 | | | 115 | | | 48 | | | 42 | | | 417 | | | 266 | | | 151 | | | 57 | | Cost of fuel and energy | 174 | | | 103 | | | 71 | | | 69 | | | 299 | | | 254 | | | 45 | | | 18 | |
| Utility margin | Utility margin | $ | 691 | | | $ | 613 | | | $ | 78 | | | 13 | % | | $ | 1,568 | | | $ | 1,451 | | | $ | 117 | | | 8 | % | Utility margin | $ | 551 | | | $ | 483 | | | $ | 68 | | | 14 | % | | $ | 1,034 | | | $ | 877 | | | $ | 157 | | | 18 | % |
| | Sales (GWhs): | Sales (GWhs): | | Sales (GWhs): | |
| Residential | Residential | 2,060 | | | 2,053 | | | 7 | | | — | % | | 5,284 | | | 5,226 | | | 58 | | | 1 | % | Residential | 1,552 | | | 1,486 | | | 66 | | | 4 | % | | 3,405 | | | 3,224 | | | 181 | | | 6 | % |
| Commercial | Commercial | 1,039 | | | 1,013 | | | 26 | | | 3 | | | 2,871 | | | 2,800 | | | 71 | | | 3 | | Commercial | 953 | | | 894 | | | 59 | | | 7 | | | 1,966 | | | 1,832 | | | 134 | | | 7 | |
| Industrial | Industrial | 4,106 | | | 3,758 | | | 348 | | | 9 | | | 11,981 | | | 10,884 | | | 1,097 | | | 10 | | Industrial | 4,149 | | | 4,056 | | | 93 | | | 2 | | | 8,128 | | | 7,875 | | | 253 | | | 3 | |
| Other | Other | 423 | | | 398 | | | 25 | | | 6 | | | 1,194 | | | 1,117 | | | 77 | | | 7 | | Other | 406 | | | 401 | | | 5 | | | 1 | | | 809 | | | 771 | | | 38 | | | 5 | |
| Total retail | Total retail | 7,628 | | | 7,222 | | | 406 | | | 6 | | | 21,330 | | | 20,027 | | | 1,303 | | | 7 | | Total retail | 7,060 | | | 6,837 | | | 223 | | | 3 | | | 14,308 | | | 13,702 | | | 606 | | | 4 | |
| Wholesale | Wholesale | 3,420 | | | 2,541 | | | 879 | | | 35 | | | 11,343 | | | 7,535 | | | 3,808 | | | 51 | | Wholesale | 4,146 | | | 3,872 | | | 274 | | | 7 | | | 9,471 | | | 7,923 | | | 1,548 | | | 20 | |
| Total sales | Total sales | 11,048 | | | 9,763 | | | 1,285 | | | 13 | % | | 32,673 | | | 27,562 | | | 5,111 | | | 19 | % | Total sales | 11,206 | | | 10,709 | | | 497 | | | 5 | % | | 23,779 | | | 21,625 | | | 2,154 | | | 10 | % |
| | Average number of retail customers (in thousands) | Average number of retail customers (in thousands) | 805 | | 796 | | 9 | | | 1 | % | | 803 | | 794 | | 9 | | | 1 | % | Average number of retail customers (in thousands) | 812 | | 803 | | 9 | | | 1 | % | | 811 | | 802 | | 9 | | | 1 | % |
| | Average revenue per MWh: | Average revenue per MWh: | | Average revenue per MWh: | |
| Retail | Retail | $ | 96.42 | | | $ | 91.62 | | | $ | 4.80 | | | 5 | % | | $ | 79.90 | | | $ | 76.92 | | | $ | 2.98 | | | 4 | % | Retail | $ | 84.18 | | | $ | 75.62 | | | $ | 8.56 | | | 11 | % | | $ | 74.52 | | | $ | 70.71 | | | $ | 3.81 | | | 5 | % |
| Wholesale | Wholesale | $ | 27.07 | | | $ | 17.34 | | | $ | 9.73 | | | 56 | % | | $ | 18.22 | | | $ | 14.54 | | | $ | 3.68 | | | 25 | % | Wholesale | $ | 25.23 | | | $ | 12.06 | | | $ | 13.17 | | | * | | $ | 22.65 | | | $ | 14.40 | | | $ | 8.25 | | | 57 | % |
| | Heating degree days | Heating degree days | 21 | | | 96 | | | (75) | | | (78) | % | | 3,820 | | | 3,698 | | | 122 | | | 3 | % | Heating degree days | 677 | | | 588 | | | 89 | | | 15 | % | | 3,992 | | | 3,799 | | | 193 | | | 5 | % |
| Cooling degree days | Cooling degree days | 870 | | | 795 | | | 75 | | | 9 | % | | 1,296 | | | 1,155 | | | 141 | | | 12 | % | Cooling degree days | 421 | | | 426 | | | (5) | | | (1) | % | | 421 | | | 426 | | | (5) | | | (1) | % |
| Sources of energy (GWhs)(1): | Sources of energy (GWhs)(1): | | Sources of energy (GWhs)(1): | |
Wind and other(2) | Wind and other(2) | 4,164 | | | 4,274 | | | (110) | | | (3) | % | | 16,163 | | | 14,268 | | | 1,895 | | | 13 | % | Wind and other(2) | 7,364 | | | 5,877 | | | 1,487 | | | 25 | % | | 15,654 | | | 11,999 | | | 3,655 | | | 30 | % |
| Coal | Coal | 4,609 | | | 3,169 | | | 1,440 | | | 45 | | | 10,302 | | | 5,771 | | | 4,531 | | | 79 | | Coal | 1,481 | | | 2,791 | | | (1,310) | | | (47) | | | 3,840 | | | 5,693 | | | (1,853) | | | (33) | |
| Nuclear | Nuclear | 1,007 | | | 1,000 | | | 7 | | | 1 | | | 2,911 | | | 2,902 | | | 9 | | | — | | Nuclear | 863 | | | 1,009 | | | (146) | | | (14) | | | 1,783 | | | 1,904 | | | (121) | | | (6) | |
| Natural gas | Natural gas | 503 | | | 324 | | | 179 | | | 55 | | | 982 | | | 517 | | | 465 | | | 90 | | Natural gas | 397 | | | 336 | | | 61 | | | 18 | | | 631 | | | 479 | | | 152 | | | 32 | |
| Total energy generated | Total energy generated | 10,283 | | | 8,767 | | | 1,516 | | | 17 | | | 30,358 | | | 23,458 | | | 6,900 | | | 29 | | Total energy generated | 10,105 | | | 10,013 | | | 92 | | | 1 | | | 21,908 | | | 20,075 | | | 1,833 | | | 9 | |
| Energy purchased | Energy purchased | 1,038 | | | 1,166 | | | (128) | | | (11) | | | 2,898 | | | 4,592 | | | (1,694) | | | (37) | | Energy purchased | 1,315 | | | 842 | | | 473 | | | 56 | | | 2,277 | | | 1,860 | | | 417 | | | 22 | |
| Total | Total | 11,321 | | | 9,933 | | | 1,388 | | | 14 | % | | 33,256 | | | 28,050 | | | 5,206 | | | 19 | % | Total | 11,420 | | | 10,855 | | | 565 | | | 5 | % | | 24,185 | | | 21,935 | | | 2,250 | | | 10 | % |
| | Average cost of energy per MWh: | Average cost of energy per MWh: | | Average cost of energy per MWh: | |
Energy generated(3) | Energy generated(3) | $ | 9.81 | | | $ | 7.34 | | | $ | 2.47 | | | 34 | % | | $ | 7.48 | | | $ | 5.53 | | | $ | 1.95 | | | 35 | % | Energy generated(3) | $ | 6.34 | | | $ | 6.43 | | | $ | (0.09) | | | (1) | % | | $ | 5.92 | | | $ | 6.29 | | | $ | (0.37) | | | (6) | % |
| Energy purchased | Energy purchased | $ | 60.32 | | | $ | 43.32 | | | $ | 17.00 | | | 39 | % | | $ | 65.60 | | | $ | 29.67 | | | $ | 35.93 | | | * | Energy purchased | $ | 83.45 | | | $ | 45.70 | | | $ | 37.75 | | | 83 | % | | $ | 74.41 | | | $ | 68.55 | | | $ | 5.86 | | | 9 | % |
* Not meaningful.
(1) GWh amounts are net of energy used by the related generating facilities.
(2) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECsrenewable energy credits or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | Utility margin (in millions): | | | | | | | | | | | |
| Operating revenue | Operating revenue | $ | 110 | | | $ | 80 | | | $ | 30 | | | 38 | % | | $ | 728 | | | $ | 384 | | | $ | 344 | | | 90 | % | Operating revenue | $ | 171 | | | $ | 106 | | | $ | 65 | | | 61 | % | | $ | 567 | | | $ | 618 | | | $ | (51) | | | (8) | % |
| Natural gas purchased for resale | Natural gas purchased for resale | 63 | | | 39 | | | 24 | | | 62 | | | 552 | | | 209 | | | 343 | | | * | Natural gas purchased for resale | 120 | | | 57 | | | 63 | | | * | | 418 | | | 489 | | | (71) | | | (15) | |
| Utility margin | Utility margin | $ | 47 | | | $ | 41 | | | $ | 6 | | | 15 | % | | $ | 176 | | | $ | 175 | | | $ | 1 | | | 1 | % | Utility margin | $ | 51 | | | $ | 49 | | | $ | 2 | | | 4 | % | | $ | 149 | | | $ | 129 | | | $ | 20 | | | 16 | % |
| | Throughput (000's Dths): | Throughput (000's Dths): | | Throughput (000's Dths): | |
| Residential | Residential | 2,689 | | | 3,190 | | | (501) | | | (16) | % | | 34,243 | | | 34,146 | | | 97 | | | — | % | Residential | 7,500 | | | 6,272 | | | 1,228 | | | 20 | % | | 34,599 | | | 31,554 | | | 3,045 | | | 10 | % |
| Commercial | Commercial | 1,511 | | | 1,671 | | | (160) | | | (10) | | | 16,255 | | | 15,634 | | | 621 | | | 4 | | Commercial | 3,599 | | | 3,011 | | | 588 | | | 20 | | | 16,059 | | | 14,744 | | | 1,315 | | | 9 | |
| Industrial | Industrial | 1,110 | | | 1,105 | | | 5 | | | — | | | 3,616 | | | 3,687 | | | (71) | | | (2) | | Industrial | 1,465 | | | 1,069 | | | 396 | | | 37 | | | 3,309 | | | 2,506 | | | 803 | | | 32 | |
| Other | Other | 4 | | | 6 | | | (2) | | | (33) | | | 52 | | | 54 | | | (2) | | | (4) | | Other | 16 | | | 11 | | | 5 | | | 45 | | | 51 | | | 48 | | | 3 | | | 6 | |
| Total retail sales | Total retail sales | 5,314 | | | 5,972 | | | (658) | | | (11) | | | 54,166 | | | 53,521 | | | 645 | | | 1 | | Total retail sales | 12,580 | | | 10,363 | | | 2,217 | | | 21 | | | 54,018 | | | 48,852 | | | 5,166 | | | 11 | |
| Wholesale sales | Wholesale sales | 6,365 | | | 5,622 | | | 743 | | | 13 | | | 22,955 | | | 24,391 | | | (1,436) | | | (6) | | Wholesale sales | 4,912 | | | 5,817 | | | (905) | | | (16) | | | 17,144 | | | 16,590 | | | 554 | | | 3 | |
| Total sales | Total sales | 11,679 | | | 11,594 | | | 85 | | | 1 | | | 77,121 | | | 77,912 | | | (791) | | | (1) | | Total sales | 17,492 | | | 16,180 | | | 1,312 | | | 8 | | | 71,162 | | | 65,442 | | | 5,720 | | | 9 | |
| Natural gas transportation service | Natural gas transportation service | 26,789 | | | 24,973 | | | 1,816 | | | 7 | | | 83,282 | | | 82,092 | | | 1,190 | | | 1 | | Natural gas transportation service | 22,491 | | | 26,853 | | | (4,362) | | | (16) | | | 53,804 | | | 56,493 | | | (2,689) | | | (5) | |
| Total throughput | Total throughput | 38,468 | | | 36,567 | | | 1,901 | | | 5 | % | | 160,403 | | | 160,004 | | | 399 | | | — | % | Total throughput | 39,983 | | | 43,033 | | | (3,050) | | | (7) | % | | 124,966 | | | 121,935 | | | 3,031 | | | 2 | % |
| | Average number of retail customers (in thousands) | Average number of retail customers (in thousands) | 776 | | | 769 | | | 7 | | | 1 | % | | 776 | | | 770 | | | 6 | | | 1 | % | Average number of retail customers (in thousands) | 781 | | | 776 | | | 5 | | | 1 | % | | 784 | | | 777 | | | 7 | | | 1 | % |
| | Average revenue per retail Dth sold | Average revenue per retail Dth sold | $ | 14.21 | | | $ | 10.43 | | | $ | 3.78 | | | 36 | % | | $ | 11.20 | | | $ | 5.91 | | | $ | 5.29 | | | 90 | % | Average revenue per retail Dth sold | $ | 10.08 | | | $ | 7.81 | | | $ | 2.27 | | | 29 | % | | $ | 8.36 | | | $ | 10.88 | | | $ | (2.52) | | | (23) | % |
| | Heating degree days | Heating degree days | 28 | | | 122 | | | (94) | | | (77) | % | | 3,954 | | | 3,899 | | | 55 | | | 1 | % | Heating degree days | 734 | | | 625 | | | 109 | | | 17 | % | | 4,219 | | | 3,926 | | | 293 | | | 7 | % |
| | Average cost of natural gas per retail Dth sold | Average cost of natural gas per retail Dth sold | $ | 7.09 | | | $ | 4.74 | | | $ | 2.35 | | | 50 | % | | $ | 8.47 | | | $ | 3.12 | | | $ | 5.35 | | | * | Average cost of natural gas per retail Dth sold | $ | 6.78 | | | $ | 3.99 | | | $ | 2.79 | | | 70 | % | | $ | 6.03 | | | $ | 8.62 | | | $ | (2.59) | | | (30) | % |
| | Combined retail and wholesale average cost of natural gas per Dth sold | Combined retail and wholesale average cost of natural gas per Dth sold | $ | 5.42 | | | $ | 3.32 | | | $ | 2.10 | | | 63 | % | | $ | 7.16 | | | $ | 2.68 | | | $ | 4.48 | | | * | Combined retail and wholesale average cost of natural gas per Dth sold | $ | 6.86 | | | $ | 3.54 | | | $ | 3.32 | | | 94 | % | | $ | 5.87 | | | $ | 7.47 | | | $ | (1.60) | | | (21) | % |
* Not meaningful.
Quarter Ended SeptemberJune 30, 20212022 Compared to Quarter Ended SeptemberJune 30, 20202021
MidAmerican Energy -
Electric utility margin increased $78$68 million, or 13%14%, for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to:
•a $41$63 million increase in wholesale utility margin due to higher marginmargins per unit of $35$61 million, reflecting higher market prices and lower energy costs, and higher volumes of 34.6%7.1%; and
•a $36$6 million increase in retail utility margin primarily due to $20$11 million from higher usage for certain industrial customers;customer usage; $6 million due to price impacts from liquidated damages related to a wind-powered generation project; $5changes in sales mix; and $1 million from the favorable impact of weather; partially offset by $12 million, net of energy costs, from higherlower recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $4 million from the favorable impact of weather.. Retail customer volumes increased 5.6%3.3%.
Natural gas utility margin increased $6$2 million, or 15%4%, for the thirdsecond quarter of 20212022 compared to 2020 primarily due to:
•an $8 million increase from higher average prices primarily due to the timing of recoveries through a capital tracker mechanism; partially offset by
•a $3 million decrease from the unfavorable impact of weather.
Operations and maintenance decreased $12 million, or 6%, for the third quarter of 2021 compared to 2020 primarily due to lower electric distribution maintenance costs of $21 million due to storm restoration costs in 2020, partially offset by higher other generation operations expenses of $4 million due to additional wind turbines and easements and higher transmission operations costs from MISO of $3 million.
Depreciation and amortization for the third quarter of 2021 increased $38 million, or 21%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service, $13 million from a regulatory mechanism deferring certain depreciation expense in 2020 and $9 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects. Refer to "Overview" above for a discussion of an IUB order extending the regulatory mechanism deferring certain depreciation expense.
Allowance for borrowed and equity funds decreased $6 million, or 29%, for the third quarter of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.
Other, net decreased $6 million, or 43%, for the third quarter of 2021 compared to 2020 primarily due to lower cash surrender values of corporate-owned life insurance policies.
Income tax benefit decreased $4 million, or 3%, for the third quarter of 2021 compared to 2020, and the effective tax rate was (61)% for 2021 and (76)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to a higher pretax income.
Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the third quarter of 2021 and 2020 totaled $103 million and $105 million, respectively.
MidAmerican Funding -
Income tax benefit decreased $4 million, or 3%, for the third quarter of 2021 compared to 2020, and the effective tax rate was (63)% for 2021 and (78)% for 2020. The changes in the effective tax rates were due to the factors discussed for MidAmerican Energy.
First Nine Months of 2021 compared to First Nine Months of 2020
MidAmerican Energy -
Electric utility margin increased $117 million, or 8%, for the first nine months of 2021 compared to 2020, due to:
•a $90 million increase in retail utility margin primarily due to $42 million from higher usage for certain industrial customers; $17 million from the favorable impact of weather; $17 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); $7 million due to price impacts from changes in sales mix and $6 million from liquidated damages related to a wind-powered generation project. Retail customer volumes increased 6.5%; and
•a $29 million increase in wholesale utility margin due to higher volumes of 50.5%, partially offset by lower margins per unit of $10 million, reflecting higher energy costs; partially offset by
•a $2 million decrease in Multi-Value Projects transmission revenue.
Natural gas utility margin increased $1 million, or 1%, for the first nine months of 2021 compared to 2020 primarily due to:
•a $5 million increase in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
•a $2 million increase natural gas transportation margin, reflectingfrom higher volumes;average prices; partially offset by
•a $7$3 million decrease from higher refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit).
Operations and maintenance increased $18$16 million, or 3%9%, for the first nine monthssecond quarter of 20212022 compared to 20202021 primarily due to higher othersteam generation operations and maintenance expenses of $12 million due to additional wind turbines and easements, higher energy efficiency program expensecosts of $9 million (offset in operating revenue),and higher natural gaselectric distribution and transmission costs of $6 million and higher transmission operations costs from MISO of $3$10 million, partially offset by lower electricgas distribution costs of $15 million due to storm restoration costs in 2020.$3 million.
Depreciation and amortization increased $68 million, or 33%, for the first nine monthssecond quarter of 2021 increased $103 million, or 19%,2022 compared to 20202021 primarily due to wind-powered generating facilities and other plant placed in-service and $39$54 million from a regulatory mechanism deferring certain depreciation expense in 2020 andhigher Iowa revenue sharing accruals, $18 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects. Refer to "Overview" above forprojects and $8 million from wind-powered generating facilities and other plant placed in-service, partially offset by $12 million from a discussion of an IUB order extending the regulatory mechanism deferring certain depreciation expense.expense in 2022.
Interest expense increased $4 million, or 5%, for the second quarter of 2022 compared to 2021 due to higher interest expense from a July 2021 long-term debt issuance and higher interest rates on variable rate long-term debt.
Allowance for borrowed and equity funds decreased $12increased $9 million, or 27%90%, for the first nine monthssecond quarter of 20212022 compared to 20202021 primarily due to lowerhigher construction work-in-progress balances related to wind-poweredwind- and solar-powered generation.
Other, net increased $4decreased $27 million, or 13%180%, for the first nine monthssecond quarter of 20212022 compared to 20202021 primarily due to higherunfavorable investment earnings, largely attributable to lower cash surrender values of corporate-owned life insurance policies, partially offset byand higher non-service costs of postretirement employee benefit plans.
Income tax benefit increased $45$29 million, or 11%18%, for the first nine monthssecond quarter of 20212022 compared to 2020, and the effective tax rate was (162)% for 2021 and (142)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to the higher PTCs and a lower pretax income.income, partially offset by state income tax impacts and the effects of ratemaking. PTCs for the first nine monthssecond quarter of 2022 and 2021 and 2020 totaled $400$185 million and $352$146 million, respectively.
MidAmerican Funding -
Income tax benefit increased $46$28 million, or 11%18%, for the first nine monthssecond quarter of 20212022 compared to 2020, and the effective tax rate was (172)% for 2021 and (147)% for 2020. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.
First Six Months of 2022 Compared to First Six Months of 2021
MidAmerican Energy -
Electric utility margin increased $157 million, or 18%, for the first six months of 2022 compared to 2021, due to:
•a $127 million increase in wholesale utility margin due to higher margins per unit of $119 million, reflecting higher market prices and lower energy costs, and higher volumes of 19.5%; and
•a $31 million increase in retail utility margin primarily due to $28 million from higher customer usage; $4 million due to price impacts from changes in sales mix; and $2 million from the favorable impact of weather; partially offset by $3 million, net of energy costs, from lower recoveries through bill riders (offset in operations and maintenance expense and income tax benefit). Retail customer volumes increased 4.4%.
Natural gas utility margin increased $20 million, or 16%, for the first six months of 2022 compared to 2021 primarily due to:
•a $10 million increase from higher average prices primarily due to the timing of recoveries through a capital tracker mechanism;
•a $5 million increase from lower refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit); and
•a $5 million increase from the favorable impact of weather.
Operations and maintenance increased $15 million, or 4%, for the first six months of 2022 compared to 2021 primarily due to higher steam generation maintenance costs of $11 million and higher electric distribution and transmission costs of $10 million, partially offset by lower energy efficiency program expense of $4 million (offset in operating revenue) and lower gas distribution costs of $3 million.
Depreciation and amortization increased $111 million, or 27%, for the first six months of 2022 compared to 2021 primarily due to $96 million from higher Iowa revenue sharing accruals, $24 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects and $15 million from wind-powered generating facilities and other plant placed in-service, partially offset by $25 million from a regulatory mechanism deferring certain depreciation expense in 2022.
Interest expense increased $8 million, or 5%, for the first six months of 2022 compared to 2021 due to higher interest expense from a July 2021 long-term debt issuance and higher interest rates on variable rate long-term debt.
Allowance for borrowed and equity funds increased $20 million, or 111%, for the first six months of 2022 compared to 2021 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation.
Other, net decreased $41 million, or 158%, for the first six months of 2022 compared to 2021 primarily due to unfavorable investment earnings, largely attributable to lower cash surrender values of corporate-owned life insurance policies, and higher non-service costs of employee benefit plans.
Income tax benefit increased $81 million, or 26%, for the first six months of 2022 compared to 2021 primarily due to higher PTCs, partially offset by the effects of ratemaking, state income tax impacts and higher pretax income. PTCs for the first six months of 2022 and 2021 totaled $388 million and $297 million, respectively.
MidAmerican Funding -
Income tax benefit increased $80 million, or 25%, for the first six months of 2022 compared to 2021 principally due to the factors discussed for MidAmerican Energy.
Liquidity and Capital Resources
As of SeptemberJune 30, 2021,2022, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
| | | | | | | | |
| MidAmerican Energy: | | |
| Cash and cash equivalents | | $ | 541495 | |
| | | |
Credit facilities, maturing 20222023 and 20242025 | | 1,505 | |
| Less: | | |
| | |
| Tax-exempt bond support | | (370) | |
| Net credit facilities | | 1,135 | |
| | | |
| MidAmerican Energy total net liquidity | | $ | 1,6761,630 | |
| | | |
| MidAmerican Funding: | | |
| MidAmerican Energy total net liquidity | | $ | 1,6761,630 | |
| Cash and cash equivalents | | 12 | |
MHC, Inc. credit facility, maturing 20222023 | | 4 | |
| MidAmerican Funding total net liquidity | | $ | 1,6811,636 | |
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021, and 2020, were $1,290$1,125 million and $1,209$721 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021, and 2020, were $1,276$1,118 million and $1,199$715 million, respectively. Cash flows from operating activities reflect higher income tax receipts and lower payments for the settlement of asset retirement obligations, partially offset by lower cashutility margins for MidAmerican Energy's regulated electric and natural gas businesses including delayedand lower payments to vendors, partially offset by lower income tax receipts and higher asset retirement obligation settlements. Higher utility margins are largely attributable to the recovery of higher natural gas costs incaused by the February 2021 discussed below, and higher payments to vendors.
In February 2021, severe coldpolar vortex weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to MidAmerican Energy's customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the nine-month period ended September 30, 2021.event.
The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.
Investing Activities
MidAmerican Energy's net cash flows from investing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021, and 2020, were $(1,276)$(860) million and $(1,339)$(726) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021, and 2020, were $(1,276)$(860) million and $(1,338)$(726) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures, which decreased primarily dueexpenditures. Refer to lower wind-powered generating facility construction"Future Uses of Cash" for further discussion of capital expenditures. Purchases and proceeds related to marketable securities substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments. Other, net for 2020 reflects $9 million of proceeds from corporate-owned life insurance policies.
Financing Activities
MidAmerican Energy's net cash flows from financing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $489$(1) million and $(1)$(2) million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021, and 2020, were $503$7 million and $12$4 million, respectively. Proceeds from long-term debt reflect MidAmerican Energy's issuance in July 2021 of $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Funding received $13$8 million and $6 million in 20212022 and 2020,2021, respectively, through its note payable with BHE.
Debt Authorizations and Related Matters
Short-term Debt
MidAmerican Energy has authority from the FERC to issue, through April 2, 2022,2024, commercial paper and bank notes aggregating $1.5 billion at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of 400 basis points.billion. MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 2024.2025. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option,Secured Overnight Financing Rate, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
Long-term Debt and Preferred Stock
MidAmerican Energy currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities and preferred stock through June 13, 2024. Additionally, following the July 2021 issuance of $500 million of first mortgage bonds, MidAmerican Energy has authorization from the FERC to issue, through June 30, 2023, long-term debt securities up to an aggregate of $2.0 billion and preferred stock up to an aggregate of $500 million and from the Illinois Commerce Commission to issue, through May 25, 2025, long-term debt securities up to an aggregate of $350$2.2 billion and preferred stock up to an aggregate of $500 million. Additionally, MidAmerican Energy has authority from the Illinois Commerce Commission through October 15, 2024, to issue $750 million through August 20, 2022.of long-term debt securities for the purpose of refinancing $250 million of its 3.70% Senior notes due September 2023 and $500 million of its 2.40% Senior notes due October 2024.
Future Uses of Cash
MidAmerican Energy and MidAmerican Funding have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including regulatory approvals, their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
MidAmerican Energy has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | Nine-Month Periods | | Annual |
| Six-Month Periods | | Annual |
| | Ended September 30, | | Forecast | | Ended June 30, | | Forecast |
| | 2020 | | 2021 | | 2021 | | 2021 | | 2022 | | 2022 |
| | Wind generation | Wind generation | $ | 713 | | | $ | 605 | | | $ | 807 | | Wind generation | $ | 286 | | | $ | 244 | | | $ | 734 | |
| Electric distribution | Electric distribution | 189 | | | 154 | | | 260 | | Electric distribution | 96 | | | 125 | | | 274 | |
| Electric transmission | Electric transmission | 132 | | | 105 | | | 194 | | Electric transmission | 54 | | | 46 | | | 158 | |
| Solar generation | Solar generation | 2 | | | 97 | | | 180 | | Solar generation | 63 | | | 77 | | | 140 | |
| Other | Other | 305 | | | 305 | | | 502 | | Other | 221 | | | 370 | | | 607 | |
| Total | Total | $ | 1,341 | | | $ | 1,266 | | | $ | 1,943 | | Total | $ | 720 | | | $ | 862 | | | $ | 1,913 | |
MidAmerican Energy's capital expenditures provided above consist of the following:
•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction and acquisition of wind-powered generating facilities totaled $275totaling $5 million and $676$172 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $73$106 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.2022.
◦Repowering of wind-powered generating facilities totaled $274totaling $214 million and $25$82 million for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, respectively. Planned spending for the repowering of wind-powered generating facilities totals $101$314 million for the remainder of 2021.2022. 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 892593 MWs of current repowering projects not in-service as of SeptemberJune 30, 2021, 5912022, 292 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.
•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.
•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.
•Solar reflects MidAmerican Energy's current plan forgeneration includes the construction of solar-powered generating facilities totaling 141 MWs of small- and utility-scale solar generation, duringwith total spend of $77 million and $63 million for the six-month periods ended June 30, 2022 and 2021, respectively and planned spending of which 61 MWs are expected to be placed in-service in 2021.$63 million for the remainder of 2022.
•Remaining expenditures primarily relate to routine expenditures for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.
Contractual ObligationsMaterial Cash Requirements
As of SeptemberJune 30, 2021,2022, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's contractual obligationscash requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2020.
2021.
Quad Cities Generating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, ("which was a subsidiary of Exelon Generation")Corporation prior to February 1, 2022), 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")ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon GenerationConstellation Energy 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,Constellation Energy, 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 capacity 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 requestRequests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms waswere filed onin October 5, 2021 and remains pending.denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Constellation Energy is strenuously opposing these appeals.
Assuming the continued effectiveness of the Illinois zero emission standard, Exelon GenerationConstellation Energy 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
MidAmerican Energy is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact itsMidAmerican Energy's current and future operations. In addition to imposing continuing compliance obligations, and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various federal, state and local agencies. All suchMidAmerican Energy believes it is in material compliance with all applicable laws and regulations, although many are subject to a range of interpretation whichthat may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2020.2021. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2020.2021.
Nevada Power Company and its subsidiaries
Consolidated Financial Section
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of SeptemberJune 30, 2021,2022, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and of cash flows for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2020,2021, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021,25, 2022, 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, 2020,2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
NovemberAugust 5, 20212022
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 85 | | | $ | 25 | | Cash and cash equivalents | $ | 42 | | | $ | 33 | |
| Trade receivables, net | Trade receivables, net | 353 | | | 234 | | Trade receivables, net | 369 | | | 227 | |
| Inventories | Inventories | 66 | | | 69 | | Inventories | 68 | | | 64 | |
| Derivative contracts | 3 | | | 26 | | |
| | Regulatory assets | Regulatory assets | 217 | | | 48 | | Regulatory assets | 401 | | | 291 | |
| Prepayments | 37 | | | 38 | | |
| | | Other current assets | Other current assets | 36 | | | 26 | | Other current assets | 62 | | | 86 | |
| Total current assets | Total current assets | 797 | | | 466 | | Total current assets | 942 | | | 701 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 6,829 | | | 6,701 | | Property, plant and equipment, net | 7,115 | | | 6,891 | |
| Finance lease right of use assets, net | 330 | | | 351 | | |
| | Regulatory assets | Regulatory assets | 686 | | | 746 | | Regulatory assets | 748 | | | 728 | |
| Other assets | Other assets | 73 | | | 72 | | Other assets | 414 | | | 432 | |
| | Total assets | Total assets | $ | 8,715 | | | $ | 8,336 | | Total assets | $ | 9,219 | | | $ | 8,752 | |
| | LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 249 | | | $ | 181 | | Accounts payable | $ | 433 | | | $ | 242 | |
| Accrued interest | Accrued interest | 38 | | | 32 | | Accrued interest | 33 | | | 32 | |
| Accrued property, income and other taxes | 60 | | | 25 | | |
| | Current portion of finance lease obligations | 26 | | | 27 | | |
| | Short-term debt | | Short-term debt | — | | | 180 | |
| Regulatory liabilities | Regulatory liabilities | 54 | | | 50 | | Regulatory liabilities | 46 | | | 49 | |
| Customer deposits | Customer deposits | 44 | | | 47 | | Customer deposits | 44 | | | 44 | |
| Asset retirement obligation | 16 | | | 25 | | |
| | Derivative contracts | | Derivative contracts | 122 | | | 55 | |
| Other current liabilities | Other current liabilities | 38 | | | 22 | | Other current liabilities | 91 | | | 91 | |
| Total current liabilities | Total current liabilities | 525 | | | 409 | | Total current liabilities | 769 | | | 693 | |
| | Long-term debt | Long-term debt | 2,498 | | | 2,496 | | Long-term debt | 2,800 | | | 2,499 | |
| Finance lease obligations | Finance lease obligations | 313 | | | 334 | | Finance lease obligations | 302 | | | 310 | |
| Regulatory liabilities | Regulatory liabilities | 1,118 | | | 1,163 | | Regulatory liabilities | 1,075 | | | 1,100 | |
| Deferred income taxes | Deferred income taxes | 753 | | | 738 | | Deferred income taxes | 816 | | | 782 | |
| Other long-term liabilities | Other long-term liabilities | 281 | | | 257 | | Other long-term liabilities | 328 | | | 338 | |
| Total liabilities | Total liabilities | 5,488 | | | 5,397 | | Total liabilities | 6,090 | | | 5,722 | |
| | Commitments and contingencies (Note 8) | 0 | | 0 | |
| Commitments and contingencies (Note 9) | | Commitments and contingencies (Note 9) | 0 | | 0 |
| | Shareholder's equity: | Shareholder's equity: | | Shareholder's equity: | |
| Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding | Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding | — | | | — | | Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding | — | | | — | |
| Additional paid-in capital | Additional paid-in capital | 2,308 | | | 2,308 | | Additional paid-in capital | 2,333 | | | 2,308 | |
| Retained earnings | Retained earnings | 922 | | | 634 | | Retained earnings | 798 | | | 724 | |
| Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | (3) | | | (3) | | Accumulated other comprehensive loss, net | (2) | | | (2) | |
| Total shareholder's equity | Total shareholder's equity | 3,227 | | | 2,939 | | Total shareholder's equity | 3,129 | | | 3,030 | |
| | Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 8,715 | | | $ | 8,336 | | Total liabilities and shareholder's equity | $ | 9,219 | | | $ | 8,752 | |
| | The accompanying notes are an integral part of the consolidated financial statements. | The accompanying notes are an integral part of the consolidated financial statements. | The accompanying notes are an integral part of the consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | Operating revenue | Operating revenue | $ | 802 | | | $ | 808 | | | $ | 1,731 | | | $ | 1,706 | | Operating revenue | $ | 639 | | | $ | 559 | | | $ | 1,054 | | | $ | 929 | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | |
| Cost of fuel and energy | Cost of fuel and energy | 328 | | | 287 | | | 745 | | | 654 | | Cost of fuel and energy | 336 | | | 252 | | | 548 | | | 417 | |
| Operations and maintenance | Operations and maintenance | 88 | | | 139 | | | 228 | | | 295 | | Operations and maintenance | 75 | | | 77 | | | 140 | | | 140 | |
| Depreciation and amortization | Depreciation and amortization | 103 | | | 92 | | | 304 | | | 273 | | Depreciation and amortization | 103 | | | 100 | | | 206 | | | 201 | |
| Property and other taxes | Property and other taxes | 12 | | | 12 | | | 36 | | | 35 | | Property and other taxes | 12 | | | 12 | | | 25 | | | 24 | |
| Total operating expenses | Total operating expenses | 531 | | | 530 | | | 1,313 | | | 1,257 | | Total operating expenses | 526 | | | 441 | | | 919 | | | 782 | |
| | Operating income | Operating income | 271 | | | 278 | | | 418 | | | 449 | | Operating income | 113 | | | 118 | | | 135 | | | 147 | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | |
| Interest expense | Interest expense | (38) | | | (40) | | | (115) | | | (122) | | Interest expense | (39) | | | (39) | | | (77) | | | (77) | |
| Allowance for borrowed funds | Allowance for borrowed funds | — | | | 1 | | | 2 | | | 3 | | Allowance for borrowed funds | 2 | | | 1 | | | 3 | | | 2 | |
| Allowance for equity funds | Allowance for equity funds | 2 | | | 1 | | | 5 | | | 5 | | Allowance for equity funds | 2 | | | 2 | | | 5 | | | 3 | |
| Interest and dividend income | Interest and dividend income | 5 | | | 3 | | | 13 | | | 8 | | Interest and dividend income | 9 | | | 3 | | | 18 | | | 8 | |
| Other, net | Other, net | 4 | | | 3 | | | 14 | | | 4 | | Other, net | (1) | | | 6 | | | — | | | 10 | |
| Total other income (expense) | Total other income (expense) | (27) | | | (32) | | | (81) | | | (102) | | Total other income (expense) | (27) | | | (27) | | | (51) | | | (54) | |
| | Income before income tax expense | Income before income tax expense | 244 | | | 246 | | | 337 | | | 347 | | Income before income tax expense | 86 | | | 91 | | | 84 | | | 93 | |
| Income tax expense | Income tax expense | 27 | | | 52 | | | 36 | | | 74 | | Income tax expense | 10 | | | 9 | | | 10 | | | 9 | |
| Net income | Net income | $ | 217 | | | $ | 194 | | | $ | 301 | | | $ | 273 | | Net income | $ | 76 | | | $ | 82 | | | $ | 74 | | | $ | 84 | |
| | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
| | | Accumulated | | | Accumulated | |
| | Additional | | Other | | Total | | Additional | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's | | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity | | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
| | Balance, June 30, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 488 | | | $ | (4) | | | $ | 2,792 | | |
| Net income | | — | | | — | | | — | | | 194 | | | — | | | 194 | | |
| | Balance, September 30, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 682 | | | $ | (4) | | | $ | 2,986 | | |
| | Balance, December 31, 2019 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 493 | | | $ | (4) | | | $ | 2,797 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 636 | | | $ | (3) | | | $ | 2,941 | |
| Net income | Net income | | — | | | — | | | — | | | 273 | | | — | | | 273 | | Net income | | — | | | — | | | — | | | 82 | | | — | | | 82 | |
| Dividends declared | Dividends declared | | — | | | — | | | — | | | (85) | | | — | | | (85) | | Dividends declared | | — | | | — | | | — | | | (13) | | | — | | | (13) | |
| Other equity transactions | | — | | | — | | | — | | | 1 | | | — | | | 1 | | |
| Balance, September 30, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 682 | | | $ | (4) | | | $ | 2,986 | | |
| | Balance, June 30, 2021 | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 705 | | | $ | (3) | | | $ | 3,010 | | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 705 | | | $ | (3) | | | $ | 3,010 | |
| Net income | | — | | | — | | | — | | | 217 | | | — | | | 217 | | |
| | Balance, September 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 922 | | | $ | (3) | | | $ | 3,227 | | |
| | Balance, December 31, 2020 | Balance, December 31, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 634 | | | $ | (3) | | | $ | 2,939 | | Balance, December 31, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 634 | | | $ | (3) | | | $ | 2,939 | |
| Net income | Net income | | — | | | — | | | — | | | 301 | | | — | | | 301 | | Net income | | — | | | — | | | — | | | 84 | | | — | | | 84 | |
| Dividends declared | Dividends declared | | — | | | — | | | — | | | (13) | | | — | | | (13) | | Dividends declared | | — | | | — | | | — | | | (13) | | | — | | | (13) | |
| | Balance, September 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 922 | | | $ | (3) | | | $ | 3,227 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 705 | | | $ | (3) | | | $ | 3,010 | |
| | Balance, March 31, 2022 | | Balance, March 31, 2022 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 722 | | | $ | (2) | | | $ | 3,028 | |
| Net income | | Net income | | — | | | — | | | — | | | 76 | | | — | | | 76 | |
| | Contributions | | Contributions | | — | | | — | | | 25 | | | — | | | — | | | 25 | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | | 1,000 | | | $ | — | | | $ | 2,333 | | | $ | 798 | | | $ | (2) | | | $ | 3,129 | |
| | Balance, December 31, 2021 | | Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 724 | | | $ | (2) | | | $ | 3,030 | |
| Net income | | Net income | | — | | | — | | | — | | | 74 | | | — | | | 74 | |
| | Contributions | | Contributions | | — | | | — | | | 25 | | | — | | | — | | | 25 | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | | 1,000 | | | $ | — | | | $ | 2,333 | | | $ | 798 | | | $ | (2) | | | $ | 3,129 | |
| | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | Nine-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 301 | | | $ | 273 | | Net income | $ | 74 | | | $ | 84 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | Adjustments to reconcile net income to net cash flows from operating activities: | | Adjustments to reconcile net income to net cash flows from operating activities: | |
| | Depreciation and amortization | Depreciation and amortization | 304 | | | 273 | | Depreciation and amortization | 206 | | | 201 | |
| Allowance for equity funds | Allowance for equity funds | (5) | | | (5) | | Allowance for equity funds | (5) | | | (3) | |
| Changes in regulatory assets and liabilities | Changes in regulatory assets and liabilities | (11) | | | 38 | | Changes in regulatory assets and liabilities | (14) | | | (17) | |
| Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | (19) | | | (3) | | Deferred income taxes and amortization of investment tax credits | 12 | | | (20) | |
| Deferred energy | Deferred energy | (154) | | | (38) | | Deferred energy | (159) | | | (1) | |
| Amortization of deferred energy | Amortization of deferred energy | (7) | | | (30) | | Amortization of deferred energy | 46 | | | 7 | |
| Other, net | Other, net | 1 | | | 5 | | Other, net | 10 | | | — | |
| Changes in other operating assets and liabilities: | Changes in other operating assets and liabilities: | | Changes in other operating assets and liabilities: | |
| Trade receivables and other assets | Trade receivables and other assets | (133) | | | (112) | | Trade receivables and other assets | (154) | | | (83) | |
| Inventories | Inventories | 3 | | | (4) | | Inventories | (4) | | | 5 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 28 | | | 48 | | Accrued property, income and other taxes | 18 | | | 21 | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 97 | | | (39) | | Accounts payable and other liabilities | 194 | | | 116 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 405 | | | 406 | | Net cash flows from operating activities | 224 | | | 310 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (323) | | | (343) | | Capital expenditures | (350) | | | (237) | |
| | Proceeds from sale of assets | — | | | 26 | | |
| Other, net | 1 | | | — | | |
| | Net cash flows from investing activities | Net cash flows from investing activities | (322) | | | (317) | | Net cash flows from investing activities | (350) | | | (237) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| Proceeds from long-term debt | Proceeds from long-term debt | — | | | 718 | | Proceeds from long-term debt | 300 | | | — | |
| Repayments of long-term debt | — | | | (575) | | |
| | Net repayment of short-term debt | | Net repayment of short-term debt | (180) | | | — | |
| | Contributions from parent | | Contributions from parent | 25 | | | — | |
| Dividends paid | Dividends paid | (13) | | | (85) | | Dividends paid | — | | | (13) | |
| Other, net | Other, net | (12) | | | (12) | | Other, net | (9) | | | (8) | |
| Net cash flows from financing activities | Net cash flows from financing activities | (25) | | | 46 | | Net cash flows from financing activities | 136 | | | (21) | |
| | Net change in cash and cash equivalents and restricted cash and cash equivalents | Net change in cash and cash equivalents and restricted cash and cash equivalents | 58 | | | 135 | | Net change in cash and cash equivalents and restricted cash and cash equivalents | 10 | | | 52 | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 36 | | | 25 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 45 | | | 36 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 94 | | | $ | 160 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 55 | | | $ | 88 | |
| | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United StatesU.S. regulated electric utility company serving retail customers, including residential, commercial and industrial customers, primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of SeptemberJune 30, 20212022 and for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020.2021. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020.2021. The results of operations for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Nevada Power's Annual Report on Form 10-K for the year ended December 31, 20202021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's assumptions regarding significant accounting estimates and policies during the nine-monthsix-month period ended SeptemberJune 30, 2021.2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United StatesU.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of 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 | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash and cash equivalents | Cash and cash equivalents | $ | 85 | | | $ | 25 | | Cash and cash equivalents | $ | 42 | | | $ | 33 | |
| Restricted cash and cash equivalents included in other current assets | Restricted cash and cash equivalents included in other current assets | 9 | | | 11 | | Restricted cash and cash equivalents included in other current assets | 13 | | | 12 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 94 | | | $ | 36 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 55 | | | $ | 45 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | As of | | As of |
| | Depreciable Life | | September 30, | | December 31, | | Depreciable Life | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Utility plant: | Utility plant: | | | | | | Utility plant: | | | | | |
| Generation | Generation | 30 - 55 years | | $ | 3,780 | | | $ | 3,690 | | Generation | 30 - 55 years | | $ | 3,879 | | | $ | 3,793 | |
| Transmission | Transmission | 45 - 70 years | | 1,493 | | | 1,468 | | Transmission | 45 - 70 years | | 1,527 | | | 1,503 | |
| Distribution | Distribution | 20 - 65 years | | 3,878 | | | 3,771 | | Distribution | 20 - 65 years | | 4,021 | | | 3,920 | |
| General and intangible plant | General and intangible plant | 5 - 65 years | | 810 | | | 791 | | General and intangible plant | 5 - 65 years | | 834 | | | 836 | |
| Utility plant | Utility plant | | 9,961 | | | 9,720 | | Utility plant | | 10,261 | | | 10,052 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (3,350) | | | (3,162) | | Accumulated depreciation and amortization | | (3,517) | | | (3,406) | |
| Utility plant, net | Utility plant, net | | 6,611 | | | 6,558 | | Utility plant, net | | 6,744 | | | 6,646 | |
| Other non-regulated, net of accumulated depreciation and amortization | Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | | Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | |
| Plant, net | Plant, net | | 6,612 | | | 6,559 | | Plant, net | | 6,745 | | | 6,647 | |
| Construction work-in-progress | Construction work-in-progress | | 217 | | | 142 | | Construction work-in-progress | | 370 | | | 244 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 6,829 | | | $ | 6,701 | | Property, plant and equipment, net | | $ | 7,115 | | | $ | 6,891 | |
(4) Recent Financing Transactions
Long-Term Debt
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate ("SOFR") or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. In May 2022, Nevada Power drew the remaining $100 million available under the facility at an initial interest rate of 1.24%. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
Credit Facilities
In June 2021,2022, Nevada Power amended and restated its existing $400 million secured credit facility expiring in June 2022 with no remaining one-year extension options.2024. The amendment extended the expiration date to June 20242025 and increasedamended pricing from the available maturity extension optionsLondon Interbank Offered Rate to an unlimited number, subject to lender consent.SOFR.
(5)(5) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expensebenefit is as follows:
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | | | | | | | | | | |
| Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| | Effects of ratemaking | Effects of ratemaking | (10) | | | — | | | (10) | | | — | | Effects of ratemaking | (10) | | | (11) | | | (10) | | | (11) | |
| | Other | | Other | 1 | | | — | | | 1 | | | — | |
| Effective income tax rate | Effective income tax rate | 11 | % | | 21 | % | | 11 | % | | 21 | % | Effective income tax rate | 12 | % | | 10 | % | | 12 | % | | 10 | % |
Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts
and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2021.
Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for federal income tax has been computed on a separate return basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the six-month period ended June 30, 2022, Nevada Power received net cash payments for federal income tax from BHE totaling $21 million. For the six-month period ended June 30, 2021, Nevada Power made net cash payments for federal income tax to BHE totaling $15 million.
(6) Employee Benefit Plans
Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Qualified Pension Plan: | Qualified Pension Plan: | | | | Qualified Pension Plan: | | | |
| Other non-current assets | Other non-current assets | $ | 11 | | | $ | 8 | | Other non-current assets | $ | 42 | | | $ | 42 | |
| | | Non-Qualified Pension Plans: | Non-Qualified Pension Plans: | | Non-Qualified Pension Plans: | |
| | Other current liabilities | Other current liabilities | (1) | | | (1) | | Other current liabilities | (1) | | | (1) | |
| Other long-term liabilities | Other long-term liabilities | (9) | | | (9) | | Other long-term liabilities | (8) | | | (8) | |
| | Other Postretirement Plans: | Other Postretirement Plans: | | Other Postretirement Plans: | |
| Other non-current assets | Other non-current assets | 4 | | | 4 | | Other non-current assets | 8 | | | 8 | |
|
(7)Risk Management and Hedging Activities
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Derivative | | | | |
| Other | | | | Contracts - | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
| As of June 30, 2022 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
| Commodity assets | $ | — | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | |
| Commodity liabilities | — | | | — | | | (122) | | | (54) | | | (176) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total derivative - net basis | $ | — | | | $ | 1 | | | $ | (122) | | | $ | (54) | | | $ | (175) | |
| | | | | | | | | |
| As of December 31, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
| Commodity assets | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 4 | |
| Commodity liabilities | — | | | — | | | (55) | | | (62) | | | (117) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total derivative - net basis | $ | 4 | | | $ | — | | | $ | (55) | | | $ | (62) | | | $ | (113) | |
(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2022 a regulatory asset of $175 million was recorded related to the net derivative liability of $175 million. As of December 31, 2021 a regulatory asset of $113 million was recorded related to the net derivative liability of $113 million.
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | June 30, | | December 31, |
| Measure | | 2022 | | 2021 |
| | | | | |
| Electricity purchases | Megawatt hours | | 3 | | | 1 | |
| Natural gas purchases | Decatherms | | 113 | | | 119 | |
| | | | | |
Credit Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, 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, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the 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 Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2022, Nevada Power'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 Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $7 million and $6 million as of June 30, 2022 and December 31, 2021, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(8) Fair Value Measurements
The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.
The following table presents Nevada Power's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | Input Levels for Fair Value Measurements | | | Input Levels for Fair Value Measurements | |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| As of September 30, 2021 | | | | | | | | |
| As of June 30, 2022: | | As of June 30, 2022: | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | | Commodity derivatives | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | |
| Money market mutual funds | Money market mutual funds | 74 | | | — | | | — | | | 74 | | Money market mutual funds | 34 | | | — | | | — | | | 34 | |
| Investment funds | Investment funds | 3 | | | — | | | — | | | 3 | | Investment funds | 3 | | | — | | | — | | | 3 | |
| | $ | 77 | | | $ | — | | | $ | 4 | | | $ | 81 | | | $ | 37 | | | $ | — | | | $ | 1 | | | $ | 38 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (18) | | | $ | (18) | | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (176) | | | $ | (176) | |
| | As of December 31, 2020 | | |
| As of December 31, 2021: | | As of December 31, 2021: | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | — | | | $ | 26 | | | $ | 26 | | Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | |
| Money market mutual funds | Money market mutual funds | 21 | | | — | | | — | | | 21 | | Money market mutual funds | 34 | | | — | | | — | | | 34 | |
| Investment funds | Investment funds | 2 | | | — | | | — | | | 2 | | Investment funds | 3 | | | — | | | — | | | 3 | |
| | $ | 23 | | | $ | — | | | $ | 26 | | | $ | 49 | | | $ | 37 | | | $ | — | | | $ | 4 | | | $ | 41 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (11) | | | $ | (11) | | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (117) | | | $ | (117) | |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of SeptemberJune 30, 20212022 and December 31, 2020,2021, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.
Nevada Power's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Nevada Power's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | Beginning balance | Beginning balance | $ | 25 | | | $ | (44) | | | $ | 15 | | | $ | (8) | | Beginning balance | $ | (168) | | | $ | 27 | | | $ | (113) | | | $ | 15 | |
| Changes in fair value recognized in regulatory assets | Changes in fair value recognized in regulatory assets | 6 | | | 13 | | | 11 | | | (31) | | Changes in fair value recognized in regulatory assets | (21) | | | (6) | | | (77) | | | 5 | |
| | Settlements | Settlements | (45) | | | 31 | | | (40) | | | 39 | | Settlements | 14 | | | 4 | | | 15 | | | 5 | |
| Ending balance | Ending balance | $ | (14) | | | $ | — | | | $ | (14) | | | $ | — | | Ending balance | $ | (175) | | | $ | 25 | | | $ | (175) | | | $ | 25 | |
Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long‑term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | As of December 31, 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
| Long-term debt | $ | 2,498 | | | $ | 3,122 | | | $ | 2,496 | | | $ | 3,245 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2022 | | As of December 31, 2021 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
| Long-term debt | $ | 2,800 | | | $ | 2,807 | | | $ | 2,499 | | | $ | 3,067 | |
(8)(9) Commitments and Contingencies
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
(9)(10) Revenue from Contracts with Customers
The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Customer Revenue: | Customer Revenue: | | | | | | | | Customer Revenue: | | | | | | | |
| Retail: | Retail: | | Retail: | |
| Residential | Residential | $ | 477 | | | $ | 495 | | | $ | 998 | | | $ | 993 | | Residential | $ | 353 | | | $ | 326 | | | $ | 566 | | | $ | 521 | |
| Commercial | Commercial | 129 | | | 127 | | | 323 | | | 317 | | Commercial | 131 | | | 110 | | | 226 | | | 194 | |
| Industrial | Industrial | 152 | | | 147 | | | 310 | | | 300 | | Industrial | 124 | | | 95 | | | 203 | | | 158 | |
| Other | Other | 4 | | | 3 | | | 10 | | | 8 | | Other | 3 | | | 3 | | | 4 | | | 6 | |
| Total fully bundled | Total fully bundled | 762 | | | 772 | | | 1,641 | | | 1,618 | | Total fully bundled | 611 | | | 534 | | | 999 | | | 879 | |
| Distribution only service | Distribution only service | 6 | | | 8 | | | 17 | | | 20 | | Distribution only service | 5 | | | 5 | | | 10 | | | 10 | |
| Total retail | Total retail | 768 | | | 780 | | | 1,658 | | | 1,638 | | Total retail | 616 | | | 539 | | | 1,009 | | | 889 | |
| Wholesale, transmission and other | Wholesale, transmission and other | 28 | | | 21 | | | 57 | | | 48 | | Wholesale, transmission and other | 18 | | | 15 | | | 34 | | | 29 | |
| Total Customer Revenue | Total Customer Revenue | 796 | | | 801 | | | 1,715 | | | 1,686 | | Total Customer Revenue | 634 | | | 554 | | | 1,043 | | | 918 | |
| Other revenue | Other revenue | 6 | | | 7 | | | 16 | | | 20 | | Other revenue | 5 | | | 5 | | | 11 | | | 11 | |
| Total revenue | Total revenue | $ | 802 | | | $ | 808 | | | $ | 1,731 | | | $ | 1,706 | | Total revenue | $ | 639 | | | $ | 559 | | | $ | 1,054 | | | $ | 929 | |
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Nevada Power's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.
Results of Operations for the ThirdSecond Quarter and First NineSix Months of 20212022 and 20202021
Overview
Net income for the thirdsecond quarter of 20212022 was $217$76 million, an increasea decrease of $23$6 million, or 12%7%, compared to 20202021 primarily due to $51$7 million of lower operations and maintenance expenses, primarilyunfavorable other, net, mainly due to lower earnings sharing and lower net regulatory instructed deferrals and amortizations, $25 millioncash surrender value of lower income tax expenses primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021 and $5 million of lower other expense. These increases are offset by $47corporate-owned life insurance policies, $4 million of lower utility margin primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, lower revenue recognized due to a favorable regulatory decision, partially offset by higher transmission revenue, and $11$3 million of higher depreciation and amortization, mainly due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.
Net income for the first nine months of 2021 was $301 million, an increase of $28 million, or 10%, compared to 2020in-service. Utility margin decreased primarily due to $67 million of lower operations and maintenance expenses, primarily due to lower net regulatory instructed deferrals and amortizations, lower earnings sharing and costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation, $38 million of lower income tax expense primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021, $10 million of higher other, net, mainly due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies, lower interest expense of $7 million and higher interest and dividend income of $5 million. These increases are offset by $66 million of lower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, partially offset byunfavorable price impacts from changes in sales mix, the unfavorable impact of weather and lower other retail revenue, partially offset by higher regulatory-related revenue deferrals, an increase in the average number of customers and favorable changes in customer usage patterns. These decreases are offset by $6 million of higher transmission revenue,interest and $31dividend income, mainly from carrying charges on regulatory balances, and $2 million of lower operations and maintenance expenses, mainly due to lower plant operations and maintenance expenses, partially offset by higher earning sharing. Energy generated decreased 17% for the second quarter of 2022 compared to 2021 due to lower natural gas-fueled generation. Wholesale electricity sales volumes increased 136% and purchased electricity volumes increased 17%.
Net income for the first six months of 2022 was $74 million, a decrease of $10 million, or 12%, compared to 2021 primarily due to $10 million of unfavorable other, net, mainly due to lower cash surrender value of corporate-owned life insurance policies, $6 million of lower utility margin and $5 million of higher depreciation and amortization, mainly due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in-service. Utility margin decreased primarily due to unfavorable price impacts from changes in service.sales mix, the unfavorable impact of weather and lower other retail revenue, partially offset by higher regulatory-related revenue deferrals, an increase in the average number of customers and favorable changes in customer usage patterns. These decreases are offset by $10 million of higher interest and dividend income, mainly from carrying charges on regulatory balances. Energy generated decreased 13% for the first six months of 2022 compared to 2021 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes increased 94% and purchased electricity volumes increased 22%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as electric operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
Nevada Power's cost of fuel and energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin: | Utility margin: | | | | | | | | | | | | | Utility margin: | | | | | | | | | | | | |
| Operating revenue | Operating revenue | | $ | 802 | | | $ | 808 | | | $ | (6) | | (1) | % | | $ | 1,731 | | | $ | 1,706 | | | $ | 25 | | 1 | % | Operating revenue | | $ | 639 | | | $ | 559 | | | $ | 80 | | 14 | % | | $ | 1,054 | | | $ | 929 | | | $ | 125 | | 13 | % |
| Cost of fuel and energy | Cost of fuel and energy | | 328 | | | 287 | | | 41 | | 14 | | | 745 | | | 654 | | | 91 | | 14 | | Cost of fuel and energy | | 336 | | | 252 | | | 84 | | 33 | | | 548 | | | 417 | | | 131 | | 31 | |
| Utility margin | Utility margin | | 474 | | | 521 | | | (47) | | (9) | | | 986 | | | 1,052 | | | (66) | | (6) | | Utility margin | | 303 | | | 307 | | | (4) | | (1) | | | 506 | | | 512 | | | (6) | | (1) | |
| Operations and maintenance | Operations and maintenance | | 88 | | | 139 | | | (51) | | (37) | | | 228 | | | 295 | | | (67) | | (23) | | Operations and maintenance | | 75 | | | 77 | | | (2) | | (3) | | | 140 | | | 140 | | | — | | — | |
| Depreciation and amortization | Depreciation and amortization | | 103 | | | 92 | | | 11 | | 12 | | | 304 | | | 273 | | | 31 | | 11 | | Depreciation and amortization | | 103 | | | 100 | | | 3 | | 3 | | | 206 | | | 201 | | | 5 | | 2 | |
| Property and other taxes | Property and other taxes | | 12 | | | 12 | | | — | | — | | | 36 | | | 35 | | | 1 | | 3 | | Property and other taxes | | 12 | | | 12 | | | — | | — | | | 25 | | | 24 | | | 1 | | 4 | |
| Operating income | Operating income | | $ | 271 | | | $ | 278 | | | $ | (7) | | (3) | % | | $ | 418 | | | $ | 449 | | | $ | (31) | | (7) | % | Operating income | | $ | 113 | | | $ | 118 | | | $ | (5) | | (4) | % | | $ | 135 | | | $ | 147 | | | $ | (12) | | (8) | % |
Utility Margin
A comparison of key operating results related to utility margin is as follows:
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | | Utility margin (in millions): | | | | | | | | | | | | |
| Operating revenue | Operating revenue | | $ | 802 | | | $ | 808 | | | $ | (6) | | (1) | % | | $ | 1,731 | | | $ | 1,706 | | | $ | 25 | | 1 | % | Operating revenue | | $ | 639 | | | $ | 559 | | | $ | 80 | | 14 | % | | $ | 1,054 | | | $ | 929 | | | $ | 125 | | 13 | % |
| Cost of fuel and energy | Cost of fuel and energy | | 328 | | | 287 | | | 41 | | 14 | | | 745 | | | 654 | | | 91 | | 14 | | Cost of fuel and energy | | 336 | | | 252 | | | 84 | | 33 | | | 548 | | | 417 | | | 131 | | 31 | |
| Utility margin | Utility margin | | $ | 474 | | | $ | 521 | | | $ | (47) | | (9) | % | | $ | 986 | | | $ | 1,052 | | | $ | (66) | | (6) | % | Utility margin | | $ | 303 | | | $ | 307 | | | $ | (4) | | (1) | % | | $ | 506 | | | $ | 512 | | | $ | (6) | | (1) | % |
| | Sales (GWhs): | Sales (GWhs): | | Sales (GWhs): | |
| Residential | Residential | | 4,343 | | | 4,378 | | | (35) | | (1) | % | | 8,737 | | | 8,557 | | | 180 | | 2 | % | Residential | | 2,612 | | | 2,807 | | | (195) | | (7) | % | | 4,197 | | | 4,394 | | | (197) | | (4) | % |
| Commercial | Commercial | | 1,568 | | | 1,471 | | | 97 | | 7 | | | 3,793 | | | 3,553 | | | 240 | | 7 | | Commercial | | 1,272 | | | 1,271 | | | 1 | | — | | | 2,270 | | | 2,225 | | | 45 | | 2 | |
| Industrial | Industrial | | 1,611 | | | 1,477 | | | 134 | | 9 | | | 3,978 | | | 3,735 | | | 243 | | 7 | | Industrial | | 1,409 | | | 1,310 | | | 99 | | 8 | | | 2,584 | | | 2,367 | | | 217 | | 9 | |
| Other | Other | | 52 | | | 48 | | | 4 | | 8 | | | 144 | | | 142 | | | 2 | | 1 | | Other | | 46 | | | 45 | | | 1 | | 2 | | | 92 | | | 92 | | | — | | — | |
Total fully bundled(1) | Total fully bundled(1) | | 7,574 | | | 7,374 | | | 200 | | 3 | | | 16,652 | | | 15,987 | | | 665 | | 4 | | Total fully bundled(1) | | 5,339 | | | 5,433 | | | (94) | | (2) | | | 9,143 | | | 9,078 | | | 65 | | 1 | |
| Distribution only service | Distribution only service | | 787 | | | 664 | | | 123 | | 19 | | | 1,923 | | | 1,776 | | | 147 | | 8 | | Distribution only service | | 661 | | | 620 | | | 41 | | 7 | | | 1,230 | | | 1,136 | | | 94 | | 8 | |
| Total retail | Total retail | | 8,361 | | | 8,038 | | | 323 | | 4 | | | 18,575 | | | 17,763 | | | 812 | | 5 | | Total retail | | 6,000 | | | 6,053 | | | (53) | | (1) | | | 10,373 | | | 10,214 | | | 159 | | 2 | |
| Wholesale | Wholesale | | 93 | | | 82 | | | 11 | | 13 | | | 266 | | | 316 | | | (50) | | (16) | | Wholesale | | 210 | | | 89 | | | 121 | | * | | 335 | | | 173 | | | 162 | | 94 | |
| Total GWhs sold | Total GWhs sold | | 8,454 | | | 8,120 | | | 334 | | 4 | % | | 18,841 | | | 18,079 | | | 762 | | 4 | % | Total GWhs sold | | 6,210 | | | 6,142 | | | 68 | | 1 | % | | 10,708 | | | 10,387 | | | 321 | | 3 | % |
| | Average number of retail customers (in thousands) | Average number of retail customers (in thousands) | | 988 | | | 970 | | | 18 | | 2 | % | | 983 | | | 966 | | | 17 | | 2 | % | Average number of retail customers (in thousands) | | 1,000 | | | 982 | | | 18 | | 2 | % | | 997 | | | 980 | | | 17 | | 2 | % |
| | | Average revenue per MWh: | Average revenue per MWh: | | Average revenue per MWh: | |
Retail - fully bundled(1) | Retail - fully bundled(1) | | $ | 100.56 | | | $ | 104.72 | | | $ | (4.16) | | (4) | % | | $ | 98.54 | | | $ | 101.21 | | | $ | (2.67) | | (3) | % | Retail - fully bundled(1) | | $ | 114.36 | | | $ | 98.10 | | | $ | 16.26 | | 17 | % | | $ | 109.26 | | | $ | 96.86 | | | $ | 12.40 | | 13 | % |
| | Wholesale | Wholesale | | $ | 90.60 | | | $ | 78.36 | | | $ | 12.24 | | 16 | % | | $ | 61.65 | | | $ | 41.28 | | | $ | 20.37 | | 49 | % | Wholesale | | $ | 34.36 | | | $ | 42.94 | | | $ | (8.58) | | (20) | % | | $ | 37.55 | | | $ | 46.09 | | | $ | (8.54) | | (19) | % |
| | Heating degree days | Heating degree days | | — | | | — | | | — | | — | | 1,008 | | | 984 | | | 24 | | 2 | % | Heating degree days | | 31 | | | 14 | | | 17 | | * | | 985 | | | 1,008 | | | (23) | | (2) | % |
| Cooling degree days | Cooling degree days | | 2,447 | | | 2,537 | | | (90) | | (4) | % | | 3,930 | | | 3,847 | | | 83 | | 2 | % | Cooling degree days | | 1,322 | | | 1,477 | | | (155) | | (10) | % | | 1,371 | | | 1,483 | | | (112) | | (8) | % |
| Sources of energy (GWhs)(2)(3): | Sources of energy (GWhs)(2)(3): | | Sources of energy (GWhs)(2)(3): | |
| Natural gas | Natural gas | | 4,776 | | | 4,888 | | | (112) | | (2) | % | | 10,857 | | | 10,628 | | | 229 | | 2 | % | Natural gas | | 2,935 | | | 3,547 | | | (612) | | (17) | % | | 5,313 | | | 6,081 | | | (768) | | (13) | % |
| | Renewables | Renewables | | 19 | | | 18 | | | 1 | | 6 | | | 55 | | | 54 | | | 1 | | 2 | | Renewables | | 20 | | | 20 | | | — | | — | | | 34 | | | 36 | | | (2) | | (6) | |
| Total energy generated | Total energy generated | | 4,795 | | | 4,906 | | | (111) | | (2) | | | 10,912 | | | 10,682 | | | 230 | | 2 | | Total energy generated | | 2,955 | | | 3,567 | | | (612) | | (17) | | | 5,347 | | | 6,117 | | | (770) | | (13) | |
| Energy purchased | Energy purchased | | 2,727 | | | 2,366 | | | 361 | | 15 | | | 6,186 | | | 5,532 | | | 654 | | 12 | | Energy purchased | | 2,472 | | | 2,104 | | | 368 | | 17 | | | 4,233 | | | 3,459 | | | 774 | | 22 | |
| Total | Total | | 7,522 | | | 7,272 | | | 250 | | 3 | % | | 17,098 | | | 16,214 | | | 884 | | 5 | % | Total | | 5,427 | | | 5,671 | | | (244) | | (4) | % | | 9,580 | | | 9,576 | | | 4 | | — | % |
| Average cost of energy per MWh(4): | Average cost of energy per MWh(4): | | Average cost of energy per MWh(4): | |
| Energy generated | Energy generated | | $ | 24.71 | | | $ | 11.83 | | | $ | 12.88 | | * | | $ | 21.49 | | | $ | 16.00 | | | $ | 5.49 | | 34 | % | Energy generated | | $ | 49.65 | | | $ | 21.82 | | | $ | 27.83 | | * | | $ | 46.19 | | | $ | 18.96 | | | $ | 27.23 | | * |
| Energy purchased | Energy purchased | | $ | 76.77 | | | $ | 96.51 | | | $ | (19.74) | | (20) | % | | $ | 82.53 | | | $ | 87.27 | | | $ | (4.74) | | (5) | % | Energy purchased | | $ | 76.63 | | | $ | 82.70 | | | $ | (6.07) | | (7) | % | | $ | 71.07 | | | $ | 87.07 | | | $ | (16.00) | | (18) | % |
* Not meaningful
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The average cost of energy per MWh and sources of energy excludes 163360 GWhs and 152249 GWhs of gas generated energy that is purchased at cost by related parties for the thirdsecond quarter of 20212022 and 2020,2021, respectively. The average cost of energy per MWh and sources of energy excludes 1,095784 GWhs and 1,180932 GWhs of gas generated energy that is purchased at cost by related parties for the first ninesix months of 20212022 and 2020,2021, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals and does not include other costs.deferrals.
Quarter Ended SeptemberJune 30, 20212022 Compared to Quarter Ended SeptemberJune 30, 20202021
Utility margin decreased $47$4 million, or 9%1%, for the thirdsecond quarter of 20212022 compared to 20202021 primarily due to:
•$277 million of lower electric retail ratesutility margin due to the 2020 regulatory rate review with new rates effective January 2021,
•$20 million of lower revenue recognized due to a favorable regulatory decision in 2020,
•$3 million due tounfavorable price impacts from changes in sales mix.mix and lower retail customer volumes. Retail customer volumes, including distribution only service customers, increased 4.0%decreased 0.9% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and favorable changes in customer usage patterns, offset by the unfavorable impact of weather,patterns;
•$3 million due toof lower energy efficiency program rates (offset in operations and maintenance expense); and
•$1 million of lower other revenue due to a regulatory amortization of an impact fee that ended December 2020.retail revenue.
The decrease in utility margin was offset by:
•$57 million of higher transmissionregulatory-related revenue and
•$3 million due to an increase in the average number of customers, primarily from the residential customer class.deferrals.
Operations and maintenance decreased $51$2 million, or 37%3%, for the thirdsecond quarter of 20212022 compared to 20202021 primarily due to lower earnings sharing, lower net regulatory instructed deferrals and amortizations, mainly relating to deferrals in 2020 of the non-labor cost savings from the Navajo generating station retirement which was approved for amortization in the 2020 regulatory rate review with new rates effective January 2021, and timing of the regulatory impacts for the ON Line lease cost reallocation, costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation and lower energy efficiency program costs (offset in operating revenue). and lower plant operations and maintenance expenses, partially offset by higher earnings sharing.
Depreciation and amortization increased $11$3 million, or 12%3%, for the thirdsecond quarter of 20212022 compared to 20202021 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.
Interest expense decreased $2 million, or 5%, for the third quarter of 2021 compared to 2020 primarily due to lower carrying charges on regulatory balances.in-service.
Interest and dividend income increased $2$6 million or 67%, for the thirdsecond quarter of 20212022 compared to 20202021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $1is unfavorable $7 million or 33%, for the thirdsecond quarter of 20212022 compared to 20202021 primarily due to lower pension expense, partially offset by lower cash surrender value of corporate-owned life insurance policies.
Income tax expense decreased $25 million, or 48%, for the third quarter of 2021 compared to 2020. The effective tax rate was 11% in 2021 and 21% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.
First NineSix Months Ended SeptemberJune 30, 20212022 Compared to First NineSix Months Ended SeptemberJune 30, 2020
Utility margin decreased $66$6 million, or 6%1%, for the first ninesix months of 20212022 compared to 20202021 primarily due to:
•$515 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,
•$20 million of lower revenue recognized due to a favorable regulatory decision in 2020,
•$7 million due to lower energy efficiency program rates (offset in operations and maintenance expense),;
•$64 million of lower electric retail utility margin due to unfavorable price impacts from changes in sales mix, offset by higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 1.6% primarily due to an adjustment to regulatory-related revenue deferralsincrease in the average number of customers and favorable changes in customer usage patterns, offset by the unfavorable impact of weather; and
•$3 million due to a regulatory amortization of an impact fee that ended December 2020.lower other retail revenue.
The decrease in utility margin was offset by:
•$11 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 4.6% primarily due to favorable changes in customer usage patterns and the favorable impact of weather,
•$5 million due to an increase in the average number of customers, primarily from the residential customer classhigher regulatory-related revenue deferrals; and
•$51 million of higher transmission and wholesale revenue.
Operations and maintenance decreased $67 million, or 23%,was consistent for the first ninesix months of 20212022 compared to 20202021 primarily due to lower net regulatory instructed deferralshigher earnings sharing and amortizations, mainly relating to deferrals in 2020 of the non-labor cost savings from the Navajo generating station retirement which was approved for amortization in the 2020 regulatory rate review with new rates effective January 2021,higher plant operations and timing of the regulatory impacts for the ON Line lease cost reallocation, lower earnings sharing,maintenance expenses, offset by lower energy efficiency program costs (offset in operating revenue) and costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation..
Depreciation and amortization increased $31$5 million, or 11%2%, for the first ninesix months of 20212022 compared to 20202021 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.
Interest expense decreased $7 million, or 6%, for the first nine months of 2021 compared to 2020 primarily due to lower carrying charges on regulatory balances of $5 million and lower interest expense on long-term debt.in-service.
Interest and dividend income increased $5$10 million or 63%, for the first ninesix months of 20212022 compared to 20202021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increasedis unfavorable $10 million for the first ninesix months of 20212022 compared to 20202021 primarily due to lower pension expense of $6 million and higher cash surrender value of corporate-owned life insurance policies.
Income tax expense decreased $38 million, or (51)%, for the first nine months of 2021 compared to 2020. The effective tax rate was 11% in 2021 and 21% in 2020 and decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.
Liquidity and Capital Resources
As of SeptemberJune 30, 2021,2022, Nevada Power's total net liquidity was as follows (in millions):
| | | | | | | | |
| Cash and cash equivalents | | $ | 8542 | |
| Credit facility | | 400 | |
| | |
| | |
| Total net liquidity | | 442 | |
| | |
Total net liquidity | | $ | 485 | |
| Credit facility: | | |
| Maturity date | | 20242025 |
Operating Activities
Net cash flows from operating activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $405$224 million and $406$310 million, respectively. The change was primarily due to higher payments related to fuel and energy costs and the timing of payments for fuel and energyoperating costs, and higher payments for income taxes, partially offset by higher collections from customers timing ofand lower payments for operating costs, increased collections of customer advances and lower inventory purchases.income taxes.
Investing Activities
Net cash flows from investing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $(322)$(350) million and $(317)$(237) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $(25)$136 million and $46$(21) million, respectively. The change was primarily due to lowerhigher proceeds from the issuance of long-term debt and contributions from NV Energy, Inc., partially offset by lowerhigher repayments of long-term debtshort-term debt.
Long-Term Debt
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. In May 2022, Nevada Power drew the remaining $100 million available under the facility at an initial interest rate of 1.24%. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and lower dividends paid to NV Energy, Inc.for general corporate purposes.
Debt Authorizations
Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $3.2$3.8 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective automatic shelf registration statement with the SEC to issue an indeterminate amount of general and refunding mortgage securities through October 2022.
Future Uses of Cash
Nevada Power has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including regulatory approvals, Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
| | | Nine-Month Periods | | Annual | | Six-Month Periods | | Annual |
| | Ended September 30, | | Forecast | | Ended June 30, | | Forecast |
| | 2020 | | 2021 | | 2021 | | 2021 | | 2022 | | 2022 |
| | Electric distribution | Electric distribution | $ | 182 | | | $ | 137 | | | $ | 194 | | Electric distribution | $ | 87 | | | $ | 108 | | | $ | 234 | |
| Electric transmission | Electric transmission | 27 | | | 38 | | | 67 | | Electric transmission | 25 | | | 39 | | | 141 | |
| Solar generation | Solar generation | — | | | 7 | | | 21 | | Solar generation | 5 | | | 23 | | | 90 | |
| Other | Other | 134 | | | 141 | | | 208 | | Other | 120 | | | 180 | | | 359 | |
| Total | Total | $ | 343 | | | $ | 323 | | | $ | 490 | | Total | $ | 237 | | | $ | 350 | | | $ | 824 | |
Nevada Power's approved Fourth Amendment to the 2018 JointPower received PUCN approval through its recent IRP includedfilings for an increase in solar generation and electric transmission. Nevada Power has included estimates from its latest IRP filing in its forecast capital expenditures for 2021.2022. These estimates may change as a result of the RFP process. Nevada Power's historical and forecast capital expenditures include the following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program of which costs are split 70% to Nevada Power and 30% to Sierra Pacific.program. In this project, the company proposedhas received approval from the PUCN to build a 350-mile, 525 kV525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation. Construction of the project was approved by the PUCN in the Fourth Amendment to the 2018 Joint IRP with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. In addition, and as instructed in Senate Bill 448 and submitted in the company's amendment to the 2021 Joint IRP, the company proposed to buildsubstation; a 235-mile, 525 kV525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345 kV345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345 kV345-kV transmission line from the new Ft. Churchill substation to the Comstock Meadows substations and the Northwest substation to Harry Allen substation segment of Greenlink West.Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Solar generation investment includes expenditures for a 150 MWs150-MW solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage known as the Dry Lake generating facility, that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Other investments includeincludes both growth projects and operating expenditures consisting of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Contractual ObligationsMaterial Cash Requirements
As of SeptemberJune 30, 2021,2022, there have been no material changes outside the normal course of business in contractual obligationscash requirements from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2020.
Regulatory Matters
Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Nevada Power's current regulatory matters.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations, and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various federal, state and local agencies. All suchNevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to a range of interpretation whichthat may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Nevada Power believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2020.2021. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2020.2021.
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of SeptemberJune 30, 2021,2022, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and of cash flows for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Sierra Pacific as of December 31, 2020,2021, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021,25, 2022, 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, 2020,2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Sierra Pacific's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
NovemberAugust 5, 20212022
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 14 | | | $ | 19 | | Cash and cash equivalents | $ | 17 | | | $ | 10 | |
| Trade receivables, net | Trade receivables, net | 118 | | | 97 | | Trade receivables, net | 127 | | | 128 | |
| | Inventories | Inventories | 68 | | | 77 | | Inventories | 75 | | | 65 | |
| | Regulatory assets | Regulatory assets | 168 | | | 67 | | Regulatory assets | 207 | | | 177 | |
| | Other current assets | Other current assets | 48 | | | 45 | | Other current assets | 25 | | | 35 | |
| Total current assets | Total current assets | 416 | | | 305 | | Total current assets | 451 | | | 415 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 3,265 | | | 3,164 | | Property, plant and equipment, net | 3,476 | | | 3,340 | |
| | Regulatory assets | Regulatory assets | 265 | | | 267 | | Regulatory assets | 282 | | | 263 | |
| Other assets | Other assets | 184 | | | 183 | | Other assets | 206 | | | 205 | |
| | Total assets | Total assets | $ | 4,130 | | | $ | 3,919 | | Total assets | $ | 4,415 | | | $ | 4,223 | |
| | LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 121 | | | $ | 108 | | Accounts payable | $ | 177 | | | $ | 147 | |
| Accrued interest | 11 | | | 14 | | |
| | Accrued property, income and other taxes | Accrued property, income and other taxes | 18 | | | 14 | | Accrued property, income and other taxes | 18 | | | 16 | |
| Short-term debt | Short-term debt | 127 | | | 45 | | Short-term debt | — | | | 159 | |
| | Regulatory liabilities | Regulatory liabilities | 23 | | | 34 | | Regulatory liabilities | 18 | | | 19 | |
| Customer deposits | Customer deposits | 15 | | | 15 | | Customer deposits | 16 | | | 15 | |
| Derivative contracts | | Derivative contracts | 38 | | | 16 | |
| Other current liabilities | Other current liabilities | 31 | | | 25 | | Other current liabilities | 48 | | | 42 | |
| Total current liabilities | Total current liabilities | 346 | | | 255 | | Total current liabilities | 315 | | | 414 | |
| | Long-term debt | Long-term debt | 1,164 | | | 1,164 | | Long-term debt | 1,148 | | | 1,164 | |
| Finance lease obligations | 116 | | | 121 | | |
| | Regulatory liabilities | Regulatory liabilities | 446 | | | 463 | | Regulatory liabilities | 435 | | | 444 | |
| Deferred income taxes | Deferred income taxes | 396 | | | 374 | | Deferred income taxes | 413 | | | 402 | |
| Other long-term liabilities | Other long-term liabilities | 144 | | | 131 | | Other long-term liabilities | 258 | | | 264 | |
| Total liabilities | Total liabilities | 2,612 | | | 2,508 | | Total liabilities | 2,569 | | | 2,688 | |
| | Commitments and contingencies (Note 8) | 0 | | 0 | |
| Commitments and contingencies (Note 9) | | Commitments and contingencies (Note 9) | 0 | | 0 |
| | Shareholder's equity: | Shareholder's equity: | | Shareholder's equity: | |
| Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — | | | — | | Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — | | | — | |
| Additional paid-in capital | Additional paid-in capital | 1,111 | | | 1,111 | | Additional paid-in capital | 1,451 | | | 1,111 | |
| Retained earnings | Retained earnings | 408 | | | 301 | | Retained earnings | 396 | | | 425 | |
| Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | (1) | | | (1) | | Accumulated other comprehensive loss, net | (1) | | | (1) | |
| Total shareholder's equity | Total shareholder's equity | 1,518 | | | 1,411 | | Total shareholder's equity | 1,846 | | | 1,535 | |
| | Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 4,130 | | | $ | 3,919 | | Total liabilities and shareholder's equity | $ | 4,415 | | | $ | 4,223 | |
| | The accompanying notes are an integral part of the consolidated financial statements. | The accompanying notes are an integral part of the consolidated financial statements. | The accompanying notes are an integral part of the consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | | | | |
| Regulated electric | Regulated electric | $ | 266 | | | $ | 220 | | | $ | 636 | | | $ | 569 | | Regulated electric | $ | 230 | | | $ | 189 | | | $ | 457 | | | $ | 370 | |
| Regulated natural gas | Regulated natural gas | 16 | | | 15 | | | 75 | | | 83 | | Regulated natural gas | 28 | | | 20 | | | 80 | | | 59 | |
| Total operating revenue | Total operating revenue | 282 | | | 235 | | | 711 | | | 652 | | Total operating revenue | 258 | | | 209 | | | 537 | | | 429 | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | |
| Cost of fuel and energy | Cost of fuel and energy | 120 | | | 81 | | | 295 | | | 233 | | Cost of fuel and energy | 129 | | | 93 | | | 253 | | | 175 | |
| Cost of natural gas purchased for resale | Cost of natural gas purchased for resale | 6 | | | 4 | | | 35 | | | 44 | | Cost of natural gas purchased for resale | 16 | | | 8 | | | 50 | | | 29 | |
| Operations and maintenance | Operations and maintenance | 40 | | | 40 | | | 117 | | | 123 | | Operations and maintenance | 47 | | | 41 | | | 88 | | | 77 | |
| Depreciation and amortization | Depreciation and amortization | 35 | | | 36 | | | 107 | | | 104 | | Depreciation and amortization | 37 | | | 36 | | | 73 | | | 72 | |
| Property and other taxes | Property and other taxes | 6 | | | 6 | | | 18 | | | 17 | | Property and other taxes | 6 | | | 6 | | | 12 | | | 12 | |
| Total operating expenses | Total operating expenses | 207 | | | 167 | | | 572 | | | 521 | | Total operating expenses | 235 | | | 184 | | | 476 | | | 365 | |
| | Operating income | Operating income | 75 | | | 68 | | | 139 | | | 131 | | Operating income | 23 | | | 25 | | | 61 | | | 64 | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | |
| Interest expense | Interest expense | (14) | | | (14) | | | (41) | | | (42) | | Interest expense | (14) | | | (13) | | | (27) | | | (27) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 1 | | | — | | | 2 | | | 1 | | Allowance for borrowed funds | — | | | 1 | | | 1 | | | 1 | |
| Allowance for equity funds | Allowance for equity funds | 2 | | | 1 | | | 5 | | | 3 | | Allowance for equity funds | 2 | | | 2 | | | 4 | | | 3 | |
| Interest and dividend income | Interest and dividend income | 3 | | | 1 | | | 6 | | | 3 | | Interest and dividend income | 4 | | | 1 | | | 7 | | | 3 | |
| Other, net | Other, net | 3 | | | 2 | | | 9 | | | 4 | | Other, net | — | | | 2 | | | 2 | | | 6 | |
| Total other income (expense) | Total other income (expense) | (5) | | | (10) | | | (19) | | | (31) | | Total other income (expense) | (8) | | | (7) | | | (13) | | | (14) | |
| | Income before income tax expense | Income before income tax expense | 70 | | | 58 | | | 120 | | | 100 | | Income before income tax expense | 15 | | | 18 | | | 48 | | | 50 | |
| Income tax expense | Income tax expense | 8 | | | 6 | | | 13 | | | 10 | | Income tax expense | 2 | | | 1 | | | 7 | | | 5 | |
| Net income | Net income | $ | 62 | | | $ | 52 | | | $ | 107 | | | $ | 90 | | Net income | $ | 13 | | | $ | 17 | | | $ | 41 | | | $ | 45 | |
| | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
| | | Accumulated | | | Accumulated | |
| | Additional | | Other | | Total | | Additional | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's | | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity | | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
| | Balance, June 30, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 228 | | | $ | (1) | | | $ | 1,338 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 329 | | | $ | (1) | | | $ | 1,439 | |
| Net income | Net income | | — | | | — | | | — | | | 52 | | | — | | | 52 | | Net income | | — | | | — | | | — | | | 17 | | | — | | | 17 | |
| | Balance, September 30, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 280 | | | $ | (1) | | | $ | 1,390 | | |
| | Balance, December 31, 2019 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 210 | | | $ | (1) | | | $ | 1,320 | | |
| Net income | | — | | | — | | | — | | | 90 | | | — | | | 90 | | |
| Dividends declared | | — | | | — | | | — | | | (20) | | | — | | | (20) | | |
| | Balance, September 30, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 280 | | | $ | (1) | | | $ | 1,390 | | |
| | Balance, June 30, 2021 | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 346 | | | $ | (1) | | | $ | 1,456 | | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 346 | | | $ | (1) | | | $ | 1,456 | |
| Net income | | — | | | — | | | — | | | 62 | | | — | | | 62 | | |
| | Balance, September 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 408 | | | $ | (1) | | | $ | 1,518 | | |
| | Balance, December 31, 2020 | Balance, December 31, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 301 | | | $ | (1) | | | $ | 1,411 | | Balance, December 31, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 301 | | | $ | (1) | | | $ | 1,411 | |
| Net income | Net income | | — | | | — | | | — | | | 107 | | | — | | | 107 | | Net income | | — | | | — | | | — | | | 45 | | | — | | | 45 | |
| | Balance, September 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 408 | | | $ | (1) | | | $ | 1,518 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 346 | | | $ | (1) | | | $ | 1,456 | |
| | Balance, March 31, 2022 | | Balance, March 31, 2022 | | 1,000 | | | $ | — | | | $ | 1,241 | | | $ | 453 | | | $ | (1) | | | $ | 1,693 | |
| Net income | | Net income | | — | | | — | | | — | | | 13 | | | — | | | 13 | |
| Dividends declared | | Dividends declared | | — | | | — | | | — | | | (70) | | | — | | | (70) | |
| Contributions | | Contributions | | — | | | — | | | 210 | | | — | | | — | | | 210 | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | | 1,000 | | | $ | — | | | $ | 1,451 | | | $ | 396 | | | $ | (1) | | | $ | 1,846 | |
| | Balance, December 31, 2021 | | Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 425 | | | $ | (1) | | | $ | 1,535 | |
| Net income | | Net income | | — | | | — | | | — | | | 41 | | | — | | | 41 | |
| Dividends declared | | Dividends declared | | — | | | — | | | — | | | (70) | | | — | | | (70) | |
| Contributions | | Contributions | | — | | | — | | | 340 | | | — | | | — | | | 340 | |
| | Balance, June 30, 2022 | | Balance, June 30, 2022 | | 1,000 | | | $ | — | | | $ | 1,451 | | | $ | 396 | | | $ | (1) | | | $ | 1,846 | |
| | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | Nine-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 107 | | | $ | 90 | | Net income | $ | 41 | | | $ | 45 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | Adjustments to reconcile net income to net cash flows from operating activities: | | Adjustments to reconcile net income to net cash flows from operating activities: | |
| | Depreciation and amortization | Depreciation and amortization | 107 | | | 104 | | Depreciation and amortization | 73 | | | 72 | |
| Allowance for equity funds | Allowance for equity funds | (5) | | | (3) | | Allowance for equity funds | (4) | | | (3) | |
| Changes in regulatory assets and liabilities | Changes in regulatory assets and liabilities | (30) | | | (30) | | Changes in regulatory assets and liabilities | (8) | | | (20) | |
| Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 10 | | | 3 | | Deferred income taxes and amortization of investment tax credits | 5 | | | 8 | |
| Deferred energy | Deferred energy | (95) | | | (5) | | Deferred energy | (67) | | | (47) | |
| Amortization of deferred energy | Amortization of deferred energy | 12 | | | (6) | | Amortization of deferred energy | 46 | | | 2 | |
| Other, net | Other, net | (1) | | | — | | Other, net | 2 | | | (2) | |
| Changes in other operating assets and liabilities: | Changes in other operating assets and liabilities: | | Changes in other operating assets and liabilities: | |
| Trade receivables and other assets | Trade receivables and other assets | (25) | | | (83) | | Trade receivables and other assets | (1) | | | (1) | |
| Inventories | Inventories | 9 | | | (18) | | Inventories | (10) | | | 10 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 3 | | | 8 | | Accrued property, income and other taxes | 3 | | | (1) | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 21 | | | 119 | | Accounts payable and other liabilities | 28 | | | 29 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 113 | | | 179 | | Net cash flows from operating activities | 108 | | | 92 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (196) | | | (192) | | Capital expenditures | (191) | | | (128) | |
| | Net cash flows from investing activities | Net cash flows from investing activities | (196) | | | (192) | | Net cash flows from investing activities | (191) | | | (128) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| Proceeds from long-term debt | Proceeds from long-term debt | — | | | 30 | | Proceeds from long-term debt | 249 | | | — | |
| Net proceeds from short-term debt | 82 | | | — | | |
| | Long-term debt reacquired | | Long-term debt reacquired | (265) | | | — | |
| Net (repayment of) proceeds from short-term debt | | Net (repayment of) proceeds from short-term debt | (159) | | | 29 | |
| Dividends paid | Dividends paid | — | | | (20) | | Dividends paid | (70) | | | — | |
| Contributions from parent | | Contributions from parent | 340 | | | — | |
| Other, net | Other, net | (5) | | | (3) | | Other, net | (4) | | | (4) | |
| Net cash flows from financing activities | Net cash flows from financing activities | 77 | | | 7 | | Net cash flows from financing activities | 91 | | | 25 | |
| | Net change in cash and cash equivalents and restricted cash and cash equivalents | Net change in cash and cash equivalents and restricted cash and cash equivalents | (6) | | | (6) | | Net change in cash and cash equivalents and restricted cash and cash equivalents | 8 | | | (11) | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 26 | | | 32 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 16 | | | 26 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 20 | | | $ | 26 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 24 | | | $ | 15 | |
| | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. | The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Sierra Pacific Power Company, together with its subsidiaries ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United StatesU.S. regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of SeptemberJune 30, 20212022 and for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020.2021. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020.2021. The results of operations for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 20202021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Sierra Pacific's assumptions regarding significant accounting estimates and policies during the nine-monthsix-month period ended SeptemberJune 30, 2021.2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United StatesU.S. Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2021 and December 31, 2020, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of 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 | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash and cash equivalents | Cash and cash equivalents | $ | 14 | | | $ | 19 | | Cash and cash equivalents | $ | 17 | | | $ | 10 | |
| Restricted cash and cash equivalents included in other current assets | Restricted cash and cash equivalents included in other current assets | 6 | | | 7 | | Restricted cash and cash equivalents included in other current assets | 7 | | | 6 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 20 | | | $ | 26 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 24 | | | $ | 16 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | As of | | As of |
| | Depreciable Life | | September 30, | | December 31, | | Depreciable Life | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Utility plant: | Utility plant: | | | | | | Utility plant: | | | | | |
| Electric generation | Electric generation | 25 - 60 years | | $ | 1,140 | | | $ | 1,130 | | Electric generation | 25 - 60 years | | $ | 1,297 | | | $ | 1,163 | |
| Electric transmission | Electric transmission | 50 - 100 years | | 914 | | | 908 | | Electric transmission | 50 - 100 years | | 976 | | | 940 | |
| Electric distribution | Electric distribution | 20 - 100 years | | 1,806 | | | 1,754 | | Electric distribution | 20 - 100 years | | 1,905 | | | 1,846 | |
| Electric general and intangible plant | Electric general and intangible plant | 5 - 70 years | | 199 | | | 189 | | Electric general and intangible plant | 5 - 70 years | | 213 | | | 204 | |
| Natural gas distribution | Natural gas distribution | 35 - 70 years | | 433 | | | 429 | | Natural gas distribution | 35 - 70 years | | 447 | | | 438 | |
| Natural gas general and intangible plant | Natural gas general and intangible plant | 5 - 70 years | | 15 | | | 15 | | Natural gas general and intangible plant | 5 - 70 years | | 15 | | | 14 | |
| Common general | Common general | 5 - 70 years | | 361 | | | 355 | | Common general | 5 - 70 years | | 376 | | | 370 | |
| Utility plant | Utility plant | | 4,868 | | | 4,780 | | Utility plant | | 5,229 | | | 4,975 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (1,834) | | | (1,755) | | Accumulated depreciation and amortization | | (1,936) | | | (1,854) | |
| Utility plant, net | Utility plant, net | | 3,034 | | | 3,025 | | Utility plant, net | | 3,293 | | | 3,121 | |
| Other non-regulated, net of accumulated depreciation and amortization | 70 years | | — | | | 2 | | |
| Plant, net | | 3,034 | | | 3,027 | | |
| | Construction work-in-progress | Construction work-in-progress | | 231 | | | 137 | | Construction work-in-progress | | 183 | | | 219 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 3,265 | | | $ | 3,164 | | Property, plant and equipment, net | | $ | 3,476 | | | $ | 3,340 | |
(4) Recent Financing Transactions
Long-Term Debt
In June 2022, Sierra Pacific purchased $60 million of its variable-rate tax-exempt Gas & Water Facilities Refunding Revenue Bonds, Series 2016B, due 2036, as required by the bond indenture. Sierra Pacific is holding this bond and can re-offer it at a future date.
In May 2022, Sierra Pacific issued $250 million of 4.71% General and Refunding Mortgage bonds, Series W, due 2052. The net proceeds were used to repay the outstanding $200 million unsecured loan with NV Energy, Inc., repay amounts outstanding under its existing revolving credit facility and for general corporate purposes.
In April 2022, Sierra Pacific entered into a $200 million unsecured loan with NV Energy payable upon demand. The net proceeds were used to purchase certain tax-exempt refunding revenue bond obligations that were subject to mandatory purchase by Sierra Pacific in April 2022. The loan has an underlying variable interest rate based on 30-day U.S. dollar deposits offered on the London Interbank Offer Rate ("LIBOR") market plus a spread of 0.75%.
In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.
Credit Facilities
In June 2021,2022, Sierra Pacific amended and restated its existing $250 million secured credit facility expiring in June 2022 with no remaining one-year extension options.2024. The amendment extended the expiration date to June 20242025 and increasedamended pricing from LIBOR to the available maturity extension options to an unlimited number, subject to lender consent.Secured Overnight Financing Rate.
(5) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| Effects of ratemaking | Effects of ratemaking | (10) | | | (11) | | | (10) | | | (10) | | Effects of ratemaking | (8) | | | (11) | | | (7) | | | (9) | |
| | Income tax credits | | Income tax credits | — | | | (1) | | | — | | | — | |
| | Other | Other | — | | | — | | | — | | | (1) | | Other | — | | | (3) | | | 1 | | | (2) | |
| Effective income tax rate | Effective income tax rate | 11 | % | | 10 | % | | 11 | % | | 10 | % | Effective income tax rate | 13 | % | | 6 | % | | 15 | % | | 10 | % |
Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2020.
147Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for federal income tax has been computed on a separate return basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the six-month periods ended June 30, 2022 and 2021, Sierra Pacific made no net cash payments for federal income tax to BHE.
(6) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific contributed $1$2 million to the Other Postretirement Plans for the nine-monthsix-month period ended SeptemberJune 30, 2021.2022. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
| | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Qualified Pension Plan: | Qualified Pension Plan: | | | | Qualified Pension Plan: | | | |
| | Other non-current assets | Other non-current assets | $ | 31 | | | $ | 26 | | Other non-current assets | $ | 64 | | | $ | 62 | |
| | | Non-Qualified Pension Plans: | Non-Qualified Pension Plans: | | Non-Qualified Pension Plans: | |
| | Other current liabilities | Other current liabilities | (1) | | | (1) | | Other current liabilities | (1) | | | (1) | |
| Other long-term liabilities | Other long-term liabilities | (8) | | | (8) | | Other long-term liabilities | (7) | | | (7) | |
| | Other Postretirement Plans: | Other Postretirement Plans: | | Other Postretirement Plans: | |
| | Other long-term liabilities | Other long-term liabilities | (13) | | | (13) | | Other long-term liabilities | (8) | | | (10) | |
(7)Risk Management and Hedging Activities
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.
Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Sierra Pacific's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Derivative | | | | |
| Other | | | | Contracts - | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
| As of June 30, 2022 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
| Commodity assets | $ | — | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | |
| Commodity liabilities | — | | | — | | | (38) | | | (17) | | | (55) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total derivative - net basis | $ | — | | | $ | 1 | | | $ | (38) | | | $ | (17) | | | $ | (54) | |
| | | | | | | | | |
| As of December 31, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
| Commodity assets | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2 | |
| Commodity liabilities | — | | | — | | | (16) | | | (19) | | | (35) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total derivative - net basis | $ | 2 | | | $ | — | | | $ | (16) | | | $ | (19) | | | $ | (33) | |
(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2022 a net regulatory asset of $54 million was recorded related to the net derivative liability of $54 million. As of December 31, 2021 a net regulatory asset of $33 million was recorded related to the net derivative liability of $33 million.
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | June 30, | | December 31, |
| Measure | | 2022 | | 2021 |
| | | | | |
| Electricity purchases | Megawatt hours | | 1 | | | 1 | |
| Natural gas purchases | Decatherms | | 50 | | | 53 | |
| | | | | |
Credit Risk
Sierra Pacific is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2022, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.
The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $— million as of June 30, 2022 and December 31, 2021, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(7)(8) Fair Value Measurements
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.
The following table presents Sierra Pacific's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | Input Levels for Fair Value Measurements | | | Input Levels for Fair Value Measurements | |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| As of September 30, 2021 | | | | | | | | |
| As of June 30, 2022: | | As of June 30, 2022: | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | Commodity derivatives | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | |
| Money market mutual funds | Money market mutual funds | 11 | | | — | | | — | | | 11 | | Money market mutual funds | 14 | | | — | | | — | | | 14 | |
| Investment funds | Investment funds | 1 | | | — | | | — | | | 1 | | Investment funds | 1 | | | — | | | — | | | 1 | |
| | $ | 12 | | | $ | — | | | $ | 2 | | | $ | 14 | | | $ | 15 | | | $ | — | | | $ | 1 | | | $ | 16 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (2) | | | $ | (2) | | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (55) | | | $ | (55) | |
| | As of December 31, 2020 | | |
| As of December 31, 2021: | | As of December 31, 2021: | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | — | | | $ | 9 | | | $ | 9 | | Commodity derivatives | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | |
| Money market mutual funds | Money market mutual funds | 17 | | | — | | | — | | | 17 | | Money market mutual funds | 10 | | | — | | | — | | | 10 | |
| | Investment funds | | Investment funds | 1 | | | — | | | — | | | 1 | |
| | $ | 17 | | | $ | — | | | $ | 9 | | | $ | 26 | | | $ | 11 | | | $ | — | | | $ | 2 | | | $ | 13 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (2) | | | $ | (2) | | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (35) | | | $ | (35) | |
Sierra Pacific's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Sierra Pacific's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Six-Month Periods |
| Ended June 30, | | Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | |
| Beginning balance | $ | (52) | | | $ | 12 | | | $ | (33) | | | $ | 7 | |
| Changes in fair value recognized in regulatory assets | (7) | | | (1) | | | (26) | | | 4 | |
| | | | | | | |
| Settlements | 5 | | | 1 | | | 5 | | | 1 | |
| Ending balance | $ | (54) | | | $ | 12 | | | $ | (54) | | | $ | 12 | |
Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Sierra Pacific's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | As of December 31, 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
| Long-term debt | $ | 1,164 | | | $ | 1,328 | | | $ | 1,164 | | | $ | 1,358 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2022 | | As of December 31, 2021 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
| Long-term debt | $ | 1,148 | | | $ | 1,164 | | | $ | 1,164 | | | $ | 1,316 | |
(8)(9) Commitments and Contingencies
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
(9)
(10) Revenue from Contracts with Customers
The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 1011 (in millions):
| | | Three-Month Periods | | Three-Month Periods |
| | Ended September 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
| Customer Revenue: | Customer Revenue: | | | | | | | | | | | | Customer Revenue: | | | | | | | | | | | |
| Retail: | Retail: | | Retail: | |
| Residential | Residential | $ | 91 | | | $ | 11 | | | $ | 102 | | | $ | 76 | | | $ | 11 | | | $ | 87 | | Residential | $ | 79 | | | $ | 19 | | | $ | 98 | | | $ | 68 | | | $ | 13 | | | $ | 81 | |
| Commercial | Commercial | 84 | | | 3 | | | 87 | | | 71 | | | 3 | | | 74 | | Commercial | 82 | | | 6 | | | 88 | | | 64 | | | 5 | | | 69 | |
| Industrial | Industrial | 71 | | | 2 | | | 73 | | | 57 | | | 1 | | | 58 | | Industrial | 53 | | | 3 | | | 56 | | | 42 | | | 2 | | | 44 | |
| Other | Other | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | | Other | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | |
| Total fully bundled | Total fully bundled | 247 | | | 16 | | | 263 | | | 205 | | | 15 | | | 220 | | Total fully bundled | 215 | | | 28 | | | 243 | | | 175 | | | 20 | | | 195 | |
| Distribution only service | Distribution only service | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | | Distribution only service | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | |
| Total retail | Total retail | 248 | | | 16 | | | 264 | | | 206 | | | 15 | | | 221 | | Total retail | 216 | | | 28 | | | 244 | | | 176 | | | 20 | | | 196 | |
| Wholesale, transmission and other | Wholesale, transmission and other | 18 | | | — | | | 18 | | | 13 | | | — | | | 13 | | Wholesale, transmission and other | 14 | | | — | | | 14 | | | 12 | | | — | | | 12 | |
| Total Customer Revenue | Total Customer Revenue | 266 | | | 16 | | | 282 | | | 219 | | | 15 | | | 234 | | Total Customer Revenue | 230 | | | 28 | | | 258 | | | 188 | | | 20 | | | 208 | |
| Other revenue | Other revenue | — | | | — | | | — | | | 1 | | | — | | | 1 | | Other revenue | — | | | — | | | — | | | 1 | | | — | | | 1 | |
| Total revenue | Total revenue | $ | 266 | | | $ | 16 | | | $ | 282 | | | $ | 220 | | | $ | 15 | | | $ | 235 | | Total revenue | $ | 230 | | | $ | 28 | | | $ | 258 | | | $ | 189 | | | $ | 20 | | | $ | 209 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six-Month Periods |
| Ended June 30, |
| 2022 | | 2021 |
| Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
| Customer Revenue: | | | | | | | | | | | |
| Retail: | | | | | | | | | | | |
| Residential | $ | 162 | | | $ | 51 | | | $ | 213 | | | $ | 138 | | | $ | 38 | | | $ | 176 | |
| Commercial | 151 | | | 21 | | | 172 | | | 117 | | | 15 | | | 132 | |
| Industrial | 102 | | | 7 | | | 109 | | | 81 | | | 5 | | | 86 | |
| Other | 3 | | | — | | | 3 | | | 3 | | | — | | | 3 | |
| Total fully bundled | 418 | | | 79 | | | 497 | | | 339 | | | 58 | | | 397 | |
| Distribution only service | 3 | | | — | | | 3 | | | 2 | | | — | | | 2 | |
| Total retail | 421 | | | 79 | | | 500 | | | 341 | | | 58 | | | 399 | |
| Wholesale, transmission and other | 35 | | | — | | | 35 | | | 28 | | | — | | | 28 | |
| Total Customer Revenue | 456 | | | 79 | | | 535 | | | 369 | | | 58 | | | 427 | |
| Other revenue | 1 | | | 1 | | | 2 | | | 1 | | | 1 | | | 2 | |
| Total revenue | $ | 457 | | | $ | 80 | | | $ | 537 | | | $ | 370 | | | $ | 59 | | | $ | 429 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2021 | | 2020 |
| Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
| Customer Revenue: | | | | | | | | | | | |
| Retail: | | | | | | | | | | | |
| Residential | $ | 229 | | | $ | 50 | | | $ | 279 | | | $ | 208 | | | $ | 54 | | | $ | 262 | |
| Commercial | 202 | | | 18 | | | 220 | | | 183 | | | 20 | | | 203 | |
| Industrial | 151 | | | 6 | | | 157 | | | 132 | | | 8 | | | 140 | |
| Other | 4 | | | — | | | 4 | | | 3 | | | — | | | 3 | |
| Total fully bundled | 586 | | | 74 | | | 660 | | | 526 | | | 82 | | | 608 | |
| Distribution only service | 2 | | | — | | | 2 | | | 3 | | | — | | | 3 | |
| Total retail | 588 | | | 74 | | | 662 | | | 529 | | | 82 | | | 611 | |
| Wholesale, transmission and other | 46 | | | — | | | 46 | | | 37 | | | — | | | 37 | |
| Total Customer Revenue | 634 | | | 74 | | | 708 | | | 566 | | | 82 | | | 648 | |
| Other revenue | 2 | | | 1 | | | 3 | | | 3 | | | 1 | | | 4 | |
| Total revenue | $ | 636 | | | $ | 75 | | | $ | 711 | | | $ | 569 | | | $ | 83 | | | $ | 652 | |
(10)(11) Segment Information
Sierra Pacific has identified 2 reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.
The following tables provide information on a reportable segment basis (in millions):
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | | | | |
| Regulated electric | Regulated electric | $ | 266 | | | $ | 220 | | | $ | 636 | | | $ | 569 | | Regulated electric | $ | 230 | | | $ | 189 | | | $ | 457 | | | $ | 370 | |
| Regulated natural gas | Regulated natural gas | 16 | | | 15 | | | 75 | | | 83 | | Regulated natural gas | 28 | | | 20 | | | 80 | | | 59 | |
| Total operating revenue | Total operating revenue | $ | 282 | | | $ | 235 | | | $ | 711 | | | $ | 652 | | Total operating revenue | $ | 258 | | | $ | 209 | | | $ | 537 | | | $ | 429 | |
| | | Operating income: | Operating income: | | Operating income: | |
| Regulated electric | Regulated electric | $ | 74 | | | $ | 66 | | | $ | 126 | | | $ | 119 | | Regulated electric | $ | 19 | | | $ | 21 | | | $ | 49 | | | $ | 52 | |
| Regulated natural gas | Regulated natural gas | 1 | | | 2 | | | 13 | | | 12 | | Regulated natural gas | 4 | | | 4 | | | 12 | | | 12 | |
| Total operating income | Total operating income | 75 | | | 68 | | | 139 | | | 131 | | Total operating income | 23 | | | 25 | | | 61 | | | 64 | |
| Interest expense | Interest expense | (14) | | | (14) | | | (41) | | | (42) | | Interest expense | (14) | | | (13) | | | (27) | | | (27) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 1 | | | — | | | 2 | | | 1 | | Allowance for borrowed funds | — | | | 1 | | | 1 | | | 1 | |
| Allowance for equity funds | Allowance for equity funds | 2 | | | 1 | | | 5 | | | 3 | | Allowance for equity funds | 2 | | | 2 | | | 4 | | | 3 | |
| Interest and dividend income | Interest and dividend income | 3 | | | 1 | | | 6 | | | 3 | | Interest and dividend income | 4 | | | 1 | | | 7 | | | 3 | |
| Other, net | Other, net | 3 | | | 2 | | | 9 | | | 4 | | Other, net | — | | | 2 | | | 2 | | | 6 | |
| Income before income tax expense | Income before income tax expense | $ | 70 | | | $ | 58 | | | $ | 120 | | | $ | 100 | | Income before income tax expense | $ | 15 | | | $ | 18 | | | $ | 48 | | | $ | 50 | |
|
| | | | | | As of | | | As of |
| | | September 30, | | December 31, | | | June 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
| Assets: | Assets: | | | | | Assets: | | | | |
| Regulated electric | Regulated electric | | $ | 3,744 | | | $ | 3,540 | | Regulated electric | | $ | 3,995 | | | $ | 3,829 | |
| Regulated natural gas | Regulated natural gas | | 354 | | | 342 | | Regulated natural gas | | 385 | | | 365 | |
Other(1) | Other(1) | | 32 | | | 37 | | Other(1) | | 35 | | | 29 | |
| Total assets | Total assets | | $ | 4,130 | | | $ | 3,919 | | Total assets | | $ | 4,415 | | | $ | 4,223 | |
(1) Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.
Results of Operations for the ThirdSecond Quarter and First NineSix Months of 20212022 and 20202021
Overview
Net income for the thirdsecond quarter of 20212022 was $62$13 million, an increasea decrease of $10$4 million, or 19%24%, compared to 20202021 primarily due to $7$6 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses, $2 million of unfavorable other, net, mainly due to lower cash surrender value of corporate-owned life insurance policies, and higher income tax expense, partially offset by $4 million of higher electric utility margin mainly from price impacts from changes in sales mix and higher transmission and wholesale revenue, and $2 million of higher interest and dividend income, mainly from carrying charges on regulatory balances. Electric utility margin increased primarily due to higher regulatory-related revenue deferrals and an increase in the average number of customers, partially offset by the unfavorable impact of weather, unfavorable price impacts from changes in sales mix and unfavorable changes in customer usage patterns. Energy generated decreased 33% for the second quarter of 2022 compared to 2021 primarily due to lower natural gas- and coal-fueled generation. Wholesale electricity sales volumes decreased 9% and purchased electricity volumes increased 38%.
Net income for the first ninesix months of 20212022 was $107$41 million, an increasea decrease of $17$4 million, or 19%9%, compared to 20202021 primarily due to $6$11 million of lowerhigher operations and maintenance expenses, mainly due to lowerhigher plant operations and maintenance expenses and lowerhigher earnings sharing, $5$4 million of higher electric utility margin, mainly from price impacts from changes in sales mix and an increase in the average number of customer, primarily from the residential customer class, partially offset by lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, $5 million of higherunfavorable other, net, mainly due to lower pension costs and higher cash surrender value of corporate-owned life insurance policies, and $3higher income tax expense, partially offset by $9 million of higher electric utility margin, $4 million of higher interest and dividend income, mainly from carrying charges on regulatory balances, partially offset by $3 million of higher depreciation and amortization, mainly from regulatory amortizations and higher plant in service, and $3 million ofallowance for equity funds, mainly due to higher income tax expenseconstruction work-in-progress. Electric utility margin increased primarily due to higher pretax income.transmission and wholesale revenue, higher regulatory-related revenue deferrals and an increase in the average number of customers, partially offset by the unfavorable impact of weather, unfavorable price impacts from changes in sales mix and unfavorable changes in customer usage patterns. Energy generated decreased 18% for the first six months of 2022 compared to 2021 primarily due to lower natural gas-fueled generation, partially offset by higher coal-fueled generation. Wholesale electricity sales volumes increased 35% and purchased electricity volumes increased 4%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Consolidated Statements of Operations.
Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Electric utility margin: | Electric utility margin: | | | | | | | | | | | | | Electric utility margin: | | | | | | | | | | | | |
| Operating revenue | Operating revenue | | $ | 266 | | | $ | 220 | | | $ | 46 | | 21 | % | | $ | 636 | | | $ | 569 | | | $ | 67 | | 12 | % | Operating revenue | | $ | 230 | | | $ | 189 | | | $ | 41 | | 22 | % | | $ | 457 | | | $ | 370 | | | $ | 87 | | 24 | % |
| Cost of fuel and energy | Cost of fuel and energy | | 120 | | | 81 | | | 39 | | 48 | | | 295 | | | 233 | | | 62 | | 27 | | Cost of fuel and energy | | 129 | | | 93 | | | 36 | | 39 | | | 253 | | | 175 | | | 78 | | 45 | |
| Electric utility margin | Electric utility margin | | 146 | | | 139 | | | 7 | | 5 | | | 341 | | | 336 | | | 5 | | 1 | | Electric utility margin | | 101 | | | 96 | | | 5 | | 5 | % | | 204 | | | 195 | | | 9 | | 5 | % |
| | Natural gas utility margin: | Natural gas utility margin: | | Natural gas utility margin: | |
| Operating revenue | Operating revenue | | 16 | | | 15 | | | 1 | | 7 | % | | 75 | | | 83 | | | (8) | | (10) | % | Operating revenue | | 28 | | | 20 | | | 8 | | 40 | % | | 80 | | | 59 | | | 21 | | 36 | % |
| Natural gas purchased for resale | Natural gas purchased for resale | | 6 | | | 4 | | | 2 | | 50 | | | 35 | | | 44 | | | (9) | | (20) | | Natural gas purchased for resale | | 16 | | | 8 | | | 8 | | 100 | | | 50 | | | 29 | | | 21 | | 72 | |
| Natural gas utility margin | Natural gas utility margin | | 10 | | | 11 | | | (1) | | (9) | | | 40 | | | 39 | | | 1 | | 3 | | Natural gas utility margin | | 12 | | | 12 | | | — | | — | % | | 30 | | | 30 | | | — | | — | % |
| | Utility margin | Utility margin | | 156 | | | 150 | | | 6 | | 4 | % | | 381 | | | 375 | | | 6 | | 2 | % | Utility margin | | 113 | | | 108 | | | 5 | | 5 | % | | 234 | | | 225 | | | 9 | | 4 | % |
| | Operations and maintenance | Operations and maintenance | | 40 | | | 40 | | | — | | — | % | | 117 | | | 123 | | | (6) | | (5) | % | Operations and maintenance | | 47 | | | 41 | | | 6 | | 15 | % | | 88 | | | 77 | | | 11 | | 14 | % |
| Depreciation and amortization | Depreciation and amortization | | 35 | | | 36 | | | (1) | | (3) | | | 107 | | | 104 | | | 3 | | 3 | | Depreciation and amortization | | 37 | | | 36 | | | 1 | | 3 | | | 73 | | | 72 | | | 1 | | 1 | |
| Property and other taxes | Property and other taxes | | 6 | | | 6 | | | — | | — | | | 18 | | | 17 | | | 1 | | 6 | | Property and other taxes | | 6 | | | 6 | | | — | | — | | | 12 | | | 12 | | | — | | — | |
| Operating income | Operating income | | $ | 75 | | | $ | 68 | | | $ | 7 | | 10 | % | | $ | 139 | | | $ | 131 | | | $ | 8 | | 6 | % | Operating income | | $ | 23 | | | $ | 25 | | | $ | (2) | | (8) | % | | $ | 61 | | | $ | 64 | | | $ | (3) | | (5) | % |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | | Utility margin (in millions): | | | | | | | | | | | | |
| Operating revenue | Operating revenue | | $ | 266 | | | $ | 220 | | | $ | 46 | | 21 | % | | $ | 636 | | | $ | 569 | | | $ | 67 | | 12 | % | Operating revenue | | $ | 230 | | | $ | 189 | | | $ | 41 | | 22 | % | | $ | 457 | | | $ | 370 | | | $ | 87 | | 24 | % |
| Cost of fuel and energy | Cost of fuel and energy | | 120 | | | 81 | | | 39 | | 48 | | | 295 | | | 233 | | | 62 | | 27 | | Cost of fuel and energy | | 129 | | | 93 | | | 36 | | 39 | | | 253 | | | 175 | | | 78 | | 45 | |
| Utility margin | Utility margin | | $ | 146 | | | $ | 139 | | | $ | 7 | | 5 | % | | $ | 341 | | | $ | 336 | | | $ | 5 | | 1 | % | Utility margin | | $ | 101 | | | $ | 96 | | | $ | 5 | | 5 | % | | $ | 204 | | | $ | 195 | | | $ | 9 | | 5 | % |
| | Sales (GWhs): | Sales (GWhs): | | Sales (GWhs): | |
| Residential | Residential | | 828 | | | 796 | | | 32 | | 4 | % | | 2,125 | | | 2,016 | | | 109 | | 5 | % | Residential | | 573 | | | 626 | | | (53) | | (8) | % | | 1,236 | | | 1,297 | | | (61) | | (5) | % |
| Commercial | Commercial | | 897 | | | 865 | | | 32 | | 4 | | | 2,362 | | | 2,288 | | | 74 | | 3 | | Commercial | | 778 | | | 788 | | | (10) | | (1) | | | 1,478 | | | 1,465 | | | 13 | | 1 | |
| Industrial | Industrial | | 989 | | | 923 | | | 66 | | 7 | | | 2,786 | | | 2,643 | | | 143 | | 5 | | Industrial | | 721 | | | 900 | | | (179) | | (20) | | | 1,476 | | | 1,797 | | | (321) | | (18) | |
| Other | Other | | 4 | | | 4 | | | — | | — | | | 11 | | | 12 | | | (1) | | (8) | | Other | | 3 | | | 3 | | | — | | — | | | 7 | | | 7 | | | — | | — | |
Total fully bundled(1) | Total fully bundled(1) | | 2,718 | | | 2,588 | | | 130 | | 5 | | | 7,284 | | | 6,959 | | | 325 | | 5 | | Total fully bundled(1) | | 2,075 | | | 2,317 | | | (242) | | (10) | | | 4,197 | | | 4,566 | | | (369) | | (8) | |
| Distribution only service | Distribution only service | | 403 | | | 422 | | | (19) | | (5) | | | 1,220 | | | 1,259 | | | (39) | | (3) | | Distribution only service | | 752 | | | 420 | | | 332 | | 79 | | | 1,337 | | | 817 | | | 520 | | 64 | |
| Total retail | Total retail | | 3,121 | | | 3,010 | | | 111 | | 4 | | | 8,504 | | | 8,218 | | | 286 | | 3 | | Total retail | | 2,827 | | | 2,737 | | | 90 | | 3 | | | 5,534 | | | 5,383 | | | 151 | | 3 | |
| Wholesale | Wholesale | | 204 | | | 87 | | | 117 | | * | | 504 | | | 376 | | | 128 | | 34 | | Wholesale | | 114 | | | 125 | | | (11) | | (9) | | | 405 | | | 300 | | | 105 | | 35 | |
| Total GWhs sold | Total GWhs sold | | 3,325 | | | 3,097 | | | 228 | | 7 | % | | 9,008 | | | 8,594 | | | 414 | | 5 | % | Total GWhs sold | | 2,941 | | | 2,862 | | | 79 | | 3 | % | | 5,939 | | | 5,683 | | | 256 | | 5 | % |
| | Average number of retail customers (in thousands) | Average number of retail customers (in thousands) | | 366 | | | 359 | | | 7 | | 2 | % | | 365 | | | 358 | | | 7 | | 2 | % | Average number of retail customers (in thousands) | | 370 | | | 365 | | | 5 | | 1 | % | | 370 | | | 364 | | | 6 | | 2 | % |
| | | Average revenue per MWh: | Average revenue per MWh: | | Average revenue per MWh: | |
Retail - fully bundled(1) | Retail - fully bundled(1) | | $ | 91.05 | | | $ | 79.22 | | | $ | 11.83 | | 15 | % | | $ | 80.56 | | | $ | 75.65 | | | $ | 4.91 | | 6 | % | Retail - fully bundled(1) | | $ | 103.25 | | | $ | 75.42 | | | $ | 27.83 | | 37 | % | | $ | 99.79 | | | $ | 74.31 | | | $ | 25.48 | | 34 | % |
| | Wholesale | Wholesale | | $ | 48.32 | | | $ | 79.72 | | | $ | (31.40) | | (39) | % | | $ | 53.39 | | | $ | 54.54 | | | $ | (1.15) | | (2) | % | Wholesale | | $ | 65.84 | | | $ | 52.18 | | | $ | 13.66 | | 26 | % | | $ | 55.28 | | | $ | 56.84 | | | $ | (1.56) | | (3) | % |
| | Heating degree days | Heating degree days | | 41 | | 15 | | 26 | | * | | 2,737 | | | 2,672 | | | 65 | | 2 | % | Heating degree days | | 661 | | 498 | | 163 | | 33 | % | | 2,698 | | | 2,696 | | | 2 | | — | % |
| Cooling degree days | Cooling degree days | | 997 | | | 946 | | | 51 | | 5 | % | | 1,366 | | | 1,166 | | | 200 | | 17 | % | Cooling degree days | | 214 | | | 369 | | | (155) | | (42) | % | | 214 | | | 369 | | | (155) | | (42) | % |
| Sources of energy (GWhs)(2)(3): | | |
Sources of energy (GWhs)(2): | | Sources of energy (GWhs)(2): | |
| Natural gas | Natural gas | | 1,463 | | | 1,587 | | | (124) | | (8) | % | | 3,678 | | | 3,967 | | | (289) | | (7) | % | Natural gas | | 707 | | | 1,133 | | | (426) | | (38) | % | | 1,697 | | | 2,215 | | | (518) | | (23) | % |
| Coal | Coal | | 373 | | | 496 | | | (123) | | (25) | % | | 838 | | | 716 | | | 122 | | 17 | % | Coal | | 352 | | | 436 | | | (84) | | (19) | | | 505 | | | 465 | | | 40 | | 9 | |
Renewables(4)(3) | Renewables(4)(3) | | 8 | | | 12 | | | (4) | | (33) | | | 27 | | | 31 | | | (4) | | (13) | | Renewables(4)(3) | | 8 | | | 13 | | | (5) | | (38) | | | 13 | | | 19 | | | (6) | | (32) | |
| Total energy generated | Total energy generated | | 1,844 | | | 2,095 | | | (251) | | (12) | | | 4,543 | | | 4,714 | | | (171) | | (4) | | Total energy generated | | 1,067 | | | 1,582 | | | (515) | | (33) | | | 2,215 | | | 2,699 | | | (484) | | (18) | |
| Energy purchased | Energy purchased | | 1,383 | | | 1,173 | | | 210 | | 18 | | | 3,905 | | | 3,625 | | | 280 | | 8 | | Energy purchased | | 1,590 | | | 1,149 | | | 441 | | 38 | | | 2,623 | | | 2,522 | | | 101 | | 4 | |
| Total | Total | | 3,227 | | | 3,268 | | | (41) | | (1) | % | | 8,448 | | | 8,339 | | | 109 | | 1 | % | Total | | 2,657 | | | 2,731 | | | (74) | | (3) | % | | 4,838 | | | 5,221 | | | (383) | | (7) | % |
| Average cost of energy per MWh(5): | | |
Average cost of energy per MWh(4): | | Average cost of energy per MWh(4): | |
| Energy generated | Energy generated | | $ | 23.64 | | | $ | 13.75 | | | $ | 9.89 | | 72 | % | | $ | 24.11 | | | $ | 21.13 | | | $ | 2.98 | | 14 | % | Energy generated | | $ | 47.59 | | | $ | 23.88 | | | $ | 23.71 | | 99 | % | | $ | 53.95 | | | $ | 24.44 | | | $ | 29.51 | | * |
| Energy purchased | Energy purchased | | $ | 55.46 | | | $ | 44.97 | | | $ | 10.49 | | 23 | % | | $ | 47.52 | | | $ | 36.83 | | | $ | 10.69 | | 29 | % | Energy purchased | | $ | 49.73 | | | $ | 48.21 | | | $ | 1.52 | | 3 | % | | $ | 51.09 | | | $ | 43.16 | | | $ | 7.93 | | 18 | % |
* Not meaningful
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The average cost of energy per MWh and sources of energy excludes 2 GWhs and 3 GWhs of coal and 6 GWhs and 7 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 2 GWhs and 3 GWhs of coal and 6 GWhs and 7 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2021 and 2020, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4)(3) Includes the Fort Churchill Solar Array which iswas under lease by Sierra Pacific.Pacific until it was acquired in December 2021.
(5)(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals and does not include other costs.deferrals.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
| | | Third Quarter | | First Nine Months | | Second Quarter | | First Six Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change | | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | | Utility margin (in millions): | | | | | | | | | | | | |
| Operating revenue | Operating revenue | | $ | 16 | | | $ | 15 | | | $ | 1 | | 7 | % | | $ | 75 | | | $ | 83 | | | $ | (8) | | (10) | % | Operating revenue | | $ | 28 | | | $ | 20 | | | $ | 8 | | 40 | % | | $ | 80 | | | $ | 59 | | | $ | 21 | | 36 | % |
| Natural gas purchased for resale | Natural gas purchased for resale | | 6 | | | 4 | | | 2 | | 50 | | | 35 | | | 44 | | | (9) | | (20) | | Natural gas purchased for resale | | 16 | | | 8 | | | 8 | | * | | 50 | | | 29 | | | 21 | | 72 | |
| Utility margin | Utility margin | | $ | 10 | | | $ | 11 | | | $ | (1) | | (9) | % | | $ | 40 | | | $ | 39 | | | $ | 1 | | 3 | % | Utility margin | | $ | 12 | | | $ | 12 | | | $ | — | | — | % | | $ | 30 | | | $ | 30 | | | $ | — | | — | % |
| | Sold (000's Dths): | Sold (000's Dths): | | Sold (000's Dths): | |
| Residential | Residential | | 774 | | | 786 | | | (12) | | (2) | % | | 6,882 | | | 6,724 | | | 158 | | 2 | % | Residential | | 1,797 | | | 1,450 | | | 347 | | 24 | % | | 6,349 | | | 6,108 | | | 241 | | 4 | % |
| Commercial | Commercial | | 471 | | | 424 | | | 47 | | 11 | | | 3,550 | | | 3,309 | | | 241 | | 7 | | Commercial | | 751 | | | 775 | | | (24) | | (3) | | | 3,263 | | | 3,079 | | | 184 | | 6 | |
| Industrial | Industrial | | 274 | | | 249 | | | 25 | | 10 | | | 1,414 | | | 1,244 | | | 170 | | 14 | | Industrial | | 402 | | | 395 | | | 7 | | 2 | | | 1,055 | | | 1,140 | | | (85) | | (7) | |
| Total retail | Total retail | | 1,519 | | | 1,459 | | | 60 | | 4 | % | | 11,846 | | | 11,277 | | | 569 | | 5 | % | Total retail | | 2,950 | | | 2,620 | | | 330 | | 13 | % | | 10,667 | | | 10,327 | | | 340 | | 3 | % |
| | Average number of retail customers (in thousands) | Average number of retail customers (in thousands) | | 177 | | | 174 | | | 3 | | 2 | % | | 177 | | | 174 | | | 3 | | 2 | % | Average number of retail customers (in thousands) | | 179 | | | 177 | | | 2 | | 1 | % | | 179 | | | 176 | | | 3 | | 2 | % |
| | Average revenue per retail Dth sold | Average revenue per retail Dth sold | | $ | 10.51 | | | $ | 9.89 | | | $ | 0.62 | | 6 | % | | $ | 6.30 | | | $ | 7.33 | | | $ | (1.03) | | (14) | % | Average revenue per retail Dth sold | | $ | 9.47 | | | $ | 7.62 | | | $ | 1.85 | | 24 | % | | $ | 7.46 | | | $ | 5.69 | | | $ | 1.77 | | 31 | % |
| | Heating degree days | Heating degree days | | 41 | | | 15 | | | 26 | | * | | 2,737 | | | 2,672 | | | 65 | | 2 | % | Heating degree days | | 661 | | | 498 | | | 163 | | 33 | % | | 2,698 | | | 2,696 | | | 2 | | — | % |
| | Average cost of natural gas per retail Dth sold | Average cost of natural gas per retail Dth sold | | $ | 3.78 | | | $ | 3.01 | | | $ | 0.77 | | 26 | % | | $ | 2.97 | | | $ | 3.93 | | | $ | (0.96) | | (24) | % | Average cost of natural gas per retail Dth sold | | $ | 5.48 | | | $ | 3.21 | | | $ | 2.27 | | 71 | % | | $ | 4.67 | | | $ | 2.86 | | | $ | 1.81 | | 63 | % |
|
* Not meaningful
Quarter Ended SeptemberJune 30, 20212022 Compared to Quarter Ended SeptemberJune 30, 2020
Electric utility margin increased$7 million, or 5%, for the third quarter of 2021 compared to 2020 primarily due to:
•$5 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 3.7% primarily due to favorable changes in customer usage patterns and the favorable impact of weather,
•$2 million of higher transmission and wholesale revenue and
•$1 million due to an increase in the average number of customers, primarily from the residential customer class.
Interest and dividend income increased $2 million for the third quarter of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Income tax expense increased $2 million, or 33%, for the third quarter of 2021 compared to 2020, primarily due to higher pretax income. The effective tax rate was 11% in 2021 and 10% in 2020.
First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020
Electric utility margin increased $5 million, or 1%5%, for the first nine monthssecond quarter of 20212022 compared to 20202021 primarily due to:
•$95 million of higher ON Line temporary rider (offset in operations and maintenance expense) for the recovery of deferred costs for the ON Line lease due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 3.5% primarily due to favorable changes in customer usage patternsthe regulatory-directed reallocation of costs between Nevada Power and the favorable impact of weather,
•$2 million due to an increase in the average number of customers, primarily from the residential customer classSierra Pacific and
•$24 million of higher transmission and wholesale revenue.regulatory-related revenue deferrals.
The increase in utility margin was offset by:
•$3 million inof lower revenue recognizedelectric retail utility margin due to a favorable regulatory decisionunfavorable price impacts from changes in 2020,
•$3 millionsales mix, offset by higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 3.3% primarily due to an adjustment to regulatory-related revenue deferralsincrease in the average number of customers, offset by the unfavorable impact of weather and unfavorable changes in customer usage patterns and
•$1 million due toof lower energy efficiency programprograms rates (offset in operations and maintenance expense).
Operations and maintenance decreasedincreased $6 million, or 5%15%, for the first nine monthssecond quarter of 20212022 compared to 20202021 primarily due to lowerhigher regulatory-approved cost recovery for the ON Line lease of $5 million (offset in operating revenue) and higher plant operations and maintenance expenses, lower earnings sharing andpartially offset by lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $3 million, or 3%, for the first nine months of 2021 compared to 2020 primarily due to regulatory amortizations and higher plant in service.
Interest and dividend income increased $3 million for the first nine monthssecond quarter of 20212022 compared to 20202021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $5is unfavorable $2 million, for the first nine monthssecond quarter of 20212022 compared to 20202021 primarily due to lower pension costs and higher cash surrender value of corporate-owned life insurance policies.policies and higher pension costs.
Income tax expense increased $1 million for the second quarter of 2022 compared to 2021 primarily due to the effects of ratemaking, offset by lower pretax income. The effective tax rate was 13% in 2022 and 6% in 2021.
First Six Months Ended June 30, 2022 Compared to First Six Months Ended June 30, 2021
Electric utility margin increased$9 million, or 5%, for the first six months of 2022 compared to 2021 primarily due to:
•$5 million of higher ON Line temporary rider (offset in operations and maintenance expense) for the recovery of deferred costs for the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific;
•$3 million of higher transmission and wholesale revenue;
•$3 million of higher regulatory-related revenue deferrals; and
•$2 million of higher energy efficiency implementation rates.
The increase in utility margin was offset by:
•$2 million of lower electric retail utility margin due to unfavorable price impacts from changes in sales mix, offset by higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 2.8% primarily due to an increase in the average number of customers, offset by the unfavorable impact of weather and unfavorable changes in customer usage patterns and
•$2 million of lower energy efficiency programs rates (offset in operations and maintenance expense).
Operations and maintenance increased $11 million, or 14%, for the first six months of 2022 compared to 2021 primarily due to higher regulatory-approved cost recovery for the ON Line lease of $5 million (offset in operating revenue), higher plant operations and maintenance expenses of $5 million and higher earnings sharing, partially offset by lower energy efficiency program costs (offset in operating revenue).
Interest and dividend income increased $4 million for the first six months of 2022 compared to 2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net unfavorable $4 million, or 67%, for the first six months of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies and higher pension costs.
Income tax expense increased $3$2 million, or 30%40%, for the first ninesix months of 20212022 compared to 2020,2021 primarily due to higherthe effects of ratemaking, offset by lower pretax income. The effective tax rate was 11%15% in 20212022 and 10% in 2020.2021.
Liquidity and Capital Resources
As of SeptemberJune 30, 2021,2022, Sierra Pacific's total net liquidity was as follows (in millions):
| | | | | | | | |
| Cash and cash equivalents | | $ | 1417 | |
| | |
| Credit facility | | 250 | |
Less - | | |
| | |
Short-term debt | | (127) | |
Net credit facility | | 123 | |
| | |
| Total net liquidity | | $ | 137267 | |
| Credit facility: | | |
| Maturity date | | 20242025 |
Operating Activities
Net cash flows from operating activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $113$108 million and $179$92 million, respectively. The change was primarily due to higher collections from customers, partially offset by higher payments related to fuel and energy costs and the timing of payments for fuel and energy costs, partially offset by higher collections from customers, lower inventory purchases and increased collections of customer advances.operating costs.
Investing Activities
Net cash flows from investing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $(196)$(191) million and $(192)$(128) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $77$91 million and $7$25 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and higher proceeds from the issuance of long-term debt, partially offset by higher long-term debt reacquired, higher repayments of short-term debt and lowerhigher dividends paid to NV Energy, Inc. offset
Long-Term Debt
In June 2022, Sierra Pacific purchased $60 million of its variable-rate tax-exempt Gas & Water Facilities Refunding Revenue Bonds, Series 2016B, due 2036, as required by lowerthe bond indenture. Sierra Pacific is holding this bond and can re-offer it at a future date.
In May 2022, Sierra Pacific issued $250 million of 4.71% General and Refunding Mortgage bonds, Series W, due 2052. The net proceeds fromwere used to repay the issuanceoutstanding $200 million unsecured loan with NV Energy, Inc., repay amounts outstanding under its existing revolving credit facility and for general corporate purposes.
In April 2022, Sierra Pacific entered into a $200 million unsecured loan with NV Energy payable upon demand. The net proceeds were used to purchase certain tax-exempt refunding revenue bond obligations that were subject to mandatory purchase by Sierra Pacific in April 2022. The loan has an underlying variable interest rate based on 30-day U.S. dollar deposits offered on the London Interbank Offered Rate market plus a spread of long-term debt.0.75%.
In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.
Debt Authorizations
Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $1.6$1.9 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.
Future Uses of Cash
Sierra Pacific has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including regulatory approvals, Sierra Pacific's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
| | | Nine-Month Periods | | Annual | | Six-Month Periods | | Annual |
| | Ended September 30, | | Forecast | | Ended June 30, | | Forecast |
| | 2020 | | 2021 | | 2021 | | 2021 | | 2022 | | 2022 |
| | | Electric distribution | Electric distribution | $ | 101 | | | $ | 66 | | | $ | 113 | | Electric distribution | $ | 42 | | | $ | 46 | | | $ | 114 | |
| Electric transmission | Electric transmission | 51 | | | 50 | | | 90 | | Electric transmission | 31 | | | 45 | | | 104 | |
| Solar generation | — | | | — | | | 18 | | |
| | Other | Other | 40 | | | 80 | | | 118 | | Other | 55 | | | 100 | | | 186 | |
| Total | Total | $ | 192 | | | $ | 196 | | | $ | 339 | | Total | $ | 128 | | | $ | 191 | | | $ | 404 | |
Sierra Pacific's approved Fourth Amendment to the 2018 JointPacific received PUCN approval through its recent IRP includedfilings for an increase in solar generation and electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2021.2022. These estimates may change as a result of the RFP process. Sierra Pacific's historical and forecast capital expenditures include the following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program of which costs are split 70% to Nevada Power and 30% to Sierra Pacific.program. In this project, the company proposedhas received approval from the PUCN to build a 350-mile, 525 kV525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation. Construction of the project was approved by the PUCN in the Fourth Amendment to the 2018 Joint IRP with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. In addition, and as instructed in Senate Bill 448 and submitted in the company's amendment to the 2021 Joint IRP, the company proposed to buildsubstation; a 235-mile, 525 kV525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345 kV345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345 kV345-kV transmission line from the new Ft. Churchill substation to the Comstock Meadows substations and the Northwest substation to Harry Allen substation segment of Greenlink West.Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Other investments includeincludes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Contractual ObligationsMaterial Cash Requirements
As of SeptemberJune 30, 2021,2022, there have been no material changes outside the normal course of business in contractual obligationscash requirements from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2020.2021, other than those disclosed in Note 4 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Regulatory Matters
Sierra Pacific is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's current regulatory matters.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations, and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various federal, state and local agencies. All suchSierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to a range of interpretation whichthat may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2020.2021. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2020.2021.
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Eastern Energy Gas Holdings, LLC
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of SeptemberJune 30, 2021,2022, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and of cash flows for the nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020,2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Eastern Energy Gas as of December 31, 2020,2021, 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, 2021,25, 2022, 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, 2020,2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Eastern Energy Gas' management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Eastern Energy Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Richmond, Virginia
NovemberAugust 5, 20212022
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | As of | | As of |
| | September 30, 2021 | | December 31, 2020 | | June 30, 2022 | | December 31, 2021 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 90 | | | $ | 35 | | Cash and cash equivalents | $ | 106 | | | $ | 22 | |
| Restricted cash and cash equivalents | 17 | | | 13 | | |
| | Trade receivables, net | Trade receivables, net | 143 | | | 177 | | Trade receivables, net | 174 | | | 183 | |
| Receivables from affiliates | Receivables from affiliates | 70 | | | 139 | | Receivables from affiliates | 26 | | | 47 | |
| Income taxes receivable | 52 | | | 20 | | |
| Other receivables | 7 | | | 51 | | |
| | Notes receivable from affiliates | | Notes receivable from affiliates | 198 | | | 7 | |
| | Inventories | Inventories | 127 | | | 119 | | Inventories | 127 | | | 122 | |
| Prepayments | 90 | | | 60 | | |
| | Natural gas imbalances | Natural gas imbalances | 69 | | | 26 | | Natural gas imbalances | 194 | | | 100 | |
| Other current assets | Other current assets | 19 | | | 16 | | Other current assets | 126 | | | 140 | |
| Total current assets | Total current assets | 684 | | | 656 | | Total current assets | 951 | | | 621 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 10,195 | | | 10,144 | | Property, plant and equipment, net | 10,131 | | | 10,200 | |
| Goodwill | Goodwill | 1,286 | | | 1,286 | | Goodwill | 1,286 | | | 1,286 | |
| | Investments | Investments | 259 | | | 244 | | Investments | 419 | | | 412 | |
| | Other assets | Other assets | 167 | | | 291 | | Other assets | 140 | | | 129 | |
| | Total assets | Total assets | $ | 12,591 | | | $ | 12,621 | | Total assets | $ | 12,927 | | | $ | 12,648 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | As of | | As of |
| | September 30, 2021 | | December 31, 2020 | | June 30, 2022 | | December 31, 2021 |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 71 | | | $ | 71 | | Accounts payable | $ | 45 | | | $ | 79 | |
| Accounts payable to affiliates | Accounts payable to affiliates | 35 | | | 39 | | Accounts payable to affiliates | 20 | | | 38 | |
| Accrued interest | Accrued interest | 49 | | | 19 | | Accrued interest | 14 | | | 19 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 73 | | | 29 | | Accrued property, income and other taxes | 78 | | | 89 | |
| | Notes payable | — | | | 9 | | |
| | Regulatory liabilities | | Regulatory liabilities | 49 | | | 40 | |
| | Current portion of long-term debt | Current portion of long-term debt | — | | | 500 | | Current portion of long-term debt | 250 | | | — | |
| Other current liabilities | Other current liabilities | 178 | | | 147 | | Other current liabilities | 187 | | | 100 | |
| Total current liabilities | Total current liabilities | 406 | | | 814 | | Total current liabilities | 643 | | | 365 | |
| | Long-term debt | Long-term debt | 3,910 | | | 3,925 | | Long-term debt | 3,636 | | | 3,906 | |
| | Regulatory liabilities | Regulatory liabilities | 646 | | | 669 | | Regulatory liabilities | 640 | | | 645 | |
| | Other long-term liabilities | Other long-term liabilities | 239 | | | 218 | | Other long-term liabilities | 291 | | | 238 | |
| Total liabilities | Total liabilities | 5,201 | | | 5,626 | | Total liabilities | 5,210 | | | 5,154 | |
| | Commitments and contingencies (Note 9) | 0 | | 0 | |
| Commitments and contingencies (Note 8) | | Commitments and contingencies (Note 8) | 0 | | 0 |
| | Equity: | Equity: | | Equity: | |
| Member's equity: | Member's equity: | | Member's equity: | |
| | Membership interests | Membership interests | 3,388 | | | 2,957 | | Membership interests | 3,733 | | | 3,501 | |
| | Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | (42) | | | (53) | | Accumulated other comprehensive loss, net | (39) | | | (43) | |
| Total member's equity | Total member's equity | 3,346 | | | 2,904 | | Total member's equity | 3,694 | | | 3,458 | |
| Noncontrolling interests | Noncontrolling interests | 4,044 | | | 4,091 | | Noncontrolling interests | 4,023 | | | 4,036 | |
| Total equity | Total equity | 7,390 | | | 6,995 | | Total equity | 7,717 | | | 7,494 | |
| | Total liabilities and equity | Total liabilities and equity | $ | 12,591 | | | $ | 12,621 | | Total liabilities and equity | $ | 12,927 | | | $ | 12,648 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | Operating revenue | Operating revenue | $ | 456 | | | $ | 531 | | | $ | 1,379 | | | $ | 1,597 | | Operating revenue | $ | 504 | | | $ | 437 | | | $ | 986 | | | $ | 923 | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | |
| | (Excess) cost of gas | (3) | | | 14 | | | (13) | | | 23 | | |
| Excess gas | | Excess gas | (21) | | | (10) | | | (22) | | | (10) | |
| Operations and maintenance | Operations and maintenance | 125 | | | 119 | | | 362 | | | 922 | | Operations and maintenance | 124 | | | 113 | | | 242 | | | 237 | |
| Depreciation and amortization | Depreciation and amortization | 83 | | | 95 | | | 244 | | | 282 | | Depreciation and amortization | 80 | | | 81 | | | 165 | | | 161 | |
| Property and other taxes | Property and other taxes | 38 | | | 38 | | | 115 | | | 109 | | Property and other taxes | 37 | | | 38 | | | 66 | | | 77 | |
| | Total operating expenses | Total operating expenses | 243 | | | 266 | | | 708 | | | 1,336 | | Total operating expenses | 220 | | | 222 | | | 451 | | | 465 | |
| | Operating income | Operating income | 213 | | | 265 | | | 671 | | | 261 | | Operating income | 284 | | | 215 | | | 535 | | | 458 | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | |
| Interest expense | Interest expense | (32) | | | (186) | | | (118) | | | (294) | | Interest expense | (36) | | | (42) | | | (72) | | | (86) | |
| | Allowance for equity funds | Allowance for equity funds | 2 | | | 1 | | | 5 | | | 11 | | Allowance for equity funds | 1 | | | 1 | | | 3 | | | 3 | |
| Interest and dividend income | — | | | 10 | | | — | | | 67 | | |
| | | Other, net | Other, net | (1) | | | 11 | | | 1 | | | 39 | | Other, net | — | | | 1 | | | (1) | | | 2 | |
| Total other income (expense) | Total other income (expense) | (31) | | | (164) | | | (112) | | | (177) | | Total other income (expense) | (35) | | | (40) | | | (70) | | | (81) | |
| | Income before income tax expense (benefit) and equity income | 182 | | | 101 | | | 559 | | | 84 | | |
| Income tax expense (benefit) | 21 | | | (10) | | | 70 | | | (40) | | |
| Income before income tax expense and equity income | | Income before income tax expense and equity income | 249 | | | 175 | | | 465 | | | 377 | |
| Income tax expense | | Income tax expense | 37 | | | 22 | | | 67 | | | 49 | |
| Equity income | Equity income | 8 | | | 7 | | | 31 | | | 30 | | Equity income | 9 | | | 7 | | | 28 | | | 23 | |
| | Net income | Net income | 169 | | | 118 | | | 520 | | | 154 | | Net income | 221 | | | 160 | | | 426 | | | 351 | |
| Net income attributable to noncontrolling interests | Net income attributable to noncontrolling interests | 100 | | | 32 | | | 302 | | | 97 | | Net income attributable to noncontrolling interests | 118 | | | 100 | | | 229 | | | 202 | |
| Net income attributable to Eastern Energy Gas | Net income attributable to Eastern Energy Gas | $ | 69 | | | $ | 86 | | | $ | 218 | | | $ | 57 | | Net income attributable to Eastern Energy Gas | $ | 103 | | | $ | 60 | | | $ | 197 | | | $ | 149 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | Net income | Net income | $ | 169 | | | $ | 118 | | | $ | 520 | | | $ | 154 | | Net income | $ | 221 | | | $ | 160 | | | $ | 426 | | | $ | 351 | |
| | | | | | | | | | | | | | | | | |
| Other comprehensive (loss) income, net of tax: | Other comprehensive (loss) income, net of tax: | | Other comprehensive (loss) income, net of tax: | |
| Unrecognized amounts on retirement benefits, net of tax of $—, $(1), $— and $— | — | | | (4) | | | 4 | | | (1) | | |
| Unrecognized amounts on retirement benefits, net of tax of $—, $—, $— and $— | | Unrecognized amounts on retirement benefits, net of tax of $—, $—, $— and $— | — | | | 2 | | | 1 | | | 4 | |
| | Unrealized (losses) gains on cash flow hedges, net of tax of $(1), $37, $2 and $8 | (2) | | | 111 | | | 11 | | | 24 | | |
| Unrealized (losses) gains on cash flow hedges, net of tax of $—, $—, $1 and $3 | | Unrealized (losses) gains on cash flow hedges, net of tax of $—, $—, $1 and $3 | (1) | | | 3 | | | 3 | | | 13 | |
| Total other comprehensive (loss) income, net of tax | Total other comprehensive (loss) income, net of tax | (2) | | | 107 | | | 15 | | | 23 | | Total other comprehensive (loss) income, net of tax | (1) | | | 5 | | | 4 | | | 17 | |
| | | | | | | | | | | | | | | | | |
| Comprehensive income | Comprehensive income | 167 | | | 225 | | | 535 | | | 177 | | Comprehensive income | 220 | | | 165 | | | 430 | | | 368 | |
| Comprehensive income attributable to noncontrolling interests | Comprehensive income attributable to noncontrolling interests | 100 | | | 32 | | | 306 | | | 97 | | Comprehensive income attributable to noncontrolling interests | 118 | | | 100 | | | 229 | | | 206 | |
| Comprehensive income attributable to Eastern Energy Gas | Comprehensive income attributable to Eastern Energy Gas | $ | 67 | | | $ | 193 | | | $ | 229 | | | $ | 80 | | Comprehensive income attributable to Eastern Energy Gas | $ | 102 | | | $ | 65 | | | $ | 201 | | | $ | 162 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
| | | | | Accumulated | | | | | Accumulated | |
| | | | Other | | | | | Other | |
| | | Membership | | Comprehensive | | Noncontrolling | | Total | | | Membership | | Comprehensive | | Noncontrolling | | Total |
| | | Interests | | Loss, Net | | Interests | | Equity | | | Interests | | Loss, Net | | Interests | | Equity |
| | Balance, June 30, 2020 | | $ | 7,352 | | | $ | (271) | | | $ | 1,375 | | | $ | 8,456 | | |
| Balance, March 31, 2021 | | Balance, March 31, 2021 | | $ | 3,035 | | | $ | (45) | | | $ | 4,088 | | | $ | 7,078 | |
| Net income | Net income | | 86 | | | — | | | 32 | | | 118 | | Net income | | 60 | | | — | | | 100 | | | 160 | |
| Other comprehensive income | Other comprehensive income | | — | | | 107 | | | — | | | 107 | | Other comprehensive income | | — | | | 5 | | | — | | | 5 | |
| Contributions | Contributions | | 299 | | | — | | | — | | | 299 | | Contributions | | 271 | | | — | | | — | | | 271 | |
| Distributions | Distributions | | (2,394) | | | — | | | (36) | | | (2,430) | | Distributions | | — | | | — | | | (116) | | | (116) | |
| Balance, September 30, 2020 | | $ | 5,343 | | | $ | (164) | | | $ | 1,371 | | | $ | 6,550 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | | $ | 3,366 | | | $ | (40) | | | $ | 4,072 | | | $ | 7,398 | |
| | Balance, December 31, 2019 | | $ | 9,031 | | | $ | (187) | | | $ | 1,385 | | | $ | 10,229 | | |
| Balance, December 31, 2020 | | Balance, December 31, 2020 | | $ | 2,957 | | | $ | (53) | | | $ | 4,091 | | | $ | 6,995 | |
| Net income | Net income | | 57 | | | — | | | 97 | | | 154 | | Net income | | 149 | | | — | | | 202 | | | 351 | |
| Other comprehensive income | Other comprehensive income | | — | | | 23 | | | — | | | 23 | | Other comprehensive income | | — | | | 13 | | | 4 | | | 17 | |
| | Contributions | Contributions | | 299 | | | — | | | — | | | 299 | | Contributions | | 282 | | | — | | | — | | | 282 | |
| Distributions | Distributions | | (4,044) | | | — | | | (111) | | | (4,155) | | Distributions | | (22) | | | — | | | (225) | | | (247) | |
| | Balance, September 30, 2020 | | $ | 5,343 | | | $ | (164) | | | $ | 1,371 | | | $ | 6,550 | | |
| Balance, June 30, 2021 | | Balance, June 30, 2021 | | $ | 3,366 | | | $ | (40) | | | $ | 4,072 | | | $ | 7,398 | |
| | Balance, June 30, 2021 | | $ | 3,366 | | | $ | (40) | | | $ | 4,072 | | | $ | 7,398 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | | $ | 3,595 | | | $ | (38) | | | $ | 4,033 | | | $ | 7,590 | |
| Net income | Net income | | 69 | | | — | | | 100 | | | 169 | | Net income | | 103 | | | — | | | 118 | | | 221 | |
| Other comprehensive loss | Other comprehensive loss | | — | | | (2) | | | — | | | (2) | | Other comprehensive loss | | — | | | (1) | | | — | | | (1) | |
| Contributions | Contributions | | 2 | | | — | | | — | | | 2 | | Contributions | | 68 | | | — | | | — | | | 68 | |
| Distributions | Distributions | | (49) | | | — | | | (128) | | | (177) | | Distributions | | (33) | | | — | | | (128) | | | (161) | |
| Balance, September 30, 2021 | | $ | 3,388 | | | $ | (42) | | | $ | 4,044 | | | $ | 7,390 | | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | | $ | 3,733 | | | $ | (39) | | | $ | 4,023 | | | $ | 7,717 | |
| | Balance, December 31, 2020 | | $ | 2,957 | | | $ | (53) | | | $ | 4,091 | | | $ | 6,995 | | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | | $ | 3,501 | | | $ | (43) | | | $ | 4,036 | | | $ | 7,494 | |
| Net income | Net income | | 218 | | | — | | | 302 | | | 520 | | Net income | | 197 | | | — | | | 229 | | | 426 | |
| Other comprehensive income | Other comprehensive income | | — | | | 11 | | | 4 | | | 15 | | Other comprehensive income | | — | | | 4 | | | — | | | 4 | |
| Contributions | Contributions | | 284 | | | — | | | — | | | 284 | | Contributions | | 68 | | | — | | | — | | | 68 | |
| Distributions | Distributions | | (71) | | | — | | | (353) | | | (424) | | Distributions | | (33) | | | — | | | (242) | | | (275) | |
| | Balance, September 30, 2021 | | $ | 3,388 | | | $ | (42) | | | $ | 4,044 | | | $ | 7,390 | | |
| Balance, June 30, 2022 | | Balance, June 30, 2022 | | $ | 3,733 | | | $ | (39) | | | $ | 4,023 | | | $ | 7,717 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | Nine-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 520 | | | $ | 154 | | Net income | $ | 426 | | | $ | 351 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | Adjustments to reconcile net income to net cash flows from operating activities: | | Adjustments to reconcile net income to net cash flows from operating activities: | |
| | (Gains) losses on other items, net | (9) | | | 463 | | |
| Losses on other items, net | | Losses on other items, net | 2 | | | 3 | |
| Depreciation and amortization | Depreciation and amortization | 244 | | | 282 | | Depreciation and amortization | 165 | | | 161 | |
| Allowance for equity funds | Allowance for equity funds | (5) | | | (11) | | Allowance for equity funds | (3) | | | (3) | |
| Equity (income) loss, net of distributions | (1) | | | 33 | | |
| Equity income, net of distributions | | Equity income, net of distributions | (5) | | | (3) | |
| Changes in regulatory assets and liabilities | Changes in regulatory assets and liabilities | (2) | | | 19 | | Changes in regulatory assets and liabilities | (2) | | | 1 | |
| Deferred income taxes | Deferred income taxes | 135 | | | (103) | | Deferred income taxes | 52 | | | 118 | |
| Other, net | Other, net | (11) | | | 8 | | Other, net | 5 | | | (9) | |
| Changes in other operating assets and liabilities: | Changes in other operating assets and liabilities: | | Changes in other operating assets and liabilities: | |
| Trade receivables and other assets | Trade receivables and other assets | 13 | | | 271 | | Trade receivables and other assets | 4 | | | 65 | |
| | Derivative collateral, net | Derivative collateral, net | 7 | | | 148 | | Derivative collateral, net | (3) | | | (1) | |
| Pension and other postretirement benefit plans | — | | | (46) | | |
| | Accrued property, income and other taxes | Accrued property, income and other taxes | (61) | | | 36 | | Accrued property, income and other taxes | (3) | | | (63) | |
| | Accounts payable and other liabilities | Accounts payable and other liabilities | 37 | | | 5 | | Accounts payable and other liabilities | 43 | | | (39) | |
| Net cash flows from operating activities | Net cash flows from operating activities | 867 | | | 1,259 | | Net cash flows from operating activities | 681 | | | 581 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (291) | | | (258) | | Capital expenditures | (151) | | | (150) | |
| | Repayment of loans by affiliates | 269 | | | 3,422 | | |
| Loans to affiliates | (170) | | | (225) | | |
| Repayment of notes by affiliates | | Repayment of notes by affiliates | 15 | | | 268 | |
| Notes to affiliates | | Notes to affiliates | (204) | | | (158) | |
| | Other, net | Other, net | (9) | | | (9) | | Other, net | (7) | | | (12) | |
| Net cash flows from investing activities | Net cash flows from investing activities | (201) | | | 2,930 | | Net cash flows from investing activities | (347) | | | (52) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| | Repayments of long-term debt | Repayments of long-term debt | (500) | | | — | | Repayments of long-term debt | — | | | (500) | |
| Net repayments of short-term debt | — | | | (62) | | |
| | Repayment of notes payable, net | Repayment of notes payable, net | (9) | | | (253) | | Repayment of notes payable, net | — | | | (9) | |
| | Proceeds from equity contributions | Proceeds from equity contributions | 256 | | | 299 | | Proceeds from equity contributions | — | | | 256 | |
| Distributions | Distributions | (353) | | | (4,155) | | Distributions | (242) | | | (225) | |
| | Other, net | Other, net | (1) | | | (1) | | Other, net | — | | | (2) | |
| Net cash flows from financing activities | Net cash flows from financing activities | (607) | | | (4,172) | | Net cash flows from financing activities | (242) | | | (480) | |
| | | Net change in cash and cash equivalents and restricted cash and cash equivalents | Net change in cash and cash equivalents and restricted cash and cash equivalents | 59 | | | 17 | | Net change in cash and cash equivalents and restricted cash and cash equivalents | 92 | | | 49 | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 48 | | | 39 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 39 | | | 48 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 107 | | | $ | 56 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 131 | | | $ | 97 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Eastern Energy Gas Holdings, LLC is a holding company, and together with its subsidiaries ("Eastern Energy Gas") is a holding company that conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transportation pipeline and underground storage operations in the eastern region of the United StatesU.S. and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. Eastern Energy Gas owns 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. In addition, Eastern Energy Gas owns a 50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 416-mile FERC-regulated interstate natural gas transportation pipeline.
In July 2020, Dominion Energy, Inc. ("DEI") entered into an agreement to sell substantially all of its gas transmission and storage operations, including Eastern Energy Gas and a 25% limited partnership interest in Cove Point, tois an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). Approval of the transaction under the Hart-Scott-Rodino Act was not obtained within 75 days and DEI and BHE mutually agreed to a dual-phase closing consisting of two separate disposal groups identified as the acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction") and the proposed sale of the Questar Pipeline Group by DEI to BHE pursuant to a purchase and sale agreement entered into on October 5, 2020 ("Q-Pipe Transaction"). In July 2021, Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Transaction. Prior to the completion of the GT&S Transaction, Eastern Energy Gas finalized a restructuring whereby Eastern Energy Gas distributed the Questar Pipeline Group and a 50% noncontrolling interest in Cove Point to DEI. This restructuring was accounted for by Eastern Energy Gas as a reorganization of entities under common control and the disposition was reflected as an equity transaction. The disposition was not reported as a discontinued operation as the disposal did not represent a strategic shift in the way management had intended to run the business. On November 1, 2020, BHE completed the GT&S Transaction. As a result of the GT&S Transaction, Eastern Energy Gas became an indirect wholly owned subsidiary of BHE. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of SeptemberJune 30, 20212022 and for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 and 2020.2021. The results of operations for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20212022 are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 20202021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Eastern Energy Gas' assumptions regarding significant accounting estimates and policies during the nine-monthsix-month period ended SeptemberJune 30, 2021.2022.
(2) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions): | | | As of | | As of |
| | September 30, | | December 31, | | June 30, | | December 31, |
| | Depreciable Life | | 2021 | | 2020 | | Depreciable Life | | 2022 | | 2021 |
| Utility Plant: | Utility Plant: | | | | | | Utility Plant: | | | | | |
| | Interstate natural gas pipeline assets | Interstate natural gas pipeline assets | 24 - 43 years | | $ | 8,555 | | | $ | 8,382 | | Interstate natural gas pipeline assets | 21 - 44 years | | $ | 8,728 | | | $ | 8,675 | |
| Intangible plant | Intangible plant | 5 - 10 years | | 111 | | | 115 | | Intangible plant | 5 - 10 years | | 106 | | | 110 | |
| Utility plant in service | | 8,666 | | | 8,497 | | |
| Utility plant in-service | | Utility plant in-service | | 8,834 | | | 8,785 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (2,859) | | | (2,759) | | Accumulated depreciation and amortization | | (2,962) | | | (2,901) | |
| Utility plant in service, net | | 5,807 | | | 5,738 | | |
| Utility plant in-service, net | | Utility plant in-service, net | | 5,872 | | | 5,884 | |
| | Nonutility Plant: | Nonutility Plant: | | Nonutility Plant: | |
| | LNG facility | LNG facility | 40 years | | 4,466 | | | 4,454 | | LNG facility | 40 years | | 4,484 | | | 4,475 | |
| Intangible plant | Intangible plant | 14 years | | 25 | | | 25 | | Intangible plant | 14 years | | 25 | | | 25 | |
| Nonutility plant in service | | 4,491 | | | 4,479 | | |
| Nonutility plant in-service | | Nonutility plant in-service | | 4,509 | | | 4,500 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (396) | | | (283) | | Accumulated depreciation and amortization | | (484) | | | (423) | |
| Nonutility plant in service, net | | 4,095 | | | 4,196 | | |
| Nonutility plant in-service, net | | Nonutility plant in-service, net | | 4,025 | | | 4,077 | |
| | Plant, net | Plant, net | | 9,902 | | | 9,934 | | Plant, net | | 9,897 | | | 9,961 | |
| Construction work-in-progress | Construction work-in-progress | | 293 | | | 210 | | Construction work-in-progress | | 234 | | | 239 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 10,195 | | | $ | 10,144 | | Property, plant and equipment, net | | $ | 10,131 | | | $ | 10,200 | |
Construction work-in-progress includes $266$200 million and $196$209 million as of SeptemberJune 30, 20212022 and December 31, 2020,2021, respectively, related to the construction of utility plant.
(3) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following (in millions):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
| Investments: | | | |
| Investment funds | $ | 13 | | | $ | — | |
| | | |
| | | |
| Equity method investments: | | | |
| Iroquois | 246 | | | 244 | |
| | | |
| | | |
| Total investments | 259 | | | 244 | |
| | | |
| Restricted cash and cash equivalents: | | | |
| Customer deposits | 17 | | | 13 | |
| Total restricted cash and cash equivalents | 17 | | | 13 | |
| | | |
| Total investments and restricted cash and cash equivalents | $ | 276 | | | $ | 257 | |
| | | |
| Reflected as: | | | |
| Current assets | $ | 17 | | | $ | 13 | |
| Noncurrent assets | 259 | | | 244 | |
| Total investments and restricted cash and cash equivalents | $ | 276 | | | $ | 257 | |
Equity Method Investments
Eastern Energy Gas, through a subsidiary, owns 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut. Prior to the GT&S Transaction, Eastern Energy Gas, through the Questar Pipeline Group, owned 50% of White River Hub, which owns and operates a natural gas pipeline in northwest Colorado.
As of September 30, 2021 and December 31, 2020, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in net assets by $130 million. The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas received distributions from its investments of $30 million and $63 million for the nine-month periods ended September 30, 2021 and 2020, respectively.
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 of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of 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, |
| 2021 | | 2020 |
| | | |
| Cash and cash equivalents | $ | 90 | | | $ | 35 | |
| Restricted cash and cash equivalents | 17 | | | 13 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | $ | 107 | | | $ | 48 | |
(4)(3) Regulatory Matters
Eastern Gas Transmission and Storage, Inc.
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. EGTS hasbillion, 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 matterIn June 2022, the parties reached an agreement in principle and the litigation procedural schedule was ordered held in abeyance for 90 days to enable the parties to finalize a settlement. The settlement is pending.expected to be filed by September 30, 2022. As of June 30, 2022, EGTS' provision for rate refund for April 2022 through June 2022 totaled $35 million and was included in other current liabilities on the Consolidated Balance Sheet.
In July 2017, the FERC audit staff communicated to EGTS that it had substantially completed an audit of EGTS' compliance with the accounting and reporting requirements of the FERC's Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report. In December 2017, EGTS provided its response to the audit report. EGTS requested FERC review of the contested findings and submitted its plan for compliance with the uncontested portions of the report. EGTS reached resolution of certain matters with the FERC in the fourth quarter of 2018. EGTS recognized a charge of $129 million ($94 million after-tax) for the year ended December 31, 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with the FERC. In December 2020, the FERC issued a final ruling on the remaining matter, which resulted in a $43 million ($31 million after-tax) estimated charge for disallowance of capitalized allowance for funds used during construction. As a condition of the December 2020 ruling, EGTS filed its proposed accounting entries and supporting documentation with the FERC during the second quarter of 2021. During the finalization of these entries, EGTS refined the estimated charge for disallowance of capitalized allowance for funds used during construction, which resulted in a reduction to the estimated charge of $11 million ($8 million after-tax) that was recorded in operations and maintenance expense in its Consolidated Statements of Operations in the second quarter of 2021. In September 2021, the FERC approved EGTS' accounting entries and supporting documentation.
In December 2014, EGTS entered into a precedent agreement with Atlantic Coast Pipeline, LLC ("Atlantic Coast Pipeline") for the project previously intended for EGTS to provide approximately 1,500,000 decatherms ("Dth") of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). As a result
(4) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the cancellation of the Atlantic Coast Pipeline project, in the second quarter of 2020 following (in millions):
| | | | | | | | | | | |
| As of |
| June 30, | | December 31, |
| 2022 | | 2021 |
| Investments: | | | |
| Investment funds | $ | 13 | | | $ | 13 | |
| | | |
| | | |
| Equity method investments: | | | |
| Iroquois | 406 | | | 399 | |
| | | |
| | | |
| Total investments | 419 | | | 412 | |
| | | |
| Restricted cash and cash equivalents: | | | |
| Customer deposits | 25 | | | 17 | |
| Total restricted cash and cash equivalents | 25 | | | 17 | |
| | | |
| Total investments and restricted cash and cash equivalents | $ | 444 | | | $ | 429 | |
| | | |
| Reflected as: | | | |
| Current assets | $ | 25 | | | $ | 17 | |
| Noncurrent assets | 419 | | | 412 | |
| Total investments and restricted cash and cash equivalents | $ | 444 | | | $ | 429 | |
Equity Method Investments
Eastern Energy Gas, recordedthrough a chargesubsidiary, owns 50% of $482 million ($359 million after-tax)Iroquois, which owns and operates an interstate natural gas pipeline located in operationsthe states of New York and maintenance expenseConnecticut.
As of both June 30, 2022 and December 31, 2021, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in its Consolidated Statements of Operations associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million asset retirement obligation. In the third quarter of 2020,net assets by $130 million. The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas recorded an additional chargereceived distributions from its investments of $10$23 million ($7and $20 million after-tax) associated withfor the probable abandonment of a significant portion of the projectsix-month periods ended June 30, 2022 and a $29 million ($20 million after-tax) benefit from a revision to the previously established asset retirement obligation, both of which were recorded in operations and maintenance expense in Eastern Energy Gas' Consolidated Statements of Operations. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.2021, respectively.
Cove PointCash and Cash Equivalents and Restricted Cash and Cash Equivalents
In January 2020, pursuant to the termsCash equivalents consist of funds invested in money market mutual funds, U.S. Treasury Bills and other investments with 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-servicematurity of $182 million. In February 2020,three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist of customer deposits as allowed under the FERC 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 participantsgas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented in the general rate case proceeding. UnderConsolidated Statements of Cash Flows is outlined below and disaggregated by the terms ofline items in which they appear on the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April 2021.Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of |
| June 30, | | December 31, |
| 2022 | | 2021 |
| | | |
| Cash and cash equivalents | $ | 106 | | | $ | 22 | |
| Restricted cash and cash equivalents included in other current assets | 25 | | | 17 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | $ | 131 | | | $ | 39 | |
(5) Recent Financing Transactions
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. The following table details the exchanged notes prior to, and subsequent to, the transaction (in millions):
| | | | | | | | | | | | | | | | | |
| Prior to Exchange | | Subsequent to Exchange |
| Eastern Energy Gas Par Value | | Eastern Energy Gas Par Value | | EGTS Par Value |
| | | | | |
| 3.6% Senior Notes due 2024 | $ | 450 | | | $ | 339 | | | $ | 111 | |
| 3.0% Senior Notes due 2029 | 600 | | | 174 | | | 426 | |
| 4.8% Senior Notes due 2043 | 400 | | | 54 | | | 346 | |
| 4.6% Senior Notes due 2044 | 500 | | | 56 | | | 444 | |
| 3.9% Senior Notes due 2049 | 300 | | | 27 | | | 273 | |
| $ | 2,250 | | | $ | 650 | | | $ | 1,600 | |
(6) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense (benefit) is as follows:
| | | Three-Month Periods | | Nine-Month Periods | | Three-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended September 30, | | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| State income tax, net of federal income tax benefit | State income tax, net of federal income tax benefit | 2 | | | (3) | | | 2 | | | (29) | | State income tax, net of federal income tax benefit | 3 | | | 2 | | | 4 | | | 3 | |
| | Equity interest | Equity interest | 1 | | | — | | | 1 | | | 8 | | Equity interest | 1 | | | 1 | | | 1 | | | 1 | |
| Effects of ratemaking | Effects of ratemaking | (1) | | | (2) | | | (1) | | | (6) | | Effects of ratemaking | — | | | (1) | | | (2) | | | (1) | |
| | Change in tax status | — | | | (18) | | | — | | | (24) | | |
| | AFUDC-equity | — | | | — | | | — | | | (2) | | |
| | Noncontrolling interest | Noncontrolling interest | (11) | | | (6) | | | (11) | | | (24) | | Noncontrolling interest | (10) | | | (12) | | | (10) | | | (11) | |
| Write-off of regulatory assets | — | | | — | | | — | | | 9 | | |
| | Other, net | Other, net | — | | | (2) | | | 1 | | | (1) | | Other, net | — | | | 2 | | | — | | | — | |
| Effective income tax rate | Effective income tax rate | 12 | % | | (10) | % | | 13 | % | | (48) | % | Effective income tax rate | 15 | % | | 13 | % | | 14 | % | | 13 | % |
Noncontrolling interest is attributable toFor the period ended June 30, 2022, Eastern Energy Gas' ownership in Cove Point. The GT&S Transaction resulted in a changereconciliation of noncontrolling interest to 75% as of September 30, 2021 from 25% as of September 30, 2020. Additionally, Eastern Energy Gas' effectivethe federal statutory income tax rate forto the periods ended September 30, 2020 is primarily a function of the impacts associated with the cancellation of the Atlantic Coast Pipeline project, the nominal year-to-date pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries.
Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federaleffective income tax return and, where applicable, combined staterate is driven primarily by an absence of tax on income tax returns. All affiliate payables or receivables were settled with DEI priorattributable to the closing date of the GT&S Transaction. Subsequent to the GT&S Transaction, Eastern Energy Gas, as a subsidiary of BHE, is included in Berkshire Hathaway's United States federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provisions for income tax have been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. Eastern Energy Gas received net cash payments for income tax from BHE totaling $34 million for the nine-month period ended September 30, 2021.Cove Point's 75% noncontrolling interest.
(7)(6) Employee Benefit Plans
Prior to the GT&S Transaction, certain Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Pension Plan,is a definedparticipant in benefit pension planplans sponsored by DEI that provides benefits to multiple DEI subsidiaries. As participating employers, Eastern Energy Gas was subject to DEI's funding policy, which was to contribute annually an amount that is in accordance with the Employee Retirement Income Security Act of 1974. Also prior to the GT&S Transaction, pension benefits for Eastern Energy Gas employees represented by collective bargaining units were provided by a separate plan that provides benefits to employees of both EGTS and Hope Gas, Inc. ("Hope"). Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Company ("MidAmerican Energy") Pension, an affiliate. The MidAmerican Energy Company Retirement Plan similar to the DEI plan.
Prior to the GT&S Transaction,includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain retiree healthcarepostretirement health care and life insurance benefits for eligible retirees on behalf of Eastern Energy Gas. Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by DEI that provides certain retiree healthcare and life insurance benefits to multiple DEI subsidiaries. Also priorcontributed $6 million to the GT&S Transaction, retiree healthMidAmerican Energy Company Retirement Plan and life insurance benefits$1 million to the MidAmerican Energy Company Welfare Benefit Plan for the six-month period ended June 30, 2022. Amounts attributable to Eastern Energy Gas employees represented by collective bargaining units were covered by a separate other postretirement benefit plan that provides benefits to both EGTSallocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. Offsetting regulatory assets and Hope. Subsequentliabilities have been recorded related to the GT&S Transaction,amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net. As of both June 30, 2022 and December 31, 2021, Eastern Energy Gas employees are covered by theGas' amount due to MidAmerican Energy Retiree Healthassociated with these plans and Welfare plan, similar toreflected in other long-term liabilities on the DEI plan.Consolidated Balance Sheets was $95 million.
Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| Pension: | | | | | | | |
| Service cost | $ | — | | | $ | 2 | | | $ | — | | | $ | 5 | |
| Interest cost | — | | | 3 | | | — | | | 8 | |
| Expected return on plan assets | — | | | (14) | | | — | | | (42) | |
| Net amortization | — | | | 1 | | | — | | | 5 | |
| Net periodic benefit credit | $ | — | | | $ | (8) | | | $ | — | | | $ | (24) | |
| | | | | | | |
| Other Postretirement: | | | | | | | |
| Service cost | $ | — | | | $ | — | | | $ | — | | | $ | 1 | |
| Interest cost | — | | | 1 | | | — | | | 3 | |
| Expected return on plan assets | — | | | (4) | | | — | | | (14) | |
| Net amortization | — | | | (1) | | | — | | | (2) | |
| Net periodic benefit credit | $ | — | | | $ | (4) | | | $ | — | | | $ | (12) | |
(8)(7) Fair Value Measurements
The carrying value of Eastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Eastern Energy Gas has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Eastern Energy Gas has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Eastern Energy Gas' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Eastern Energy Gas develops these inputs based on the best information available, including its own data.
The following table presents Eastern Energy Gas' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | Input Levels for Fair Value Measurements | | | Input Levels for Fair Value Measurements | |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| As of September 30, 2021 | | | | | | | | | |
| As of June 30, 2022: | | As of June 30, 2022: | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| | Foreign currency exchange rate derivatives | | $ | — | | | $ | 8 | | | $ | — | | | $ | 8 | | |
| | Money market mutual funds | Money market mutual funds | | 75 | | | — | | | — | | | 75 | | Money market mutual funds | | $ | 66 | | | $ | — | | | $ | — | | | $ | 66 | |
| Equity securities: | | Equity securities: | |
| Investment funds | Investment funds | | 13 | | | — | | | — | | | 13 | | Investment funds | | 13 | | | — | | | — | | | 13 | |
| | $ | 88 | | | $ | 8 | | | $ | — | | | $ | 96 | | | $ | 79 | | | $ | — | | | $ | — | | | $ | 79 | |
| | Liabilities: | Liabilities: | | Liabilities: | |
| Commodity derivatives | Commodity derivatives | | $ | — | | | $ | (1) | | | $ | — | | | $ | (1) | | Commodity derivatives | | $ | — | | | $ | (1) | | | $ | — | | | $ | (1) | |
| Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | — | | | (4) | | | — | | | (4) | | Foreign currency exchange rate derivatives | | — | | | (19) | | | — | | | (19) | |
| | | $ | — | | | $ | (5) | | | $ | — | | | $ | (5) | | | $ | — | | | $ | (20) | | | $ | — | | | $ | (20) | |
| | As of December 31, 2020 | | |
| As of December 31, 2021: | | As of December 31, 2021: | |
| Assets: | Assets: | | Assets: | |
| | Foreign currency exchange rate derivatives | | Foreign currency exchange rate derivatives | | $ | — | | | $ | 3 | | | $ | — | | | $ | 3 | |
| Equity securities: | | Equity securities: | |
| Investment funds | | Investment funds | | 13 | | | — | | | — | | | 13 | |
| | | $ | 13 | | | $ | 3 | | | $ | — | | | $ | 16 | |
| | Liabilities: | | Liabilities: | |
| | Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | $ | — | | | $ | 20 | | | $ | — | | | $ | 20 | | Foreign currency exchange rate derivatives | | $ | — | | | $ | (3) | | | $ | — | | | $ | (3) | |
| | | $ | — | | | $ | 20 | | | $ | — | | | $ | 20 | | | $ | — | | | $ | (3) | | | $ | — | | | $ | (3) | |
| | Liabilities: | | |
| Commodity derivatives | | $ | — | | | $ | (1) | | | $ | — | | | $ | (1) | | |
| Foreign currency exchange rate derivatives | | — | | | (2) | | | — | | | (2) | | |
| Interest rate derivatives | | — | | | (6) | | | — | | | (6) | | |
| $ | — | | | $ | (9) | | | $ | — | | | $ | (9) | | |
Eastern Energy Gas' investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Eastern Energy Gas transacts. When quoted prices for identical contracts are not available, Eastern Energy Gas uses forward price curves. Forward price curves represent Eastern Energy Gas' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Eastern Energy Gas bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by Eastern Energy Gas. Market price quotations are generally readily obtainable for the applicable term of Eastern Energy Gas' outstanding derivative contracts; therefore, Eastern Energy Gas' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, Eastern Energy Gas uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets.Financial Statements. The fair value of Eastern Energy Gas' long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Eastern Energy Gas' variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Eastern Energy Gas' long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of September 30, 2021 | | As of December 31, 2020 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
| Long-term debt | | $ | 3,910 | | | $ | 4,327 | | | $ | 4,425 | | | $ | 5,012 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of June 30, 2022 | | As of December 31, 2021 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
| Long-term debt | | $ | 3,886 | | | $ | 3,656 | | | $ | 3,906 | | | $ | 4,266 | |
(9)(8) Commitments and Contingencies
Legal Matters
Eastern Energy Gas is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Eastern Energy Gas does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact itsEastern Energy Gas' current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
(10)
(9) Revenue from Contracts with Customers
The following table summarizes Eastern Energy Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| Customer Revenue: | | | | | | | |
| Regulated: | | | | | | | |
| Gas transportation and storage | $ | 249 | | | $ | 311 | | | $ | 774 | | | $ | 957 | |
| Wholesale | 14 | | | 25 | | | 31 | | | 27 | |
| Other | 1 | | | 1 | | | (1) | | | 4 | |
| Total regulated | 264 | | | 337 | | | 804 | | | 988 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Nonregulated | 193 | | | 193 | | | 573 | | | 606 | |
| Total Customer Revenue | 457 | | | 530 | | | 1,377 | | | 1,594 | |
| Other revenue | (1) | | | 1 | | | 2 | | | 3 | |
| Total operating revenue | $ | 456 | | | $ | 531 | | | $ | 1,379 | | | $ | 1,597 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Six-Month Periods |
| Ended June 30, | | Ended June 30, |
| 2022 | | 2021 | | 2022 | | 2021 |
| Customer Revenue: | | | | | | | |
| Regulated: | | | | | | | |
| Gas transportation and storage | $ | 286 | | | $ | 246 | | | $ | 571 | | | $ | 525 | |
| Wholesale | — | | | — | | | — | | | 17 | |
| | | | | | | |
| Total regulated | 286 | | | 246 | | | 571 | | | 542 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Nonregulated | 216 | | | 190 | | | 419 | | | 380 | |
| Total Customer Revenue | 502 | | | 436 | | | 990 | | | 922 | |
Other revenue(1) | 2 | | | 1 | | | (4) | | | 1 | |
| Total operating revenue | $ | 504 | | | $ | 437 | | | $ | 986 | | | $ | 923 | |
Remaining Performance Obligations
The following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of SeptemberJune 30, 20212022 (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
| Eastern Energy Gas | $ | 1,574 | | | $ | 16,413 | | | $ | 17,987 | |
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
| Eastern Energy Gas | $ | 2,228 | | | $ | 16,609 | | | $ | 18,837 | |
(11)(10) Components of Accumulated Other Comprehensive Loss, Net
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income tax (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Unrecognized | | | | | | Accumulated |
| | Amounts On | | Unrealized | | | | Other |
| | Retirement | | Losses on Cash | | Noncontrolling | | Comprehensive |
| | Benefits | | Flow Hedges | | Interests | | Loss, Net |
| Balance, December 31, 2019 | | $ | (106) | | | $ | (81) | | | $ | — | | | $ | (187) | |
| Other comprehensive (loss) income | | (1) | | | 24 | | | — | | | 23 | |
| Balance, September 30, 2020 | | $ | (107) | | | $ | (57) | | | $ | — | | | $ | (164) | |
| | | | | | | | |
| Balance, December 31, 2020 | | $ | (12) | | | $ | (51) | | | $ | 10 | | | $ | (53) | |
| Other comprehensive income (loss) | | 4 | | | 11 | | | (4) | | | 11 | |
| Balance, September 30, 2021 | | $ | (8) | | | $ | (40) | | | $ | 6 | | | $ | (42) | |
In July 2020, Eastern Energy Gas recorded a loss of $141 million ($105 million after-tax) in interest expense in the Consolidated Statement of Operations, for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction.
(12) Variable Interest Entities
The primary beneficiary of a variable interest entity ("VIE") is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity's economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
In November 2019, DEI contributed to Eastern Energy Gas a 75% controlling limited partner interest in Cove Point. In December 2019, DEI sold its retained 25% noncontrolling limited partner interest in Cove Point. As part of the GT&S Transaction, Eastern Energy Gas finalized a restructuring which included the disposition of a 50% noncontrolling interest in Cove Point to DEI, which resulted in Eastern Energy Gas owning 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. Eastern Energy Gas concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Eastern Energy Gas is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Unrecognized | | | | | | Accumulated |
| | Amounts On | | Unrealized | | | | Other |
| | Retirement | | Losses on Cash | | Noncontrolling | | Comprehensive |
| | Benefits | | Flow Hedges | | Interests | | Loss, Net |
| Balance, December 31, 2020 | | $ | (12) | | | $ | (51) | | | $ | 10 | | | $ | (53) | |
| Other comprehensive income (loss) | | 4 | | | 13 | | | (4) | | | 13 | |
| Balance, June 30, 2021 | | $ | (8) | | | $ | (38) | | | $ | 6 | | | $ | (40) | |
| | | | | | | | |
| Balance, December 31, 2021 | | $ | (6) | | | $ | (42) | | | $ | 5 | | | $ | (43) | |
| Other comprehensive income | | 1 | | | 3 | | | — | | | 4 | |
| Balance, June 30, 2022 | | $ | (5) | | | $ | (39) | | | $ | 5 | | | $ | (39) | |
Eastern Energy Gas purchased shared services from Carolina Gas Services, Inc. ("Carolina Gas Services") an affiliated VIE, of $3 million for each of the three-month periods ended September 30, 2021 and 2020, and $9 million and $10 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $31 million and $22 million as of September 30, 2021 and December 31, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities is the primary beneficiary of Carolina Gas Services as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Carolina Gas Services provides marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities has any obligation to absorb more than its allocated share of Carolina Gas Services costs.
Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Questar Pipeline Services, Inc. ("DEQPS"), an affiliated VIE, of $7 million and $21 million for the three- and nine-month periods ended September 30, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DEQPS, as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DEQPS provided marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DEQPS costs.
Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Services, Inc. ("DES"), an affiliated VIE, of $22 million and $80 million for the three- and nine-month periods ended September 30, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DES as neither it nor any of its consolidated entities had both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DES provided accounting, legal, finance and certain administrative and technical services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DES costs.
(13) Related Party Transactions
Transactions Prior to the GT&S Transaction
Prior to the GT&S Transaction, Eastern Energy Gas engaged in related party transactions primarily with other DEI subsidiaries (affiliates). Eastern Energy Gas' receivable and payable balances with affiliates were settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. All affiliate payables or receivables were settled with DEI prior to the closing of the GT&S Transaction.
Eastern Energy Gas transacted with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Eastern Energy Gas provided transportation and storage services to affiliates. Eastern Energy Gas also entered into certain other contracts with affiliates, and related parties, including construction services, which were presented separately from contracts involving commodities or services. Eastern Energy Gas participated in certain DEI benefit plans as described in Note 7.
DES, Carolina Gas Services, DEQPS and other affiliates provided accounting, legal, finance and certain administrative and technical services to Eastern Energy Gas. Eastern Energy Gas provided certain services to related parties, including technical services.
The financial statements for the three-month and nine-month periods ended September 30, 2020 include costs for certain general, administrative and corporate expenses assigned by DES, Carolina Gas Services and DEQPS to Eastern Energy Gas on the basis of direct and allocated methods in accordance with Eastern Energy Gas' services agreements with DES, Carolina Gas Services and DEQPS. Where costs incurred cannot be determined by specific identification, the costs were allocated based on the proportional level of effort devoted by DES, Carolina Gas Services and DEQPS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.
Subsequent to the GT&S Transaction, and with the exception of Cove Point, Eastern Energy Gas' transactions with other DEI subsidiaries are no longer related-party transactions.
Presented below are Eastern Energy Gas' significant transactions with DES, Carolina Gas Services, DEQPS and other affiliated and related parties for the three- and nine-month periods ended September 30, 2020 (in millions):
| | | | | | | | | | | | | | | |
| Three-Month Period | | Nine-Month Period | | | | |
| Ended September 30, 2020 | | Ended September 30, 2020 | | | | |
| Sales of natural gas and transportation and storage services | $ | 60 | | | $ | 188 | | | | | |
| Purchases of natural gas and transportation and storage services | 3 | | | 9 | | | | | |
Services provided by related parties(1) | 34 | | | 114 | | | | | |
Services provided to related parties(2) | 17 | | | 78 | | | | | |
(1) Includes capitalized expenditures of $5 million and $12 million for the three- and nine-month periods ended September 30, 2020, respectively.
(2) Amounts primarily attributable to Atlantic Coast Pipeline, LLC, a related-party VIE prior to the GT&S Transaction.
Interest income related to the affiliated notes receivable under the DEI money pool was $3 million for the nine-month period ended September 30, 2020.
Interest income related to Eastern Energy Gas' affiliated notes receivable from DEI was $9 million and $32 million for the three- and nine-month periods ended September 30, 2020, respectively.
Interest income related to Eastern Energy Gas' affiliated notes receivable from East Ohio Gas Company was $33 million for the nine-month period ended September 30, 2020.
Interest charges related to Eastern Energy Gas' total borrowings under an intercompany revolving credit agreement with DEI were $3 million for the nine-month period ended September 30, 2020.
Interest charges related to CPMLP Holdings Company, LLC's total borrowings from DES were $3 million for the nine-month period ended September 30, 2020.
For the nine-month period ended September 30, 2020, Eastern Energy Gas distributed $4.2 billion to DEI.
Transactions Subsequent to the GT&S Transaction
Eastern Energy Gas is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $31 million and $20 million as of September 30, 2021 and December 31, 2020, respectively.
Other assets included amounts due from an affiliate of $4 million and $7 million as of September 30, 2021 and December 31, 2020, respectively.
As of September 30, 2021, Eastern Energy Gas had $3 million of natural gas imbalances payable to affiliates, presented in other current liabilities on the Consolidated Balance Sheet.
Presented below are Eastern Energy Gas' significant transactions with affiliated and related parties for the three- and nine-month periods ended September 30, 2021 (in millions):
| | | | | | | | | | | | | | | |
| Three-Month Period | | Nine-Month Period | | | | |
| Ended September 30, 2021 | | Ended September 30, 2021 | | | | |
| Sales of natural gas and transportation and storage services | $ | 7 | | | $ | 21 | | | | | |
| Purchases of natural gas and transportation and storage services | 1 | | | 4 | | | | | |
| Services provided by related parties | 16 | | | 31 | | | | | |
| Services provided to related parties | 8 | | | 24 | | | | | |
Eastern Energy Gas has a $400 million intercompany revolving credit agreement from its parent, BHE GT&S, LLC ("BHE GT&S") expiring in November 2022. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") plus a fixed spread. As of September 30, 2021 and December 31, 2020, $— million and $9 million, respectively, was outstanding under the credit agreement.
BHE GT&S has an intercompany revolving credit agreement from Eastern Energy Gas expiring in December 2022. In March 2021, BHE GT&S increased its credit facility limit from $200 million to $400 million. The credit agreement has a variable interest rate based on LIBOR plus a fixed spread. As of September 30, 2021 and December 31, 2020, $28 million and $124 million, respectively, was outstanding under the credit agreement.
Eastern Energy Gas participates in certain MidAmerican Energy benefit plans as described in Note 7. As of September 30, 2021 and December 31, 2020, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $110 million and $115 million, respectively.
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.
Results of Operations for the ThirdSecond Quarter and First NineSix Months of 20212022 and 20202021
Overview
Net income attributable to Eastern Energy Gas for the thirdsecond quarter of 20212022 was $69$103 million, a decreasean increase of $17$43 million compared to 2020.2021. Net income decreasedincreased primarily due to higher margins from regulated gas transportation and storage operations of $52 million, partially offset by an increase in net income attributable to DEI's 50% noncontrolling interest in Cove Point LNG, LP ("Cove Point") of $68 million, the November 2020 disposition of Questar Pipeline Group of $26 million and a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI of $14 million, all of which were a result of the GT&S Transaction, and income tax expense of $21$15 million in 2021 versus income tax benefit of $10 million in 2020, primarily due to higher pre-tax income. These decreases were partially offset by a 2020 charge of $141 million for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction.
Net income attributable to Eastern Energy Gas for the first ninesix months of 20212022 was $218$197 million, an increase of $161$48 million compared to 2020.2021. Net income increased primarily due to a 2020 charge of $463 million associated with the probable abandonment of a significant portion of a project previously intended for EGTS to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"), a 2020 charge of $141 million for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction and higher margins from regulated gas transportation and storage operations of $39$37 million, lower interest expense of $13 million primarily due to favorable natural gas prices. These increases werethe repayment of long-term debt in the second quarter of 2021 and lower than estimated 2021 tax assessments of $11 million, partially offset by a decrease in net income due to an increase in net income attributable to DEI's 50% noncontrolling interest in Cove Point of $205 million, the November 2020 disposition of Questar Pipeline Group of $68 million, interest income from DEI and its affiliates recognized in 2020 of $65 million and a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI of $42 million, all of which were a result of the GT&S Transaction, and income tax expense of $70$18 million in 2021 versus income tax benefit of $40 million in 2020, primarily due to higher pre-tax income.
Quarter Ended SeptemberJune 30, 20212022 Compared to Quarter Ended SeptemberJune 30, 20202021
Operating revenue decreased $75increased $67 million, or 14%15%, for the second quarter of 2022 compared to 2021, primarily due to an increase in regulated gas transportation and storage services rates due to an agreement in principle for EGTS' general rate case of $25 million, an increase in Cove Point liquefied natural gas variable revenue of $25 million, an increase in variable revenue related to park and loan activity of $6 million and a $4 million increase from the West Loop transmission pipeline being placed into service in the third quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $58 million and a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased prices of $11 million.2021.
(Excess) cost ofExcess gas was a credit of $3increased $11 million for the thirdsecond quarter of 20212022 compared to an expense of $14 million for the third quarter of 2020. The change in (excess) cost of gas is2021, primarily due to favorable valuations of system gas of $27 million, partially offset by a favorable changedecrease in natural gas prices.retained volumes of $16 million.
Operations and maintenance increased $6$11 million, or 5%10%, for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to a 20202021 benefit associated withfrom the probable abandonmentfinalization of a significant portionentries for the disallowance of the Supply Header Projectcapitalized AFUDC of $19$11 million and an increase in post-retirement benefit related costs of $6 million, partially offset by the November 2020 dispositionbank and legal fees recorded in 2021 related to Eastern Energy Gas' debt exchange of Questar Pipeline Group of $13$4 million.
Depreciation and amortization decreased $12$1 million, or 13%1%, for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to the November 2020 dispositiona decrease due to an agreement in principle for EGTS' general rate case of Questar Pipeline Group.$6 million, partially offset by higher plant placed in-service of $5 million.
Interest expense decreased $1546 million, or 83%14%, for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to a charge in 2020 for cash flow hedges of $141 million of debt-related items that were probable of not occurring as a result of the GT&S Transaction, the November 2020 disposition of Questar Pipeline Group of $5 million and lower interest expense of $5 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $4 million from the repayment of $500 million of long-term debt in the second quarter of 2021.
Interest and dividend incomeIncome tax expense decreased $10increased $15 million, or 68%, for the thirdsecond quarter of 20212022 compared to 2020,2021, primarily due to interest income from DEI recognized in 2020 as a result of the GT&S Transaction.
Other, net was an expense of $1 million for the third quarter of 2021 compared to income of $11 million for the third quarter of 2020.higher pre-tax income. The change in other, net is primarily due to a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI as a result of the GT&S Transaction.
Income tax expense (benefit) was an expense of $21 million for the third quarter of 2021 compared to a benefit of $10 million for the third quarter of 2020 and the effective tax rate was 12%15% for the thirdsecond quarter of 20212022 and (10)%13% for the thirdsecond quarter of 2020. The effective tax rate increased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction, lower pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries in 2020.2021.
Net income attributable to noncontrolling interests increased $68$18 million, or 18%, for the thirdsecond quarter of 20212022 compared to 20202021, primarily due to DEI's 50% noncontrolling interestan increase in Cove Point effective with the GT&S Transaction.liquefied natural gas variable revenue.
First NineSix Months Ended SeptemberJune 30, 20212022 Compared to First NineSix Months Ended SeptemberJune 30, 20202021
Operating revenue decreased $218increased $63 million, or 14%7%, for the first ninesix months of 20212022 compared to 2020,2021, primarily due to the November 2020 dispositionan increase in Cove Point liquefied natural gas variable revenue of Questar Pipeline Group of $178$38 million, and a decrease in services performed for Atlantic Coast Pipeline, LLC of $40 million, which is offset in operations and maintenance expense. This decrease in operating revenue was partially offset by an increase in regulated gas transportation and storage services rates due to an agreement in principle for EGTS' general rate case of $25 million, an increase in variable revenue related to park and loan activity of $11 million and a $7 million increase from the West Loop transmission pipeline being placed into service in the third quarter of 2021, partially offset by a decrease in regulated gas sales of $17 million for operational and system balancing purposes primarily due to increased prices of $6 million.decreased volumes.
(Excess) cost ofExcess gas was a credit of $13increased $12 million for the first ninesix months of 20212022 compared to an expense of $23 million for the first nine months of 2020. The change in (excess) cost of gas is2021, primarily due to a favorable changedecrease in natural gas pricesvolumes sold of $48$14 million and the November 2020 dispositionfavorable valuations of Questar Pipeline Groupsystem gas of $3$18 million, partially offset by an increase in pricesunfavorable change to volumes of natural gas sold of $15$20 million.
Operations and maintenance decreased $560increased $5 million, or 61%2%, for the first ninesix months of 20212022 compared to 2020,2021, primarily due to a 2020 charge associated with2021 benefit from the probable abandonmentfinalization of a significant portionentries for the disallowance of the Supply Header Projectcapitalized AFUDC of $463$11 million, a decreasepartially offset by bank and legal fees recorded in services performed for Atlantic Coast Pipeline, LLC2021 related to Eastern Energy Gas' debt exchange of $41 million and the November 2020 disposition of Questar Pipeline Group of $39$4 million.
Depreciation and amortization decreased $38increased $4 million, or 13%2%, for the first ninesix months of 20212022 compared to 2020,2021, primarily due to the November 2020 dispositionhigher plant placed in-service of Questar Pipeline Group.$10 million, partially offset by a decrease due to an agreement in principle for EGTS' general rate case of $6 million.
Property and other taxesincreased $6decreased $11 million, or 6%14%, for the first ninesix months of 20212022 compared to 2020,2021, primarily due to higherlower than estimated 2021 tax assessments.
Interest expense decreased $176$14 million, or 60%16%, for the first ninesix months of 20212022 compared to 2020,2021, primarily due to a charge in 2020 for cash flow hedges of $141 million of debt-related items that were probable of not occurring as a result of the GT&S Transaction, the November 2020 disposition of Questar Pipeline Group of $15 million and lower interest expense of $15 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $4 million from the repayment of $500 million of long-term debt in the second quarter of 2021.
Allowance for equity fundsIncome tax expense decreased $6increased $18 million, or 55%37%, for the first ninesix months of 20212022 compared to 2020,2021, primarily due to lower capital expenditures related to the Supply Header Project as a result of the abandonment of the project.
Interest and dividend income decreased $67 million for the first nine months of 2021 compared to 2020, primarily due to interest income from the East Ohio Gas Company of $33 million and DEI of $32 million recognized in 2020 as a result of the GT&S Transaction.
Other, net decreased $38 million, or 97%, for the first nine months of 2021 compared to 2020, primarily due to a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI as a result of the GT&S Transaction.
Income tax expense (benefit) was an expense of $70 million for the first nine months of 2021 compared to a benefit of $40 million for the first nine months of 2020 and thehigher pre-tax income. The effective tax rate was 14% for the first six months of 2022 and 13% for the first ninesix months of 2021 and (48)% for the first nine months of 2020. The effective tax rate increased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction, lower pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries in 2020.2021.
Net income attributable to noncontrolling interests increased $205$27 million, or 13%, for the first ninesix months of 20212022 compared to 20202021, primarily due to DEI's 50% noncontrolling interestan increase in Cove Point effective with the GT&S Transaction.liquefied natural gas variable revenue.
Liquidity and Capital Resources
As of SeptemberJune 30, 2021,2022, Eastern Energy Gas' total net liquidity was $490$506 million as follows (in millions):
| | | | | | | | |
| Cash and cash equivalents | | $ | 90106 | |
| | |
Intercompany revolving credit agreement(1) | | 400 | |
| | |
| | |
| | |
| | |
| | |
| Total net liquidity | | $ | 490506 | |
| | |
| Intercompany revolving credit agreement: | | |
| Maturity date | | 2022 |
(1)Refer to Note 13 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for further discussion regarding Eastern Energy Gas' intercompany credit agreement.
Operating Activities
Net cash flows from operating activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $867$681 million and $1.3 billion,$581 million, respectively. The change wasis primarily due to lower collections from affiliates, lower income tax receipts, lower distributions from equity method investments and the timing of income tax payments, of operating costs.the impacts from the proposed rates in effect April 1, 2022 for the EGTS general rate case and other working capital adjustments.
The timing of Eastern Energy Gas' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods elected and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-monthsix-month periods ended SeptemberJune 30, 2022 and 2021 and 2020 were $(201)$(347) million and $2.9 billion,$(52) million, respectively. The change wasincrease is primarily due to a decrease in repayments of loans by affiliates of $3.2 billion, partially offset by a decrease$253 million and an increase in loans to affiliatesits parent under an intercompany revolving credit agreement of $55$46 million.
Financing Activities
Net cash flows from financing activities for the nine-monthsix-month period ended SeptemberJune 30, 2022 were $(242) million and consisted of distributions to noncontrolling interests from Cove Point.
Net cash flows from financing activities for the six-month period ended June 30, 2021 were $(607)$(480) million. Sources of cash totaled $256 million and consisted of proceeds from equity contributions, that primarily included a contribution from its indirect parent, BHE, to Eastern Energy Gas to assist in the repayment of $500 million of debt. Uses of cash totaled $863$736 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $353$225 million and repayment of notes to affiliates of $9 million.
Net cash flows from financing activities for the nine-month period ended September 30, 2020 were $(4.2) billion. Sources of cash totaled $299 million and consisted of equity contributions. Uses of cash totaled $4.5 billion and consisted mainly of distributions to DEI of $4.2 billion, repayment of notes to affiliates of $253 million and repayments of short-term debt of $62 million.
Future Uses of Cash
Eastern Energy Gas has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use ofintercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which Eastern Energy Gas and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, Eastern Energy Gas' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.natural gas transportation pipeline and storage and LNG export, import and storage industries.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisition of existing assets.
Eastern Energy Gas' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | Nine-Month Periods | | Annual | | Six-Month Periods | | Annual |
| | Ended September 30, | | Forecast | | Ended June 30, | | Forecast |
| | 2020 | | 2021 | | 2021 | | 2021 | | 2022 | | 2022 |
| | Natural gas transmission and storage | Natural gas transmission and storage | $ | 89 | | | $ | 15 | | | $ | 22 | | Natural gas transmission and storage | $ | 11 | | | $ | 23 | | | $ | 51 | |
| Other | Other | 169 | | | 276 | | | 454 | | Other | 139 | | | 128 | | | 314 | |
| Total | Total | $ | 258 | | | $ | 291 | | | $ | 476 | | Total | $ | 150 | | | $ | 151 | | | $ | 365 | |
Eastern Energy Gas' natural gas transmission and storage capital expenditures primarily include growth capital expenditures related to planned regulated projects. Eastern Energy Gas' other capital expenditures consist primarily of non-regulated and routine capital expenditures for natural gas transmission, storage and liquefied natural gas terminalling infrastructure needed to serve existing and expected demand.
Contractual ObligationsMaterial Cash Requirements
As of SeptemberJune 30, 2021,2022, there have been no material changes outside the normal course of business in contractual obligationscash requirements from the information provided in Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020.
Regulatory Matters
Eastern Energy Gas is subject to comprehensive regulation. Refer to Note 4 of Notes to Consolidated Financial Statements"Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 12 of this Form 10-Q for discussion regarding Eastern Energy Gas' current regulatory matters.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact itsEastern Energy Gas' current and future operations. In addition to imposing continuing compliance obligations, and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Eastern Energy Gas is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets and income taxes. For additional discussion of Eastern Energy Gas' critical accounting estimates, see Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020.2021. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2020.2021.
Item 3.Quantitative and Qualitative Disclosures About Market Risk
For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020.2021. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2020.2021. Refer to Note 7 of the Notes to Consolidated Financial Statements of PacifiCorp, Note 7 of the Notes to Consolidated Financial Statements of Nevada Power and Note 7 of the Notes to Consolidated Financial Statements of Sierra Pacific in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of SeptemberJune 30, 2021.2022.
Item 4.Controls and Procedures
At the end of the period covered by this Quarterly Report on Form 10-Q, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended SeptemberJune 30, 20212022 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
PART II
Item 1.Legal Proceedings
Berkshire Hathaway Energy and PacifiCorp
On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20cv33885, Circuit Court, Multnomah County, Oregon. The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain, South Obenchain, Two Four Two and Santiam Canyon (also known as Beachie Creek) fires, as well as to add claims for noneconomic damages. The amended complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp acted with gross negligence, among other things. The amended complaint seeks the following damages for the plaintiffs and the putative class: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal property and other economic losses of not less than $600 million; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (v) double the damages for the costs of litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The plaintiffs demand a trial by jury and have reserved their right to further amend the complaint to allege claims for punitive damages. In May 2022, the Multnomah Circuit Court granted issue class certification and consolidated this case with others as described below. PacifiCorp requested an immediate appeal of the issue class certification before the Oregon Court of Appeals.
On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21cv33595, Multnomah County, Oregon, in which two complaints, Case No. 21cv09339 and Case No. 21cv09520, previously filed in Circuit Court, Marion County, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek Fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek Fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint with an intent to add a claim for punitive damages. In May 2022, this case was consolidated with others as described below.
In May 2022, the Multnomah Circuit Court granted plaintiffs' motion to consolidate Shylo Salter et al. v. PacifiCorp, Case No. 21cv33595 (described above) and Amy Allen, et al. v. PacifiCorp, Case No. 20cv37430 ("Allen") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20cv33885 (described above). Plaintiffs' motion to bifurcate issues for trial between class-wide liability and individual damages was also granted. The Allen case was filed by five individuals as amended in September 2021 claiming in excess of $32 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest.
In June 2022, an amended complaint against PacifiCorp was filed, captioned Tim Goforth et al. v. PacifiCorp, Case No. 20cv37637, Douglas County, Oregon, in which a previously filed complaint associated with the Archie Creek Fire, Susan Creek Fire and Smith Springs Road Fire in Douglas County in September 2020 was amended to add punitive damages. The complaint alleges (i) PacifiCorp's conduct not only constituted common law negligence but gross negligence and contributed to or was the cause of ignition and spread of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence, inverse condemnation. The complaint seeks the following damages: (i) economic and property damages of $11 million under a determination of negligence or inverse condemnation and subject to doubling under Oregon statute if applicable; (ii) doubling of those economic and property damages to $22 million under a determination of gross negligence; (iii) damages for injuries in excess of $47 million; (iv) punitive damages not to exceed 10 times the amount of non-economic damages awarded; (v) all costs of the lawsuit; (vi) pre- and post-judgment interest as allowed by law; and (vii) attorneys' fees and other costs.
Other individual lawsuits alleging similar claims have been filed in Oregon and California related to the 2020 Wildfires. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 98 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.
PacifiCorp
On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22cv09346, Circuit Court, Douglas County, Oregon. The complaint was filed by nine businesses and public pension plans that own and/or operate timberlands or possess property in Douglas County who allege damages, losses and injuries associated with their timberlands as a result of the French Creek Fire, the Archie Creek Fire, the Susan Creek Fire and the Smith Springs Road Fire in Douglas County in September 2020. The complaint alleges (i) PacifiCorp's conduct constituted not only common law negligence but also gross negligence and that such conduct contributed to or caused the ignition and spread of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence, inverse condemnation. The complaint seeks the following damages: (i) economic and property damages in excess of $175 million under a determination of negligence or inverse condemnation; (ii) doubling of those economic damages to in excess of $350 million under a determination of gross negligence pursuant to Oregon statutes; (iii) all costs of the lawsuit; (iv) prejudgment and post-judgment interest as allowed by law; and (v) attorneys' fees and other costs.
Item 1A.Risk Factors
There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020.2021, except as disclosed below.
Potential terrorist activities and the impact of military or other actions, including sanctions, export controls and similar measures, could adversely affect each Registrant's financial results.
The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the U.S. government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Further, the potential or actual outbreak of war or other hostilities, such as Russia's invasion of Ukraine in February 2022 and the resulting economic sanctions on Russia and the sale of Russian natural gas and petroleum, as well as the existing and potential further responses from Russia or other countries to such sanctions and military actions, could adversely affect global and regional economies and financial markets. For instance, the current ban on imports of Russian oil, liquefied natural gas and coal to the U.S. could contribute to increases in prices for such commodities in the U.S. and elsewhere which could adversely affect each Registrant's business. Further, each Registrant's business must be conducted in compliance with applicable economic and trade sanctions laws and regulations, including those administered and enforced by the U.S. Department of Treasury's Office of Foreign Assets Control, the U.S. Department of State, the U.S. Department of Commerce, the United Nations Security Council and other relevant governmental authorities in the U.S., Canada, the United Kingdom and European Union, which include sanctions that could potentially restrict or prohibit each Registrant's relationships with certain suppliers and customers. Political, economic, social or financial market instability or damage to or interference with the operating assets of the Registrants, customers or suppliers, or continued increases in the price of natural gas and other petroleum commodities may result in business interruptions, lost revenue, higher costs, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect its consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
Not applicable.
Item 3.Defaults Upon Senior Securities
Not applicable.
Item 4.Mine Safety Disclosures
Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.
Item 5.Other Information
Not applicable.
Item 6.Exhibits
The following is a list of exhibits filed as part of this Quarterly Report.
BERKSHIRE HATHAWAY ENERGY
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| 4.1 | Fiscal Agency Agreement,Seventeenth Supplemental Indenture, dated as of April 9, 2021,21, 2022, by and between Northern Natural GasBerkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent,as trustee, relating to the $550,000,0004.600% Senior Notes due 2053 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated April 25, 2022). |
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| 4.2 | |
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| 10.1 | $3,500,000,000 SecondThird Amended and Restated Credit Agreement, dated as of June 30, 2021,2022, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Union Bank, N.A,Ltd. as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).Banks. |
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| 15.1 | |
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| 31.1 | |
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| 31.2 | |
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| 32.1 | |
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| 32.2 | |
PACIFICORP
BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
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4.2 | |
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| 10.2 | $1,200,000,000 SecondThird Amended and Restated Credit Agreement, dated as of June 30, 2021,2022, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, asInitial Lenders, JP Morgan Chase Bank, N.A. as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.2 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).Banks. |
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| 95 | |
MIDAMERICAN ENERGY
BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY
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4.3 | |
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4.4 | |
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| 10.3 | $1,500,000,000 SecondThird Amended and Restated Credit Agreement, dated as of June 30, 2021,2022, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Mizuho Bank, Ltd., as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).Banks. |
MIDAMERICAN FUNDING
NEVADA POWER
BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
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| 10.4 | $400,000,000 Fourth400,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 2021,2022, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.4 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).Banks. |
SIERRA PACIFIC
BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
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10.54.3 | |
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| 4.4 | |
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| 4.5 | |
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| 10.6 | $250,000,000 Fourth250,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 2021,2022, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.5 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021).Banks. |
EASTERN ENERGY GAS
BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS
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4.5 | Fifteenth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as trustee, to the Indenture dated as of October 1, 2013, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated July 1, 2021). |
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4.6 | |
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4.7 | First Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.900% Senior Notes due 2049 (incorporated by reference to Exhibit 4.7 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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4.8 | Second Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.600% Senior Notes due 2044 (incorporated by reference to Exhibit 4.8 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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4.9 | Third Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.800% Senior Notes due 2043 (incorporated by reference to Exhibit 4.9 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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4.10 | Fourth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.000% Senior Notes due 2029 (incorporated by reference to Exhibit 4.10 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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4.11 | Fifth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.600% Senior Notes due 2024 (incorporated by reference to Exhibit 4.11 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
ALL REGISTRANTS
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| 101 | The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended SeptemberJune 30, 2021,2022, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail. |
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| 104 | Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| | BERKSHIRE HATHAWAY ENERGY COMPANY |
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Date: NovemberAugust 5, 20212022 | /s/ Calvin D. Haack |
| | Calvin D. Haack |
| | Senior Vice President and Chief Financial Officer |
| | (principal financial and accounting officer) |
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| | PACIFICORP |
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Date: NovemberAugust 5, 20212022 | /s/ Nikki L. Kobliha |
| | Nikki L. Kobliha |
| | Vice President, Chief Financial Officer and Treasurer |
| | (principal financial and accounting officer) |
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| | MIDAMERICAN FUNDING, LLC |
| | MIDAMERICAN ENERGY COMPANY |
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Date: NovemberAugust 5, 20212022 | /s/ Thomas B. Specketer |
| | Thomas B. Specketer |
| | Vice President and Controller |
| | of MidAmerican Funding, LLC and |
| Vice President and Chief Financial Officer |
| | of MidAmerican Energy Company |
| | (principal financial and accounting officer) |
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| NEVADA POWER COMPANY |
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Date: NovemberAugust 5, 20212022 | /s/ Michael E. Cole |
| Michael E. Cole |
| Senior Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |
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| SIERRA PACIFIC POWER COMPANY |
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Date: NovemberAugust 5, 20212022 | /s/ Michael E. Cole |
| Michael E. Cole |
| Senior Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |
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| EASTERN ENERGY GAS HOLDINGS, LLC |
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Date: NovemberAugust 5, 20212022 | /s/ Scott C. Miller |
| Scott C. Miller |
| Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |