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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 June 30, 2022March 31, 2023
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 | | |
| | | | |
| 333-266049 | | EASTERN GAS TRANSMISSION AND STORAGE, INC. | | 55-0629203 |
| | (A Delaware Corporation) | | |
| | 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 |
| EASTERN GAS TRANSMISSION AND STORAGE, INC. | 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 |
| EASTERN GAS TRANSMISSION AND STORAGE, INC. | 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 | ☒ | |
| EASTERN GAS TRANSMISSION AND STORAGE, INC. | ☒ | |
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 | ☐ | ☐ | ☒ | ☐ | ☐ |
| EASTERN GAS TRANSMISSION AND STORAGE, INC. | ☐ | ☐ | ☒ | ☐ | ☐ |
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 AugustMay 4, 2022,2023, 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 AugustMay 4, 2022,2023, 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 AugustMay 4, 2022.2023.
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 AugustMay 4, 2022,2023, 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 AugustMay 4, 2022,2023, 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 AugustMay 4, 2022,2023, 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 AugustMay 4, 2022.2023.
All shares of outstanding common stock of Eastern Gas Transmission and Storage, Inc. are owned by its parent company, Eastern Energy Gas Holdings, LLC, which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of May 4, 2023, 60,101 shares of common stock, $10,000 par value, were outstanding.
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.LLC and Eastern Gas Transmission and Storage, Inc. 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 |
| EGTS | | Eastern Gas Transmission and Storage, Inc. 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 and Eastern Gas Transmission and Storage, Inc. 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 its 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 |
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EGTS | | Eastern Gas Transmission and Storage, Inc. |
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| Certain Industry Terms | | |
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2017 Tax Reform2020 Wildfires | | The Tax CutsWildfires in Oregon and Jobs Act enacted on December 22, 2017, effective January 1, 2018Northern California that occurred September of 2020 |
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| AFUDC | | Allowance for Funds Used During Construction |
| AUC | | Alberta Utilities Commission |
| BART | | Best Available Retrofit Technology |
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| 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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| 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 |
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| GTA | | General Tariff Application |
| GWh | | Gigawatt Hour |
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| IRP | | Integrated Resource Plan |
| IUB | | Iowa Utilities Board |
| kV | | Kilovolt |
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| LNG | | Liquefied Natural Gas |
| MATS | | Mercury and Air Toxics Standards |
| 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 |
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| RFP | | Request for Proposals |
| 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 |
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| 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, costly litigation, wars (including, for example, Russia's invasion of Ukraine in February 2022), terrorism, pandemics, 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;wildfires;
•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 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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| Eastern Gas Transmission and Storage, Inc. 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 June 30, 2022,March 31, 2023, the related consolidated statements of operations, comprehensive income and(loss), changes in equity, for the three-month and six-month periods ended June 30, 2022 and 2021, and of cash flows for the six-monththree-month periods ended June 30,March 31, 2023 and 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 the Company as of December 31, 2021,2022, 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 25, 2022,24, 2023, 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, 2021,2022, 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
AugustMay 5, 20222023
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | As of | | As of |
| | | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 2,081 | | | $ | 1,096 | | Cash and cash equivalents | $ | 963 | | | $ | 1,591 | |
| Restricted cash and cash equivalents | 201 | | | 127 | | |
| Investments and restricted cash and cash equivalents | | Investments and restricted cash and cash equivalents | 3,032 | | | 2,141 | |
| Trade receivables, net | Trade receivables, net | 2,734 | | | 2,468 | | Trade receivables, net | 2,567 | | | 2,876 | |
| Income tax receivable | 25 | | | 344 | | |
| | Inventories | Inventories | 1,163 | | | 1,122 | | Inventories | 1,299 | | | 1,256 | |
| Mortgage loans held for sale | Mortgage loans held for sale | 1,084 | | | 1,263 | | Mortgage loans held for sale | 650 | | | 474 | |
| | Regulatory assets | Regulatory assets | 778 | | | 544 | | Regulatory assets | 1,612 | | | 1,319 | |
| Other current assets | Other current assets | 1,294 | | | 1,284 | | Other current assets | 1,202 | | | 1,345 | |
| Total current assets | Total current assets | 9,360 | | | 8,248 | | Total current assets | 11,325 | | | 11,002 | |
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| Property, plant and equipment, net | Property, plant and equipment, net | 90,795 | | | 89,816 | | Property, plant and equipment, net | 93,583 | | | 93,043 | |
| Goodwill | Goodwill | 11,559 | | | 11,650 | | Goodwill | 11,503 | | | 11,489 | |
| Regulatory assets | Regulatory assets | 3,481 | | | 3,419 | | Regulatory assets | 3,945 | | | 3,743 | |
| Investments and restricted cash, cash equivalents and investments | 16,728 | | | 15,788 | | |
| Investments and restricted cash and cash equivalents and investments | | Investments and restricted cash and cash equivalents and investments | 10,825 | | | 11,273 | |
| Other assets | Other assets | 3,372 | | | 3,144 | | Other assets | 3,273 | | | 3,290 | |
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| Total assets | Total assets | $ | 135,295 | | | $ | 132,065 | | Total assets | $ | 134,454 | | | $ | 133,840 | |
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 |
| | | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 2,290 | | | $ | 2,136 | | Accounts payable | $ | 2,109 | | | $ | 2,679 | |
| Accrued interest | Accrued interest | 557 | | | 537 | | Accrued interest | 701 | | | 558 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 789 | | | 606 | | Accrued property, income and other taxes | 625 | | | 746 | |
| Accrued employee expenses | Accrued employee expenses | 457 | | | 372 | | Accrued employee expenses | 351 | | | 333 | |
| Short-term debt | Short-term debt | 1,948 | | | 2,009 | | Short-term debt | 1,819 | | | 1,119 | |
| Current portion of long-term debt | Current portion of long-term debt | 2,069 | | | 1,265 | | Current portion of long-term debt | 3,090 | | | 3,201 | |
| Other current liabilities | Other current liabilities | 1,802 | | | 1,837 | | Other current liabilities | 1,720 | | | 1,677 | |
| Total current liabilities | Total current liabilities | 9,912 | | | 8,762 | | Total current liabilities | 10,415 | | | 10,313 | |
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| BHE senior debt | BHE senior debt | 13,594 | | | 13,003 | | BHE senior debt | 13,097 | | | 13,096 | |
| BHE junior subordinated debentures | BHE junior subordinated debentures | 100 | | | 100 | | BHE junior subordinated debentures | 100 | | | 100 | |
| Subsidiary debt | Subsidiary debt | 35,354 | | | 35,394 | | Subsidiary debt | 34,863 | | | 35,238 | |
| Regulatory liabilities | Regulatory liabilities | 7,028 | | | 6,960 | | Regulatory liabilities | 6,578 | | | 7,070 | |
| Deferred income taxes | Deferred income taxes | 13,394 | | | 12,938 | | Deferred income taxes | 12,705 | | | 12,678 | |
| Other long-term liabilities | Other long-term liabilities | 4,722 | | | 4,319 | | Other long-term liabilities | 5,045 | | | 4,706 | |
| Total liabilities | Total liabilities | 84,104 | | | 81,476 | | Total liabilities | 82,803 | | | 83,201 | |
| | | | | | | | | |
| Commitments and contingencies (Note 8) | 0 | | 0 | |
| Commitments and contingencies (Note 9) | | Commitments and contingencies (Note 9) | |
| | | | | | | | | |
| Equity: | Equity: | | | | Equity: | | | |
| BHE shareholders' equity: | BHE shareholders' equity: | | | | BHE shareholders' equity: | | | |
| Preferred stock - 100 shares authorized, $0.01 par value, 1 and 2 shares issued and outstanding | 850 | | | 1,650 | | |
| Preferred stock - 100 shares authorized, $0.01 par value, 1 and 1 shares issued and outstanding | | Preferred stock - 100 shares authorized, $0.01 par value, 1 and 1 shares issued and outstanding | 850 | | | 850 | |
| 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 | 6,298 | | | 6,374 | | Additional paid-in capital | 6,298 | | | 6,298 | |
| Long-term income tax receivable | (744) | | | (744) | | |
| | Retained earnings | Retained earnings | 42,688 | | | 40,754 | | Retained earnings | 42,814 | | | 41,833 | |
| Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | (1,788) | | | (1,340) | | Accumulated other comprehensive loss, net | (2,109) | | | (2,149) | |
| Total BHE shareholders' equity | Total BHE shareholders' equity | 47,304 | | | 46,694 | | Total BHE shareholders' equity | 47,853 | | | 46,832 | |
| Noncontrolling interests | Noncontrolling interests | 3,887 | | | 3,895 | | Noncontrolling interests | 3,798 | | | 3,807 | |
| Total equity | Total equity | 51,191 | | | 50,589 | | Total equity | 51,651 | | | 50,639 | |
| | | | | | | | | |
| Total liabilities and equity | Total liabilities and equity | $ | 135,295 | | | $ | 132,065 | | Total liabilities and equity | $ | 134,454 | | | $ | 133,840 | |
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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | |
| Energy | Energy | $ | 4,940 | | | $ | 4,301 | | | $ | 9,763 | | | $ | 9,150 | | Energy | | $ | 5,471 | | | $ | 4,823 | |
| Real estate | Real estate | 1,672 | | | 1,763 | | | 2,879 | | | 2,995 | | Real estate | | 875 | | | 1,207 | |
| Total operating revenue | Total operating revenue | 6,612 | | | 6,064 | | | 12,642 | | | 12,145 | | Total operating revenue | | 6,346 | | | 6,030 | |
| | | | | | | | | | | | | | |
| Operating expenses: | Operating expenses: | | | | | | | Operating expenses: | | | |
| Energy: | Energy: | | | | | | | Energy: | | | |
| Cost of sales | Cost of sales | 1,525 | | | 1,110 | | | 2,985 | | | 2,679 | | Cost of sales | | 1,955 | | | 1,460 | |
| Operations and maintenance | Operations and maintenance | 1,081 | | | 1,037 | | | 2,024 | | | 1,971 | | Operations and maintenance | | 1,542 | | | 943 | |
| Depreciation and amortization | Depreciation and amortization | 1,045 | | | 936 | | | 2,052 | | | 1,851 | | Depreciation and amortization | | 1,050 | | | 1,007 | |
| Property and other taxes | Property and other taxes | 199 | | | 189 | | | 404 | | | 399 | | Property and other taxes | | 212 | | | 205 | |
| Real estate | Real estate | 1,555 | | | 1,584 | | | 2,734 | | | 2,704 | | Real estate | | 920 | | | 1,179 | |
| Total operating expenses | Total operating expenses | 5,405 | | | 4,856 | | | 10,199 | | | 9,604 | | Total operating expenses | | 5,679 | | | 4,794 | |
| | | | | | | | | | | | | | |
| Operating income | Operating income | 1,207 | | | 1,208 | | | 2,443 | | | 2,541 | | Operating income | | 667 | | | 1,236 | |
| | | | | | | | | | | | | | |
| Other income (expense): | Other income (expense): | | | | | | | Other income (expense): | | | |
| Interest expense | Interest expense | (550) | | | (532) | | | (1,082) | | | (1,062) | | Interest expense | | (586) | | | (532) | |
| Capitalized interest | Capitalized interest | 18 | | | 14 | | | 35 | | | 28 | | Capitalized interest | | 24 | | | 17 | |
| Allowance for equity funds | Allowance for equity funds | 42 | | | 30 | | | 80 | | | 56 | | Allowance for equity funds | | 49 | | | 38 | |
| Interest and dividend income | Interest and dividend income | 30 | | | 26 | | | 53 | | | 47 | | Interest and dividend income | | 86 | | | 23 | |
| Gains on marketable securities, net | 2,528 | | | 1,966 | | | 1,271 | | | 848 | | |
| Gains (losses) on marketable securities, net | | Gains (losses) on marketable securities, net | | 699 | | | (1,257) | |
| Other, net | Other, net | (26) | | | 48 | | | (21) | | | 56 | | Other, net | | 40 | | | 5 | |
| Total other income (expense) | Total other income (expense) | 2,042 | | | 1,552 | | | 336 | | | (27) | | Total other income (expense) | | 312 | | | (1,706) | |
| | | | | | | | | | | | | | |
| Income before income tax expense (benefit) and equity loss | 3,249 | | | 2,760 | | | 2,779 | | | 2,514 | | |
| Income (loss) before income tax expense (benefit) and equity income (loss) | | Income (loss) before income tax expense (benefit) and equity income (loss) | | 979 | | | (470) | |
| Income tax expense (benefit) | Income tax expense (benefit) | 149 | | | 327 | | | (358) | | | (208) | | Income tax expense (benefit) | | (162) | | | (507) | |
| Equity loss | (83) | | | (50) | | | (140) | | | (229) | | |
| Net income | 3,017 | | | 2,383 | | | 2,997 | | | 2,493 | | |
| Equity income (loss) | | Equity income (loss) | | (38) | | | (57) | |
| Net income (loss) | | Net income (loss) | | 1,103 | | | (20) | |
| Net income attributable to noncontrolling interests | Net income attributable to noncontrolling interests | 120 | | | 102 | | | 229 | | | 208 | | Net income attributable to noncontrolling interests | | 114 | | | 109 | |
| Net income attributable to BHE shareholders | 2,897 | | | 2,281 | | | 2,768 | | | 2,285 | | |
| Net income (loss) attributable to BHE shareholders | | Net income (loss) attributable to BHE shareholders | | 989 | | | (129) | |
| Preferred dividends | Preferred dividends | 13 | | | 37 | | | 29 | | | 75 | | Preferred dividends | | 8 | | | 16 | |
| Earnings on common shares | $ | 2,884 | | | $ | 2,244 | | | $ | 2,739 | | | $ | 2,210 | | |
| Earnings (loss) on common shares | | Earnings (loss) on common shares | | $ | 981 | | | $ | (145) | |
The accompanying notes are an integral part of these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three-Month Periods | | Six-Month Periods |
| Ended June 30, | | Ended June 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | | |
| Net income | $ | 3,017 | | | $ | 2,383 | | | $ | 2,997 | | | $ | 2,493 | |
| | | | | | | | |
| Other comprehensive (loss) income, net of tax: | | | | | | | |
| Unrecognized amounts on retirement benefits, net of tax of $9, $1, $12 and $5 | 25 | | | 15 | | | 40 | | | 22 | |
| Foreign currency translation adjustment | (481) | | | 68 | | | (591) | | | 159 | |
| 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 | (430) | | | 84 | | | (448) | | | 196 | |
| | | | | | | | |
| Comprehensive income | 2,587 | | | 2,467 | | | 2,549 | | | 2,689 | |
| Comprehensive income attributable to noncontrolling interests | 120 | | | 106 | | | 229 | | | 212 | |
| Comprehensive income attributable to BHE shareholders | $ | 2,467 | | | $ | 2,361 | | | $ | 2,320 | | | $ | 2,477 | |
| | | | | | | | | | | | | | | |
| | | | Three-Month Periods |
| | | Ended March 31, |
| | | | | | 2023 | | 2022 |
| | | | | | | | |
| Net income (loss) | | | | | $ | 1,103 | | | $ | (20) | |
| | | | | | | | |
| Other comprehensive income (loss), net of tax: | | | | | | | |
| Unrecognized amounts on retirement benefits, net of tax of $(3) and $3 | | | | | (4) | | | 15 | |
| Foreign currency translation adjustment | | | | | 99 | | | (110) | |
| Unrealized (losses) gains on cash flow hedges, net of tax of $(20) and $28 | | | | | (55) | | | 77 | |
| Total other comprehensive income (loss), net of tax | | | | | 40 | | | (18) | |
| | | | | | | | |
| Comprehensive income (loss) | | | | | 1,143 | | | (38) | |
| Comprehensive income attributable to noncontrolling interests | | | | | 114 | | | 109 | |
| Comprehensive income (loss) attributable to BHE shareholders | | | | | $ | 1,029 | | | $ | (147) | |
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, March 31, 2021 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 35,060 | | | $ | (1,440) | | | $ | 3,962 | | | $ | 47,051 | | |
| | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2021 | | Balance, December 31, 2021 | $ | 1,650 | | | $ | — | | | $ | 6,374 | | | $ | (744) | | | $ | 40,754 | | | $ | (1,340) | | | $ | 3,895 | | | $ | 50,589 | |
| Net (loss) income | | Net (loss) income | — | | | — | | | — | | | — | | | (129) | | | — | | | 109 | | | (20) | |
| Other comprehensive loss | | Other comprehensive loss | — | | | — | | | — | | | — | | | — | | | (18) | | | — | | | (18) | |
| | Preferred stock dividend | | Preferred stock dividend | — | | | — | | | — | | | — | | | (16) | | | — | | | — | | | (16) | |
| | Distributions | | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (116) | | | (116) | |
| | Other equity transactions | | Other equity transactions | — | | | — | | | — | | | — | | | (1) | | | — | | | 6 | | | 5 | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | 1,650 | | | $ | — | | | $ | 6,374 | | | $ | (744) | | | $ | 40,608 | | | $ | (1,358) | | | $ | 3,894 | | | $ | 50,424 | |
| | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2022 | | Balance, December 31, 2022 | $ | 850 | | | $ | — | | | $ | 6,298 | | | $ | — | | | $ | 41,833 | | | $ | (2,149) | | | $ | 3,807 | | | $ | 50,639 | |
| Net income | Net income | — | | | — | | | — | | | — | | | 2,281 | | | — | | | 102 | | | 2,383 | | Net income | — | | | — | | | — | | | — | | | 989 | | | — | | | 114 | | | 1,103 | |
| Other comprehensive income | Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 80 | | | 4 | | | 84 | | Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 40 | | | — | | | 40 | |
| | Preferred stock dividend | Preferred stock dividend | — | | | — | | | — | | | — | | | (37) | | | — | | | — | | | (37) | | Preferred stock dividend | — | | | — | | | — | | | — | | | (8) | | | — | | | — | | | (8) | |
| | Distributions | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (121) | | | (121) | | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (125) | | | (125) | |
| Contributions | Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 9 | | | 9 | | Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 2 | | | 2 | |
| | Other equity transactions | — | | | — | | | — | | | — | | | (1) | | | — | | | (3) | | | (4) | | |
| Balance, June 30, 2021 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 37,303 | | | $ | (1,360) | | | $ | 3,953 | | | $ | 49,365 | | |
| | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2020 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 35,093 | | | $ | (1,552) | | | $ | 3,967 | | | $ | 46,977 | | |
| Net income | — | | | — | | | — | | | — | | | 2,285 | | | — | | | 208 | | | 2,493 | | |
| Other comprehensive income | — | | | — | | | — | | | — | | | — | | | 192 | | | 4 | | | 196 | | |
| Preferred stock dividend | — | | | — | | | — | | | — | | | (75) | | | — | | | — | | | (75) | | |
| | Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (234) | | | (234) | | |
| Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 9 | | | 9 | | |
| | Other equity transactions | — | | | — | | | — | | | — | | | — | | | — | | | (1) | | | (1) | | |
| Balance, June 30, 2021 | $ | 3,750 | | | $ | — | | | $ | 6,377 | | | $ | (658) | | | $ | 37,303 | | | $ | (1,360) | | | $ | 3,953 | | | $ | 49,365 | | |
| | Balance, March 31, 2022 | $ | 1,650 | | | $ | — | | | $ | 6,374 | | | $ | (744) | | | $ | 40,608 | | | $ | (1,358) | | | $ | 3,894 | | | $ | 50,424 | | |
| Net income | — | | | — | | | — | | | — | | | 2,897 | | | — | | | 120 | | | 3,017 | | |
| Other comprehensive loss | — | | | — | | | — | | | — | | | — | | | (430) | | | — | | | (430) | | |
| Preferred stock redemptions | (800) | | | — | | | — | | | — | | | — | | | — | | | — | | | (800) | | |
| Preferred stock dividend | — | | | — | | | — | | | — | | | (13) | | | — | | | — | | | (13) | | |
| Common stock purchases | — | | | — | | | (77) | | | — | | | (793) | | | — | | | — | | | (870) | | |
| Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (129) | | | (129) | | |
| Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 2 | | | 2 | | |
| | Other equity transactions | — | | | — | | | 1 | | | — | | | (11) | | | — | | | — | | | (10) | | |
| Balance, June 30, 2022 | $ | 850 | | | $ | — | | | $ | 6,298 | | | $ | (744) | | | $ | 42,688 | | | $ | (1,788) | | | $ | 3,887 | | | $ | 51,191 | | |
| | | | | | | | | | | | | | | | | |
| Balance, December 31, 2021 | $ | 1,650 | | | $ | — | | | $ | 6,374 | | | $ | (744) | | | $ | 40,754 | | | $ | (1,340) | | | $ | 3,895 | | | $ | 50,589 | | |
| Net income | — | | | — | | | — | | | — | | | 2,768 | | | — | | | 229 | | | 2,997 | | |
| Other comprehensive loss | — | | | — | | | — | | | — | | | — | | | (448) | | | — | | | (448) | | |
| Preferred stock redemptions | (800) | | | — | | | — | | | — | | | — | | | — | | | — | | | (800) | | |
| Preferred stock dividend | — | | | — | | | — | | | — | | | (29) | | | — | | | — | | | (29) | | |
| Common stock purchases | — | | | — | | | (77) | | | — | | | (793) | | | — | | | — | | | (870) | | |
| Distributions | — | | | — | | | — | | | — | | | — | | | — | | | (245) | | | (245) | | |
| Contributions | — | | | — | | | — | | | — | | | — | | | — | | | 2 | | | 2 | | |
| | Other equity transactions | — | | | — | | | 1 | | | — | | | (12) | | | — | | | 6 | | | (5) | | |
| Balance, June 30, 2022 | $ | 850 | | | $ | — | | | $ | 6,298 | | | $ | (744) | | | $ | 42,688 | | | $ | (1,788) | | | $ | 3,887 | | | $ | 51,191 | | |
| Balance, March 31, 2023 | | Balance, March 31, 2023 | $ | 850 | | | $ | — | | | $ | 6,298 | | | $ | — | | | $ | 42,814 | | | $ | (2,109) | | | $ | 3,798 | | | $ | 51,651 | |
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) | | | | Six-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended March 31, |
| | | 2022 | | 2021 | | 2023 | | 2022 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | $ | 2,997 | | | $ | 2,493 | | |
| Adjustments to reconcile net income to net cash flows from operating activities: | | |
| Gains on marketable securities, net | (1,271) | | | (848) | | |
| Net income (loss) | | Net income (loss) | $ | 1,103 | | | $ | (20) | |
| Adjustments to reconcile net income (loss) to net cash flows from operating activities: | | Adjustments to reconcile net income (loss) to net cash flows from operating activities: | |
| (Gains) losses on marketable securities, net | | (Gains) losses on marketable securities, net | (699) | | | 1,257 | |
| Depreciation and amortization | Depreciation and amortization | 2,081 | | | 1,874 | | Depreciation and amortization | 1,063 | | | 1,022 | |
| Allowance for equity funds | Allowance for equity funds | (80) | | | (56) | | Allowance for equity funds | (49) | | | (38) | |
| Equity loss, net of distributions | 202 | | | 313 | | |
| Changes in regulatory assets and liabilities | (226) | | | (199) | | |
| Equity (income) loss, net of distributions | | Equity (income) loss, net of distributions | 68 | | | 88 | |
| Net power cost deferrals | | Net power cost deferrals | (504) | | | (72) | |
| Amortization of net power cost deferrals | | Amortization of net power cost deferrals | 130 | | | 47 | |
| Other changes in regulatory assets and liabilities | | Other changes in regulatory assets and liabilities | (26) | | | (17) | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 385 | | | 613 | | Deferred income taxes and investment tax credits, net | (11) | | | (203) | |
| Other, net | Other, net | 37 | | | (26) | | Other, net | 15 | | | 6 | |
| 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 | (317) | | | (254) | | Trade receivables and other assets | 120 | | | 333 | |
| Derivative collateral, net | Derivative collateral, net | 189 | | | 92 | | Derivative collateral, net | (225) | | | 85 | |
| Pension and other postretirement benefit plans | Pension and other postretirement benefit plans | (21) | | | (33) | | Pension and other postretirement benefit plans | (7) | | | (11) | |
| Accrued property, income and other taxes, net | Accrued property, income and other taxes, net | 489 | | | 76 | | Accrued property, income and other taxes, net | (177) | | | (347) | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 682 | | | 187 | | Accounts payable and other liabilities | 294 | | | 91 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 5,147 | | | 4,232 | | Net cash flows from operating activities | 1,095 | | | 2,221 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | | | Cash flows from investing activities: | | | |
| Capital expenditures | Capital expenditures | (3,382) | | | (2,848) | | Capital expenditures | (1,848) | | | (1,553) | |
| | Purchases of marketable securities | Purchases of marketable securities | (281) | | | (185) | | Purchases of marketable securities | (106) | | | (170) | |
| Proceeds from sales of marketable securities | Proceeds from sales of marketable securities | 257 | | | 163 | | Proceeds from sales of marketable securities | 1,091 | | | 149 | |
| | Purchases of U.S. Treasury Bills | | Purchases of U.S. Treasury Bills | (1,519) | | | — | |
| Proceeds from maturities of U.S. Treasury Bills | | Proceeds from maturities of U.S. Treasury Bills | 623 | | | — | |
| Equity method investments | Equity method investments | (28) | | | (52) | | Equity method investments | (19) | | | (17) | |
| Other, net | Other, net | (18) | | | (53) | | Other, net | — | | | 19 | |
| Net cash flows from investing activities | Net cash flows from investing activities | (3,452) | | | (2,975) | | Net cash flows from investing activities | (1,778) | | | (1,572) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | | | Cash flows from financing activities: | | | |
| | Preferred stock redemptions | (800) | | | — | | |
| Common stock purchases | (870) | | | — | | |
| Proceeds from BHE senior debt | 987 | | | — | | |
| | Repayments of BHE senior debt | Repayments of BHE senior debt | — | | | (450) | | Repayments of BHE senior debt | (400) | | | — | |
| Preferred dividends | (33) | | | (75) | | |
| Proceeds from subsidiary debt | Proceeds from subsidiary debt | 1,201 | | | 539 | | Proceeds from subsidiary debt | — | | | 405 | |
| Repayments of subsidiary debt | Repayments of subsidiary debt | (542) | | | (1,210) | | Repayments of subsidiary debt | (136) | | | (193) | |
| Net (repayments of) proceeds from short-term debt | (54) | | | 245 | | |
| Net proceeds from (repayments of) short-term debt | | Net proceeds from (repayments of) short-term debt | 699 | | | (165) | |
| | Distributions to noncontrolling interests | Distributions to noncontrolling interests | (246) | | | (234) | | Distributions to noncontrolling interests | (126) | | | (117) | |
| | Other, net | Other, net | (248) | | | (19) | | Other, net | (17) | | | (240) | |
| Net cash flows from financing activities | Net cash flows from financing activities | (605) | | | (1,204) | | Net cash flows from financing activities | 20 | | | (310) | |
| | Effect of exchange rate changes | Effect of exchange rate changes | (33) | | | 2 | | Effect of exchange rate changes | 1 | | | (1) | |
| | 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 | 1,057 | | | 55 | | Net change in cash and cash equivalents and restricted cash and cash equivalents | (662) | | | 338 | |
| 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 | 1,244 | | | 1,445 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 1,817 | | | 1,244 | |
| 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 | $ | 2,301 | | | $ | 1,500 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 1,155 | | | $ | 1,582 | |
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 8eight 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 and its subsidiaries), BHE Renewables, LLC and its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through these locally managed and operated businesses, owns 4four utility companies in the U.S. serving customers in 11 states, 2two electricity distribution companies in Great Britain, 5five interstate natural gas pipeline companies and interests in a liquefied natural gas ("LNG") export, import and storage facility in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, one of the largest residential real estate brokerage firm in the U.S.firms and 1 of the largest residential real estate brokerage franchise networks in the 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 June 30, 2022March 31, 2023, and for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The results of operations for the three- and six-month periodsthree-month period ended June 30, 2022March 31, 2023, 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, 20212022, 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 accounting policies or its assumptions regarding significant accounting estimates and policies during the six-monththree-month period ended June 30, 2022,March 31, 2023, other than the updates associated with the Company's estimates of loss contingencies related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and the 2022 McKinney fire as discussed in Note 8.9.
(2) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | | | | As of | | | | As of |
| | | Depreciable | | June 30, | | December 31, | | Depreciable | | March 31, | | December 31, |
| | Life | | 2022 | | 2021 | | Life | | 2023 | | 2022 |
| Regulated assets: | Regulated assets: | | | | | | Regulated assets: | | | | | |
| Utility generation, transmission and distribution systems | Utility generation, transmission and distribution systems | 5-80 years | | $ | 90,810 | | | $ | 90,223 | | Utility generation, transmission and distribution systems | 5-80 years | | $ | 93,123 | | | $ | 92,759 | |
| Interstate natural gas pipeline assets | Interstate natural gas pipeline assets | 3-80 years | | 17,547 | | | 17,423 | | Interstate natural gas pipeline assets | 3-80 years | | 18,492 | | | 18,328 | |
| | | | 108,357 | | | 107,646 | | | | 111,615 | | | 111,087 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (33,618) | | | (32,680) | | Accumulated depreciation and amortization | | (35,395) | | | (34,599) | |
| Regulated assets, net | Regulated assets, net | | 74,739 | | | 74,966 | | Regulated assets, net | | 76,220 | | | 76,488 | |
| | | | | | | | | | | |
| Nonregulated assets: | Nonregulated assets: | | | | | Nonregulated assets: | | | | |
| Independent power plants | Independent power plants | 2-50 years | | 8,073 | | | 7,665 | | Independent power plants | 2-50 years | | 8,514 | | | 8,545 | |
| Cove Point LNG facility | Cove Point LNG facility | 40 years | | 3,373 | | | 3,364 | | Cove Point LNG facility | 40 years | | 3,416 | | | 3,412 | |
| Other assets | Other assets | 2-30 years | | 3,042 | | | 2,666 | | Other assets | 2-30 years | | 2,680 | | | 2,693 | |
| | | | 14,488 | | | 13,695 | | | | 14,610 | | | 14,650 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (3,206) | | | (3,041) | | Accumulated depreciation and amortization | | (3,493) | | | (3,452) | |
| Nonregulated assets, net | Nonregulated assets, net | | 11,282 | | | 10,654 | | Nonregulated assets, net | | 11,117 | | | 11,198 | |
| | | | | | | | | | | |
| Net operating assets | | 86,021 | | | 85,620 | | |
| | | | 87,337 | | | 87,686 | |
| Construction work-in-progress | Construction work-in-progress | | 4,774 | | | 4,196 | | Construction work-in-progress | | 6,246 | | | 5,357 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 90,795 | | | $ | 89,816 | | Property, plant and equipment, net | | $ | 93,583 | | | $ | 93,043 | |
Construction work-in-progress includes $4.4$5.8 billion as of June 30, 2022March 31, 2023 and $3.8$4.9 billion as of December 31, 2021,2022, related to the construction of regulated assets.
(3) 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 |
| | | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Investments: | Investments: | | | | Investments: | | | |
| BYD Company Limited common stock | BYD Company Limited common stock | $ | 9,003 | | | $ | 7,693 | | BYD Company Limited common stock | $ | 3,321 | | | $ | 3,763 | |
| U.S. Treasury Bills | | U.S. Treasury Bills | 2,854 | | | 1,931 | |
| Rabbi trusts | Rabbi trusts | 429 | | | 492 | | Rabbi trusts | 449 | | | 433 | |
| Other | Other | 328 | | | 305 | | Other | 318 | | | 335 | |
| Total investments | Total investments | 9,760 | | | 8,490 | | Total investments | 6,942 | | | 6,462 | |
| | | | | | | | | |
| Equity method investments: | Equity method investments: | | Equity method investments: | |
| BHE Renewables tax equity investments | BHE Renewables tax equity investments | 4,680 | | | 4,931 | | BHE Renewables tax equity investments | 4,430 | | | 4,535 | |
| Electric Transmission Texas, LLC | | Electric Transmission Texas, LLC | 641 | | | 623 | |
| Iroquois Gas Transmission System, L.P. | Iroquois Gas Transmission System, L.P. | 742 | | | 735 | | Iroquois Gas Transmission System, L.P. | 604 | | | 600 | |
| Electric Transmission Texas, LLC | 606 | | | 595 | | |
| | Other | Other | 302 | | | 293 | | Other | 352 | | | 304 | |
| Total equity method investments | Total equity method investments | 6,330 | | | 6,554 | | Total equity method investments | 6,027 | | | 6,062 | |
| | Restricted cash, cash equivalents and investments: | | | | |
| Restricted cash and cash equivalents and investments: | | Restricted cash and cash equivalents and investments: | | | |
| Quad Cities Station nuclear decommissioning trust funds | Quad Cities Station nuclear decommissioning trust funds | 658 | | | 768 | | Quad Cities Station nuclear decommissioning trust funds | 696 | | | 664 | |
| Other restricted cash and cash equivalents | Other restricted cash and cash equivalents | 220 | | | 148 | | Other restricted cash and cash equivalents | 192 | | | 226 | |
| Total restricted cash, cash equivalents and investments | 878 | | | 916 | | |
| Total restricted cash and cash equivalents and investments | | Total restricted cash and cash equivalents and investments | 888 | | | 890 | |
| | | | | | | | | |
| Total investments and restricted cash, cash equivalents and investments | $ | 16,968 | | | $ | 15,960 | | |
| Total investments and restricted cash and cash equivalents and investments | | Total investments and restricted cash and cash equivalents and investments | $ | 13,857 | | | $ | 13,414 | |
| | Reflected as: | Reflected as: | | Reflected as: | |
| Current assets | $ | 240 | | | $ | 172 | | |
| Other current assets | | Other current assets | $ | 3,032 | | | $ | 2,141 | |
| Noncurrent assets | Noncurrent assets | 16,728 | | | 15,788 | | Noncurrent assets | 10,825 | | | 11,273 | |
| Total investments and restricted cash, cash equivalents and investments | $ | 16,968 | | | $ | 15,960 | | |
| Total investments and restricted cash and cash equivalents and investments | | Total investments and restricted cash and cash equivalents and investments | $ | 13,857 | | | $ | 13,414 | |
Investments
Gains (losses) on marketable securities, net recognized during the period consists of the following (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2023 | | 2022 |
| Unrealized gains (losses) recognized on marketable securities held at the reporting date | | | | | $ | 529 | | | $ | (1,257) | |
| Net gains recognized on marketable securities sold during the period | | | | | 170 | | | — | |
| Gains (losses) on marketable securities, net | | | | | $ | 699 | | | $ | (1,257) | |
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.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 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 presented inon 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 | | March 31, | | December 31, |
| | June 30, | | December 31, | | 2023 | | 2022 |
| | 2022 | | 2021 | | | | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 2,081 | | | $ | 1,096 | | Cash and cash equivalents | $ | 963 | | | $ | 1,591 | |
| Restricted cash and cash equivalents | 201 | | | 127 | | |
| Investments and restricted cash, cash equivalents and investments | 19 | | | 21 | | |
| Investments and restricted cash and cash equivalents | | Investments and restricted cash and cash equivalents | 133 | | | 173 | |
| Investments and restricted cash and cash equivalents and investments | | Investments and restricted cash and cash equivalents and investments | 59 | | | 53 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 2,301 | | | $ | 1,244 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 1,155 | | | $ | 1,817 | |
(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, 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 June 2022, BHE amended and restated its existing $3.5 billion unsecured credit facility expiring in June 2024. The amendmentApril 2023, AltaLink Investments, L.P. extended, with lender consent, the expiration date to June 2025 and amended pricing from the London Interbank Offered Rate ("LIBOR") to SOFR.
In June 2022, PacifiCorp amended and restatedfor its existing $1.2 billion unsecuredC$200 million one year revolving credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from LIBOR to SOFR.
In June 2022, MidAmerican Energy amended and restated its existing $1.5 billion unsecured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from LIBOR to SOFR.
In June 2022, Nevada Power and Sierra Pacific each amended and restated its existing $400 million and $250 million secured credit facilities expiring in June 2024. The amendments extended the expiration date to June 2025 and amended pricing from LIBOR to SOFR.April 2024, by exercising a one-year extension option.
(5) Income Taxes
The effective income tax rate for the three-month period ended March 31, 2022, is 108% and results from a $507 million income tax benefit associated with a $470 million pre-tax loss, primarily relating to a pre-tax unrealized loss of $1,247 million on the Company's investment in BYD Company Limited. The $507 million income tax benefit is primarily comprised of a $99 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss and a $339 million benefit (72%) from income tax credits.
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income (loss) before income tax benefitexpense (benefit) is as follows:
| | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| | | | | | | | | | | | | | |
| Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | | 21 | % | | 21 | % |
| Income tax credits | Income tax credits | (13) | | | (13) | | | (28) | | | (27) | | Income tax credits | | (35) | | | 72 | |
| State income tax, net of federal income tax impacts | State income tax, net of federal income tax impacts | (1) | | | 4 | | | — | | | 2 | | State income tax, net of federal income tax impacts | | (4) | | | (3) | |
| Income tax effect of foreign income | Income tax effect of foreign income | — | | | 3 | | | (1) | | | 3 | | Income tax effect of foreign income | | 7 | | | 3 | |
| Effects of ratemaking | Effects of ratemaking | (1) | | | (2) | | | (2) | | | (4) | | Effects of ratemaking | | (3) | | | 8 | |
| Equity income | Equity income | (1) | | | — | | | (1) | | | (2) | | Equity income | | (1) | | | 3 | |
| Noncontrolling interest | Noncontrolling interest | (1) | | | (1) | | | (2) | | | (2) | | Noncontrolling interest | | (2) | | | 5 | |
| Other, net | Other, net | 1 | | | — | | | — | | | 1 | | Other, net | | — | | | (1) | |
| Effective income tax rate | Effective income tax rate | 5 | % | | 12 | % | | (13) | % | | (8) | % | Effective income tax rate | | (17) | % | | 108 | % |
Income tax credits relate primarily to PTCsproduction tax credits ("PTCs") from wind-poweredwind- and solar-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity PTCs are earned as energy from qualifying wind-poweredwind- and solar-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-poweredWind- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the six-monththree-month periods ended June 30,March 31, 2023 and 2022 and 2021 totaled $734$343 million and $678$338 million, respectively.
Income tax effect on foreign income includes, among other items, a deferred income tax charge of $109$82 million recognized in June 2021 uponMarch 2023 related to the July 2022 enactment of a new Energy Profits Levy 25% income tax in the United Kingdom effective May 26, 2022, through December 31, 2025, as well as an increase in the United Kingdom's corporate income tax rate from 19%25% to 25%35% effective AprilJanuary 1, 2023, through March 31, 2028, enacted in January 2023.
The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated U.S. federal and Iowa state income tax returns and the majority of the Company's U.S. federal income tax is remitted to or received from Berkshire Hathaway. The Company received net cashmade no payments for federal income taxes fromto Berkshire Hathaway for the six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021 totaling $1,249 million and $943 million, respectively.2022.
15In July 2022, the Company amended its tax allocation agreement with Berkshire Hathaway, which changed how state tax attributes will be settled with respect to state income tax returns that Berkshire Hathaway includes the Company. As a result, the Company no longer expects to receive the cash benefits from the state of Iowa net operating loss carryforward previously recorded as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity, and recognized a noncash distribution of $744 million to retained earnings.
(6) 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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Pension: | Pension: | | | | | | | | Pension: | | | | |
| Service cost | Service cost | $ | 6 | | | $ | 8 | | | $ | 13 | | | $ | 15 | | Service cost | | $ | 4 | | | $ | 7 | |
| Interest cost | Interest cost | 19 | | | 18 | | | 38 | | | 38 | | Interest cost | | 28 | | | 19 | |
| Expected return on plan assets | Expected return on plan assets | (27) | | | (36) | | | (54) | | | (69) | | Expected return on plan assets | | (31) | | | (27) | |
| Settlement | Settlement | — | | | — | | | 2 | | | — | | Settlement | | (5) | | | 2 | |
| Net amortization | Net amortization | 5 | | | 7 | | | 9 | | | 13 | | Net amortization | | 4 | | | 4 | |
| Net periodic benefit cost (credit) | $ | 3 | | | $ | (3) | | | $ | 8 | | | $ | (3) | | |
| Net periodic benefit cost | | Net periodic benefit cost | | $ | — | | | $ | 5 | |
| | Other postretirement: | Other postretirement: | | Other postretirement: | | |
| Service cost | Service cost | $ | 4 | | | $ | 4 | | | $ | 6 | | | $ | 6 | | Service cost | | $ | 1 | | | $ | 2 | |
| Interest cost | Interest cost | 5 | | | 5 | | | 10 | | | 10 | | Interest cost | | 7 | | | 5 | |
| Expected return on plan assets | Expected return on plan assets | (7) | | | (6) | | | (14) | | | (11) | | Expected return on plan assets | | (8) | | | (7) | |
| Net amortization | Net amortization | (1) | | | (1) | | | (1) | | | (2) | | Net amortization | | (1) | | | — | |
| Net periodic benefit cost | $ | 1 | | | $ | 2 | | | $ | 1 | | | $ | 3 | | |
| Net periodic benefit (credit) cost | | Net periodic benefit (credit) cost | | $ | (1) | | | $ | — | |
Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other,other, net inon the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $5$7 million, respectively, during 2022.2023. As of June 30, 2022, $7March 31, 2023, $3 million and $5$1 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
Foreign Operations
Net periodic benefit creditcost (credit) for the United Kingdom pension plan included the following components (in millions):
| | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| | | | | | | | | | | | | | |
| Service cost | Service cost | $ | 3 | | | $ | 4 | | | $ | 7 | | | $ | 8 | | Service cost | | $ | 2 | | | $ | 4 | |
| Interest cost | Interest cost | 9 | | | 7 | | | 19 | | | 15 | | Interest cost | | 14 | | | 10 | |
| Expected return on plan assets | Expected return on plan assets | (23) | | | (28) | | | (48) | | | (56) | | Expected return on plan assets | | (19) | | | (25) | |
| | Net amortization | Net amortization | 6 | | | 14 | | | 12 | | | 28 | | Net amortization | | 6 | | | 6 | |
| Net periodic benefit credit | $ | (5) | | | $ | (3) | | | $ | (10) | | | $ | (5) | | |
| Net periodic benefit cost (credit) | | Net periodic benefit cost (credit) | | $ | 3 | | | $ | (5) | |
Amounts other than the service cost for the United Kingdom pension plan are recorded in Other,other, net inon the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £12£11 million during 2022.2023. As of June 30, 2022, £6March 31, 2023, £3 million, or $8$4 million, of contributions had been made to the United Kingdom pension plan.
(7) Asset Retirement Obligations
MidAmerican Energy estimates its asset retirement obligation ("ARO") liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of expected work. During the three-month period ended March 31, 2023, MidAmerican Energy recorded an increase of $88 million for decommissioning its wind-generating facilities due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.
(78) 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 June 30, 2022: | | | | | | | | | | | |
| As of March 31, 2023: | | As of March 31, 2023: | | | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | | $ | 11 | | | $ | 660 | | | $ | 77 | | | $ | (164) | | | $ | 584 | | Commodity derivatives | | $ | 3 | | | $ | 280 | | | $ | 16 | | | $ | (65) | | | $ | 234 | |
| | Interest rate derivatives | Interest rate derivatives | | 16 | | | 45 | | | 24 | | | — | | | 85 | | Interest rate derivatives | | 42 | | | 43 | | | 16 | | | — | | | 101 | |
| Mortgage loans held for sale | Mortgage loans held for sale | | — | | | 1,084 | | | — | | | — | | | 1,084 | | Mortgage loans held for sale | | — | | | 650 | | | — | | | — | | | 650 | |
| Money market mutual funds | Money market mutual funds | | 1,492 | | | — | | | — | | | — | | | 1,492 | | Money market mutual funds | | 671 | | | — | | | — | | | — | | | 671 | |
| Debt securities: | Debt securities: | | Debt securities: | |
| U.S. government obligations | U.S. government obligations | | 220 | | | — | | | — | | | — | | | 220 | | U.S. government obligations | | 3,079 | | | — | | | — | | | — | | | 3,079 | |
| International government obligations | International government obligations | | — | | | 1 | | | — | | | — | | | 1 | | International government obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Corporate obligations | Corporate obligations | | — | | | 75 | | | — | | | — | | | 75 | | Corporate obligations | | — | | | 70 | | | — | | | — | | | 70 | |
| Municipal obligations | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | | Municipal obligations | | — | | | 4 | | | — | | | — | | | 4 | |
| Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | | |
| | Equity securities: | Equity securities: | | Equity securities: | |
| U.S. companies | U.S. companies | | 348 | | | — | | | — | | | — | | | 348 | | U.S. companies | | 385 | | | — | | | — | | | — | | | 385 | |
| International companies | International companies | | 9,011 | | | — | | | — | | | — | | | 9,011 | | International companies | | 3,329 | | | — | | | — | | | — | | | 3,329 | |
| Investment funds | Investment funds | | 258 | | | — | | | — | | | — | | | 258 | | Investment funds | | 278 | | | — | | | — | | | — | | | 278 | |
| | | | $ | 11,356 | | | $ | 1,869 | | | $ | 101 | | | $ | (164) | | | $ | 13,162 | | | | $ | 7,787 | | | $ | 1,048 | | | $ | 32 | | | $ | (65) | | | $ | 8,802 | |
| Liabilities: | Liabilities: | | | | | | | | | | | Liabilities: | | | | | | | | | | |
| Commodity derivatives | Commodity derivatives | | $ | (14) | | | $ | (211) | | | $ | (255) | | | $ | 77 | | | $ | (403) | | Commodity derivatives | | $ | (8) | | | $ | (92) | | | $ | (166) | | | $ | 52 | | | $ | (214) | |
| Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | — | | | (19) | | | — | | | — | | | (19) | | Foreign currency exchange rate derivatives | | — | | | (20) | | | — | | | — | | | (20) | |
| Interest rate derivatives | Interest rate derivatives | | — | | | (6) | | | (3) | | | — | | | (9) | | Interest rate derivatives | | — | | | (5) | | | (1) | | | 1 | | | (5) | |
| | $ | (14) | | | $ | (236) | | | $ | (258) | | | $ | 77 | | | $ | (431) | | | $ | (8) | | | $ | (117) | | | $ | (167) | | | $ | 53 | | | $ | (239) | |
| | | 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, 2021: | | | | | | | | | | | |
| As of December 31, 2022: | | As of December 31, 2022: | | | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | | $ | 5 | | | $ | 271 | | | $ | 73 | | | $ | (47) | | | $ | 302 | | Commodity derivatives | | $ | 6 | | | $ | 614 | | | $ | 51 | | | $ | (194) | | | $ | 477 | |
| Foreign currency exchange rate derivatives | | — | | | 3 | | | — | | | — | | | 3 | | |
| | Interest rate derivatives | Interest rate derivatives | | 1 | | | 3 | | | 20 | | | — | | | 24 | | Interest rate derivatives | | 50 | | | 54 | | | 8 | | | — | | | 112 | |
| Mortgage loans held for sale | Mortgage loans held for sale | | — | | | 1,263 | | | — | | | — | | | 1,263 | | Mortgage loans held for sale | | — | | | 474 | | | — | | | — | | | 474 | |
| Money market mutual funds | Money market mutual funds | | 554 | | | — | | | — | | | — | | | 554 | | Money market mutual funds | | 1,178 | | | — | | | — | | | — | | | 1,178 | |
| Debt securities: | Debt securities: | | Debt securities: | |
| U.S. government obligations | U.S. government obligations | | 232 | | | — | | | — | | | — | | | 232 | | U.S. government obligations | | 2,146 | | | — | | | — | | | — | | | 2,146 | |
| International government obligations | International government obligations | | — | | | 2 | | | — | | | — | | | 2 | | International government obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Corporate obligations | Corporate obligations | | — | | | 90 | | | — | | | — | | | 90 | | Corporate obligations | | — | | | 70 | | | — | | | — | | | 70 | |
| Municipal obligations | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
| Agency, asset and mortgage-backed obligations | Agency, asset and mortgage-backed obligations | | — | | | 2 | | | — | | | — | | | 2 | | Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Equity securities: | Equity securities: | | Equity securities: | |
| U.S. companies | U.S. companies | | 428 | | | — | | | — | | | — | | | 428 | | U.S. companies | | 360 | | | — | | | — | | | — | | | 360 | |
| International companies | International companies | | 7,703 | | | — | | | — | | | — | | | 7,703 | | International companies | | 3,771 | | | — | | | — | | | — | | | 3,771 | |
| Investment funds | Investment funds | | 237 | | | — | | | — | | | — | | | 237 | | Investment funds | | 231 | | | — | | | — | | | — | | | 231 | |
| | | | $ | 9,160 | | | $ | 1,637 | | | $ | 93 | | | $ | (47) | | | $ | 10,843 | | | | $ | 7,742 | | | $ | 1,217 | | | $ | 59 | | | $ | (194) | | | $ | 8,824 | |
| Liabilities: | Liabilities: | | | | | | | | | | | Liabilities: | | | | | | | | | | |
| Commodity derivatives | Commodity derivatives | | $ | (2) | | | $ | (113) | | | $ | (224) | | | $ | 73 | | | $ | (266) | | Commodity derivatives | | $ | (8) | | | $ | (206) | | | $ | (110) | | | $ | 106 | | | $ | (218) | |
| Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | — | | | (3) | | | — | | | — | | | (3) | | Foreign currency exchange rate derivatives | | — | | | (21) | | | — | | | — | | | (21) | |
| Interest rate derivatives | Interest rate derivatives | | — | | | (7) | | | (1) | | | — | | | (8) | | Interest rate derivatives | | — | | | (2) | | | (2) | | | 1 | | | (3) | |
| | $ | (2) | | | $ | (123) | | | $ | (225) | | | $ | 73 | | | $ | (277) | | | $ | (8) | | | $ | (229) | | | $ | (112) | | | $ | 107 | | | $ | (242) | |
(1)Represents netting under master netting arrangements and a net cash collateral payable of $87$12 million and receivable of $26$87 million as of June 30, 2022March 31, 2023 and December 31, 2021,2022, 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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | Interest | | | Interest | | | | Interest |
| | | Commodity | | Rate | | Commodity | | Rate | | | Commodity | | Rate |
| | Derivatives | | Derivatives | | Derivatives | | Derivatives | | | Derivatives | | Derivatives |
| 2022: | | | | | | | | |
| 2023: | | 2023: | | | | |
| Beginning balance | Beginning balance | $ | (239) | | | $ | 13 | | | $ | (151) | | | $ | 19 | | Beginning balance | | $ | (59) | | | $ | 6 | |
Changes included in earnings(1) | Changes included in earnings(1) | (26) | | | 8 | | | (82) | | | 2 | | Changes included in earnings(1) | | 9 | | | 9 | |
| Changes in fair value recognized in OCI | Changes in fair value recognized in OCI | 5 | | | — | | | 10 | | | — | | Changes in fair value recognized in OCI | | (3) | | | — | |
| Changes in fair value recognized in net regulatory assets | Changes in fair value recognized in net regulatory assets | 1 | | | — | | | (59) | | | — | | Changes in fair value recognized in net regulatory assets | | (98) | | | — | |
| | Purchases | 1 | | | — | | | 1 | | | — | | |
| | | Settlements | Settlements | 11 | | | — | | | 34 | | | — | | Settlements | | 1 | | | — | |
| Transfers out of Level 3 into Level 2 | 69 | | | — | | | 69 | | | — | | |
| | | Ending balance | Ending balance | $ | (178) | | | $ | 21 | | | $ | (178) | | | $ | 21 | | Ending balance | | $ | (150) | | | $ | 15 | |
| | | | 2021: | | |
| 2022: | | 2022: | | |
| Beginning balance | Beginning balance | $ | 124 | | | $ | 41 | | | $ | 116 | | | $ | 62 | | Beginning balance | | $ | (151) | | | $ | 19 | |
Changes included in earnings(1) | Changes included in earnings(1) | (10) | | | — | | | (16) | | | (21) | | Changes included in earnings(1) | | (56) | | | (6) | |
| Changes in fair value recognized in OCI | Changes in fair value recognized in OCI | (6) | | | — | | | (7) | | | — | | Changes in fair value recognized in OCI | | 5 | | | — | |
| Changes in fair value recognized in net regulatory assets | Changes in fair value recognized in net regulatory assets | (7) | | | — | | | 9 | | | — | | Changes in fair value recognized in net regulatory assets | | (60) | | | — | |
| Purchases | 1 | | | — | | | 1 | | | — | | |
| | | Settlements | Settlements | 3 | | | — | | | 2 | | | — | | Settlements | | 23 | | | — | |
| | Ending balance | Ending balance | $ | 105 | | | $ | 41 | | | $ | 105 | | | $ | 41 | | Ending balance | | $ | (239) | | | $ | 13 | |
(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 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 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of March 31, 2023 | | As of December 31, 2022 |
| | Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | | |
| Long-term debt | $ | 51,150 | | | $ | 47,805 | | | $ | 51,635 | | | $ | 46,906 | |
(8)9) Commitments and Contingencies
Commitments
The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheets.
Construction Commitments
During the six-month period ended June 30, 2022,In April 2023, PacifiCorp entered into a procurement and construction services agreement for $849 millionbuild transfer agreements totaling $1.2 billion through 20242025 for the construction of a keycertain wind-powered generating facilities in Wyoming.
During the three-month period ended March 31, 2023, MidAmerican Energy Gateway Transmission segment extending betweenentered into firm construction commitments totaling $183 million for the Aeolus substation near Medicine Bow, Wyoming andremainder of 2023 through 2024 related to the Clover substation near Mona, Utah.construction of wind-powered generating facilities in Iowa.
Fuel Contracts
During the six-monththree-month period ended June 30, 2022,March 31, 2023, PacifiCorp entered into certain coal supply and transportation agreements totaling approximately$247 million through 2025.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, hazardous 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.
Lower Klamath Hydroelectric Project
In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility is anticipated to begin in 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has $450 million in funding available for dam removal and restoration; $200 million through 2024.collected from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $45 million contingency fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete.
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.
2020 WildfiresWildfire Liability Overview
A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures 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.
Multiple 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 from wildfires 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;damages; fire suppression costs; personal injury and loss of life damages; and interest.
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over 500,000 acres in aggregate. Third-party reports for these wildfires indicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million.
During
Investigations into the three-month period ended June 30, 2022,cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, numerous lawsuits have been filed in Oregon and California, including a class action complaint in Oregon, on behalf of plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of litigation and recent settlements, PacifiCorp has accrued $64 million ofcumulative estimated probable losses net of expected insurance recoveries associated with the 2020 Wildfires resulting in an overall lossof $877 million through March 31, 2023. PacifiCorp's cumulative accrual net of expected insurance recoveries of $200 million as of June 30, 2022 compared to $136 million as of December 31, 2021. These accruals include PacifiCorp's estimateincludes estimates of losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life 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 certain areas of 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 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.
The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires (in millions):
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2023 | | 2022 |
| Beginning balance | $ | 424 | | | $ | 252 | |
| Accrued losses | 400 | | | — | |
| | | |
| Ending balance | $ | 824 | | | $ | 252 | |
PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $277$287 million and $246 million, respectively, as of June 30,March 31, 2023 and December 31, 2022. During the three-month periods ended March 31, 2023 and 2022 PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $359 million and $— million, respectively, and are recorded in operations and maintenance on the Consolidated Statements of Operations.
Environmental Laws and Regulations2022 McKinney Fire
According to the California Department of Forestry and Fire Protection, on July 29, 2022, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and four fatalities and consumed 60,000 acres. The Companycause of the 2022 McKinney Fire is subject to federal, state, localundetermined 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 haveremains under investigation by 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.U.S. Forest Service.
Hydroelectric RelicensingDue to the preliminary nature of the investigation PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $31 million, net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp is unable to estimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $103 million, to cover potential losses.
PacifiCorp is a partyAs of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related 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.2022 McKinney Fire. The KHSA establishes a process for PacifiCorp, the states of Oregonplaintiffs seek damages that include property damages, economic and California ("States")noneconomic losses, punitive damages, exemplary damages, attorneys' fees and other stakeholders to assess whether dam removal can occur consistent withdamages but the settlement's terms. For PacifiCorp, the key elementsamount 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) transferdamages sought are not specified. Final determinations 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 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. 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. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property 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 only be effective within 30 daysmade following the issuancecompletion 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.comprehensive investigations and litigation processes.
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.
(9)(10) Revenue from Contracts with Customers
Energy Products and Services
The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business, including a reconciliation to the Company's reportable segment information included in Note 12 (in millions):
| | | For the Three-Month Period Ended June 30, 2022 | | For the Three-Month Period Ended March 31, 2023 |
| | 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 | | $ | 1,167 | | | $ | 594 | | | $ | 831 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 2,591 | | Retail electric | | $ | 1,349 | | | $ | 491 | | | $ | 848 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,688 | |
| Retail gas | Retail gas | | — | | | 136 | | | 28 | | | — | | | — | | | — | | | — | | | — | | | 164 | | Retail gas | | — | | | 296 | | | 96 | | | — | | | — | | | — | | | — | | | — | | | 392 | |
| Wholesale | Wholesale | | 55 | | | 119 | | | 15 | | | — | | | — | | | — | | | — | | | (2) | | | 187 | | Wholesale | | 61 | | | 100 | | | 31 | | | — | | | — | | | — | | | — | | | (1) | | | 191 | |
Transmission and
distribution | Transmission and
distribution | | 45 | | | 13 | | | 18 | | | 274 | | | — | | | 172 | | | — | | | — | | | 522 | | Transmission and
distribution | | 38 | | | 14 | | | 18 | | | 281 | | | — | | | 165 | | | — | | | — | | | 516 | |
| Interstate pipeline | Interstate pipeline | | — | | | — | | | — | | | — | | | 524 | | | — | | | — | | | (27) | | | 497 | | Interstate pipeline | | — | | | — | | | — | | | — | | | 878 | | | — | | | — | | | (56) | | | 822 | |
| Other | Other | | 28 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 28 | | Other | | 32 | | | — | | | — | | | — | | | 2 | | | — | | | — | | | — | | | 34 | |
| Total Regulated | Total Regulated | | 1,295 | | | 862 | | | 892 | | | 274 | | | 524 | | | 172 | | | — | | | (30) | | | 3,989 | | Total Regulated | | 1,480 | | | 901 | | | 993 | | | 281 | | | 880 | | | 165 | | | — | | | (57) | | | 4,643 | |
| Nonregulated | Nonregulated | | — | | | — | | | 1 | | | 42 | | | 285 | | | 15 | | | 262 | | | 151 | | | 756 | | Nonregulated | | — | | | 3 | | | 1 | | | 45 | | | 266 | | | 40 | | | 305 | | | — | | | 660 | |
| Total Customer Revenue | Total Customer Revenue | | 1,295 | | | 862 | | | 893 | | | 316 | | | 809 | | | 187 | | | 262 | | | 121 | | | 4,745 | | Total Customer Revenue | | 1,480 | | | 904 | | | 994 | | | 326 | | | 1,146 | | | 205 | | | 305 | | | (57) | | | 5,303 | |
| Other revenue | Other revenue | | 19 | | | 35 | | | 6 | | | 29 | | | 47 | | | (4) | | | 32 | | | 31 | | | 195 | | Other revenue | | 4 | | | 16 | | | 5 | | | 28 | | | 27 | | | — | | | 88 | | | — | | | 168 | |
| Total | Total | | $ | 1,314 | | | $ | 897 | | | $ | 899 | | | $ | 345 | | | $ | 856 | | | $ | 183 | | | $ | 294 | | | $ | 152 | | | $ | 4,940 | | Total | | $ | 1,484 | | | $ | 920 | | | $ | 999 | | | $ | 354 | | | $ | 1,173 | | | $ | 205 | | | $ | 393 | | | $ | (57) | | | $ | 5,471 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 June 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 | | $ | 1,188 | | | $ | 516 | | | $ | 708 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 2,411 | |
| Retail gas | | — | | | 89 | | | 20 | | | — | | | — | | | — | | | — | | | — | | | 109 | |
| Wholesale | | 30 | | | 69 | | | 10 | | | — | | | — | | | — | | | — | | | (1) | | | 108 | |
Transmission and
distribution | | 37 | | | 15 | | | 22 | | | 243 | | | — | | | 178 | | | — | | | — | | | 495 | |
| Interstate pipeline | | — | | | — | | | — | | | — | | | 458 | | | — | | | — | | | (25) | | | 433 | |
| Other | | 31 | | | — | | | 1 | | | — | | | (1) | | | — | | | — | | | — | | | 31 | |
| Total Regulated | | 1,286 | | | 689 | | | 761 | | | 243 | | | 457 | | | 178 | | | — | | | (27) | | | 3,587 | |
| Nonregulated | | — | | | 1 | | | 1 | | | 8 | | | 232 | | | 7 | | | 239 | | | 124 | | | 612 | |
| Total Customer Revenue | | 1,286 | | | 690 | | | 762 | | | 251 | | | 689 | | | 185 | | | 239 | | | 97 | | | 4,199 | |
| Other revenue | | 12 | | | 3 | | | 5 | | | 29 | | | 17 | | | (3) | | | 28 | | | 11 | | | 102 | |
| Total | | $ | 1,298 | | | $ | 693 | | | $ | 767 | | | $ | 280 | | | $ | 706 | | | $ | 182 | | | $ | 267 | | | $ | 108 | | | $ | 4,301 | |
| | | For the Six-Month Period Ended June 30, 2021 | | For the Three-Month Period Ended March 31, 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 | | $ | 2,333 | | | $ | 968 | | | $ | 1,219 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | $ | 4,519 | | Retail electric | | $ | 1,185 | | | $ | 472 | | | $ | 599 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,256 | |
| Retail gas | Retail gas | | — | | | 549 | | | 58 | | | — | | | — | | | — | | | — | | | — | | | 607 | | Retail gas | | — | | | 337 | | | 51 | | | — | | | — | | | — | | | — | | | — | | | 388 | |
| Wholesale | Wholesale | | 66 | | | 194 | | | 25 | | | — | | | 17 | | | — | | | — | | | (1) | | | 301 | | Wholesale | | 55 | | | 161 | | | 20 | | | — | | | — | | | — | | | — | | | — | | | 236 | |
Transmission and
distribution | Transmission and
distribution | | 62 | | | 30 | | | 43 | | | 506 | | | — | | | 350 | | | — | | | — | | | 991 | | Transmission and
distribution | | 32 | | | 15 | | | 17 | | | 269 | | | — | | | 176 | | | — | | | — | | | 509 | |
| Interstate pipeline | Interstate pipeline | | — | | | — | | | — | | | — | | | 1,273 | | | — | | | — | | | (66) | | | 1,207 | | Interstate pipeline | | — | | | — | | | — | | | — | | | 745 | | | — | | | — | | | (41) | | | 704 | |
| Other | Other | | 54 | | | — | | | 1 | | | — | | | 1 | | | — | | | — | | | — | | | 56 | | Other | | 20 | | | — | | | 1 | | | — | | | 1 | | | — | | | — | | | — | | | 22 | |
| Total Regulated | Total Regulated | | 2,515 | | | 1,741 | | | 1,346 | | | 506 | | | 1,291 | | | 350 | | | — | | | (68) | | | 7,681 | | Total Regulated | | 1,292 | | | 985 | | | 688 | | | 269 | | | 746 | | | 176 | | | — | | | (41) | | | 4,115 | |
| Nonregulated | Nonregulated | | — | | | 11 | | | 1 | | | 18 | | | 469 | | | 15 | | | 405 | | | 311 | | | 1,230 | | Nonregulated | | — | | | 2 | | | — | | | 15 | | | 278 | | | 7 | | | 302 | | | — | | | 604 | |
| Total Customer Revenue | Total Customer Revenue | | 2,515 | | | 1,752 | | | 1,347 | | | 524 | | | 1,760 | | | 365 | | | 405 | | | 243 | | | 8,911 | | Total Customer Revenue | | 1,292 | | | 987 | | | 688 | | | 284 | | | 1,024 | | | 183 | | | 302 | | | (41) | | | 4,719 | |
| Other revenue | Other revenue | | 25 | | | 8 | | | 11 | | | 56 | | | 39 | | | (3) | | | 52 | | | 51 | | | 239 | | Other revenue | | 5 | | | 18 | | | 5 | | | 31 | | | 11 | | | — | | | 34 | | | — | | | 104 | |
| Total | Total | | $ | 2,540 | | | $ | 1,760 | | | $ | 1,358 | | | $ | 580 | | | $ | 1,799 | | | $ | 362 | | | $ | 457 | | | $ | 294 | | | $ | 9,150 | | Total | | $ | 1,297 | | | $ | 1,005 | | | $ | 693 | | | $ | 315 | | | $ | 1,035 | | | $ | 183 | | | $ | 336 | | | $ | (41) | | | $ | 4,823 | |
(1)The BHE and Other reportable segment represents amounts related principally to other corporate 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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Customer Revenue: | Customer Revenue: | | | | | | | | Customer Revenue: | | | | |
| Brokerage | Brokerage | $ | 1,544 | | | $ | 1,569 | | | $ | 2,636 | | | $ | 2,591 | | Brokerage | | $ | 799 | | | $ | 1,092 | |
| Franchise | Franchise | 17 | | | 24 | | | 37 | | | 42 | | Franchise | | 12 | | | 20 | |
| Total Customer Revenue | Total Customer Revenue | 1,561 | | | 1,593 | | | 2,673 | | | 2,633 | | Total Customer Revenue | | 811 | | | 1,112 | |
| Mortgage and other revenue | Mortgage and other revenue | 111 | | | 170 | | | 206 | | | 362 | | Mortgage and other revenue | | 64 | | | 95 | |
| Total | Total | $ | 1,672 | | | $ | 1,763 | | | $ | 2,879 | | | $ | 2,995 | | Total | | $ | 875 | | | $ | 1,207 | |
Remaining Performance Obligations
The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2022,March 31, 2023, by reportable segment (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied: | | |
| Less than 12 months | | More than 12 months | | Total |
| BHE Pipeline Group | $ | 3,324 | | | $ | 21,878 | | | $ | 25,202 | |
| BHE Transmission | 695 | | | 348 | | | 1,043 | |
| Total | $ | 4,019 | | | $ | 22,226 | | | $ | 26,245 | |
(10) BHE Shareholders' Equity
In May 2022, BHE redeemed at par 800,006 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $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. | | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied: | | |
| Less than 12 months | | More than 12 months | | Total |
| BHE Pipeline Group | $ | 2,786 | | | $ | 20,146 | | | $ | 22,932 | |
| BHE Transmission | 490 | | | — | | | 490 | |
| Total | $ | 3,276 | | | $ | 20,146 | | | $ | 23,422 | |
(11) Components of Accumulated Other Comprehensive Loss, Net
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income tax (in millions):
| | | Unrecognized | | Foreign | | Unrealized | | AOCI | | Unrecognized | | Foreign | | Unrealized | | AOCI |
| | Amounts on | | Currency | | (Losses) Gains | | Attributable | | Amounts on | | Currency | | 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, 2020 | | $ | (492) | | | $ | (1,062) | | | $ | (8) | | | $ | 10 | | | $ | (1,552) | | |
| Other comprehensive income (loss) | | 22 | | | 159 | | | 15 | | | (4) | | | 192 | | |
| Balance, June 30, 2021 | | $ | (470) | | | $ | (903) | | | $ | 7 | | | $ | 6 | | | $ | (1,360) | | |
| | Balance, December 31, 2021 | Balance, December 31, 2021 | | $ | (318) | | | $ | (1,086) | | | $ | 59 | | | $ | 5 | | | $ | (1,340) | | Balance, December 31, 2021 | | $ | (318) | | | $ | (1,086) | | | $ | 59 | | | $ | 5 | | | $ | (1,340) | |
| Other comprehensive income (loss) | Other comprehensive income (loss) | | 40 | | | (591) | | | 103 | | | — | | | (448) | | Other comprehensive income (loss) | | 15 | | | (110) | | | 77 | | | — | | | (18) | |
| Balance, June 30, 2022 | | $ | (278) | | | $ | (1,677) | | | $ | 162 | | | $ | 5 | | | $ | (1,788) | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | | $ | (303) | | | $ | (1,196) | | | $ | 136 | | | $ | 5 | | | $ | (1,358) | |
| | Balance, December 31, 2022 | | Balance, December 31, 2022 | | $ | (390) | | | $ | (1,896) | | | $ | 135 | | | $ | 2 | | | $ | (2,149) | |
| Other comprehensive (loss) income | | Other comprehensive (loss) income | | (4) | | | 99 | | | (55) | | | — | | | 40 | |
| Balance, March 31, 2023 | | Balance, March 31, 2023 | | $ | (394) | | | $ | (1,797) | | | $ | 80 | | | $ | 2 | | | $ | (2,109) | |
(12) 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. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been changed to reflect this activity in BHE Renewables. Information related to the Company's reportable segments is shown below (in millions):
| | | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | |
| PacifiCorp | PacifiCorp | $ | 1,314 | | | $ | 1,298 | | | $ | 2,611 | | | $ | 2,540 | | PacifiCorp | | $ | 1,484 | | | $ | 1,297 | |
| MidAmerican Funding | MidAmerican Funding | 897 | | | 693 | | | 1,902 | | | 1,760 | | MidAmerican Funding | | 920 | | | 1,005 | |
| NV Energy | NV Energy | 899 | | | 767 | | | 1,592 | | | 1,358 | | NV Energy | | 999 | | | 693 | |
| Northern Powergrid | Northern Powergrid | 345 | | | 280 | | | 660 | | | 580 | | Northern Powergrid | | 354 | | | 315 | |
| BHE Pipeline Group | BHE Pipeline Group | 856 | | | 706 | | | 1,891 | | | 1,799 | | BHE Pipeline Group | | 1,173 | | | 1,035 | |
| BHE Transmission | BHE Transmission | 183 | | | 182 | | | 366 | | | 362 | | BHE Transmission | | 205 | | | 183 | |
| BHE Renewables | BHE Renewables | 294 | | | 267 | | | 461 | | | 457 | | BHE Renewables | | 393 | | | 336 | |
| HomeServices | HomeServices | 1,672 | | | 1,763 | | | 2,879 | | | 2,995 | | HomeServices | | 875 | | | 1,207 | |
BHE and Other(1) | BHE and Other(1) | 152 | | | 108 | | | 280 | | | 294 | | BHE and Other(1) | | (57) | | | (41) | |
| Total operating revenue | Total operating revenue | $ | 6,612 | | | $ | 6,064 | | | $ | 12,642 | | | $ | 12,145 | | Total operating revenue | | $ | 6,346 | | | $ | 6,030 | |
| | | | Depreciation and amortization: | Depreciation and amortization: | | Depreciation and amortization: | | |
| PacifiCorp | PacifiCorp | $ | 279 | | | $ | 275 | | | $ | 559 | | | $ | 539 | | PacifiCorp | | $ | 279 | | | $ | 280 | |
| MidAmerican Funding | MidAmerican Funding | 277 | | | 209 | | | 527 | | | 416 | | MidAmerican Funding | | 234 | | | 250 | |
| NV Energy | NV Energy | 139 | | | 137 | | | 279 | | | 273 | | NV Energy | | 152 | | | 140 | |
| Northern Powergrid | Northern Powergrid | 100 | | | 73 | | | 180 | | | 144 | | Northern Powergrid | | 85 | | | 80 | |
| BHE Pipeline Group | BHE Pipeline Group | 125 | | | 121 | | | 256 | | | 239 | | BHE Pipeline Group | | 172 | | | 131 | |
| BHE Transmission | BHE Transmission | 60 | | | 60 | | | 118 | | | 118 | | BHE Transmission | | 61 | | | 58 | |
| BHE Renewables | BHE Renewables | 66 | | | 61 | | | 131 | | | 121 | | BHE Renewables | | 66 | | | 66 | |
| HomeServices | HomeServices | 14 | | | 12 | | | 29 | | | 23 | | HomeServices | | 13 | | | 15 | |
BHE and Other(1) | BHE and Other(1) | (1) | | | (1) | | | 2 | | | 1 | | BHE and Other(1) | | 1 | | | 2 | |
| Total depreciation and amortization | Total depreciation and amortization | $ | 1,059 | | | $ | 947 | | | $ | 2,081 | | | $ | 1,874 | | Total depreciation and amortization | | $ | 1,063 | | | $ | 1,022 | |
| | | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Operating income: | Operating income: | | | | | | | | Operating income: | | | | |
| PacifiCorp | PacifiCorp | $ | 158 | | | $ | 283 | | | $ | 374 | | | $ | 517 | | PacifiCorp | | $ | (167) | | | $ | 216 | |
| MidAmerican Funding | MidAmerican Funding | 90 | | | 103 | | | 190 | | | 151 | | MidAmerican Funding | | 88 | | | 100 | |
| NV Energy | NV Energy | 140 | | | 145 | | | 202 | | | 215 | | NV Energy | | 57 | | | 62 | |
| Northern Powergrid | Northern Powergrid | 110 | | | 126 | | | 269 | | | 277 | | Northern Powergrid | | 146 | | | 159 | |
| BHE Pipeline Group | BHE Pipeline Group | 352 | | | 245 | | | 890 | | | 863 | | BHE Pipeline Group | | 584 | | | 538 | |
| BHE Transmission | BHE Transmission | 84 | | | 85 | | | 167 | | | 166 | | BHE Transmission | | 88 | | | 83 | |
| BHE Renewables | BHE Renewables | 134 | | | 97 | | | 132 | | | 130 | | BHE Renewables | | (69) | | | 54 | |
| HomeServices | HomeServices | 117 | | | 179 | | | 145 | | | 291 | | HomeServices | | (45) | | | 28 | |
BHE and Other(1) | BHE and Other(1) | 22 | | | (55) | | | 74 | | | (69) | | BHE and Other(1) | | (15) | | | (4) | |
| Total operating income | Total operating income | 1,207 | | | 1,208 | | | 2,443 | | | 2,541 | | Total operating income | | 667 | | | 1,236 | |
| Interest expense | Interest expense | (550) | | | (532) | | | (1,082) | | | (1,062) | | Interest expense | | (586) | | | (532) | |
| Capitalized interest | Capitalized interest | 18 | | | 14 | | | 35 | | | 28 | | Capitalized interest | | 24 | | | 17 | |
| Allowance for equity funds | Allowance for equity funds | 42 | | | 30 | | | 80 | | | 56 | | Allowance for equity funds | | 49 | | | 38 | |
| Interest and dividend income | Interest and dividend income | 30 | | | 26 | | | 53 | | | 47 | | Interest and dividend income | | 86 | | | 23 | |
| Gains on marketable securities, net | 2,528 | | | 1,966 | | | 1,271 | | | 848 | | |
| Gains (losses) on marketable securities, net | | Gains (losses) on marketable securities, net | | 699 | | | (1,257) | |
| Other, net | Other, net | (26) | | | 48 | | | (21) | | | 56 | | Other, net | | 40 | | | 5 | |
| Total income before income tax expense (benefit) and equity loss | $ | 3,249 | | | $ | 2,760 | | | $ | 2,779 | | | $ | 2,514 | | |
| Total income (loss) before income tax expense (benefit) and equity income (loss) | | Total income (loss) before income tax expense (benefit) and equity income (loss) | | $ | 979 | | | $ | (470) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | | | |
| 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 | |
| | | | | | | |
| | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | | | |
| Interest expense: | | | | | | | |
| PacifiCorp | | | | | $ | 124 | | | $ | 106 | |
| MidAmerican Funding | | | | | 84 | | | 82 | |
| NV Energy | | | | | 63 | | | 51 | |
| Northern Powergrid | | | | | 30 | | | 32 | |
| BHE Pipeline Group | | | | | 39 | | | 37 | |
| BHE Transmission | | | | | 37 | | | 38 | |
| BHE Renewables | | | | | 45 | | | 42 | |
| HomeServices | | | | | 4 | | | 1 | |
BHE and Other(1) | | | | | 160 | | | 143 | |
| Total interest expense | | | | | $ | 586 | | | $ | 532 | |
| | | | | | | | | | | | | | | |
| Earnings (loss) on common shares: | | | | | | | |
| PacifiCorp | | | | | $ | (120) | | | $ | 130 | |
| MidAmerican Funding | | | | | 249 | | | 241 | |
| NV Energy | | | | | 34 | | | 29 | |
| Northern Powergrid | | | | | 11 | | | 111 | |
| BHE Pipeline Group | | | | | 369 | | | 322 | |
| BHE Transmission | | | | | 64 | | | 62 | |
| BHE Renewables | | | | | 79 | | | 145 | |
| HomeServices | | | | | (34) | | | 21 | |
BHE and Other(1) | | | | | 329 | | | (1,206) | |
| Total earnings (loss) on common shares | | | | | $ | 981 | | | $ | (145) | |
| | | | | | | |
| | | | As of | | As of |
| | | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Assets: | Assets: | | | | Assets: | | | |
| PacifiCorp | PacifiCorp | $ | 28,596 | | | $ | 27,615 | | PacifiCorp | $ | 30,268 | | | $ | 30,559 | |
| MidAmerican Funding | MidAmerican Funding | 25,733 | | | 25,352 | | MidAmerican Funding | 25,899 | | | 26,077 | |
| NV Energy | NV Energy | 15,905 | | | 15,239 | | NV Energy | 17,210 | | | 16,676 | |
| Northern Powergrid | Northern Powergrid | 9,343 | | | 9,326 | | Northern Powergrid | 9,216 | | | 9,005 | |
| BHE Pipeline Group | BHE Pipeline Group | 20,691 | | | 20,434 | | BHE Pipeline Group | 20,931 | | | 21,005 | |
| BHE Transmission | BHE Transmission | 9,441 | | | 9,476 | | BHE Transmission | 9,380 | | | 9,334 | |
| BHE Renewables | BHE Renewables | 11,853 | | | 11,829 | | BHE Renewables | 11,693 | | | 12,632 | |
| HomeServices | HomeServices | 4,115 | | | 4,574 | | HomeServices | 3,625 | | | 3,436 | |
BHE and Other(1) | BHE and Other(1) | 9,618 | | | 8,220 | | BHE and Other(1) | 6,232 | | | 5,116 | |
| Total assets | Total assets | $ | 135,295 | | | $ | 132,065 | | Total assets | $ | 134,454 | | | $ | 133,840 | |
(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other corporate entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
| | | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Operating revenue by country: | Operating revenue by country: | | | | | | | | Operating revenue by country: | | | | |
| U.S. | U.S. | $ | 6,087 | | | $ | 5,604 | | | $ | 11,621 | | | $ | 11,201 | | U.S. | | $ | 5,815 | | | $ | 5,534 | |
| United Kingdom | United Kingdom | 345 | | | 280 | | | 660 | | | 580 | | United Kingdom | | 333 | | | 315 | |
| Canada | Canada | 180 | | | 180 | | | 361 | | | 357 | | Canada | | 177 | | | 181 | |
| Other | — | | | — | | | — | | | 7 | | |
| Australia | | Australia | | 21 | | | — | |
| | Total operating revenue by country | Total operating revenue by country | $ | 6,612 | | | $ | 6,064 | | | $ | 12,642 | | | $ | 12,145 | | Total operating revenue by country | | $ | 6,346 | | | $ | 6,030 | |
| | Income before income tax expense (benefit) and equity loss by country: | | |
| Income (loss) before income tax expense (benefit) and equity income (loss) by country: | | Income (loss) before income tax expense (benefit) and equity income (loss) by country: | | |
| U.S. | U.S. | $ | 3,117 | | | $ | 2,611 | | | $ | 2,463 | | | $ | 2,188 | | U.S. | | $ | 819 | | | $ | (654) | |
| United Kingdom | United Kingdom | 87 | | | 104 | | | 226 | | | 236 | | United Kingdom | | 113 | | | 139 | |
| Canada | Canada | 46 | | | 46 | | | 92 | | | 85 | | Canada | | 43 | | | 46 | |
| Australia | | Australia | | 5 | | | — | |
| Other | Other | (1) | | | (1) | | | (2) | | | 5 | | Other | | (1) | | | (1) | |
| Total income before income tax expense (benefit) and equity loss by country | $ | 3,249 | | | $ | 2,760 | | | $ | 2,779 | | | $ | 2,514 | | |
| Total income (loss) before income tax expense (benefit) and equity income (loss) by country | | Total income (loss) before income tax expense (benefit) and equity income (loss) by country | | $ | 979 | | | $ | (470) | |
The following table shows the change in the carrying amount of goodwill by reportable segment for the six-monththree-month period ended June 30, 2022March 31, 2023 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | BHE Pipeline Group | | | | | | | | | | |
| PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | | BHE Transmission | | BHE Renewables | | HomeServices | | | | |
| | | | | | | | | | | Total |
| | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 992 | | | $ | 1,814 | | | $ | 1,563 | | | $ | 95 | | | $ | 1,586 | | | | | $ | 11,650 | |
| Acquisitions | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 8 | | | | | 8 | |
| Foreign currency translation | — | | | — | | | — | | | (70) | | | — | | | (29) | | | — | | | — | | | | | (99) | |
| | | | | | | | | | | | | | | | | | | |
| June 30, 2022 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 922 | | | $ | 1,814 | | | $ | 1,534 | | | $ | 95 | | | $ | 1,594 | | | | | $ | 11,559 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | BHE Pipeline Group | | | | | | | | | | |
| PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | | BHE Transmission | | BHE Renewables | | HomeServices | | | | |
| | | | | | | | | | | Total |
| | | | | | | | | | | | | | | | | | | | |
| December 31, 2022 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 917 | | | $ | 1,814 | | | $ | 1,461 | | | $ | 95 | | | $ | 1,602 | | | | | $ | 11,489 | |
| | | | | | | | | | | | | | | | | | | |
| Foreign currency translation | — | | | — | | | — | | | 13 | | | — | | | 1 | | | — | | | — | | | | | 14 | |
| | | | | | | | | | | | | | | | | | | |
| March 31, 2023 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 930 | | | $ | 1,814 | | | $ | 1,462 | | | $ | 95 | | | $ | 1,602 | | | | | $ | 11,503 | |
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 and operated businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway. As of AugustMay 4, 2022,2023, 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 voting 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 U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in the U.S., one of which owns a liquefied natural gas ("LNG")LNG export, import and storage facility, in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, one of the largest residential real estate brokerage firmfirms in the U.S. and one of the largest residential real estate brokerage franchise networks in the 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 corporate entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been changed to reflect this activity in BHE Renewables.
Results of Operations for the SecondFirst Quarter of 2023 and First Six Months of 2022 and 2021
Overview
Operating revenue and earnings (loss) on common shares for the Company's reportable segments are summarized as follows (in millions):
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Operating revenue: | Operating revenue: | | | | | | | | | | | | Operating revenue: | | | | | | |
| PacifiCorp | PacifiCorp | $ | 1,314 | | | $ | 1,298 | | | $ | 16 | | | 1 | % | | $ | 2,611 | | | $ | 2,540 | | | $ | 71 | | | 3 | % | PacifiCorp | $ | 1,484 | | | $ | 1,297 | | | $ | 187 | | | 14 | % | |
| MidAmerican Funding | MidAmerican Funding | 897 | | | 693 | | | 204 | | | 29 | | | 1,902 | | | 1,760 | | | 142 | | | 8 | | MidAmerican Funding | 920 | | | 1,005 | | | (85) | | | (8) | | |
| NV Energy | NV Energy | 899 | | | 767 | | | 132 | | | 17 | | | 1,592 | | | 1,358 | | | 234 | | | 17 | | NV Energy | 999 | | | 693 | | | 306 | | | 44 | | |
| Northern Powergrid | Northern Powergrid | 345 | | | 280 | | | 65 | | | 23 | | | 660 | | | 580 | | | 80 | | | 14 | | Northern Powergrid | 354 | | | 315 | | | 39 | | | 12 | | |
| BHE Pipeline Group | BHE Pipeline Group | 856 | | | 706 | | | 150 | | | 21 | | | 1,891 | | | 1,799 | | | 92 | | | 5 | BHE Pipeline Group | 1,173 | | | 1,035 | | | 138 | | | 13 | | |
| BHE Transmission | BHE Transmission | 183 | | | 182 | | | 1 | | | 1 | | | 366 | | | 362 | | | 4 | | | 1 | | BHE Transmission | 205 | | | 183 | | | 22 | | | 12 | | |
| BHE Renewables | BHE Renewables | 294 | | | 267 | | | 27 | | | 10 | | | 461 | | | 457 | | | 4 | | | 1 | | BHE Renewables | 393 | | | 336 | | | 57 | | | 17 | | |
| HomeServices | HomeServices | 1,672 | | | 1,763 | | | (91) | | | (5) | | | 2,879 | | | 2,995 | | | (116) | | | (4) | | HomeServices | 875 | | | 1,207 | | | (332) | | | (28) | | |
| BHE and Other | BHE and Other | 152 | | | 108 | | | 44 | | | 41 | | | 280 | | | 294 | | | (14) | | | (5) | | BHE and Other | (57) | | | (41) | | | (16) | | | 39 | | |
| Total operating revenue | Total operating revenue | $ | 6,612 | | | $ | 6,064 | | | $ | 548 | | | 9 | % | | $ | 12,642 | | | $ | 12,145 | | | $ | 497 | | | 4 | % | Total operating revenue | $ | 6,346 | | | $ | 6,030 | | | $ | 316 | | | 5 | % | |
| | Earnings on common shares: | | |
| Earnings (loss) on common shares: | | Earnings (loss) on common shares: | | |
| PacifiCorp | PacifiCorp | $ | 83 | | | $ | 226 | | | $ | (143) | | | (63) | % | | $ | 213 | | | $ | 395 | | | $ | (182) | | | (46) | % | PacifiCorp | $ | (120) | | | $ | 130 | | | $ | (250) | | | * | |
| MidAmerican Funding | MidAmerican Funding | 204 | | | 211 | | | (7) | | | (3) | | | 445 | | | 355 | | | 90 | | | 25 | | MidAmerican Funding | 249 | | | 241 | | | 8 | | | 3 | | |
| NV Energy | NV Energy | 93 | | | 100 | | | (7) | | | (7) | | | 122 | | | 134 | | | (12) | | | (9) | | NV Energy | 34 | | | 29 | | | 5 | | | 17 | | |
| Northern Powergrid | Northern Powergrid | 71 | | | (25) | | | 96 | | | * | | 182 | | | 79 | | | 103 | | | * | Northern Powergrid | 11 | | | 111 | | | (100) | | | (90) | | |
| BHE Pipeline Group | BHE Pipeline Group | 199 | | | 100 | | | 99 | | | 99 | | | 521 | | | 483 | | | 38 | | | 8 | | BHE Pipeline Group | 369 | | | 322 | | | 47 | | | 15 | | |
| BHE Transmission | BHE Transmission | 62 | | | 60 | | | 2 | | | 3 | | | 124 | | | 119 | | | 5 | | | 4 | | BHE Transmission | 64 | | | 62 | | | 2 | | | 3 | | |
BHE Renewables(1) | BHE Renewables(1) | 249 | | | 181 | | | 68 | | | 38 | | 353 | | | 197 | | | 156 | | | 79 | | BHE Renewables(1) | 79 | | | 145 | | | (66) | | | (46) | |
| HomeServices | HomeServices | 84 | | | 135 | | | (51) | | | (38) | | | 105 | | | 219 | | | (114) | | | (52) | | HomeServices | (34) | | | 21 | | | (55) | | | * | |
| BHE and Other | BHE and Other | 1,839 | | | 1,256 | | | 583 | | | 46 | | | 674 | | | 229 | | | 445 | | | * | BHE and Other | 329 | | | (1,206) | | | 1,535 | | | * | |
| Total earnings on common shares | $ | 2,884 | | | $ | 2,244 | | | $ | 640 | | | 29 | % | | $ | 2,739 | | | $ | 2,210 | | | $ | 529 | | | 24 | % | |
| Total earnings (loss) on common shares | | Total earnings (loss) on common shares | $ | 981 | | | $ | (145) | | | $ | 1,126 | | | * | |
(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
* Not meaningful
Earnings on common shares increased $640$1,126 million for the secondfirst quarter of 20222023 compared to 2021. The second2022. Included in these results was a pre-tax gain in the first quarter of 2022 included a pre-tax unrealized gain2023 of $2,557$717 million ($2,020567 million after-tax) compared to a pre-tax unrealized gainloss in the second quarter of 2021 of $1,954 million ($1,420 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 secondfirst quarter of 2022 was $864of $1,247 million an increase of $40 million, or 5%, compared to adjusted earnings on common shares in the second quarter of 2021 of $824 million.
Earnings on common shares increased $529 million for the first six months of 2022 compared to 2021. The first six months of 2022 included a pre-tax unrealized gain of $1,310 million ($1,035985 million after-tax) comparedrelated to a pre-tax unrealized gain in the first six months of 2021 of $830 million ($602 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first six monthsquarter of 20222023 was $1,704$414 million, an increasea decrease of $96$426 million, or 6%51%, compared to adjusted earnings on commonscommon shares infor the first six monthsquarter of 20212022 of $1,608$840 million.
The increasesincrease in earnings on common shares for the secondfirst quarter and for the first six months of 20222023 compared to 20212022 were primarily due to the following:
•The Utilities' earnings decreased $157 million for the second quarter and $104$237 million for the first six monthsquarter of 20222023 compared to 2021, reflecting2022, primarily from higher operations and maintenance expense, largely due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires. The higher depreciationoperations and amortizationmaintenance expense and unfavorable investment earnings,was partially offset by higherfavorable electric utility margin, higher allowances for equity and borrowed funds used during construction, increases in the cash surrender value of corporate-owned life insurance policies and a favorable income tax benefit from higher PTCs recognized.valuation allowance changes on state net operating loss carryforwards. Electric retail customer volumes increased 1.3%2.6% for the first six monthsquarter of 20222023 compared to 2021, primarily due to2022, driven by higher customer usage and an increase in the average number of customers;
•Northern Powergrid's earnings increased $96 million for the second quarter and $103decreased $100 million for the first six monthsquarter of 20222023 compared to 2021,2022, primarily due to a deferred income tax charge of $109$82 million recognized in March 2023 related to the enactment of a June 2021 enacted increase innew Energy Profits Levy income tax. Units distributed declined 4.8% due to the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023;unfavorable impact of weather and lower customer usage;
•BHE Pipeline Group's earnings increased $99 million for the second quarter and $38$47 million for the first six monthsquarter of 20222023 compared to 2021,2022, largely due to higher earningsa favorable general rate case settlement at BHE GT&S from favorable state unitary income tax adjustments,EGTS in 2022 and the impacts of the EGTSa general rate case, and lower operations and maintenance expense. In addition, earnings for the first six months decreased from the effects of higher margins on natural gas sales and higher transportation revenue in the first quarter of 2021with interim rates effective January 1, 2023, subject to refund, at Northern Natural Gas from the February 2021 polar vortex weather event;Gas;
•BHE Renewables' earnings increased $68 million for the second quarter and $156decreased $66 million for the first six monthsquarter of 20222023 compared to 2021,2022, primarily due to higher operating revenue from owned renewable energy projects and higher earnings from tax equity investments, with the first six months being positively impacted by the unfavorable impactschanges in the first quarter of 2021 from the February 2021 polar vortex weather event;unrealized positions on derivative contracts due to lower forward electricity price curves;
•HomeServices' earnings decreased $51 million for the second quarter and $114$55 million for the first six monthsquarter of 20222023 compared to 2021, reflecting lower earnings from mortgage services mainly from a decrease in funded volumes and2022, primarily due to lower earnings from brokerage and settlement services largely attributable toand from mortgage services, reflecting the impact of rising interest rates and a decreasecorresponding decline in closed units at existing companies;home sales; and
•BHE and Other's earnings increased $583 million for the second quarter and $445$1,535 million for the first six monthsquarter of 20222023 compared to 2021, mainly2022, primarily due to $600the $1,552 million and $433 million, respectively, of favorable changes in the after-tax unrealized position ofcomparative change related to 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, partially offset by lower federal income tax credits recognized on a consolidated basis.Limited.
Reportable Segment Results
PacifiCorp
Operating revenue increased $16$187 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higher retail revenue of $159 million and higher wholesale and other revenue of $30$28 million, primarily from higher average wholesale market prices, partially offset by lower retail revenue of $14 million. Wholesale and otherwholesale volumes. Retail revenue increased primarily due to higher average wholesale prices and higher wheeling revenue. Retail revenue decreased primarily due to lower retail volumes of $42 million, partially offset by price impacts of $28$107 million from higher average retail rates primarilylargely due to tariff changes.changes and product mix and $52 million from higher volumes. Retail customer volumes decreasedincreased 3.3%, primarily due to the unfavorablefavorable impact of weather, and lowerhigher customer usage partially offset byand an increase in the average number of customers.
Earnings decreased $143$250 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higher operations and maintenance expense of $120$428 million, an unfavorable income tax benefit and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by higher utility margin of $6 million.$38 million, higher allowances for equity and borrowed funds used during construction of $21 million and a favorable income tax benefit from valuation allowance changes on state net operating loss carryforwards. Operations and maintenance expense increased mainlywas unfavorable primarily due to an increase in the loss accruals, net of expected insurance recoveries, associated with the September 2020 wildfires, netWildfires of estimated insurance recoveries,$359 million, higher wildfire mitigation and vegetation management costs, and higher general and plant maintenance costs. Utility margin increased primarily due to lower purchasedhigher retail rates and volumes, favorable deferred net power costs and the higher average wholesale and other revenue,market prices, partially offset by higher purchased power and thermal generation costs the lower retail revenue and lower deferred net power costs in accordance with established adjustment mechanisms. The unfavorable income tax benefit was largely due to lower PTCs recognized of $22 million and the effects of ratemaking of $18 million.
Operating revenue increased $71 million for the first six months of 2022 compared to 2021, primarily due to higher wholesale and other revenue of $45 million and higher retail revenue of $26 million. Wholesale and other revenue increased primarily due to higher average wholesale prices and higher wheeling revenue. Retail revenue increased primarily due to price impacts of $43 million from higher average retail rates largely due to tariff changes, partially offset by lower retail volumes of $17 million. Retail customer volumes decreased 0.7%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers.
Earnings decreased $182 million for the first six months of 2022 compared to 2021, primarily due to higher operations and maintenance expense of $138 million, an unfavorable income tax benefit, higher depreciation and amortization expense of $20 million, mainly from additional assets placed in-service, and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, 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 September 2020 wildfires, net of estimated insurance recoveries, and higher general and plant maintenance costs. Utility margin increased primarily due to the higher retail, wholesale and other revenues, partially offset by higher thermal generation costs. The unfavorable income tax benefit was largely due to lower PTCs recognized of $27 million and the effects of ratemaking of $27 million.volumes.
MidAmerican Funding
Operating revenue increased $204decreased $85 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higher electric operating revenue of $139 million and higherlower natural gas operating revenue of $65$70 million and lower electric operating revenue of $17 million. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $61 million (fully offset in cost of sales) and the unfavorable impact of weather of $5 million. Electric operating revenue increaseddecreased due to higher retail revenue of $77 million and higherlower wholesale and other revenue of $62$33 million, partially offset by higher retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower wholesale volumes of $22 million and lower average wholesale per-unit prices of $13 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $59$14 million (fully(largely offset in expense, primarily cost of sales) and higher customer volumes of $11 million. Electric wholesale and other revenue increased mainly due to higher average wholesale per-unit prices of $59 million.. Electric retail customer volumes increased 3.3%1.0%, primarily due to higher customer usage, andpartially offset by the favorableunfavorable impact of 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.
Earnings decreased $7increased $8 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higherlower depreciation and amortization expense of $68$17 million, unfavorablea one-time gain on the sale of an investment of $13 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $12 million, partially offset by higher operations and maintenance expense of $16$13 million, lower natural gas utility margin of $8 million and higher interest expense of $5 million, partially offset by higherlower electric utility margin of $68 million, a favorable income tax benefit and higher allowances for equity and borrowed funds used during construction of $9$7 million. Depreciation and amortization expense increaseddecreased primarily from the impacts of certain regulatory mechanisms, andpartially offset by additional assets placed in-service. ElectricOperations and maintenance expense increased due to higher general and plant maintenance costs and unfavorable property insurance costs. Natural gas utility margin increaseddecreased primarily due to the higher retail andunfavorable impact of weather. Electric utility margin decreased primarily due to lower wholesale revenues,revenue, partially offset by higher retail revenue and lower purchased power costs. The favorable income tax benefit was largely due to higher PTCs recognized of $39 million from higher wind-powered generation, partially offset by the effects of ratemaking.
Operating revenue increased $142 million for the first six months of 2022 compared to 2021, primarily due to higher electric operating revenue of $202 million, partially offset by lower natural gas operating revenue of $51 million. Electric operating revenue increased due to higher wholesale and other revenue of $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 $63 million (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), primarily from a lower average per-unit cost of natural gas sold driven largely by the February 2021 polar vortex weather event, partially offset by the impacts of certain regulatory recovery mechanisms of $5 million, the impacts of tax reform of $5 million and the favorable impact of weather of $5 million.
Earnings increased $90 million for the first six months of 2022 compared to 2021, primarily due to higher electric utility margin of $157 million, 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 $111 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies, higher operations and maintenance expense of $15 million, higher interest expense of $9 million and lower nonregulated utility margin of $8 million. Electric utility margin increased primarily due to the higher wholesale and retail revenues, partially offset by higher purchased power costs. The 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 amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service.
NV Energy
Operating revenue increased $132$306 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higher electric operating revenue of $123$260 million and higher natural gas operating revenue of $8 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of $121$44 million and higher regulatory-related revenue deferrals of $11 million, partially offset by unfavorable price impacts from changes in sales mix of $12 million. Electric retail customer volumes increased 0.4%, primarily due to an increase in the average number of customers, 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 $7 million for the second quarter of 2022 compared to 2021, mainly due to unfavorable 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 higher 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 operating revenue of $213 million and higher natural gas operating revenue of $21 million. Electric operating revenue increased primarily due to higher fully-bundledfully bundled energy rates (fully offset in cost of sales) of $209$229 million, higher regulatory-related revenue deferralscustomer volumes of $8 million, increased base tariff general rates of $8 million at Sierra Pacific and higherfavorable 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%2.9%, primarily due to the favorable impact of weather and 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).customers.
Earnings decreased $12increased $5 million for the first six monthsquarter of 20222023 compared to 2021, mainly2022, primarily due to unfavorable changes in the cash surrender valuehigher electric utility margin of corporate-owned life insurance policies,$31 million and favorable interest and dividend income of $16 million, mainly from carrying charges on higher deferred energy balances, partially offset by higher operations and maintenance expenseexpenses of $8$24 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 $6$13 million and increased interest expense of $12 million due to higher outstanding long-term debt balances. Electric utility margin increased primarily fromdue to higher electric retail customer volumes, increased base tariff general rates at Sierra Pacific and higher transmission and wholesale revenue. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs. Depreciation and amortization expense increased primarily due to additional plantassets placed in-service, partially offset by higher interest and dividend income of $14 million, primarily from carrying charges on regulatory balances.in-service.
Northern Powergrid
Operating revenue increased $65$39 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higher distribution revenue of $60$41 million and higher revenue from a gas project that commenced commercial operation in March 2022 totaling $40at CE Gas of $29 million, partially offset by $40$37 million from the stronger U.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier of Last Resort payments totaling $45of $43 million (fully offset in cost of sales) and higher tariff rates of $25 million, partially offset by$10 million. Also impacting distribution revenue was a 4.0%4.8% decline in units distributed, of $9 million.
Earnings increased $96 million for the second quarter of 2022 compared to 2021, primarilylargely due to a deferred income tax chargethe unfavorable impact 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, 2023weather and the higher distribution tariff rates, partially offset by higher distribution-related operating and depreciation expenseslower customer usage, of $27 million, including higher storm-related costs, $9 million from the stronger U.S. dollar and the decline in units distributed.
Operating$11 million. CE Gas 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 offsetand a solar project that commenced commercial operation in cost of sales) and higher tariff rates of $39 million, partially offset by a 3.3% decline in units distributed of $12 million.July 2022.
Earnings increased $103decreased $100 million for the first six monthsquarter of 20222023 compared to 2021,2022, primarily due to a deferred income tax charge of $109$82 million recognized in March 2023 related to the enactment of a June 2021 enacted increase in the United Kingdom corporatenew Energy Profits Levy income tax rate from 19% to 25% effective April 1, 2023 and the higher distribution tariff rates, partially offsettax. Earnings were also impacted by higherunfavorable distribution-related operating and depreciation expenses of $27$11 million including higher storm-relatedand increased non-service benefit plan costs the decline in units distributed andof $10 million, partially offset by favorable operating performance at CE Gas of $8 million from the stronger U.S. dollar.gas and solar projects that commenced commercial operations in 2022.
BHE Pipeline Group
Operating revenue increased $150$138 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higher non-regulatedoperating revenue of $58$71 million at Northern Natural Gas and $55 million at BHE GT&S. The increase in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $63 million and higher transportation revenue of $34 million from higher rates in the Field Area, partially offset by lower gas sales of $25 million (largely offset in cost of sales) from system balancing activities. The increase in operating revenue at BHE GT&S from favorable pricing,was primarily due to an increase in regulated gas transportation and storage services rates due to an agreement in principle forthe settlement of EGTS' general rate case of $25$42 million, higher LNG variable revenue of $25 million at Cove Point, higher transportation revenue of $17 million at Northern Natural Gas due to 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 $99 million for the second quarter of 2022 compared to 2021, primarily due to higher earnings of $90 million 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 margin from non-regulated activities.
Operating revenue increased $92 million for the first six months of 2022 compared to 2021, primarily due to higher non-regulated revenue of $69 million (largely offset in cost of sales) at BHE GT&S from favorable pricing, higher LNG variable revenue of $38$16 million at Cove Point, and an increase in regulated gas transportationvariable revenue related to park and storage services rates due to an agreement in principle for EGTS' general rate caseloan activity of $25$10 million at EGTS, 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 transportationnon-regulated 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 $49 million, respectively, from the February 2021 polar vortex weather event. Excluding this item, gas sales increased $45$22 million (largely offset in cost of sales) and transportation revenue increased $46 million due to higherfrom lower volumes and rates.unfavorable commodity prices.
Earnings increased $38$47 million for the first six monthsquarter of 20222023 compared to 2021, primarily2022, largely due to higher earnings at Northern Natural Gas of $99$28 million and higher earnings at BHE GT&S partially offset by lower earnings of $60 million at Northern Natural Gas. 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 at Cove Point and higher margin from non-regulated activities. Earnings$14 million. The increase at Northern Natural Gas decreased asis due to the higher gross margin on gas salesimpacts of a general rate case of $16 million and higher transportation revenue in the first quarter of 2021 from the February 2021 polar vortex weather event wereField Area, partially offset by the favorable transportation revenuehigher operations and maintenance expense. The increase at BHE GT&S is due to a favorable general rate case settlement at EGTS in 2022 and higher equity earnings at Iroquois Gas Transmission System, partially offset by higher operations and maintenance expense and increased cost of gas from the unfavorable revaluation of volumes and rates.retained, due to lower natural gas prices.
BHE Transmission
Operating revenue increased $1 million for the second quarter and $4$22 million for the first six monthsquarter of 20222023 compared to 2021,2022, primarily due to $26 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue and higher revenue at AltaLink from recovery of higher costs,BHE Canada, partially offset by $7$12 million from the weakerstronger U.S. dollar.
Earnings increased $2 million for the secondfirst quarter and $5 million for the first six months of 20222023 compared to 2021,2022, primarily due to the higher non-regulated revenue and improved equity$6 million of incremental earnings at Electric Transmission Texas, LLC,non-regulated wind-powered generating facilities acquired in November 2022, partially offset by $2$3 million from the weakerstronger U.S. dollar.
BHE Renewables
Operating revenue increased $27$57 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higher wind geothermal and solar revenues of $51$60 million, from higher generation and pricing, partially offset by unfavorablelargely due to favorable changes in the valuation of certain derivative contracts, totaling $14and higher natural gas and electric retail energy services revenue of $23 million, partially offset by lower solar revenues of $20 million from lower generation due to weather events in California. Natural gas and electric retail energy services revenue increased due to higher electric volumes and favorable natural gas and electric pricing, partially offset by lower natural gas revenues of $13 million from lower generation.volumes.
Earnings increased $68decreased $66 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to lower earnings of $79 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $40 million, primarily due to maintenance outages, and lower solar earnings of $18 million from lower generation due to weather events in California. These items were partially offset by higher wind earnings of $58 million and higher geothermal earnings of $11$74 million, largely due to favorable changes in the higher operating revenue and lower maintenance costs. Wind earnings increased primarily due to higher earnings from owned projectsvaluation of $31 million, largely from the higher operating revenue and favorable production tax credits offset by the unfavorablecertain derivative contract valuations,contracts and higher earnings from tax equity investments of $27 million, mainly from higher production tax credits offset by unfavorable performance.
Operating revenue increased $4 million for the first six months of 2022 compared to 2021, primarily due to higher wind, geothermal and solar revenues of $77 million from higher generation and pricing, partially offset by unfavorable changes in the valuation of certain derivative contracts totaling $57 million, lower natural gas revenues of $10 million from lower generation and lower hydro revenues of $6$28 million due to the transfer of the Casecnan generating facility to the Philippine National Irrigation Administration in December 2021.
Earnings increased $156 million for the first six months of 2022 compared to 2021, primarily due to higher wind earnings of $150 million, higher solar earnings of $10 million, mainly due to the higher operating revenue, and higher geothermal earnings of $9 million, largely due to the higher operating revenue and lower maintenance costs, partially offset by lower hydro earnings of $10 million due to the Casecnan generating facility transfer. Wind earnings increased primarily due to higher earnings from tax equity investments of $123 million, mainly as a result of the unfavorable impacts in the first quarter of 2021 from the February 2021 polar vortex weather eventlosses and higher production tax credits offset by unfavorable performance, and higher earnings from owned projects of $27 million, largely from the higher operating revenue and favorable production tax credits offset by the unfavorable derivative contract valuations.credits.
HomeServices
Operating revenue decreased $91$332 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to lower mortgage revenue of $63 million from a 29% decrease in funded volume due to a decline in refinance activity and lower brokerage and settlement services revenue of $26$293 million and lower mortgage revenue of $34 million. The decrease in brokerage and settlement services revenue resulted from a 29% decrease in closed transaction volumes.volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 41% decrease in funded volume, primarily due to rising interest rates.
Earnings decreased $51$55 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to lower earnings from brokerage and settlement services of $33$38 million largely attributable to the decrease in closed units at existing companies, and lower earnings from mortgage services of $22$12 million, largely from the decrease in funded volume.
Operating revenue decreased $116 million for the first six months of 2022 compared to 2021, primarily due to lower mortgage revenue of $160 millionvolumes from a 34% decrease in funded volume due to a decline in refinance activity, partially offset by higher brokerage revenue of $67 million from a 3% increase in closed transaction volume. The increase in brokerage volume was due to acquisitions and a 10% increase in average sales pricerising interest rates. Earnings at existing companies offset by 15% fewer closed units at existing companies.
Earnings decreased $114 million for the first six months of 2022 compared to 2021, primarily due to lower earnings from mortgage services of $71 million and lower earnings from brokerage and settlement services of $49 milliondeclined due to the decrease in closed units at existing companies. Earnings from mortgage services were lower primarily due to the decrease in funded volumes,transaction volume, partially offset by favorable operating expense variances.expenses primarily due to lower compensation costs.
BHE and Other
Operating revenue increased $44decreased $16 million for the secondfirst quarter of 20222023 compared to 2021, primarily2022, due to higher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing and higher electricity volumes offset by lower natural gas volumes.intersegment eliminations.
Earnings increased $583$1,535 million for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to the $600$1,552 million favorable comparative change in the after-tax unrealized position ofrelated to the Company's investment in BYD Company Limited, lower corporate costsfavorable changes in the cash surrender value of corporate-owned life insurance policies of $14 million and $25$8 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway,Hathaway. These items were partially offset by $41higher BHE corporate interest expense from an April 2022 debt issuance and $17 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 and higher BHE corporate interest expense from an April 2022 debt issuance.basis.
Operating revenue decreased $14 million for the first six months of 2022 compared to 2021, primarily due to lower electricity sales revenue at MidAmerican Energy Services, LLC, from unfavorable pricing offset by higher volumes, partially offset by higher natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes.
Earnings increased $445 million for the first six months of 2022 compared to 2021, primarily due to the $433 million favorable comparative change in the after-tax unrealized position of the Company's investment in BYD Company Limited, lower corporate costs, $46 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway and higher earnings of $45 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts, partially 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 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, 20212022 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of June 30, 2022,March 31, 2023, the Company's total net liquidity was as follows (in millions):
| | | BHE Pipeline | | | BHE Pipeline | |
| | MidAmerican | | NV | | Northern | | BHE | | Group and | | | MidAmerican | | NV | | Northern | | BHE | | Group and | |
| | BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Other | | Total | | BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Other | | Total |
| | Cash and cash equivalents | Cash and cash equivalents | $ | 61 | | | $ | 390 | | | $ | 497 | | | $ | 83 | | | $ | 327 | | | $ | 60 | | | $ | 294 | | | $ | 369 | | | $ | 2,081 | | Cash and cash equivalents | $ | 173 | | | $ | 19 | | | $ | 58 | | | $ | 21 | | | $ | 18 | | | $ | 64 | | | $ | 216 | | | $ | 394 | | | $ | 963 | |
| Credit facilities(1) | Credit facilities(1) | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 259 | | | 835 | | | 3,400 | | | — | | | 11,353 | | Credit facilities(1) | 3,500 | | | 2,000 | | | 1,509 | | | 650 | | | 295 | | | 795 | | | 2,725 | | | — | | | 11,474 | |
| Less: | Less: | | Less: | |
| Short-term debt | Short-term debt | (385) | | | — | | | — | | | — | | | (15) | | | (378) | | | (1,170) | | | — | | | (1,948) | | Short-term debt | (755) | | | — | | | — | | | (83) | | | (49) | | | (127) | | | (805) | | | — | | | (1,819) | |
| 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 | — | | | (249) | | | (363) | | | — | | | — | | | (1) | | | — | | | — | | | (613) | |
| Net credit facilities | Net credit facilities | 3,115 | | | 982 | | | 1,139 | | | 650 | | | 244 | | | 456 | | | 2,230 | | | — | | | 8,816 | | Net credit facilities | 2,745 | | | 1,751 | | | 1,146 | | | 567 | | | 246 | | | 667 | | | 1,920 | | | — | | | 9,042 | |
| | Total net liquidity | Total net liquidity | $ | 3,176 | | | $ | 1,372 | | | $ | 1,636 | | | $ | 733 | | | $ | 571 | | | $ | 516 | | | $ | 2,524 | | | $ | 369 | | | $ | 10,897 | | Total net liquidity | $ | 2,918 | | | $ | 1,770 | | | $ | 1,204 | | | $ | 588 | | | $ | 264 | | | $ | 731 | | | $ | 2,136 | | | $ | 394 | | | $ | 10,005 | |
| Credit facilities: | Credit facilities: | | | | | | | | | | | | | | | | | | Credit facilities: | | | | | | | | | | | | | | | | | |
| Maturity dates | Maturity dates | 2025 | | 2025 | | 2023, 2025 | | 2025 | | 2024, 2026 | | 2023, 2026 | | 2022, 2023, 2026 | | Maturity dates | 2025 | | 2024, 2025 | | 2023, 2025 | | 2025 | | 2025 | | 2023, 2026, 2027 | | 2023, 2024, 2026 | |
(1)Includes $15$48 million drawn on a capital expenditure and other uncommitted credit facilityfacilities at Northern Powergrid Holdings.Powergrid.
Operating Activities
Net cash flows from operating activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $5.1$1.1 billion and $4.2$2.2 billion, respectively. The increasedecrease was primarily due to changes in working capital and favorable income tax cash flows.regulatory assets and unfavorable operating results.
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 made for each payment date.
Investing ActivitiesPacifiCorp
Net cash flows from investing activitiesOperating revenue increased $187 million for the six-month periods ended June first quarter of 2023 compared to 2022, primarily due to higher retail revenue of $159 million and higher wholesale and other revenue of $28 million, primarily from higher average wholesale market prices, partially offset by lower wholesale volumes. Retail revenue increased primarily due to price impacts of $107 million from higher average retail rates largely due to tariff changes and product mix and $52 million from higher volumes. Retail customer volumes increased 3.3%, primarily due to the favorable impact of weather, higher customer usage and an increase in the average number of customers.
Earnings decreased $250 million for the first quarter of 2023 compared to 2022, primarily due to higher operations and maintenance expense of $428 million, partially offset by higher utility margin of $38 million, higher allowances for equity and borrowed funds used during construction of $21 million and a favorable income tax benefit from valuation allowance changes on state net operating loss carryforwards. Operations and maintenance expense was unfavorable primarily due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $359 million, higher wildfire mitigation and vegetation management costs, and higher general and plant maintenance costs. Utility margin increased primarily due to higher retail rates and volumes, favorable deferred net power costs and higher average wholesale market prices, partially offset by higher purchased power and thermal generation costs and lower wholesale volumes.
MidAmerican Funding
Operating revenue decreased $85 million for the first quarter of 2023 compared to 2022, primarily due to lower natural gas operating revenue of $70 million and lower electric operating revenue of $17 million. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $61 million (fully offset in cost of sales) and the unfavorable impact of weather of $5 million. Electric operating revenue decreased due to lower wholesale and other revenue of $33 million, partially offset by higher retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower wholesale volumes of $22 million and lower average wholesale per-unit prices of $13 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $14 million (largely offset in expense, primarily cost of sales). Electric retail customer volumes increased 1.0%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.
Earnings increased $8 million for the first quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $17 million, a one-time gain on the sale of an investment of $13 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $12 million, partially offset by higher operations and maintenance expense of $13 million, lower natural gas utility margin of $8 million and lower electric utility margin of $7 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Operations and maintenance expense increased due to higher general and plant maintenance costs and unfavorable property insurance costs. Natural gas utility margin decreased primarily due to the unfavorable impact of weather. Electric utility margin decreased primarily due to lower wholesale revenue, partially offset by higher retail revenue and lower purchased power costs.
NV Energy
Operating revenue increased $306 million for the first quarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $260 million and higher natural gas operating revenue of $44 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $229 million, higher customer volumes of $8 million, increased base tariff general rates of $8 million at Sierra Pacific and favorable transmission and wholesale revenue of $7 million. Electric retail customer volumes increased 2.9%, primarily due to the favorable impact of weather and an increase in the average number of customers.
Earnings increased $5 million for the first quarter of 2023 compared to 2022, primarily due to higher electric utility margin of $31 million and favorable interest and dividend income of $16 million, mainly from carrying charges on higher deferred energy balances, partially offset by higher operations and maintenance expenses of $24 million, unfavorable depreciation and amortization expense of $13 million and increased interest expense of $12 million due to higher outstanding long-term debt balances. Electric utility margin increased primarily due to higher electric retail customer volumes, increased base tariff general rates at Sierra Pacific and higher transmission and wholesale revenue. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service.
Northern Powergrid
Operating revenue increased $39 million for the first quarter of 2023 compared to 2022, primarily due to higher distribution revenue of $41 million and higher revenue at CE Gas of $29 million, partially offset by $37 million from the stronger U.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier of Last Resort payments of $43 million (fully offset in cost of sales) and higher tariff rates of $10 million. Also impacting distribution revenue was a 4.8% decline in units distributed, largely due to the unfavorable impact of weather and lower customer usage, of $11 million. CE Gas revenue increased from a gas project that commenced commercial operation in March 2022 and 2021a solar project that commenced commercial operation in July 2022.
Earnings decreased $100 million for the first quarter of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax. Earnings were $(3.5) billionalso impacted by unfavorable distribution-related operating and $(3.0) billion, respectively.depreciation expenses of $11 million and increased non-service benefit plan costs of $10 million, partially offset by favorable operating performance at CE Gas of $8 million from the gas and solar projects that commenced commercial operations in 2022.
BHE Pipeline Group
Operating revenue increased $138 million for the first quarter of 2023 compared to 2022, primarily due to higher operating revenue of $71 million at Northern Natural Gas and $55 million at BHE GT&S. The changeincrease in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $63 million and higher transportation revenue of $34 million from higher rates in the Field Area, partially offset by lower gas sales of $25 million (largely offset in cost of sales) from system balancing activities. The increase in operating revenue at BHE GT&S was primarily due to an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $42 million, higher capital expendituresLNG revenue of $534 million. Refer$16 million at Cove Point, and an increase in variable revenue related to "Future Usespark and loan activity of Cash" for a discussion$10 million at EGTS, partially offset by lower non-regulated revenue of capital expenditures.$22 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices.
Financing ActivitiesEarnings increased $47 million for the first quarter of 2023 compared to 2022, largely due to higher earnings at Northern Natural Gas of $28 million and higher earnings at BHE GT&S of $14 million. The increase at Northern Natural Gas is due to the impacts of a general rate case of $16 million and higher transportation revenue in the Field Area, partially offset by higher operations and maintenance expense. The increase at BHE GT&S is due to a favorable general rate case settlement at EGTS in 2022 and higher equity earnings at Iroquois Gas Transmission System, partially offset by higher operations and maintenance expense and increased cost of gas from the unfavorable revaluation of volumes retained, due to lower natural gas prices.
Net cash flows from financing activities for the six-month period ended June 30, 2022 was $(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 $2,793 million and consisted mainly of purchases of common stock totaling $870 million, preferred stock redemptions of $800 million, repayments of subsidiary debt totaling $542 million, distributions to noncontrolling interests of $246 million and net repayments of short-term debt totaling $54 million.Transmission
For discussionsOperating revenue increased $22 million for the first quarter of recent2023 compared to 2022, primarily due to $26 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $12 million from the stronger U.S. dollar.
Earnings increased $2 million for the first quarter of 2023 compared to 2022, primarily due to $6 million of incremental earnings at non-regulated wind-powered generating facilities acquired in November 2022, partially offset by $3 million from the stronger U.S. dollar.
BHE Renewables
Operating revenue increased $57 million for the first quarter of 2023 compared to 2022, primarily due to higher wind revenues of $60 million, largely due to favorable changes in the valuation of certain derivative contracts, and higher natural gas and electric retail energy services revenue of $23 million, partially offset by lower solar revenues of $20 million from lower generation due to weather events in California. Natural gas and electric retail energy services revenue increased due to higher electric volumes and favorable natural gas and electric pricing, partially offset by lower natural gas volumes.
Earnings decreased $66 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings of $79 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $40 million, primarily due to maintenance outages, and lower solar earnings of $18 million from lower generation due to weather events in California. These items were partially offset by higher wind earnings of $74 million, largely due to favorable changes in the valuation of certain derivative contracts and higher earnings from tax equity investments of $28 million due to lower equity losses and higher production tax credits.
HomeServices
Operating revenue decreased $332 million for the first quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $293 million and lower mortgage revenue of $34 million. The decrease in brokerage and settlement services revenue resulted from a 29% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 41% decrease in funded volume, primarily due to rising interest rates.
Earnings decreased $55 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $38 million and mortgage services of $12 million, largely from the decrease in funded volumes from rising interest rates. Earnings at brokerage and settlement services declined due to the decrease in closed transaction volume, partially offset by favorable operating expenses primarily due to lower compensation costs.
BHE and Other
Operating revenue decreased $16 million for the first quarter of 2023 compared to 2022, due to higher intersegment eliminations.
Earnings increased $1,535 million for the first quarter of 2023 compared to 2022, primarily due to the $1,552 million favorable comparative change related to the Company's investment in BYD Company Limited, favorable changes in the cash surrender value of corporate-owned life insurance policies of $14 million and $8 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway. These items were partially offset by higher BHE corporate interest expense from an April 2022 debt issuance and $17 million of lower federal income tax credits recognized on a consolidated basis.
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 shareholders' equity transactions, referor affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to Notes 4 and 10redeem 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 Part I, Item 1 of this Form 10-Q.
Net cash flows from financing activities for the six-month period ended June 30, 2021 was $(1.2) billion. Sources of cash totaled $784 million and consisted of proceeds from subsidiary debt issuances totaling $539 million and net proceeds from short-term debt of $245 million. Uses of cash totaled $2.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.2 billion, repayments of BHE senior debt totaling $450 million and distributions to noncontrolling interests of $234 million.
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.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Six-Month Periods | | Annual |
| Ended June 30, | | Forecast |
| 2021 | | 2022 | | 2022 |
| Capital expenditures by business: | | | | | |
| PacifiCorp | $ | 819 | | | $ | 894 | | | $ | 2,279 | |
| MidAmerican Funding | 720 | | | 862 | | | 1,913 | |
| NV Energy | 365 | | | 541 | | | 1,228 | |
| Northern Powergrid | 369 | | | 450 | | | 776 | |
| BHE Pipeline Group | 308 | | | 457 | | | 1,252 | |
| BHE Transmission | 156 | | | 95 | | | 210 | |
| BHE Renewables | 80 | | | 60 | | | 185 | |
| HomeServices | 18 | | | 20 | | | 55 | |
BHE and Other(1) | 13 | | | 3 | | | 16 | |
| Total | $ | 2,848 | | | $ | 3,382 | | | $ | 7,914 | |
| | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | |
| Capital expenditures by type: | | | | | |
| Wind generation | $ | 483 | | | $ | 300 | | | $ | 886 | |
| Electric distribution | 817 | | | 815 | | | 1,763 | |
| Electric transmission | 339 | | | 620 | | | 1,773 | |
| Natural gas transmission and storage | 308 | | | 336 | | | 976 | |
| Solar generation | 67 | | | 100 | | | 230 | |
| Other | 834 | | | 1,211 | | | 2,286 | |
| 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 of wind-powered generating facilities at MidAmerican Energy totaling $5 million and $172 million for the six-month periods ended June 30, 2022 and 2021, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $106 million for the remainder of 2022.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $214 million and $82 million for the six-month periods ended June 30, 2022 and 2021, respectively. Planned spending for the repowering of wind-powered generating facilities totals $314 million for the remainder of 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 593 MWs of current repowering projects not in-service as of June 30, 2022, 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 $4 million and $79 million for the six-month periods ended June 30, 2022 and 2021, respectively. Construction includes 516 MWs of new wind-powered generating facilities that were placed in-service in 2021. Planned spending for the construction of additional wind-powered generating facilities totals $24 million for the remainder of 2022. The energy production from the new wind-powered generating facilities placed in-service by the end of 2024 is expected to qualify for 60% of the federal PTCs available for 10 years once the equipment is placed in-service.
◦Planned acquisition and repowering of two wind-powered generating facilities by PacifiCorp totaling $7 million and $2 million (excluding the 2021 sale of wind 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 be placed in-service in 2023 and 2024. Planned spending for acquiring and repowering generating facilities totals $14 million for the remainder of 2022.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $45 million for the six-month period ended June 30, 2022. Planned spending for repowering generating facilities totals $43 million for the remainder of 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 transmission investment primarily reflects planned costs for the 416-mile, 500-kV high-voltage transmission line 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 these Energy Gateway Transmission segments to be placed in-service in 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 other growth projects totaled $60 million and $41 million for the 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 spending for the following:
◦Construction of solar-powered generating facilities at MidAmerican Energy totaling 141 MWs of small- and utility-scale solar generation, with total spend of $77 million and $63 million for the six-month periods ended June 30, 2022 and 2021, respectively and planned spending of $63 million for the remainder of 2022.
◦Construction of a solar-powered generating facility at Nevada Power 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-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation 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.
Material Cash Requirements
As of June 30, 2022, there have been no material changes in cash requirements from the information provided in Item 78 of the Company's Annual Report on Form 10-K for the year ended December 31, 2021, other than those disclosed in Notes 4 and 82022 for further discussion regarding the limitation of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.distributions from BHE's subsidiaries.
As of March 31, 2023, the Company's total net liquidity was as follows (in millions):
Quad Cities Generating Station Operating Status | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | BHE Pipeline | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | | | Group and | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Other | | Total |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 173 | | | $ | 19 | | | $ | 58 | | | $ | 21 | | | $ | 18 | | | $ | 64 | | | $ | 216 | | | $ | 394 | | | $ | 963 | |
| | | | | | | | | | | | | | | | | |
Credit facilities(1) | 3,500 | | | 2,000 | | | 1,509 | | | 650 | | | 295 | | | 795 | | | 2,725 | | | — | | | 11,474 | |
| Less: | | | | | | | | | | | | | | | | | |
| Short-term debt | (755) | | | — | | | — | | | (83) | | | (49) | | | (127) | | | (805) | | | — | | | (1,819) | |
| Tax-exempt bond support and letters of credit | — | | | (249) | | | (363) | | | — | | | — | | | (1) | | | — | | | — | | | (613) | |
| Net credit facilities | 2,745 | | | 1,751 | | | 1,146 | | | 567 | | | 246 | | | 667 | | | 1,920 | | | — | | | 9,042 | |
| | | | | | | | | | | | | | | | | |
| Total net liquidity | $ | 2,918 | | | $ | 1,770 | | | $ | 1,204 | | | $ | 588 | | | $ | 264 | | | $ | 731 | | | $ | 2,136 | | | $ | 394 | | | $ | 10,005 | |
| Credit facilities: | | | | | | | | | | | | | | | | | |
| Maturity dates | 2025 | | 2024, 2025 | | 2023, 2025 | | 2025 | | 2025 | | 2023, 2026, 2027 | | 2023, 2024, 2026 | | | | |
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, which(1)Includes $48 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $1.1 billion and $2.2 billion, respectively. The decrease was a subsidiary of Exelon Corporation priorprimarily due to February 1, 2022), the operator of Quad Cities Generating Station Units 1changes in working capital 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 ZECsregulatory assets and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Constellation 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.unfavorable operating results.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjectedtiming of the Company's income tax cash flows from period to a MOPR, its offer price inperiod can be significantly affected by 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.estimated federal income tax payment methods selected and assumptions made for each payment date.
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, 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 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. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and 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, Constellation 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, 2021 and new regulatory matters occurring in 2022.
PacifiCorp
OregonOperating revenue increased $187 million for the first quarter of 2023 compared to 2022, primarily due to higher retail revenue of $159 million and higher wholesale and other revenue of $28 million, primarily from higher average wholesale market prices, partially offset by lower wholesale volumes. Retail revenue increased primarily due to price impacts of $107 million from higher average retail rates largely due to tariff changes and product mix and $52 million from higher volumes. Retail customer volumes increased 3.3%, primarily due to the favorable impact of weather, higher customer usage and an increase in the average number of customers.
In MarchEarnings decreased $250 million for the first quarter of 2023 compared to 2022, PacifiCorp filedprimarily due to higher operations and maintenance expense of $428 million, partially offset by higher utility margin of $38 million, higher allowances for equity and borrowed funds used during construction of $21 million and a general rate case requestingfavorable income tax benefit from valuation allowance changes on state net operating loss carryforwards. Operations and maintenance expense was unfavorable primarily due to an overall rate changeincrease in loss accruals, net of $82 million, or 6.6%, to become effective January 1, 2023, that includes cost increasesexpected insurance recoveries, associated with the implementation2020 Wildfires of PacifiCorp's$359 million, higher wildfire mitigation and vegetation management plans. Partiescosts, and higher general and plant maintenance costs. Utility margin increased primarily due to the case filed testimony in June 2022. PacifiCorp filed reply testimony in July 2022 supporting an overall rate increase of $94 million but proposing that the request be capped at PacifiCorp's original request. A hearing in the rate case will be held in September 2022 with an order expected in December 2022.higher retail rates and volumes, favorable deferred net power costs and higher average wholesale market prices, partially offset by higher purchased power and thermal generation costs and lower wholesale volumes.
In May 2022, PacifiCorp filed its 2021 power cost adjustment mechanism ("PCAM"), which is the first time since the mechanism has been in place that a rate change has been warranted. After consideration of the mechanism's deadband, sharing band and earnings test, PacifiCorp is requesting recovery of $52 million, or a 4.2% increase, to become effective January 1, 2023. This request is incremental to the rate change sought in the general rate case.MidAmerican Funding
In JulyOperating revenue decreased $85 million for the first quarter of 2023 compared to 2022, PacifiCorp filed an application requesting approvalprimarily due to lower natural gas operating revenue of an automatic$70 million and lower electric operating revenue of $17 million. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment clause with a balancing accountrecoveries of $61 million (fully offset in cost of sales) and the unfavorable impact of weather of $5 million. Electric operating revenue decreased due to recover costs associated with implementing PacifiCorp's wildfire protection planlower wholesale and other revenue of $33 million, partially offset by higher retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower wholesale volumes of $22 million and lower average wholesale per-unit prices of $13 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $14 million (largely offset in Oregon. Oregon Senate Bill 762 provides for utilitiesexpense, primarily cost of sales). Electric retail customer volumes increased 1.0%, primarily due to timely recover these costs through an automatic adjustment clause. The filing requests a rate increasehigher customer usage, partially offset by the unfavorable impact of $20 million, or 1.6%, to recover incremental costs in 2022. While PacifiCorp requested an effective date of August 24, 2022, the OPUC has suspended the filing for further review.weather.
Washington
In June 2021, PacifiCorp filedEarnings increased $8 million for the first quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $17 million, a power cost only rate case to update baseline net power costs for 2022. PacifiCorp requested aone-time gain on the sale of an investment of $13 million or 3.7%, rate increase with 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 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 effective May 1, 2022.
In June 2022, PacifiCorp filed its 2021 PCAM and the new tracking mechanism for PTCs approvedfavorable changes in the 2021cash surrender value of corporate-owned life insurance policies of $12 million, partially offset by higher operations and maintenance expense of $13 million, lower natural gas utility margin of $8 million and lower electric utility margin of $7 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Operations and maintenance expense increased due to higher general rate case. Forand plant maintenance costs and unfavorable property insurance costs. Natural gas utility margin decreased primarily due to the 2021 PCAM, PacifiCorp is requesting recoveryunfavorable impact of $26 million, or a 6.5% increase. PacifiCorp proposed that the 2021 PCAM be amortized over two years, rather than the one-year period required under the current terms of the PCAM. For the new 2021 PTC tracker, PacifiCorp is seeking recovery of $3 million, or an 0.8% increase. Should the WUTC approve the proposalweather. Electric utility margin decreased primarily due to extend the amortization period of the 2021 PCAM from one to two years, the combined annual increase would be $16 million, or 4.0%, effective January 1, 2023.
California
In May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become effective January 1, 2023. In June 2022, a proposed procedural schedule was developed that would result in a decision in August 2023.lower wholesale revenue, partially offset by higher retail revenue and lower purchased power costs.
MidAmericanNV Energy
South DakotaOperating revenue increased $306 million for the first quarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $260 million and higher natural gas operating revenue of $44 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $229 million, higher customer volumes of $8 million, increased base tariff general rates of $8 million at Sierra Pacific and favorable transmission and wholesale revenue of $7 million. Electric retail customer volumes increased 2.9%, primarily due to the favorable impact of weather and an increase in the average number of customers.
In MayEarnings increased $5 million for the first quarter of 2023 compared to 2022, MidAmerican Energy filed a request with the South Dakota Public Utilities Commission ("SDPUC") for an increase in its South Dakotaprimarily due to higher electric utility margin of $31 million and favorable interest and dividend income of $16 million, mainly from carrying charges on higher deferred energy balances, partially offset by higher operations and maintenance expenses of $24 million, unfavorable depreciation and amortization expense of $13 million and increased interest expense of $12 million due to higher outstanding long-term debt balances. Electric utility margin increased primarily due to higher electric retail natural gascustomer volumes, increased base tariff general rates which would increase revenue by $7 million annually. If approved, the requested rates would increase retail customers' bills by an average of 6.4%.
Wind PRIME
In January 2022, MidAmerican Energy filed an application with the IUB for 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 IUB are scheduled to begin in October 2022.
NV Energy (Nevada Power and Sierra Pacific)
Regulatory Rate Review
In June 2022,at 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 madeand higher transmission and wholesale revenue. Operations and maintenance expense increased primarily due to revise depreciation rates based on a study, the results of which are reflected in the proposed revenue requirement. An order is expected by the end of 2022higher general and if approved, would be effective January 1, 2023.
Senate Bill 448 ("SB 448")
SB 448 was signed into law on June 10, 2021. The legislation is intendedplant maintenance costs and higher customer service operations costs. Depreciation and amortization expense increased primarily due to accelerate transmission development, renewable energy and storage, and accelerate transportation electrification within the state of Nevada. In 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 high-voltage transmission infrastructure, Greenlink North among others, that will beadditional assets 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 other regulations that 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 with 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 as well as the related on-going reallocated revenue requirement. Sierra Pacific's application would have, if approved by the PUCN as filed, resulted 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.in-service.
Northern Powergrid Distribution Companies
GEMA, through Ofgem, is undertaking its scheduled reviewOperating revenue increased $39 million for the first quarter of 2023 compared to 2022, primarily due to higher distribution revenue of $41 million and higher revenue at CE Gas of $29 million, partially offset by $37 million from the electricitystronger U.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier of Last Resort payments of $43 million (fully offset in cost of sales) and higher tariff rates of $10 million. Also impacting distribution price controlrevenue was a 4.8% decline in units distributed, largely due to putthe unfavorable impact of weather and lower customer usage, of $11 million. CE Gas revenue increased from a gas project that commenced commercial operation in placeMarch 2022 and a new price control at the end of the current periodsolar project that ends March 2023. The new price control ("ED2") will run for five years from April 2023 to March 2028. In December 2020 and March 2021, GEMA published its decision on the methodology it will use to set ED2. This confirmed that Ofgem will maintain many aspects of the current price control and that the changes being made will generally follow the template that was set by the price controls implementedcommenced commercial operation in April 2021 for transmission and gas distribution in Great Britain. Specific changes include new service standard incentives and mechanisms to adjust cost allowances in specific circumstances, while others will be discontinued, and partially updating the allowed return on equity within the period for changes in the interest rate on government bonds.July 2022.
In December 2021, Northern Powergrid publishedEarnings decreased $100 million for the first quarter of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax. Earnings were also impacted by unfavorable distribution-related operating and filed its businessdepreciation expenses of $11 million and increased non-service benefit plan with Ofgem, setting out its detailed approach for 2023-2028 includingcosts of $10 million, partially offset by favorable operating performance at CE Gas of $8 million from the cost allowances this approach would require. In June 2022, Ofgem published its draft determinations, which included an allowed cost of equity of 4.75% plus inflation (calculated using the United Kingdom's consumer price index including owner occupiers' housing costs). When placed on a comparable footing, by adjusting for differencesgas and solar projects that commenced commercial operations in the assumed equity ratio and the measure of inflation used, this working assumption is approximately two percentage points lower than the current cost of equity for electricity distribution. Ofgem's proposals also set out cost allowances and associated expectations. Final values from Ofgem are expected in late 2022.
BHE Pipeline Group
Operating revenue increased $138 million for the first quarter of 2023 compared to 2022, primarily due to higher operating revenue of $71 million at Northern Natural Gas and $55 million at BHE GT&S. The increase in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $63 million and higher transportation revenue of $34 million from higher rates in the Field Area, partially offset by lower gas sales of $25 million (largely offset in cost of sales) from system balancing activities. The increase in operating revenue at BHE GT&S was primarily due to an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $42 million, higher LNG revenue of $16 million at Cove Point, and an increase in variable revenue related to park and loan activity of $10 million at EGTS, partially offset by lower non-regulated revenue of $22 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices.
Earnings increased $47 million for the first quarter of 2023 compared to 2022, largely due to higher earnings at Northern Natural Gas of $28 million and higher earnings at BHE GT&S of $14 million. The increase at Northern Natural Gas is due to the impacts of a general rate case of $16 million and higher transportation revenue in the Field Area, partially offset by higher operations and maintenance expense. The increase at BHE GT&S is due to a favorable general rate case settlement at EGTS in 2022 and higher equity earnings at Iroquois Gas Transmission System, partially offset by higher operations and maintenance expense and increased cost of gas from the unfavorable revaluation of volumes retained, due to lower natural gas prices.
BHE Transmission
Operating revenue increased $22 million for the first quarter of 2023 compared to 2022, primarily due to $26 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $12 million from the stronger U.S. dollar.
Earnings increased $2 million for the first quarter of 2023 compared to 2022, primarily due to $6 million of incremental earnings at non-regulated wind-powered generating facilities acquired in November 2022, partially offset by $3 million from the stronger U.S. dollar.
BHE Renewables
Operating revenue increased $57 million for the first quarter of 2023 compared to 2022, primarily due to higher wind revenues of $60 million, largely due to favorable changes in the valuation of certain derivative contracts, and higher natural gas and electric retail energy services revenue of $23 million, partially offset by lower solar revenues of $20 million from lower generation due to weather events in California. Natural gas and electric retail energy services revenue increased due to higher electric volumes and favorable natural gas and electric pricing, partially offset by lower natural gas volumes.
Earnings decreased $66 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings of $79 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $40 million, primarily due to maintenance outages, and lower solar earnings of $18 million from lower generation due to weather events in California. These items were partially offset by higher wind earnings of $74 million, largely due to favorable changes in the valuation of certain derivative contracts and higher earnings from tax equity investments of $28 million due to lower equity losses and higher production tax credits.
HomeServices
Operating revenue decreased $332 million for the first quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $293 million and lower mortgage revenue of $34 million. The decrease in brokerage and settlement services revenue resulted from a 29% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 41% decrease in funded volume, primarily due to rising interest rates.
Earnings decreased $55 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $38 million and mortgage services of $12 million, largely from the decrease in funded volumes from rising interest rates. Earnings at brokerage and settlement services declined due to the decrease in closed transaction volume, partially offset by favorable operating expenses primarily due to lower compensation costs.
BHE and Other
Operating revenue decreased $16 million for the first quarter of 2023 compared to 2022, due to higher intersegment eliminations.
Earnings increased $1,535 million for the first quarter of 2023 compared to 2022, primarily due to the $1,552 million favorable comparative change related to the Company's investment in BYD Company Limited, favorable changes in the cash surrender value of corporate-owned life insurance policies of $14 million and $8 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway. These items were partially offset by higher BHE corporate interest expense from an April 2022 debt issuance and $17 million of lower federal income tax credits recognized on a consolidated basis.
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, 2022 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of March 31, 2023, the Company's total net liquidity was as follows (in millions):
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| | | | | | | | | | | | | | | BHE Pipeline | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | | | Group and | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Other | | Total |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 173 | | | $ | 19 | | | $ | 58 | | | $ | 21 | | | $ | 18 | | | $ | 64 | | | $ | 216 | | | $ | 394 | | | $ | 963 | |
| | | | | | | | | | | | | | | | | |
Credit facilities(1) | 3,500 | | | 2,000 | | | 1,509 | | | 650 | | | 295 | | | 795 | | | 2,725 | | | — | | | 11,474 | |
| Less: | | | | | | | | | | | | | | | | | |
| Short-term debt | (755) | | | — | | | — | | | (83) | | | (49) | | | (127) | | | (805) | | | — | | | (1,819) | |
| Tax-exempt bond support and letters of credit | — | | | (249) | | | (363) | | | — | | | — | | | (1) | | | — | | | — | | | (613) | |
| Net credit facilities | 2,745 | | | 1,751 | | | 1,146 | | | 567 | | | 246 | | | 667 | | | 1,920 | | | — | | | 9,042 | |
| | | | | | | | | | | | | | | | | |
| Total net liquidity | $ | 2,918 | | | $ | 1,770 | | | $ | 1,204 | | | $ | 588 | | | $ | 264 | | | $ | 731 | | | $ | 2,136 | | | $ | 394 | | | $ | 10,005 | |
| Credit facilities: | | | | | | | | | | | | | | | | | |
| Maturity dates | 2025 | | 2024, 2025 | | 2023, 2025 | | 2025 | | 2025 | | 2023, 2026, 2027 | | 2023, 2024, 2026 | | | | |
(1)Includes $48 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $1.1 billion and $2.2 billion, respectively. The decrease was primarily due to changes in working capital and regulatory assets and unfavorable operating results.
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 made for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(1.8) billion and $(1.6) billion, respectively. The change was primarily due to higher purchases, net of proceeds from maturities, of U.S. Treasury Bills totaling $896 million and higher capital expenditures of $295 million, partially offset by higher proceeds from sales of marketable securities of $942 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2023, was $20 million. Sources of cash totaled $699 million and consisted of net proceeds from short-term debt. Uses of cash totaled $679 million and consisted mainly of repayments of BHE senior debt totaling $400 million, repayments of subsidiary debt totaling $136 million and distributions to noncontrolling interests of $126 million.
Net cash flows from financing activities for the three-month period ended March 31, 2022, was $(310) million. Sources of cash totaled $405 million and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $715 million and consisted mainly of repayments of subsidiary debt totaling $193 million, net repayments of short-term debt totaling $165 million and distributions to noncontrolling interests of $117 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 customer 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.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2022 | | 2023 | | 2023 |
| Capital expenditures by business: | | | | | |
| PacifiCorp | $ | 374 | | | $ | 643 | | | $ | 3,662 | |
| MidAmerican Funding | 459 | | | 382 | | | 2,324 | |
| NV Energy | 272 | | | 437 | | | 1,751 | |
| Northern Powergrid | 169 | | | 124 | | | 597 | |
| BHE Pipeline Group | 205 | | | 169 | | | 1,431 | |
| BHE Transmission | 47 | | | 43 | | | 191 | |
| BHE Renewables | 19 | | | 29 | | | 269 | |
| HomeServices | 12 | | | 11 | | | 46 | |
BHE and Other(1) | (4) | | | 10 | | | 12 | |
| Total | $ | 1,553 | | | $ | 1,848 | | | $ | 10,283 | |
| | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | |
| Capital expenditures by type: | | | | | |
| Wind generation | $ | 153 | | | $ | 105 | | | $ | 2,172 | |
| Electric distribution | 388 | | | 477 | | | 2,071 | |
| Electric transmission | 261 | | | 291 | | | 2,063 | |
| Natural gas transmission and storage | 103 | | | 65 | | | 1,097 | |
| Solar generation | 51 | | | 40 | | | 236 | |
| Electric battery and pumped hydro storage | 1 | | | 40 | | | 236 | |
| Other | 596 | | | 830 | | | 2,408 | |
| Total | $ | 1,553 | | | $ | 1,848 | | | $ | 10,283 | |
(1)BHE and Other represents amounts related principally to other entities corporate functions and intersegment eliminations.
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $75 million and $3 million for the three-month periods ended March 31, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $1,025 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $5 million and $120 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $16 million for the remainder of 2023. 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.
◦Construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties at PacifiCorp totaling $14 million and $6 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $807 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $25 million for the three-month period ended March 31, 2022. Planned spending for the repower of wind-powered facilities totals $50 million for the remainder of 2023.
•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 enhancements 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 transmission investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $110 million and $96 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $898 million for the remainder of 2023.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Expenditures for the expansion program and other growth projects totaled $42 million and $30 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026 through 2028 and other growth projects totals $88 million for the remainder of 2023.
◦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 asset modernization and the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for pipeline integrity projects, automation and controls upgrades, corrosion control, unit exchanges, compressor modifications, projects related to Pipeline and Hazardous Materials Safety Administration natural gas storage rules and natural gas transmission, storage and LNG terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including spending for the following:
◦Construction of solar-powered generating facilities at PacifiCorp totaling 377 MWs of new generation and are expected to be placed in-service in 2026. Planned spending totals $12 million for the remainder of 2023.
◦Construction and operation of solar-powered generating facilities at MidAmerican Energy, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the three-month periods ended March 31, 2023 and 2022 solar generation spend totaled $9 million and $44 million, respectively. Planned spending totals $1 million for the remainder of 2023.
◦Construction of a solar-powered generating facility at Nevada Power totaling $31 million and $7 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending totals $175 million for the remainder of 2023. Construction includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:
◦Construction at the Nevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada and a 220-MW grid-tied battery energy storage system that will be developed on the site of the retired Reid Gardner generating station in Clark County, Nevada, both with commercial operation expected by the end of 2023. Also, a 200-MW battery energy storage system that will be developed on the site of the Valmy generating station in Humboldt County, Nevada with commercial operation expected by the end of 2025. Total spending for the three-month period ended March 31, 2023, was $39 million with planned spending of $159 million for the remainder of 2023.
•Other 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.
Material Cash Requirements
As of March 31, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2022, 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
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, 2022, and new regulatory matters occurring in 2023.
PacifiCorp
Utah
In May 2023, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2022. The filing requested a rate increase of $98 million, or 4.6%, effective on an interim basis July 1, 2023.
Oregon
In April 2023, PacifiCorp filed its transition adjustment mechanism requesting approval to update net power costs for 2024. The filing requested a rate increase of $164 million, or 9.5%, to become effective January 1, 2024.
Wyoming
In March 2023, PacifiCorp filed a general rate case requesting a rate increase of $140 million, or 21.6%, to become effective January 1, 2024. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities.
In April 2023, PacifiCorp filed its energy cost adjustment and renewable energy credit and sulfur dioxide revenue credit mechanisms to recover deferred net power costs from 2022. The combined filing requested a rate increase of $49 million, or 7.4%, to become effective on an interim basis July 1, 2023.
Washington
In March 2023, PacifiCorp filed a general rate case requesting a two-year rate plan with a rate increase of $27 million, or 6.6%, to become effective March 1, 2024, and a second rate increase of $28 million, or 6.5%, to become effective March 1, 2025. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities.
California
In May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to establish a memorandum account to track the change in rates beginning January 1, 2023, until the new rates become effective upon the issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in February 2023 with a slight adjustment of an overall rate increase of $27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling requesting additional information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum accounts. In March 2023, the CPUC split the general rate case into two tracks. The first track addresses the general rate case with an expected decision from the CPUC in late 2023, and the second track addresses the wildfire memorandum accounts with an expected decision in early 2024.
MidAmerican Energy
South Dakota
In May 2022, MidAmerican Energy filed a request with the South Dakota Public Utilities Commission ("SDPUC") for a $7 million, or 6.4%, annual increase in South Dakota retail natural gas rates. In March 2023, MidAmerican Energy filed a settlement agreement between all parties allowing a total increase of $6 million, or 5.5%, annual increase in South Dakota retail natural gas rates, upon completion of the capital investment phase-in adjustment clause. On March 31, 2023, the SDPUC issued an order approving the settlement agreement with final rates effective April 1, 2023.
Wind PRIME
In January 2022, MidAmerican Energy filed an application with the IUB for 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 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 expects to be eligible for 100% PTCs under current tax law for the Wind PRIME projects. In December 2022, MidAmerican Energy, the Iowa Office of Consumer Advocate and the Iowa Business Energy Coalition filed a non-unanimous settlement with the IUB that includes a rate of return of 11.0%. The settlement would benefit customers by providing an immediate rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. The IUB conducted a hearing on the application and proposed settlement during the week of February 20, 2023. On April 27, 2023, the IUB issued its final order regarding the application. The IUB found that MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application, but rejected the settlement and proposed its own principles for the project. MidAmerican Energy is reviewing the order and assessing options for rejection or motion to reconsider. MidAmerican Energy must either accept or reject the order, or file a motion for reconsideration within 20 days and no later than May 17, 2023.
Iowa Transmission Legislation
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law provides MidAmerican Energy, as an incumbent electric transmission owner, the legal right to construct, own and maintain transmission lines in MidAmerican Energy's service territory that have been approved by the MISO (or another federally registered planning authority) and are eligible to receive regional cost allocation. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for the construction of eligible electric transmission lines that it intends to construct, own and maintain. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the eligible electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the eligible electric transmission line. In October 2020, national transmission interests filed a lawsuit that challenged the law on state constitutional grounds. The suit argues that the law was enacted in violation of the "single-subject" provision of Iowa's state constitution because it was "log-rolled" into a late session appropriations bill and violates the equal protection provision of the Iowa constitution. The State of Iowa defended the law, and MidAmerican Energy and ITC Midwest both intervened and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of standing, and the national transmission interests appealed. In June 2022, the Iowa Court of Appeals upheld the district court's decision, after which the national transmission interests asked the Iowa Supreme Court to reconsider. In November 2022, the Iowa Supreme Court granted the motion to reconsider. On March 24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower courts, held the national transmission interests had standing, and remanded the case to the district court to consider the state constitutional claims on their merits. The opinion also imposed a temporary injunction that stayed enforcement of the law pending a decision on the merits. On April 7, 2023, the State of Iowa, acting individually, and MidAmerican Energy and ITC Midwest, acting jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19, 2023, the national transmission interests filed a reply that (1) expressed its opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to hold that the injunction specifically applied to and precluded advancement of MidAmerican Energy's Long Range Transmission Projects ("LRTP") Tranche 1 projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on the constitutional claims on the merits without further briefing or argument. On April 26, 2023, the Iowa Supreme Court issued an order that denied the petitions for rehearing without comment and made minor, non-substantive changes to the decision, with no changes to the injunction. No earlier than May 18, 2023, the Iowa Supreme Court will remand the case to the district court for further proceedings on the merits. To this point, MISO has taken no action to reverse or disrupt its approval of MidAmerican Energy's LRTP Tranche 1 projects. This matter only potentially affects the manner in which MidAmerican Energy would secure the right to construct transmission lines that are eligible for regional cost allocation and are otherwise subject to competitive bidding under the MISO tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing rights to construct any other transmission lines, including lines required to serve new or expanded retail load, connect new generators or meet reliability criteria.
NV Energy (Nevada Power and Sierra Pacific)
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. In October 2022, all parties to the proceedings relating to the joint application entered into a Stipulation to delay the procedural schedule. The Nevada Utilities made a supplemental filing on December 30, 2022. In March 2023, the proceedings relating to the joint application were postponed to May 2023. In April 2023, the Nevada Utilities filed a notice with the PUCN requesting to withdraw the joint application to merge into a single corporate entity and vacate the current procedural schedule, and executed a termination of the related merger agreement.
Transportation Electrification Plan ("TEP")
In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of a Distributed Resource Plan amendment to implement the state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs and schedules to implement the TEP. The 2022 TEP outlines programs, investments and incentives to accelerate transportation electrification across Nevada. The Nevada Utilities proposed a budget of $348 million, which represents the maximum cost over the depreciable life of the TEP's programs and assets, to deploy the TEP in 2023 through 2024. In March 2023, the PUCN issued an order approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on the program management and contingency budget amounts. The unapproved programs have been deferred for approval in future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs.In April 2023, interveners filed a petition for reconsideration of the PUCN's March 2023 Order.
Northern Powergrid Distribution Companies
Ofgem has completed the price control review that resulted in a new price control effective April 1, 2023. The license modifications that give effect to the price control were published by Ofgem on February 3, 2023 and were subject to appeal to the Competition and Markets Authority ("CMA") if an appeal was filed by March 3, 2023. On March 2, 2023, Northern Powergrid sought permission from the CMA to appeal against the license modifications that give effect to the RIIO-ED2 price control. The appeal relates to two specific areas:
•Ofgem's misallocation of allowances that is inconsistent with efficient costs; and
•Ofgem's approach to determine rewards for the Business Plan Incentive.
The permission for the appeal was granted by the CMA and the appeal is expected to conclude in the fourth quarter of 2023 in accordance with the timetable required of the CMA. The outcome of this appeal may increase the revenue available to the Company if the CMA amends the price control determination.
BHE Pipeline Group
BHE GT&S
In September 2021, 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 transportationtransmission 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 refundrefund. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the outcometerms of hearing procedures. In June 2022, the parties reachedsettlement agreement, EGTS' rates result in an agreementincrease to annual firm transmission and storage services revenues of approximately $160 million and a decrease in principle andannual depreciation expense of approximately $30 million, compared to the litigation procedural schedule was ordered heldrates in abeyance for 90 dayseffect prior to enable the parties to finalize a settlement. The settlement is expected to be filed by September 30,April 1, 2022. As of June 30, 2022, EGTS' provision for rate refund for April 2022 through JuneFebruary 2023, including accrued interest, totaled $91 million. In November 2022, totaled $35 millionthe FERC approved the settlement agreement and was includedthe rate refunds to customers were processed in other current liabilities on the Consolidated Balance Sheet.late February 2023.
Northern Natural Gas
In July 2022, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $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 and storage 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.rates. In July 2022,January 2023, the FERC issued an order that suspended theapproved Northern Natural Gas filing to implement its interim rates proposed for five months following the proposed effective date, until January 1, 2023, subject to refund and the outcome of hearing procedures. Procedural hearings are scheduled to begin June 14, 2023.
BHE Transmission
AltaLink
2022-20232024-2025 General Tariff Application
In April 2021,2023, AltaLink filed its 2022-20232024-2025 GTA delivering onwith the last two yearsAUC with total total transmission tariffs of itsC$902.3 million and C$908.6 million for 2024 and 2025, respectively, which extends AltaLink's previous five-year commitment to keep rates flat for customersmaintain its tariff at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year-over-year increase of approximately 2% in 2022 and 2023 revenue requirements.for another year. The application requestedalso requests the approval to reinstate C$98.9 million cost of transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively. In September 2021, AltaLink provided responsesremoval to rate base which was not previously approved, based on additional information requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates. In November 2021, the AUC approved the 2022 interim refundable transmission tariff at C$57 million per month effective January 2022.filed.
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 January 2022, the AUC initiated the 2023 generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with respect to the first stage of the 2023 GCOC proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial markets due to the COVID-19 pandemic. In June 2022, the AUC initiated the second stage to explore a formula-based approach to determine the return on equity for 2024 and future test periods.
In February 2023, AltaLink and other stakeholders filed evidence. AltaLink filed expert evidence recommending a 10.3% return on equity, on a recommended equity ratio of 40%. Other utilities filed similar recommendations. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the Industrial Power Consumers Association of Alberta recommended returns on equity ranging from 6.75% to 7.7% and equity ratios ranging from 35% to 37%. AltaLink's expert witness, as well as all other utility experts, submitted that they are generally not in favor of implementing a formulaic adjustment mechanism for allowed return on equity due to the challenges in maintaining the Fair Return Standard through formulaic adjustments. The interveners are generally in favor of a formula. The AUC expects to conclude the second stage of the GCOC proceeding in the third quarter of 2023.
Environmental Laws and Regulations
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, RPS, air and water quality, emissions performance standards, water quality, coal combustion byproductash 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 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, 2021,2022, and new environmental matters occurring in 2022.2023.
Climate Change
Affordable Clean Energy Rule
In June 2014, the EPA released proposed regulations to address greenhouse gas emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "best system of 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 litigation 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 actions 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 standards 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 the 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 on June 30, 2022, the United States Supreme Court issued its decision regarding the scope of the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The United States Supreme 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 fence lines of individual generating facilities, is not permitted under Section 111(d) of the Clean Air Act. The United States Supreme Court reversed the D.C. Circuit's vacatur of the Affordable Clean Energy rule and remanded 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 Affordable Clean Energy rule.
Clean Air ActQuality Regulations
The Clean Air Act, is a federal law administered by the EPA thatas well as state laws and regulations impacting air emissions, 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 ofThese laws and regulations programs and policiescontinue to be followed. SIPs vary by statepromulgated and are subject to public hearingsimplemented and EPA approval. Some states may adopt additional or more stringent requirements than those implemented bywill impact the EPA. The major Clean Air Act programs most directly affecting the Registrants' operations are described below.
National Ambient Air Quality Standards
Under the authorityoperation of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx, particulate matter, ozoneBHE's generating facilities 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 requiredrequire them to reduce emissions. Currently,emissions at those facilities to comply with the exceptions described inrequirements. In addition, the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainmentpotential adoption of the current NAAQS.state or federal clean energy standards, which include low-carbon, non-carbon and renewable electricity generating resources, may also impact electricity generators and natural gas providers.
OnMercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015, with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects and unit retirements to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the U.S. Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. In June 4,2015, the U.S. Supreme Court reversed and remanded the MATS rule, finding that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. In December 2018, the EPA published final ozone designationsissued a proposed revised supplemental cost finding for muchthe MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from generating facilities under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the U.S. RelevantMATS rule, because the EPA did not propose to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada;remove coal- and the 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 meet the 2015 standard three yearsoil-fueled generating facilities from the August 3, 2018, effective date. All other areas relevantlist of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the Registrantsappropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were designated attainment/unclassifiable with this same action. However, on January 29, 2021,filed in the D.C. Circuit vacated several provisions ofby parties challenging and supporting the 2018 implementing rules forEPA's decision to rescind the 2015 ozone standards for contraveningappropriate and necessary finding, which were stayed pending the Clean Air Act. The EPA and environmental groups finalized a consent decree inEPA's plans to revisit the finding. On January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of interstate ozone plans of dozens 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 Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the Registrants, 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 15, 2022. In addition, the EPA must, by December 15, 2022, approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. On April 15, 2022, the EPA issued its final rule approving Iowa's SIP as meeting the good neighbor provisions for the 2015 ozone standard. On 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 28,31, 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. Relevantseveral actions relating to the Registrants, the Southern Wasatch Front in Utah and Yuma, Arizona areMATS. The EPA proposed to have metrestore the 2015 ozone standard;appropriate and necessary finding to regulate generating facilities under Clean Air Act Section 112. The EPA finalized its restoration of the MATS appropriate and necessary finding in February 2023.
On April 5, 2023, the EPA released a proposal to revise several aspects of the MATS rule following the agency's review of the 2020 Residual Risk and Technology Review. The EPA proposes two specific standard changes - one applicable to all covered units and one specific to the existing lignite subcategory. The EPA proposes a more stringent standard for emissions of filterable particulate matter, the surrogate standard for non-mercury metals for coal-fueled electric generating units. The EPA proposes to reduce the filterable particulate matter emission standard by two-thirds based on a demonstration that 91% of coal-based capacity, which has not been identified as retiring before the proposed compliance period, has an emission rate at or below the proposed limit. The EPA also proposes to require continuous emissions monitoring for filterable particulate matter to demonstrate compliance with the revised standard. Compliance would be due no later than three years after the effective date of a final rule and the Cincinnati area of Ohio and Kentucky andEPA will accept comments on the Northern Wasatch Frontproposal for 60 days following its publication in Utahthe Federal Register. The relevant Registrants are proposed tonot included in the lignite subcategory. The relevant Registrants have not met the 2015 ozone, willidentified that compliance can be reclassified as Moderate Non-Attainment, and will have until August 3, 2024 to meet the standard.achieved with existing controls. Until the EPA takes final action on the proposal, and the affected states submit any required SIPs, the relevant Registrants cannot determine thefull impacts of the proposed rule.rule cannot be determined.
Cross-State Air Pollution RulePacifiCorp
The EPA promulgatedOperating revenue increased $187 million for the first quarter of 2023 compared to 2022, primarily due to higher retail revenue of $159 million and higher wholesale and other revenue of $28 million, primarily from higher average wholesale market prices, partially offset by lower wholesale volumes. Retail revenue increased primarily due to price impacts of $107 million from higher average retail rates largely due to tariff changes and product mix and $52 million from higher volumes. Retail customer volumes increased 3.3%, primarily due to the favorable impact of weather, higher customer usage and an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sourcesincrease in the eastern 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 transportaverage number of SO2 and NOx emissions in 27 eastern and Midwestern states.customers.
TheEarnings decreased $250 million for the first phasequarter of 2023 compared to 2022, primarily due to higher operations and maintenance expense of $428 million, partially offset by higher utility margin of $38 million, higher allowances for equity and borrowed funds used during construction of $21 million and a favorable income tax benefit from valuation allowance changes on state net operating loss carryforwards. Operations and maintenance expense was unfavorable primarily due to an increase in loss accruals, net of expected insurance recoveries, associated with the rule was implemented January 1, 2015. In November 2015,2020 Wildfires of $359 million, higher wildfire mitigation and vegetation management costs, and higher general and plant maintenance costs. Utility margin increased primarily due to higher retail rates and volumes, favorable deferred net power costs and higher average wholesale market prices, partially offset by higher purchased power and thermal generation costs and lower wholesale volumes.
MidAmerican Funding
Operating revenue decreased $85 million for the EPA releasedfirst quarter of 2023 compared to 2022, primarily due to lower natural gas operating revenue of $70 million and lower electric operating revenue of $17 million. Natural gas operating revenue decreased primarily due to a proposed rule that would further reduce NOx emissionslower average per-unit cost of natural gas sold resulting in 2017. The final "CSAPR Update Rule" was publishedlower purchased gas adjustment recoveries of $61 million (fully offset in cost of sales) and the unfavorable impact of weather of $5 million. Electric operating revenue decreased due to lower wholesale and other revenue of $33 million, partially offset by higher retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower wholesale volumes of $22 million and lower average wholesale per-unit prices of $13 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $14 million (largely offset in expense, primarily cost of sales). Electric retail customer volumes increased 1.0%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.
Earnings increased $8 million for the first quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $17 million, a one-time gain on the sale of an investment of $13 million and favorable changes in the Federal Register in October 2016cash surrender value of corporate-owned life insurance policies of $12 million, partially offset by higher operations and requiredmaintenance expense of $13 million, lower natural gas utility margin of $8 million and lower electric utility margin of $7 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, the EPA finalized a ruleassets placed in-service. Operations and maintenance expense increased due 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 obligationshigher general and that there will be no remaining nonattainment orplant maintenance receptors with respectcosts and unfavorable property insurance costs. Natural gas utility margin decreased primarily due to the 2008 ozone NAAQS in the eastern U.S. in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantlyunfavorable impact of weather. Electric utility margin decreased primarily due to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Updatelower wholesale revenue, partially offset by higher retail revenue and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind states to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update Rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from generating facilities in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update Rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at generating 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.lower purchased power costs.
NV Energy
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 NO
x, precursors to ozone formation and covers 26 states. Relevant to the Registrants, four states are included in the cross-state program
Operating revenue increased $306 million for the first time - California, Nevada, Utahquarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $260 million and Wyoming. Iowa is not includedhigher natural gas operating revenue of $44 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $229 million, higher customer volumes of $8 million, increased base tariff general rates of $8 million at Sierra Pacific and favorable transmission and wholesale revenue of $7 million. Electric retail customer volumes increased 2.9%, primarily due to the favorable impact of weather and an increase in the proposal. In a separate but related action in February 2022, the EPA proposed to approve the good neighbor provisionsaverage number 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 sectorcustomers.
Earnings increased $5 million for the first time, with a focusquarter of 2023 compared to 2022, primarily due to higher electric utility margin of $31 million and favorable interest and dividend income of $16 million, mainly from carrying charges on the top NOx emitting stationary source categories. These include natural gas pipeline compressor stations, pulphigher deferred energy balances, partially offset by higher operations and paper mills, cement production, ironmaintenance expenses of $24 million, unfavorable depreciation and steel boilersamortization expense of $13 million and furnaces, glass furnaces, chemical manufacturingincreased interest expense of $12 million due to higher outstanding long-term debt balances. Electric utility margin increased primarily due to higher electric retail customer volumes, increased base tariff general rates at Sierra Pacific and petroleumhigher transmission and coal product manufacturing. These sources will not have accesswholesale revenue. Operations and maintenance expense increased primarily due to tradinghigher general and will instead be subjectplant maintenance costs and higher customer service operations costs. Depreciation and amortization expense increased primarily due 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.additional assets placed in-service.
Regional HazeNorthern Powergrid
Operating revenue increased $39 million for the first quarter of 2023 compared to 2022, primarily due to higher distribution revenue of $41 million and higher revenue at CE Gas of $29 million, partially offset by $37 million from the stronger U.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier of Last Resort payments of $43 million (fully offset in cost of sales) and higher tariff rates of $10 million. Also impacting distribution revenue was a 4.8% decline in units distributed, largely due to the unfavorable impact of weather and lower customer usage, of $11 million. CE Gas revenue increased from a gas project that commenced commercial operation in March 2022 and a solar project that commenced commercial operation in July 2022.
Earnings decreased $100 million for the first quarter of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax. Earnings were also impacted by unfavorable distribution-related operating and depreciation expenses of $11 million and increased non-service benefit plan costs of $10 million, partially offset by favorable operating performance at CE Gas of $8 million from the gas and solar projects that commenced commercial operations in 2022.
BHE Pipeline Group
Operating revenue increased $138 million for the first quarter of 2023 compared to 2022, primarily due to higher operating revenue of $71 million at Northern Natural Gas and $55 million at BHE GT&S. The EPA's Regional Haze Rule, finalizedincrease in 1999, requires statesoperating revenue at Northern Natural Gas was largely due to developthe impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $63 million and implement planshigher transportation revenue of $34 million from higher rates in the Field Area, partially offset by lower gas sales of $25 million (largely offset in cost of sales) from system balancing activities. The increase in operating revenue at BHE GT&S was primarily due to improve visibilityan increase in designated federally protected areas ("Class I areas"). Someregulated gas transportation and storage services rates due to the settlement of PacifiCorp's coal-fueledEGTS' general rate case of $42 million, higher LNG revenue of $16 million at Cove Point, and an increase in variable revenue related to park and loan activity of $10 million at EGTS, partially offset by lower non-regulated revenue of $22 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices.
Earnings increased $47 million for the first quarter of 2023 compared to 2022, largely due to higher earnings at Northern Natural Gas of $28 million and higher earnings at BHE GT&S of $14 million. The increase at Northern Natural Gas is due to the impacts of a general rate case of $16 million and higher transportation revenue in the Field Area, partially offset by higher operations and maintenance expense. The increase at BHE GT&S is due to a favorable general rate case settlement at EGTS in 2022 and higher equity earnings at Iroquois Gas Transmission System, partially offset by higher operations and maintenance expense and increased cost of gas from the unfavorable revaluation of volumes retained, due to lower natural gas prices.
BHE Transmission
Operating revenue increased $22 million for the first quarter of 2023 compared to 2022, primarily due to $26 million of incremental revenue from non-regulated wind-powered generating facilities acquired in Utah, Wyoming, ArizonaNovember 2022 and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject tohigher other non-regulated revenue at BHE Canada, partially offset by $12 million from 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.stronger U.S. dollar.
The stateEarnings increased $2 million for the first quarter of Utah issued a regional haze SIP requiring2023 compared to 2022, primarily due to $6 million of incremental earnings at non-regulated wind-powered generating facilities acquired in November 2022, partially offset by $3 million from the installationstronger U.S. dollar.
BHE Renewables
Operating revenue increased $57 million for the first quarter 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 portion2023 compared to 2022, primarily due to higher wind revenues 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$60 million, largely due 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 positionfavorable changes in the litigation, the Tenth Circuit held the litigationvaluation of certain derivative contracts, and higher natural gas and electric retail energy services revenue of $23 million, partially offset by lower solar revenues of $20 million from lower generation due to weather events in abeyanceCalifornia. Natural gas and imposed a stay of the compliance obligations of the FIPelectric retail energy services revenue increased due to higher electric volumes and favorable natural gas and electric pricing, partially offset by lower natural gas volumes.
Earnings decreased $66 million for the numberfirst quarter of days2023 compared to 2022, primarily due to lower earnings of $79 million from the stay isretail energy services business, largely due to unfavorable changes in effect whileunrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $40 million, primarily due to maintenance outages, and lower solar earnings of $18 million from lower generation due to weather events in California. These items were partially offset by higher wind earnings of $74 million, largely due to favorable changes in the EPA conducts its reconsideration process. To supportvaluation of certain derivative contracts and higher earnings from tax equity investments of $28 million due to lower equity losses and higher production tax credits.
HomeServices
Operating revenue decreased $332 million for the reconsideration, PacifiCorp undertook additional air quality modeling usingfirst quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $293 million and lower mortgage revenue of $34 million. The decrease in brokerage and settlement services revenue resulted from a 29% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 41% decrease in funded volume, primarily due to rising interest rates.
Earnings decreased $55 million for the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019,first quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $38 million and mortgage services of $12 million, largely from the state of Utah submitted a SIP revisiondecrease in funded volumes from rising interest rates. Earnings at brokerage and settlement services declined due to the EPA, which includesdecrease in closed transaction volume, partially offset by favorable operating expenses primarily due to lower compensation costs.
BHE and Other
Operating revenue decreased $16 million for the updated modeling information and additional analysis. On June 24, 2019,first quarter of 2023 compared to 2022, due to higher intersegment eliminations.
Earnings increased $1,535 million for the Utah Air Quality Board unanimously votedfirst quarter of 2023 compared 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 revision2022, primarily due to the EPA for approval at$1,552 million favorable comparative change related to 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 AlternativeCompany's investment in BYD Company Limited, favorable changes in the Tenth Circuit. PacifiCorpcash surrender value of corporate-owned life insurance policies of $14 million and the state$8 million of Utah movedlower dividends on BHE's 4.00% Perpetual Preferred Stock issued to intervene in the litigation. After reviewcertain insurance subsidiaries of the ruleBerkshire Hathaway. These items were partially offset by the Biden administration, the EPA determined it would defend the rule,higher BHE corporate interest expense from an April 2022 debt issuance 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$17 million of Air Quality's SIP for the regional haze second planning periodlower federal income tax credits recognized 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.consolidated basis.
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 in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NOx and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The EPA, U.S. Department of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to install SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement. The EPA did not proceed with final approval of the settlement agreement for Wyodak and is currently engaged with Wyoming and PacifiCorp concerning alternative paths for resolution. On February 5, 2019, PacifiCorp submitted a reasonable 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 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 SO2 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 any 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 December 31, 2031 for Tracy Unit 4. The enforceable retirement dates will implement Nevada's SIP for the regional haze second planning period. The revised permits were received in March and April 2022. The Nevada Division of Environmental Protection accepted public comment on its SIP through July 25, 2022, and is on track to submit the final SIP to the EPA in August 2022.
Critical Accounting EstimatesLiquidity and Capital Resources
Certain accounting measurements requireEach 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, 2022 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of March 31, 2023, the Company's total net liquidity was as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | BHE Pipeline | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | | | Group and | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Other | | Total |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 173 | | | $ | 19 | | | $ | 58 | | | $ | 21 | | | $ | 18 | | | $ | 64 | | | $ | 216 | | | $ | 394 | | | $ | 963 | |
| | | | | | | | | | | | | | | | | |
Credit facilities(1) | 3,500 | | | 2,000 | | | 1,509 | | | 650 | | | 295 | | | 795 | | | 2,725 | | | — | | | 11,474 | |
| Less: | | | | | | | | | | | | | | | | | |
| Short-term debt | (755) | | | — | | | — | | | (83) | | | (49) | | | (127) | | | (805) | | | — | | | (1,819) | |
| Tax-exempt bond support and letters of credit | — | | | (249) | | | (363) | | | — | | | — | | | (1) | | | — | | | — | | | (613) | |
| Net credit facilities | 2,745 | | | 1,751 | | | 1,146 | | | 567 | | | 246 | | | 667 | | | 1,920 | | | — | | | 9,042 | |
| | | | | | | | | | | | | | | | | |
| Total net liquidity | $ | 2,918 | | | $ | 1,770 | | | $ | 1,204 | | | $ | 588 | | | $ | 264 | | | $ | 731 | | | $ | 2,136 | | | $ | 394 | | | $ | 10,005 | |
| Credit facilities: | | | | | | | | | | | | | | | | | |
| Maturity dates | 2025 | | 2024, 2025 | | 2023, 2025 | | 2025 | | 2025 | | 2023, 2026, 2027 | | 2023, 2024, 2026 | | | | |
(1)Includes $48 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $1.1 billion and $2.2 billion, respectively. The decrease was primarily due to changes in working capital and regulatory assets and unfavorable operating results.
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 made for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(1.8) billion and $(1.6) billion, respectively. The change was primarily due to higher purchases, net of proceeds from maturities, of U.S. Treasury Bills totaling $896 million and higher capital expenditures of $295 million, partially offset by higher proceeds from sales of marketable securities of $942 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2023, was $20 million. Sources of cash totaled $699 million and consisted of net proceeds from short-term debt. Uses of cash totaled $679 million and consisted mainly of repayments of BHE senior debt totaling $400 million, repayments of subsidiary debt totaling $136 million and distributions to noncontrolling interests of $126 million.
Net cash flows from financing activities for the three-month period ended March 31, 2022, was $(310) million. Sources of cash totaled $405 million and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $715 million and consisted mainly of repayments of subsidiary debt totaling $193 million, net repayments of short-term debt totaling $165 million and distributions to noncontrolling interests of $117 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 make estimatescustomer rates; changes in environmental and judgments concerning transactionsother 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.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2022 | | 2023 | | 2023 |
| Capital expenditures by business: | | | | | |
| PacifiCorp | $ | 374 | | | $ | 643 | | | $ | 3,662 | |
| MidAmerican Funding | 459 | | | 382 | | | 2,324 | |
| NV Energy | 272 | | | 437 | | | 1,751 | |
| Northern Powergrid | 169 | | | 124 | | | 597 | |
| BHE Pipeline Group | 205 | | | 169 | | | 1,431 | |
| BHE Transmission | 47 | | | 43 | | | 191 | |
| BHE Renewables | 19 | | | 29 | | | 269 | |
| HomeServices | 12 | | | 11 | | | 46 | |
BHE and Other(1) | (4) | | | 10 | | | 12 | |
| Total | $ | 1,553 | | | $ | 1,848 | | | $ | 10,283 | |
| | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | |
| Capital expenditures by type: | | | | | |
| Wind generation | $ | 153 | | | $ | 105 | | | $ | 2,172 | |
| Electric distribution | 388 | | | 477 | | | 2,071 | |
| Electric transmission | 261 | | | 291 | | | 2,063 | |
| Natural gas transmission and storage | 103 | | | 65 | | | 1,097 | |
| Solar generation | 51 | | | 40 | | | 236 | |
| Electric battery and pumped hydro storage | 1 | | | 40 | | | 236 | |
| Other | 596 | | | 830 | | | 2,408 | |
| Total | $ | 1,553 | | | $ | 1,848 | | | $ | 10,283 | |
(1)BHE and Other represents amounts related principally to other entities corporate functions and intersegment eliminations.
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $75 million and $3 million for the three-month periods ended March 31, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $1,025 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $5 million and $120 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $16 million for the remainder of 2023. 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.
◦Construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties at PacifiCorp totaling $14 million and $6 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $807 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $25 million for the three-month period ended March 31, 2022. Planned spending for the repower of wind-powered facilities totals $50 million for the remainder of 2023.
•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 enhancements 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 transmission investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $110 million and $96 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $898 million for the remainder of 2023.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Expenditures for the expansion program and other growth projects totaled $42 million and $30 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026 through 2028 and other growth projects totals $88 million for the remainder of 2023.
◦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 asset modernization and the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for pipeline integrity projects, automation and controls upgrades, corrosion control, unit exchanges, compressor modifications, projects related to Pipeline and Hazardous Materials Safety Administration natural gas storage rules and natural gas transmission, storage and LNG terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including spending for the following:
◦Construction of solar-powered generating facilities at PacifiCorp totaling 377 MWs of new generation and are expected to be placed in-service in 2026. Planned spending totals $12 million for the remainder of 2023.
◦Construction and operation of solar-powered generating facilities at MidAmerican Energy, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the three-month periods ended March 31, 2023 and 2022 solar generation spend totaled $9 million and $44 million, respectively. Planned spending totals $1 million for the remainder of 2023.
◦Construction of a solar-powered generating facility at Nevada Power totaling $31 million and $7 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending totals $175 million for the remainder of 2023. Construction includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be settled several yearsdeveloped in Clark County, Nevada. Commercial operation is expected by the future. Amounts recognizedend of 2023.
•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:
◦Construction at the Nevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada and a 220-MW grid-tied battery energy storage system that will be developed on the Consolidated Financial Statements basedsite of the retired Reid Gardner generating station in Clark County, Nevada, both with commercial operation expected by the end of 2023. Also, a 200-MW battery energy storage system that will be developed on such estimates involve numerous assumptions subject to varying and potentially significant degreesthe site of judgment and uncertainty and will likely changethe Valmy generating station in Humboldt County, Nevada with commercial operation expected by the future as additional information becomes available. Estimates are used for, but not limited to, the accountingend of 2025. Total spending for the effectsthree-month period ended March 31, 2023, was $39 million with planned spending of certain types$159 million for the remainder of regulation, impairment of goodwill2023.
•Other includes both growth and long-lived assets, pensionoperating expenditures, including spending for routine expenditures for generation and other postretirement benefits, income taxesinfrastructure needed to serve existing and revenue recognition - unbilled revenue. For additional discussionexpected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.
Material Cash Requirements
As of March 31, 2023, there have been no material changes in cash requirements from the Company's critical accounting estimates, seeinformation provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2021. There have been no significant changes2022, other than those disclosed in Note 9 of the Company's assumptions regarding critical accounting estimates sinceNotes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
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, 2021.2022, and new regulatory matters occurring in 2023.
PacifiCorp
Utah
In May 2023, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2022. The filing requested a rate increase of $98 million, or 4.6%, effective on an interim basis July 1, 2023.
Oregon
In April 2023, PacifiCorp filed its transition adjustment mechanism requesting approval to update net power costs for 2024. The filing requested a rate increase of $164 million, or 9.5%, to become effective January 1, 2024.
Wyoming
In March 2023, PacifiCorp filed a general rate case requesting a rate increase of $140 million, or 21.6%, to become effective January 1, 2024. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities.
In April 2023, PacifiCorp filed its energy cost adjustment and renewable energy credit and sulfur dioxide revenue credit mechanisms to recover deferred net power costs from 2022. The combined filing requested a rate increase of $49 million, or 7.4%, to become effective on an interim basis July 1, 2023.
Washington
In March 2023, PacifiCorp filed a general rate case requesting a two-year rate plan with a rate increase of $27 million, or 6.6%, to become effective March 1, 2024, and a second rate increase of $28 million, or 6.5%, to become effective March 1, 2025. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities.
California
In May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to establish a memorandum account to track the change in rates beginning January 1, 2023, until the new rates become effective upon the issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in February 2023 with a slight adjustment of an overall rate increase of $27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling requesting additional information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum accounts. In March 2023, the CPUC split the general rate case into two tracks. The first track addresses the general rate case with an expected decision from the CPUC in late 2023, and the second track addresses the wildfire memorandum accounts with an expected decision in early 2024.
PacifiCorpMidAmerican Energy
South Dakota
In May 2022, MidAmerican Energy filed a request with the South Dakota Public Utilities Commission ("SDPUC") for a $7 million, or 6.4%, annual increase in South Dakota retail natural gas rates. In March 2023, MidAmerican Energy filed a settlement agreement between all parties allowing a total increase of $6 million, or 5.5%, annual increase in South Dakota retail natural gas rates, upon completion of the capital investment phase-in adjustment clause. On March 31, 2023, the SDPUC issued an order approving the settlement agreement with final rates effective April 1, 2023.
Wind PRIME
In January 2022, MidAmerican Energy filed an application with the IUB for 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 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 subsidiaries
Consolidated Financial SectionIowa retail customers' annual energy needs. MidAmerican Energy expects to be eligible for 100% PTCs under current tax law for the Wind PRIME projects. In December 2022, MidAmerican Energy, the Iowa Office of Consumer Advocate and the Iowa Business Energy Coalition filed a non-unanimous settlement with the IUB that includes a rate of return of 11.0%. The settlement would benefit customers by providing an immediate rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. The IUB conducted a hearing on the application and proposed settlement during the week of February 20, 2023. On April 27, 2023, the IUB issued its final order regarding the application. The IUB found that MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application, but rejected the settlement and proposed its own principles for the project. MidAmerican Energy is reviewing the order and assessing options for rejection or motion to reconsider. MidAmerican Energy must either accept or reject the order, or file a motion for reconsideration within 20 days and no later than May 17, 2023.
PART IIowa Transmission Legislation
Item 1.
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law provides MidAmerican Energy, as an incumbent electric transmission owner, the legal right to construct, own and maintain transmission lines in MidAmerican Energy's service territory that have been approved by the MISO (or another federally registered planning authority) and are eligible to receive regional cost allocation. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for the construction of eligible electric transmission lines that it intends to construct, own and maintain. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the eligible electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the eligible electric transmission line. In October 2020, national transmission interests filed a lawsuit that challenged the law on state constitutional grounds. The suit argues that the law was enacted in violation of the "single-subject" provision of Iowa's state constitution because it was "log-rolled" into a late session appropriations bill and violates the equal protection provision of the Iowa constitution. The State of Iowa defended the law, and MidAmerican Energy and ITC Midwest both intervened and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of standing, and the national transmission interests appealed. In June 2022, the Iowa Court of Appeals upheld the district court's decision, after which the national transmission interests asked the Iowa Supreme Court to reconsider. In November 2022, the Iowa Supreme Court granted the motion to reconsider. On March 24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower courts, held the national transmission interests had standing, and remanded the case to the district court to consider the state constitutional claims on their merits. The opinion also imposed a temporary injunction that stayed enforcement of the law pending a decision on the merits. On April 7, 2023, the State of Iowa, acting individually, and MidAmerican Energy and ITC Midwest, acting jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19, 2023, the national transmission interests filed a reply that (1) expressed its opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to hold that the injunction specifically applied to and precluded advancement of MidAmerican Energy's Long Range Transmission Projects ("LRTP") Tranche 1 projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on the constitutional claims on the merits without further briefing or argument. On April 26, 2023, the Iowa Supreme Court issued an order that denied the petitions for rehearing without comment and made minor, non-substantive changes to the decision, with no changes to the injunction. No earlier than May 18, 2023, the Iowa Supreme Court will remand the case to the district court for further proceedings on the merits. To this point, MISO has taken no action to reverse or disrupt its approval of MidAmerican Energy's LRTP Tranche 1 projects. This matter only potentially affects the manner in which MidAmerican Energy would secure the right to construct transmission lines that are eligible for regional cost allocation and are otherwise subject to competitive bidding under the MISO tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing rights to construct any other transmission lines, including lines required to serve new or expanded retail load, connect new generators or meet reliability criteria.
NV Energy (Nevada Power and Sierra Pacific)
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. In October 2022, all parties to the proceedings relating to the joint application entered into a Stipulation to delay the procedural schedule. The Nevada Utilities made a supplemental filing on December 30, 2022. In March 2023, the proceedings relating to the joint application were postponed to May 2023. In April 2023, the Nevada Utilities filed a notice with the PUCN requesting to withdraw the joint application to merge into a single corporate entity and vacate the current procedural schedule, and executed a termination of the related merger agreement.
TransportationFinancial Statements Electrification Plan ("TEP")
In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of a Distributed Resource Plan amendment to implement the state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs and schedules to implement the TEP. The 2022 TEP outlines programs, investments and incentives to accelerate transportation electrification across Nevada. The Nevada Utilities proposed a budget of $348 million, which represents the maximum cost over the depreciable life of the TEP's programs and assets, to deploy the TEP in 2023 through 2024. In March 2023, the PUCN issued an order approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on the program management and contingency budget amounts. The unapproved programs have been deferred for approval in future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs.In April 2023, interveners filed a petition for reconsideration of the PUCN's March 2023 Order.
Northern Powergrid Distribution Companies
Ofgem has completed the price control review that resulted in a new price control effective April 1, 2023. The license modifications that give effect to the price control were published by Ofgem on February 3, 2023 and were subject to appeal to the Competition and Markets Authority ("CMA") if an appeal was filed by March 3, 2023. On March 2, 2023, Northern Powergrid sought permission from the CMA to appeal against the license modifications that give effect to the RIIO-ED2 price control. The appeal relates to two specific areas:
•Ofgem's misallocation of allowances that is inconsistent with efficient costs; and
•Ofgem's approach to determine rewards for the Business Plan Incentive.
The permission for the appeal was granted by the CMA and the appeal is expected to conclude in the fourth quarter of 2023 in accordance with the timetable required of the CMA. The outcome of this appeal may increase the revenue available to the Company if the CMA amends the price control determination.
BHE Pipeline Group
BHE GT&S
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. 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 transmission 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. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.
Northern Natural Gas
In July 2022, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $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 and storage reservation rates. In January 2023, the FERC approved Northern Natural Gas filing to implement its interim rates effective January 1, 2023, subject to refund and the outcome of hearing procedures. Procedural hearings are scheduled to begin June 14, 2023.
BHE Transmission
AltaLink
2024-2025 General Tariff Application
In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total total transmission tariffs of C$902.3 million and C$908.6 million for 2024 and 2025, respectively, which extends AltaLink's previous five-year commitment to maintain its tariff at or below C$904 million from 2019 to 2023 for another year. The application also requests the approval to reinstate C$98.9 million cost of removal to rate base which was not previously approved, based on additional information filed.
Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with respect to the first stage of the GCOC proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial markets due to the COVID-19 pandemic. In June 2022, the AUC initiated the second stage to explore a formula-based approach to determine the return on equity for 2024 and future test periods.
In February 2023, AltaLink and other stakeholders filed evidence. AltaLink filed expert evidence recommending a 10.3% return on equity, on a recommended equity ratio of 40%. Other utilities filed similar recommendations. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the Industrial Power Consumers Association of Alberta recommended returns on equity ranging from 6.75% to 7.7% and equity ratios ranging from 35% to 37%. AltaLink's expert witness, as well as all other utility experts, submitted that they are generally not in favor of implementing a formulaic adjustment mechanism for allowed return on equity due to the challenges in maintaining the Fair Return Standard through formulaic adjustments. The interveners are generally in favor of a formula. The AUC expects to conclude the second stage of the GCOC proceeding in the third quarter of 2023.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMEnvironmental Laws and Regulations
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal 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 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, 2022, and new environmental matters occurring in 2023.
ToAir Quality Regulations
The Clean Air Act, as well as state laws and regulations impacting air emissions, provides a framework for protecting and improving the Boardnation's air quality and controlling sources of Directorsair emissions. These laws and Shareholdersregulations continue to be promulgated and implemented and will impact the operation of BHE's generating facilities and require them to reduce emissions at those facilities to comply with the requirements. In addition, the potential adoption of state or federal clean energy standards, which include low-carbon, non-carbon and renewable electricity generating resources, may also impact electricity generators and natural gas providers.
Mercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015, with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects and unit retirements to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the U.S. Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. In June 2015, the U.S. Supreme Court reversed and remanded the MATS rule, finding that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. In December 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from generating facilities under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled generating facilities from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding, which were stayed pending the EPA's plans to revisit the finding. On January 31, 2022, the EPA proposed several actions relating to the MATS. The EPA proposed to restore the appropriate and necessary finding to regulate generating facilities under Clean Air Act Section 112. The EPA finalized its restoration of the MATS appropriate and necessary finding in February 2023.
On April 5, 2023, the EPA released a proposal to revise several aspects of the MATS rule following the agency's review of the 2020 Residual Risk and Technology Review. The EPA proposes two specific standard changes - one applicable to all covered units and one specific to the existing lignite subcategory. The EPA proposes a more stringent standard for emissions of filterable particulate matter, the surrogate standard for non-mercury metals for coal-fueled electric generating units. The EPA proposes to reduce the filterable particulate matter emission standard by two-thirds based on a demonstration that 91% of coal-based capacity, which has not been identified as retiring before the proposed compliance period, has an emission rate at or below the proposed limit. The EPA also proposes to require continuous emissions monitoring for filterable particulate matter to demonstrate compliance with the revised standard. Compliance would be due no later than three years after the effective date of a final rule and the EPA will accept comments on the proposal for 60 days following its publication in the Federal Register. The relevant Registrants are not included in the lignite subcategory. The relevant Registrants have identified that compliance can be achieved with existing controls. Until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.
PacifiCorp
Operating revenue increased $187 million for the first quarter of 2023 compared to 2022, primarily due to higher retail revenue of $159 million and higher wholesale and other revenue of $28 million, primarily from higher average wholesale market prices, partially offset by lower wholesale volumes. Retail revenue increased primarily due to price impacts of $107 million from higher average retail rates largely due to tariff changes and product mix and $52 million from higher volumes. Retail customer volumes increased 3.3%, primarily due to the favorable impact of weather, higher customer usage and an increase in the average number of customers.
Earnings decreased $250 million for the first quarter of 2023 compared to 2022, primarily due to higher operations and maintenance expense of $428 million, partially offset by higher utility margin of $38 million, higher allowances for equity and borrowed funds used during construction of $21 million and a favorable income tax benefit from valuation allowance changes on state net operating loss carryforwards. Operations and maintenance expense was unfavorable primarily due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $359 million, higher wildfire mitigation and vegetation management costs, and higher general and plant maintenance costs. Utility margin increased primarily due to higher retail rates and volumes, favorable deferred net power costs and higher average wholesale market prices, partially offset by higher purchased power and thermal generation costs and lower wholesale volumes.
MidAmerican Funding
Operating revenue decreased $85 million for the first quarter of 2023 compared to 2022, primarily due to lower natural gas operating revenue of $70 million and lower electric operating revenue of $17 million. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $61 million (fully offset in cost of sales) and the unfavorable impact of weather of $5 million. Electric operating revenue decreased due to lower wholesale and other revenue of $33 million, partially offset by higher retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower wholesale volumes of $22 million and lower average wholesale per-unit prices of $13 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $14 million (largely offset in expense, primarily cost of sales). Electric retail customer volumes increased 1.0%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.
Earnings increased $8 million for the first quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $17 million, a one-time gain on the sale of an investment of $13 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $12 million, partially offset by higher operations and maintenance expense of $13 million, lower natural gas utility margin of $8 million and lower electric utility margin of $7 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Operations and maintenance expense increased due to higher general and plant maintenance costs and unfavorable property insurance costs. Natural gas utility margin decreased primarily due to the unfavorable impact of weather. Electric utility margin decreased primarily due to lower wholesale revenue, partially offset by higher retail revenue and lower purchased power costs.
NV Energy
Operating revenue increased $306 million for the first quarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $260 million and higher natural gas operating revenue of $44 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $229 million, higher customer volumes of $8 million, increased base tariff general rates of $8 million at Sierra Pacific and favorable transmission and wholesale revenue of $7 million. Electric retail customer volumes increased 2.9%, primarily due to the favorable impact of weather and an increase in the average number of customers.
Earnings increased $5 million for the first quarter of 2023 compared to 2022, primarily due to higher electric utility margin of $31 million and favorable interest and dividend income of $16 million, mainly from carrying charges on higher deferred energy balances, partially offset by higher operations and maintenance expenses of $24 million, unfavorable depreciation and amortization expense of $13 million and increased interest expense of $12 million due to higher outstanding long-term debt balances. Electric utility margin increased primarily due to higher electric retail customer volumes, increased base tariff general rates at Sierra Pacific and higher transmission and wholesale revenue. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service.
Northern Powergrid
Operating revenue increased $39 million for the first quarter of 2023 compared to 2022, primarily due to higher distribution revenue of $41 million and higher revenue at CE Gas of $29 million, partially offset by $37 million from the stronger U.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier of Last Resort payments of $43 million (fully offset in cost of sales) and higher tariff rates of $10 million. Also impacting distribution revenue was a 4.8% decline in units distributed, largely due to the unfavorable impact of weather and lower customer usage, of $11 million. CE Gas revenue increased from a gas project that commenced commercial operation in March 2022 and a solar project that commenced commercial operation in July 2022.
Earnings decreased $100 million for the first quarter of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax. Earnings were also impacted by unfavorable distribution-related operating and depreciation expenses of $11 million and increased non-service benefit plan costs of $10 million, partially offset by favorable operating performance at CE Gas of $8 million from the gas and solar projects that commenced commercial operations in 2022.
BHE Pipeline Group
Operating revenue increased $138 million for the first quarter of 2023 compared to 2022, primarily due to higher operating revenue of $71 million at Northern Natural Gas and $55 million at BHE GT&S. The increase in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $63 million and higher transportation revenue of $34 million from higher rates in the Field Area, partially offset by lower gas sales of $25 million (largely offset in cost of sales) from system balancing activities. The increase in operating revenue at BHE GT&S was primarily due to an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $42 million, higher LNG revenue of $16 million at Cove Point, and an increase in variable revenue related to park and loan activity of $10 million at EGTS, partially offset by lower non-regulated revenue of $22 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices.
Earnings increased $47 million for the first quarter of 2023 compared to 2022, largely due to higher earnings at Northern Natural Gas of $28 million and higher earnings at BHE GT&S of $14 million. The increase at Northern Natural Gas is due to the impacts of a general rate case of $16 million and higher transportation revenue in the Field Area, partially offset by higher operations and maintenance expense. The increase at BHE GT&S is due to a favorable general rate case settlement at EGTS in 2022 and higher equity earnings at Iroquois Gas Transmission System, partially offset by higher operations and maintenance expense and increased cost of gas from the unfavorable revaluation of volumes retained, due to lower natural gas prices.
BHE Transmission
Operating revenue increased $22 million for the first quarter of 2023 compared to 2022, primarily due to $26 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $12 million from the stronger U.S. dollar.
Earnings increased $2 million for the first quarter of 2023 compared to 2022, primarily due to $6 million of incremental earnings at non-regulated wind-powered generating facilities acquired in November 2022, partially offset by $3 million from the stronger U.S. dollar.
BHE Renewables
Operating revenue increased $57 million for the first quarter of 2023 compared to 2022, primarily due to higher wind revenues of $60 million, largely due to favorable changes in the valuation of certain derivative contracts, and higher natural gas and electric retail energy services revenue of $23 million, partially offset by lower solar revenues of $20 million from lower generation due to weather events in California. Natural gas and electric retail energy services revenue increased due to higher electric volumes and favorable natural gas and electric pricing, partially offset by lower natural gas volumes.
Earnings decreased $66 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings of $79 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $40 million, primarily due to maintenance outages, and lower solar earnings of $18 million from lower generation due to weather events in California. These items were partially offset by higher wind earnings of $74 million, largely due to favorable changes in the valuation of certain derivative contracts and higher earnings from tax equity investments of $28 million due to lower equity losses and higher production tax credits.
HomeServices
Operating revenue decreased $332 million for the first quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $293 million and lower mortgage revenue of $34 million. The decrease in brokerage and settlement services revenue resulted from a 29% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 41% decrease in funded volume, primarily due to rising interest rates.
Earnings decreased $55 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $38 million and mortgage services of $12 million, largely from the decrease in funded volumes from rising interest rates. Earnings at brokerage and settlement services declined due to the decrease in closed transaction volume, partially offset by favorable operating expenses primarily due to lower compensation costs.
BHE and Other
Operating revenue decreased $16 million for the first quarter of 2023 compared to 2022, due to higher intersegment eliminations.
Earnings increased $1,535 million for the first quarter of 2023 compared to 2022, primarily due to the $1,552 million favorable comparative change related to the Company's investment in BYD Company Limited, favorable changes in the cash surrender value of corporate-owned life insurance policies of $14 million and $8 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway. These items were partially offset by higher BHE corporate interest expense from an April 2022 debt issuance and $17 million of lower federal income tax credits recognized on a consolidated basis.
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, 2022 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of March 31, 2023, the Company's total net liquidity was as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | BHE Pipeline | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | | | Group and | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Other | | Total |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 173 | | | $ | 19 | | | $ | 58 | | | $ | 21 | | | $ | 18 | | | $ | 64 | | | $ | 216 | | | $ | 394 | | | $ | 963 | |
| | | | | | | | | | | | | | | | | |
Credit facilities(1) | 3,500 | | | 2,000 | | | 1,509 | | | 650 | | | 295 | | | 795 | | | 2,725 | | | — | | | 11,474 | |
| Less: | | | | | | | | | | | | | | | | | |
| Short-term debt | (755) | | | — | | | — | | | (83) | | | (49) | | | (127) | | | (805) | | | — | | | (1,819) | |
| Tax-exempt bond support and letters of credit | — | | | (249) | | | (363) | | | — | | | — | | | (1) | | | — | | | — | | | (613) | |
| Net credit facilities | 2,745 | | | 1,751 | | | 1,146 | | | 567 | | | 246 | | | 667 | | | 1,920 | | | — | | | 9,042 | |
| | | | | | | | | | | | | | | | | |
| Total net liquidity | $ | 2,918 | | | $ | 1,770 | | | $ | 1,204 | | | $ | 588 | | | $ | 264 | | | $ | 731 | | | $ | 2,136 | | | $ | 394 | | | $ | 10,005 | |
| Credit facilities: | | | | | | | | | | | | | | | | | |
| Maturity dates | 2025 | | 2024, 2025 | | 2023, 2025 | | 2025 | | 2025 | | 2023, 2026, 2027 | | 2023, 2024, 2026 | | | | |
(1)Includes $48 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $1.1 billion and $2.2 billion, respectively. The decrease was primarily due to changes in working capital and regulatory assets and unfavorable operating results.
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 made for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(1.8) billion and $(1.6) billion, respectively. The change was primarily due to higher purchases, net of proceeds from maturities, of U.S. Treasury Bills totaling $896 million and higher capital expenditures of $295 million, partially offset by higher proceeds from sales of marketable securities of $942 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2023, was $20 million. Sources of cash totaled $699 million and consisted of net proceeds from short-term debt. Uses of cash totaled $679 million and consisted mainly of repayments of BHE senior debt totaling $400 million, repayments of subsidiary debt totaling $136 million and distributions to noncontrolling interests of $126 million.
Net cash flows from financing activities for the three-month period ended March 31, 2022, was $(310) million. Sources of cash totaled $405 million and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $715 million and consisted mainly of repayments of subsidiary debt totaling $193 million, net repayments of short-term debt totaling $165 million and distributions to noncontrolling interests of $117 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 customer 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.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2022 | | 2023 | | 2023 |
| Capital expenditures by business: | | | | | |
| PacifiCorp | $ | 374 | | | $ | 643 | | | $ | 3,662 | |
| MidAmerican Funding | 459 | | | 382 | | | 2,324 | |
| NV Energy | 272 | | | 437 | | | 1,751 | |
| Northern Powergrid | 169 | | | 124 | | | 597 | |
| BHE Pipeline Group | 205 | | | 169 | | | 1,431 | |
| BHE Transmission | 47 | | | 43 | | | 191 | |
| BHE Renewables | 19 | | | 29 | | | 269 | |
| HomeServices | 12 | | | 11 | | | 46 | |
BHE and Other(1) | (4) | | | 10 | | | 12 | |
| Total | $ | 1,553 | | | $ | 1,848 | | | $ | 10,283 | |
| | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | |
| Capital expenditures by type: | | | | | |
| Wind generation | $ | 153 | | | $ | 105 | | | $ | 2,172 | |
| Electric distribution | 388 | | | 477 | | | 2,071 | |
| Electric transmission | 261 | | | 291 | | | 2,063 | |
| Natural gas transmission and storage | 103 | | | 65 | | | 1,097 | |
| Solar generation | 51 | | | 40 | | | 236 | |
| Electric battery and pumped hydro storage | 1 | | | 40 | | | 236 | |
| Other | 596 | | | 830 | | | 2,408 | |
| Total | $ | 1,553 | | | $ | 1,848 | | | $ | 10,283 | |
(1)BHE and Other represents amounts related principally to other entities corporate functions and intersegment eliminations.
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $75 million and $3 million for the three-month periods ended March 31, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $1,025 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $5 million and $120 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $16 million for the remainder of 2023. 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.
◦Construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties at PacifiCorp totaling $14 million and $6 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $807 million for the remainder of 2023.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $25 million for the three-month period ended March 31, 2022. Planned spending for the repower of wind-powered facilities totals $50 million for the remainder of 2023.
•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 enhancements 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 transmission investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $110 million and $96 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $898 million for the remainder of 2023.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have 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 substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Expenditures for the expansion program and other growth projects totaled $42 million and $30 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026 through 2028 and other growth projects totals $88 million for the remainder of 2023.
◦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 asset modernization and the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for pipeline integrity projects, automation and controls upgrades, corrosion control, unit exchanges, compressor modifications, projects related to Pipeline and Hazardous Materials Safety Administration natural gas storage rules and natural gas transmission, storage and LNG terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including spending for the following:
◦Construction of solar-powered generating facilities at PacifiCorp totaling 377 MWs of new generation and are expected to be placed in-service in 2026. Planned spending totals $12 million for the remainder of 2023.
◦Construction and operation of solar-powered generating facilities at MidAmerican Energy, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the three-month periods ended March 31, 2023 and 2022 solar generation spend totaled $9 million and $44 million, respectively. Planned spending totals $1 million for the remainder of 2023.
◦Construction of a solar-powered generating facility at Nevada Power totaling $31 million and $7 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending totals $175 million for the remainder of 2023. Construction includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:
◦Construction at the Nevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada and a 220-MW grid-tied battery energy storage system that will be developed on the site of the retired Reid Gardner generating station in Clark County, Nevada, both with commercial operation expected by the end of 2023. Also, a 200-MW battery energy storage system that will be developed on the site of the Valmy generating station in Humboldt County, Nevada with commercial operation expected by the end of 2025. Total spending for the three-month period ended March 31, 2023, was $39 million with planned spending of $159 million for the remainder of 2023.
•Other 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.
Material Cash Requirements
As of March 31, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2022, 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
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, 2022, and new regulatory matters occurring in 2023.
PacifiCorp
Utah
In May 2023, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2022. The filing requested a rate increase of $98 million, or 4.6%, effective on an interim basis July 1, 2023.
Oregon
In April 2023, PacifiCorp filed its transition adjustment mechanism requesting approval to update net power costs for 2024. The filing requested a rate increase of $164 million, or 9.5%, to become effective January 1, 2024.
Wyoming
In March 2023, PacifiCorp filed a general rate case requesting a rate increase of $140 million, or 21.6%, to become effective January 1, 2024. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities.
In April 2023, PacifiCorp filed its energy cost adjustment and renewable energy credit and sulfur dioxide revenue credit mechanisms to recover deferred net power costs from 2022. The combined filing requested a rate increase of $49 million, or 7.4%, to become effective on an interim basis July 1, 2023.
Washington
In March 2023, PacifiCorp filed a general rate case requesting a two-year rate plan with a rate increase of $27 million, or 6.6%, to become effective March 1, 2024, and a second rate increase of $28 million, or 6.5%, to become effective March 1, 2025. The requested rate increase includes recovery of increases in net power costs and new major capital investments in transmission and wind-powered generating facilities.
California
In May 2022, PacifiCorp filed a general rate case requesting an overall rate change of $28 million, or 25.7%, to become effective January 1, 2023. In November 2022, the CPUC granted the requested rate effective date and directed PacifiCorp to establish a memorandum account to track the change in rates beginning January 1, 2023, until the new rates become effective upon the issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in February 2023 with a slight adjustment of an overall rate increase of $27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling requesting additional information on PacifiCorp's wildfire and risk analyses and requested additional information regarding wildfire memorandum accounts. In March 2023, the CPUC split the general rate case into two tracks. The first track addresses the general rate case with an expected decision from the CPUC in late 2023, and the second track addresses the wildfire memorandum accounts with an expected decision in early 2024.
MidAmerican Energy
South Dakota
In May 2022, MidAmerican Energy filed a request with the South Dakota Public Utilities Commission ("SDPUC") for a $7 million, or 6.4%, annual increase in South Dakota retail natural gas rates. In March 2023, MidAmerican Energy filed a settlement agreement between all parties allowing a total increase of $6 million, or 5.5%, annual increase in South Dakota retail natural gas rates, upon completion of the capital investment phase-in adjustment clause. On March 31, 2023, the SDPUC issued an order approving the settlement agreement with final rates effective April 1, 2023.
Wind PRIME
In January 2022, MidAmerican Energy filed an application with the IUB for 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 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 expects to be eligible for 100% PTCs under current tax law for the Wind PRIME projects. In December 2022, MidAmerican Energy, the Iowa Office of Consumer Advocate and the Iowa Business Energy Coalition filed a non-unanimous settlement with the IUB that includes a rate of return of 11.0%. The settlement would benefit customers by providing an immediate rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. The IUB conducted a hearing on the application and proposed settlement during the week of February 20, 2023. On April 27, 2023, the IUB issued its final order regarding the application. The IUB found that MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application, but rejected the settlement and proposed its own principles for the project. MidAmerican Energy is reviewing the order and assessing options for rejection or motion to reconsider. MidAmerican Energy must either accept or reject the order, or file a motion for reconsideration within 20 days and no later than May 17, 2023.
Iowa Transmission Legislation
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law provides MidAmerican Energy, as an incumbent electric transmission owner, the legal right to construct, own and maintain transmission lines in MidAmerican Energy's service territory that have been approved by the MISO (or another federally registered planning authority) and are eligible to receive regional cost allocation. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for the construction of eligible electric transmission lines that it intends to construct, own and maintain. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the eligible electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the eligible electric transmission line. In October 2020, national transmission interests filed a lawsuit that challenged the law on state constitutional grounds. The suit argues that the law was enacted in violation of the "single-subject" provision of Iowa's state constitution because it was "log-rolled" into a late session appropriations bill and violates the equal protection provision of the Iowa constitution. The State of Iowa defended the law, and MidAmerican Energy and ITC Midwest both intervened and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of standing, and the national transmission interests appealed. In June 2022, the Iowa Court of Appeals upheld the district court's decision, after which the national transmission interests asked the Iowa Supreme Court to reconsider. In November 2022, the Iowa Supreme Court granted the motion to reconsider. On March 24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower courts, held the national transmission interests had standing, and remanded the case to the district court to consider the state constitutional claims on their merits. The opinion also imposed a temporary injunction that stayed enforcement of the law pending a decision on the merits. On April 7, 2023, the State of Iowa, acting individually, and MidAmerican Energy and ITC Midwest, acting jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19, 2023, the national transmission interests filed a reply that (1) expressed its opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to hold that the injunction specifically applied to and precluded advancement of MidAmerican Energy's Long Range Transmission Projects ("LRTP") Tranche 1 projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on the constitutional claims on the merits without further briefing or argument. On April 26, 2023, the Iowa Supreme Court issued an order that denied the petitions for rehearing without comment and made minor, non-substantive changes to the decision, with no changes to the injunction. No earlier than May 18, 2023, the Iowa Supreme Court will remand the case to the district court for further proceedings on the merits. To this point, MISO has taken no action to reverse or disrupt its approval of MidAmerican Energy's LRTP Tranche 1 projects. This matter only potentially affects the manner in which MidAmerican Energy would secure the right to construct transmission lines that are eligible for regional cost allocation and are otherwise subject to competitive bidding under the MISO tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing rights to construct any other transmission lines, including lines required to serve new or expanded retail load, connect new generators or meet reliability criteria.
NV Energy (Nevada Power and Sierra Pacific)
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. In October 2022, all parties to the proceedings relating to the joint application entered into a Stipulation to delay the procedural schedule. The Nevada Utilities made a supplemental filing on December 30, 2022. In March 2023, the proceedings relating to the joint application were postponed to May 2023. In April 2023, the Nevada Utilities filed a notice with the PUCN requesting to withdraw the joint application to merge into a single corporate entity and vacate the current procedural schedule, and executed a termination of the related merger agreement.
Transportation Electrification Plan ("TEP")
In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of a Distributed Resource Plan amendment to implement the state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs and schedules to implement the TEP. The 2022 TEP outlines programs, investments and incentives to accelerate transportation electrification across Nevada. The Nevada Utilities proposed a budget of $348 million, which represents the maximum cost over the depreciable life of the TEP's programs and assets, to deploy the TEP in 2023 through 2024. In March 2023, the PUCN issued an order approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on the program management and contingency budget amounts. The unapproved programs have been deferred for approval in future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs.In April 2023, interveners filed a petition for reconsideration of the PUCN's March 2023 Order.
Northern Powergrid Distribution Companies
Ofgem has completed the price control review that resulted in a new price control effective April 1, 2023. The license modifications that give effect to the price control were published by Ofgem on February 3, 2023 and were subject to appeal to the Competition and Markets Authority ("CMA") if an appeal was filed by March 3, 2023. On March 2, 2023, Northern Powergrid sought permission from the CMA to appeal against the license modifications that give effect to the RIIO-ED2 price control. The appeal relates to two specific areas:
•Ofgem's misallocation of allowances that is inconsistent with efficient costs; and
•Ofgem's approach to determine rewards for the Business Plan Incentive.
The permission for the appeal was granted by the CMA and the appeal is expected to conclude in the fourth quarter of 2023 in accordance with the timetable required of the CMA. The outcome of this appeal may increase the revenue available to the Company if the CMA amends the price control determination.
BHE Pipeline Group
BHE GT&S
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. 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 transmission 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. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.
Northern Natural Gas
In July 2022, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $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 and storage reservation rates. In January 2023, the FERC approved Northern Natural Gas filing to implement its interim rates effective January 1, 2023, subject to refund and the outcome of hearing procedures. Procedural hearings are scheduled to begin June 14, 2023.
BHE Transmission
AltaLink
2024-2025 General Tariff Application
In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total total transmission tariffs of C$902.3 million and C$908.6 million for 2024 and 2025, respectively, which extends AltaLink's previous five-year commitment to maintain its tariff at or below C$904 million from 2019 to 2023 for another year. The application also requests the approval to reinstate C$98.9 million cost of removal to rate base which was not previously approved, based on additional information filed.
Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with respect to the first stage of the GCOC proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial markets due to the COVID-19 pandemic. In June 2022, the AUC initiated the second stage to explore a formula-based approach to determine the return on equity for 2024 and future test periods.
In February 2023, AltaLink and other stakeholders filed evidence. AltaLink filed expert evidence recommending a 10.3% return on equity, on a recommended equity ratio of 40%. Other utilities filed similar recommendations. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the Industrial Power Consumers Association of Alberta recommended returns on equity ranging from 6.75% to 7.7% and equity ratios ranging from 35% to 37%. AltaLink's expert witness, as well as all other utility experts, submitted that they are generally not in favor of implementing a formulaic adjustment mechanism for allowed return on equity due to the challenges in maintaining the Fair Return Standard through formulaic adjustments. The interveners are generally in favor of a formula. The AUC expects to conclude the second stage of the GCOC proceeding in the third quarter of 2023.
Environmental Laws and Regulations
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal 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 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, 2022, and new environmental matters occurring in 2023.
Air Quality Regulations
The Clean Air Act, as well as state laws and regulations impacting air emissions, provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. These laws and regulations continue to be promulgated and implemented and will impact the operation of BHE's generating facilities and require them to reduce emissions at those facilities to comply with the requirements. In addition, the potential adoption of state or federal clean energy standards, which include low-carbon, non-carbon and renewable electricity generating resources, may also impact electricity generators and natural gas providers.
Mercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015, with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects and unit retirements to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the U.S. Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. In June 2015, the U.S. Supreme Court reversed and remanded the MATS rule, finding that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. In December 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from generating facilities under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled generating facilities from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding, which were stayed pending the EPA's plans to revisit the finding. On January 31, 2022, the EPA proposed several actions relating to the MATS. The EPA proposed to restore the appropriate and necessary finding to regulate generating facilities under Clean Air Act Section 112. The EPA finalized its restoration of the MATS appropriate and necessary finding in February 2023.
On April 5, 2023, the EPA released a proposal to revise several aspects of the MATS rule following the agency's review of the 2020 Residual Risk and Technology Review. The EPA proposes two specific standard changes - one applicable to all covered units and one specific to the existing lignite subcategory. The EPA proposes a more stringent standard for emissions of filterable particulate matter, the surrogate standard for non-mercury metals for coal-fueled electric generating units. The EPA proposes to reduce the filterable particulate matter emission standard by two-thirds based on a demonstration that 91% of coal-based capacity, which has not been identified as retiring before the proposed compliance period, has an emission rate at or below the proposed limit. The EPA also proposes to require continuous emissions monitoring for filterable particulate matter to demonstrate compliance with the revised standard. Compliance would be due no later than three years after the effective date of a final rule and the EPA will accept comments on the proposal for 60 days following its publication in the Federal Register. The relevant Registrants are not included in the lignite subcategory. The relevant Registrants have identified that compliance can be achieved with existing controls. Until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.
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 U.S. 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. 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. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key industry regulated by the rule and will have access to emissions allowance trading beginning in summer 2023. The final rule shifted the maximum daily backstop rate for coal-fueled generating units, which drives the installation of new controls or curtailment, to take effect in 2030 instead of 2027. PacifiCorp's Hunter Units 1-3 and Huntington Units 1-2, which do not have SCR controls, are impacted by the rule. PacifiCorp's 2023 IRP selected the installation of non-SCR on the Hunter and Huntington Units by 2026 as part of the preferred portfolio. The level of NOx allowances for the Utah units remains similar to 2021 levels, with significant reductions for the coal units beginning in 2026. The daily limit, which takes effect in 2030, will further restrict operation of units without adequate controls. NV Energy's fossil-fueled units are also covered by the final rule. North Valmy Units 1 and 2, which do not have SCR, will require additional controls or reduced operations during the ozone season if operated beyond 2025. Nevada's regional haze SIP has an enforceable retirement date for North Valmy Units 1 and 2 of December 31, 2028, and NV Energy's IRP identified a December 31, 2025, retirement date for the units. The EPA's updated modeling suggests that Arizona, Iowa and Kansas may be significantly contributing to nonattainment in downwind states. The EPA intends to undertake additional assessment of its modeling for these states and will determine if it is necessary to address obligations for these states in future actions. The EPA also deferred final action for Wyoming, pending further review of updated air quality and contribution modeling and analysis. Additional notice and comment rulemaking, such as a supplemental rule, would be required to rescind Iowa's approved SIP and incorporate additional states into the program. The states of Utah and Wyoming challenged the EPA's denial and deferral, respectively, of their interstate ozone transport SIPs in the Tenth Circuit Court of Appeals. PacifiCorp also filed petitions with the court opposing the EPA's action in both states. At the time of filing, at least six other states have challenged the EPA's action to disapprove SIPs in different regional federal Courts of Appeal. Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants cannot be determined.
The EPA included additional sectors in the expanded CSAPR program. Relevant to the Registrants, this includes the pipeline transportation of natural gas. Requirements for that sector focus on emissions reductions from reciprocating internal combustion engines involved in the transport of natural gas and take effect in 2026. There is no access to allowance trading for the non-electric generation sectors. The EPA excluded emergency engines and engines that do not operate during the ozone season, included a facility-wide averaging plan and eased requirements for monitoring. Northern Natural Gas operates 18 affected units; BHE GT&S operates 157 affected units; and Kern River is not affected by the final rule.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
In June 2019, the state of Utah incorporated a BART alternative into its SIP for regional haze planning period one. 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 EPA approved the SIP revision with the BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. 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. The EPA defended the SIP, and PacifiCorp and the state of Utah intervened in the litigation. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. A final decision from the court is expected by fall 2023. The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for the regional haze second planning period on June 6, 2022. The SIP sets mass-based NOx emissions limits and rate-based SO2 limits for PacifiCorp's Hunter and Huntington generating facilities to ensure reasonable visibility progress for the second planning period. The state submitted the SIP to the EPA in August 2022 and the EPA determined the submission was complete August 22, 2022. The EPA is required to make a determination on the Utah SIP by August 2023.
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 in October 2014. The EPA's final action on the Wyoming SIP in 2014 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 by 2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental groups also filed an appeal of the EPA's final action. 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 parties worked to mediate claims under the Wyoming regional haze requirements until the abatement on litigation was lifted in September 2022. Opening briefs were submitted in October 2022. In the litigation, PacifiCorp objects to the EPA's FIP requiring SCR on the Wyodak Unit. That requirement in the agency's plan remains stayed by the court. PacifiCorp has also intervened on behalf of the EPA against claims that Naughton Units 1 and 2 should have been subject to a SCR requirement. Oral argument will be held May 16, 2023. PacifiCorp has claimed the Naughton claims are moot but that a court ruling on the Wyodak claims is necessary to determine whether the EPA's federal plan complies with the Clean Air Act. Separately, 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 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, PacifiCorp must convert Jim Bridger Units 1 and 2 to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. 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. On December 30, 2022, the Wyoming Air Quality Division submitted the state-approved revised regional haze SIP requiring natural gas conversion of Jim Bridger Units 1 and 2 to the EPA for approval. The plan revision replaces a previous requirement for SCR at the units. The Wyoming Air Quality Division also issued an air permit for the natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. PacifiCorp submitted a notice of compliance to the EPA on March 9, 2023, to certify completion of the Jim Bridger administrative compliance order through completion of the requirements to comply with Wyoming's consent decree and revised SIP submission. PacifiCorp remains subject to the compliance terms of the Wyoming consent decree as it works to convert Jim Bridger Units 1 and 2 to natural gas. The EPA is in on-going discussions with Wyoming to finalize a determination on the SIP revisions, with a decision anticipated by fall 2023. Wyoming submitted a SIP for the second round of regional haze planning to the EPA in August 2022 and the EPA determined the submission was complete that same month. Wyoming determined that no additional controls are necessary on any Wyoming resources to make reasonable progress under the regional haze rules. The EPA is required to make a determination on the Wyoming SIP by August 2023.
The state of Colorado regional haze SIP requires SCR equipment at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are in-service. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021, with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in its 2023 IRP.
Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA in August 2022. The EPA has 18 months to approve or disapprove all or parts of the states' plans. On August 25, 2022, the EPA promulgated a finding of failure to submit a SIP for the regional haze second planning period for 15 states, including Iowa. The finding establishes a two-year deadline for the agency to promulgate FIPs to address the requirements, unless prior to promulgating a FIP, the state submits, and the agency approves, a SIP meeting the requirements. The finding says the agency intends to continue to work with states in developing approvable SIP submittals in a timely manner. The Iowa Department of Natural Resources continues to work with the EPA on development of its SIP. On February 13, 2023, Iowa issued a draft SIP and accepted comment on the draft plan through March 16, 2023. Iowa proposes to require operational improvements to existing control equipment at MidAmerican Energy's Louisa Generation Station and Walter Scott Jr. Energy Center - Unit 3. Iowa anticipates submitting a final plan to the EPA in summer 2023.
Water Quality Standards
In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. In November 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule took effect in December 2020. The final rule changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport water, revises the voluntary incentives program for flue gas desulfurization wastewater, and adds subcategories for high-flow units, low utilization units, and those that will transition away from coal combustion by 2028. While most of the issues raised by this rule are already being addressed through the CCR rule and are not expected to impose significant additional requirements, the Dave Johnston generating facility is impacted by the rule's bottom ash handling requirements at Units 1 and 2. The generating facility submitted notice to the Wyoming Department of Environmental Quality that it will either achieve a cessation of coal combustion at Units 1 and 2 by December 31, 2028, or install bottom ash transport treatment technology by December 31, 2025. On March 8, 2023, the EPA proposed additional changes to the effluent limitations guidelines to replace the 2020 rule and provide stricter limits for bottom ash transport water, flue gas desulfurization wastewater and coal combustion residual leachate. The relevant Registrants use a combination of zero discharge, enrollment in cessation-of-coal subcategory and dry bottom ash handling to manage the affected wastestreams. As a result, significant impacts are not anticipated. However, until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined. The EPA will accept public comments through May 30, 2023, and intends to finalize a rule by spring 2024.
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, 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, 2022. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2022.
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 June 30, 2022,March 31, 2023, the related consolidated statements of operations, and changes in shareholders' equity, and cash flows for the three-month and six-month periods ended June 30,March 31, 2023 and 2022, and 2021, and 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, 2021,2022, 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 25, 2022,24, 2023, 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, 2021,2022, 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
AugustMay 5, 20222023
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | As of | | | As of |
| | | | June 30, | | December 31, | | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | | $ | 390 | | | $ | 179 | | Cash and cash equivalents | | $ | 19 | | | $ | 641 | |
| Trade receivables, net | Trade receivables, net | | 730 | | | 725 | | Trade receivables, net | | 780 | | | 825 | |
| Other receivables, net | Other receivables, net | | 49 | | | 52 | | Other receivables, net | | 112 | | | 72 | |
| Inventories | Inventories | | 490 | | | 474 | | Inventories | | 491 | | | 474 | |
| Derivative contracts | Derivative contracts | | 127 | | | 76 | | Derivative contracts | | 114 | | | 184 | |
| | Regulatory assets | Regulatory assets | | 150 | | | 65 | | Regulatory assets | | 302 | | | 275 | |
| | Other current assets | Other current assets | | 83 | | | 150 | | Other current assets | | 215 | | | 213 | |
| Total current assets | Total current assets | | 2,019 | | | 1,721 | | Total current assets | | 2,033 | | | 2,684 | |
| | | | | |
| Property, plant and equipment, net | Property, plant and equipment, net | | 23,414 | | | 22,914 | | Property, plant and equipment, net | | 24,695 | | | 24,430 | |
| Regulatory assets | Regulatory assets | | 1,257 | | | 1,287 | | Regulatory assets | | 1,684 | | | 1,605 | |
| Other assets | Other assets | | 750 | | | 534 | | Other assets | | 707 | | | 686 | |
| | | | | | | | | | | |
| Total assets | Total assets | | $ | 27,440 | | | $ | 26,456 | | Total assets | | $ | 29,119 | | | $ | 29,405 | |
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 |
| | | | June 30, | | December 31, | | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| LIABILITIES AND SHAREHOLDERS' EQUITY | LIABILITIES AND SHAREHOLDERS' EQUITY | LIABILITIES AND SHAREHOLDERS' EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | | $ | 848 | | | $ | 680 | | Accounts payable | | $ | 900 | | | $ | 1,049 | |
| Accrued interest | Accrued interest | | 122 | | | 121 | | Accrued interest | | 143 | | | 128 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | | 189 | | | 78 | | Accrued property, income and other taxes | | 92 | | | 67 | |
| | Accrued employee expenses | Accrued employee expenses | | 117 | | | 89 | | Accrued employee expenses | | 97 | | | 86 | |
| | Current portion of long-term debt | Current portion of long-term debt | | 455 | | | 155 | | Current portion of long-term debt | | 440 | | | 449 | |
| Regulatory liabilities | Regulatory liabilities | | 115 | | | 118 | | Regulatory liabilities | | 97 | | | 96 | |
| Other current liabilities | Other current liabilities | | 195 | | | 219 | | Other current liabilities | | 389 | | | 271 | |
| Total current liabilities | Total current liabilities | | 2,041 | | | 1,460 | | Total current liabilities | | 2,158 | | | 2,146 | |
| | | | | |
| Long-term debt | Long-term debt | | 8,268 | | | 8,575 | | Long-term debt | | 9,218 | | | 9,217 | |
| Regulatory liabilities | Regulatory liabilities | | 2,833 | | | 2,650 | | Regulatory liabilities | | 2,690 | | | 2,843 | |
| Deferred income taxes | Deferred income taxes | | 2,908 | | | 2,847 | | Deferred income taxes | | 3,097 | | | 3,152 | |
| Other long-term liabilities | Other long-term liabilities | | 1,364 | | | 1,011 | | Other long-term liabilities | | 1,635 | | | 1,306 | |
| Total liabilities | Total liabilities | | 17,414 | | | 16,543 | | Total liabilities | | 18,798 | | | 18,664 | |
| | | | | | | | | | | |
| Commitments and contingencies (Note 9) | Commitments and contingencies (Note 9) | | 0 | | 0 | Commitments and contingencies (Note 9) | |
| | | | | |
| 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 | | 5,561 | | | 5,449 | | Retained earnings | | 5,849 | | | 6,269 | |
| Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | | (16) | | | (17) | | Accumulated other comprehensive loss, net | | (9) | | | (9) | |
| Total shareholders' equity | Total shareholders' equity | | 10,026 | | | 9,913 | | Total shareholders' equity | | 10,321 | | | 10,741 | |
| | | | | | | | | | | |
| Total liabilities and shareholders' equity | Total liabilities and shareholders' equity | | $ | 27,440 | | | $ | 26,456 | | Total liabilities and shareholders' equity | | $ | 29,119 | | | $ | 29,405 | |
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 | | Six-Month Periods | | | Three-Month Periods |
| | | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| | | | | | | | | | | | | | |
| Operating revenue | Operating revenue | $ | 1,314 | | | $ | 1,298 | | | $ | 2,611 | | | $ | 2,540 | | Operating revenue | | $ | 1,484 | | | $ | 1,297 | |
| | | | | | | | | | | | | | |
| Operating expenses: | Operating expenses: | | Operating expenses: | | |
| Cost of fuel and energy | Cost of fuel and energy | 451 | | | 441 | | | 916 | | | 865 | | Cost of fuel and energy | | 614 | | | 465 | |
| Operations and maintenance | Operations and maintenance | 375 | | | 255 | | | 652 | | | 514 | | Operations and maintenance | | 705 | | | 277 | |
| Depreciation and amortization | Depreciation and amortization | 279 | | | 275 | | | 559 | | | 539 | | Depreciation and amortization | | 279 | | | 280 | |
| Property and other taxes | Property and other taxes | 51 | | | 43 | | | 110 | | | 104 | | Property and other taxes | | 53 | | | 59 | |
| Total operating expenses | Total operating expenses | 1,156 | | | 1,014 | | | 2,237 | | | 2,022 | | Total operating expenses | | 1,651 | | | 1,081 | |
| | | | | | | | | | | | | | |
| Operating income | 158 | | | 284 | | | 374 | | | 518 | | |
| Operating (loss) income | | Operating (loss) income | | (167) | | | 216 | |
| | | | | | | | | | | | | | |
| Other income (expense): | Other income (expense): | | | | Other income (expense): | | | |
| Interest expense | Interest expense | (107) | | | (105) | | | (213) | | | (212) | | Interest expense | | (124) | | | (106) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 6 | | | 6 | | | 12 | | | 12 | | Allowance for borrowed funds | | 13 | | | 6 | |
| Allowance for equity funds | Allowance for equity funds | 15 | | | 12 | | | 28 | | | 25 | | Allowance for equity funds | | 27 | | | 13 | |
| Interest and dividend income | Interest and dividend income | 7 | | | 5 | | | 14 | | | 11 | | Interest and dividend income | | 19 | | | 7 | |
| Other, net | Other, net | (5) | | | 4 | | | (9) | | | 10 | | Other, net | | 2 | | | (4) | |
| Total other income (expense) | Total other income (expense) | (84) | | | (78) | | | (168) | | | (154) | | Total other income (expense) | | (63) | | | (84) | |
| | | | | | | | | | | | | | |
| Income before income tax benefit | 74 | | | 206 | | | 206 | | | 364 | | |
| Income tax benefit | (8) | | | (19) | | | (6) | | | (30) | | |
| Net income | $ | 82 | | | $ | 225 | | | $ | 212 | | | $ | 394 | | |
| (Loss) income before income tax expense (benefit) | | (Loss) income before income tax expense (benefit) | | (230) | | | 132 | |
| Income tax expense (benefit) | | Income tax expense (benefit) | | (110) | | | 2 | |
| Net (loss) income | | Net (loss) income | | $ | (120) | | | $ | 130 | |
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, March 31, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,880 | | | $ | (19) | | | $ | 9,342 | | |
| Net income | | — | | | — | | | — | | | 225 | | | — | | | 225 | | |
| | Balance, June 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,105 | | | $ | (19) | | | $ | 9,567 | | |
| | Balance, December 31, 2020 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,711 | | | $ | (19) | | | $ | 9,173 | | |
| Net income | | — | | | — | | | — | | | 394 | | | — | | | 394 | | |
| | Balance, June 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,105 | | | $ | (19) | | | $ | 9,567 | | |
| | | | | | | | | | | | | | | |
| Balance, March 31, 2022 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,579 | | | $ | (16) | | | $ | 10,044 | | |
| Net income | | — | | | — | | | — | | | 82 | | | — | | | 82 | | |
| | Common stock dividends declared | | — | | | — | | | — | | | (100) | | | — | | | (100) | | |
| 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 | | Balance, December 31, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,449 | | | $ | (17) | | | $ | 9,913 | |
| Net income | Net income | | — | | | — | | | — | | | 212 | | | — | | | 212 | | Net income | | — | | | — | | | — | | | 130 | | | — | | | 130 | |
| Other comprehensive income | Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | | Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| | Balance, March 31, 2022 | | Balance, March 31, 2022 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,579 | | | $ | (16) | | | $ | 10,044 | |
| | | | | | | | | | | | | | | |
| | Balance, December 31, 2022 | | Balance, December 31, 2022 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 6,269 | | | $ | (9) | | | $ | 10,741 | |
| Net loss | | Net loss | | — | | | — | | | — | | | (120) | | | — | | | (120) | |
| | Common stock dividends declared | Common stock dividends declared | | — | | | — | | | — | | | (100) | | | — | | | (100) | | Common stock dividends declared | | — | | | — | | | — | | | (300) | | | — | | | (300) | |
| Balance, June 30, 2022 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,561 | | | $ | (16) | | | $ | 10,026 | | |
| Balance, March 31, 2023 | | Balance, March 31, 2023 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,849 | | | $ | (9) | | | $ | 10,321 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | Six-Month Periods | | Three-Month Periods |
| | | Ended June 30, | | Ended March 31, |
| | | 2022 | | 2021 | | 2023 | | 2022 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | $ | 212 | | | $ | 394 | | |
| Adjustments to reconcile net income to net cash flows from operating activities: | | | | |
| Net (loss) income | | Net (loss) income | $ | (120) | | | $ | 130 | |
| Adjustments to reconcile net (loss) income to net cash flows from operating activities: | | Adjustments to reconcile net (loss) income to net cash flows from operating activities: | | | |
| Depreciation and amortization | Depreciation and amortization | 559 | | | 539 | | Depreciation and amortization | 279 | | | 280 | |
| Allowance for equity funds | Allowance for equity funds | (28) | | | (25) | | Allowance for equity funds | (27) | | | (13) | |
| Changes in regulatory assets and liabilities | (76) | | | (98) | | |
| Net power cost deferrals | | Net power cost deferrals | (136) | | | (14) | |
| Amortization of net power cost deferrals | | Amortization of net power cost deferrals | 36 | | | 11 | |
| Other changes in regulatory assets and liabilities | | Other changes in regulatory assets and liabilities | (6) | | | (6) | |
| Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 29 | | | 22 | | Deferred income taxes and amortization of investment tax credits | (75) | | | 19 | |
| Other, net | Other, net | 12 | | | (1) | | Other, net | (2) | | | 4 | |
| 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 | (142) | | | (10) | | Trade receivables, other receivables and other assets | 37 | | | 59 | |
| Inventories | Inventories | (16) | | | 8 | | Inventories | (17) | | | (5) | |
| Derivative collateral, net | Derivative collateral, net | 69 | | | 35 | | Derivative collateral, net | (78) | | | 22 | |
| | Accrued property, income and other taxes, net | Accrued property, income and other taxes, net | 152 | | | 79 | | Accrued property, income and other taxes, net | (11) | | | 15 | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 442 | | | 103 | | Accounts payable and other liabilities | 459 | | | 35 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 1,213 | | | 1,046 | | Net cash flows from operating activities | 339 | | | 537 | |
| | | | | | | | | |
| Cash flows from investing activities: | Cash flows from investing activities: | | | | Cash flows from investing activities: | | | |
| Capital expenditures | Capital expenditures | (894) | | | (819) | | Capital expenditures | (643) | | | (374) | |
| Other, net | Other, net | 6 | | | — | | Other, net | (1) | | | 3 | |
| Net cash flows from investing activities | Net cash flows from investing activities | (888) | | | (819) | | Net cash flows from investing activities | (644) | | | (371) | |
| | | | | | | | | |
| 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 | (9) | | | (400) | | Repayments of long-term debt | (9) | | | (9) | |
| Net proceeds from short-term debt | — | | | 208 | | |
| | | Dividends paid | Dividends paid | (100) | | | — | | Dividends paid | (300) | | | — | |
| Other, net | Other, net | (2) | | | (4) | | Other, net | (2) | | | (2) | |
| Net cash flows from financing activities | Net cash flows from financing activities | (111) | | | (196) | | Net cash flows from financing activities | (311) | | | (11) | |
| | | | | | | | | |
| 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 | 214 | | | 31 | | Net change in cash and cash equivalents and restricted cash and cash equivalents | (616) | | | 155 | |
| 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 | 186 | | | 19 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 674 | | | 186 | |
| 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 | $ | 400 | | | $ | 50 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 58 | | | $ | 341 | |
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 U.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 June 30, 2022March 31, 2023, and for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The results of operations for the three- and six-month periodsthree-month period ended June 30, 2022 and 2021March 31, 2023, 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, 20212022, 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 accounting policies or its assumptions regarding significant accounting estimates and policies during the six-monththree-month period ended June 30, 2022,March 31, 2023, other than the updates associated with PacifiCorp's estimates of loss contingencies related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and the 2022 McKinney fire 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, U.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, nuclear decommissioning and custodial 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 presented inon 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 | | March 31, | | December 31, |
| | June 30, | | December 31, | | 2023 | | 2022 |
| | 2022 | | 2021 | | | | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 390 | | | $ | 179 | | Cash and cash equivalents | $ | 19 | | | $ | 641 | |
| Restricted cash and cash equivalents included in other current assets | Restricted cash and cash equivalents included in other current assets | 7 | | | 4 | | Restricted cash and cash equivalents included in other current assets | 8 | | | 7 | |
| Restricted cash included in other assets | Restricted cash included in other assets | 3 | | | 3 | | Restricted cash included in other assets | 31 | | | 26 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 400 | | | $ | 186 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 58 | | | $ | 674 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | | | | As of | | | | As of |
| | | | June 30, | | December 31, | | | March 31, | | December 31, |
| | Depreciable Life | | 2022 | | 2021 | | Depreciable Life | | 2023 | | 2022 |
| Utility Plant: | | | | | | |
| Utility plant: | | Utility plant: | | | | | |
| Generation | Generation | 15 - 59 years | | $ | 13,770 | | | $ | 13,679 | | Generation | 15 - 59 years | | $ | 13,721 | | | $ | 13,726 | |
| Transmission | Transmission | 60 - 90 years | | 7,952 | | | 7,894 | | Transmission | 60 - 90 years | | 8,063 | | | 8,051 | |
| Distribution | Distribution | 20 - 75 years | | 8,211 | | | 8,044 | | Distribution | 20 - 75 years | | 8,578 | | | 8,477 | |
Intangible plant(1) | 5 - 75 years | | 1,114 | | | 1,106 | | |
| Other | 5 - 60 years | | 1,584 | | | 1,539 | | |
Intangible plant(1) and other | | Intangible plant(1) and other | 5 - 75 years | | 2,758 | | | 2,755 | |
| Utility plant in-service | Utility plant in-service | | 32,631 | | | 32,262 | | Utility plant in-service | | 33,120 | | | 33,009 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | | (10,874) | | | (10,507) | | Accumulated depreciation and amortization | | | (11,256) | | | (11,093) | |
| Utility plant in-service, net | Utility plant in-service, net | | | 21,757 | | | 21,755 | | Utility plant in-service, net | | | 21,864 | | | 21,916 | |
| Other non-regulated, net of accumulated depreciation and amortization | 14 - 95 years | | 18 | | | 18 | | |
| Plant, net | | 21,775 | | | 21,773 | | |
| Nonregulated, net of accumulated depreciation and amortization | | Nonregulated, net of accumulated depreciation and amortization | 14 - 95 years | | 18 | | | 18 | |
| | | | 21,882 | | | 21,934 | |
| Construction work-in-progress | Construction work-in-progress | | | 1,639 | | | 1,141 | | Construction work-in-progress | | | 2,813 | | | 2,496 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | | $ | 23,414 | | | $ | 22,914 | | Property, plant and equipment, net | | | $ | 24,695 | | | $ | 24,430 | |
(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
(4) Recent Financing Transactions
Credit Facilities
In June 2022, PacifiCorp amended and restated its existing $1.2 billion unsecured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from the London Interbank Offered Rate to the Secured Overnight Financing Rate.
Common Shareholders' Equity
In May 2022,January 2023, PacifiCorp declared a common stock dividend of $100$300 million, paid in June 2022,February 2023, to PPW Holdings LLC.
(5) Income Taxes
The effective income tax rate for the three-month period ended March 31, 2023 of 48% results from a $110 million income tax benefit associated with a $230 million pre-tax loss primarily resulting from the $359 million pre-tax loss associated with the 2020 Wildfires described in Note 9. The $110 million income tax benefit is primarily comprised of a $48 million benefit (21%) from the application of the federal statutory income tax rate to the pre-tax loss and a $29 million benefit (13%) from federal income tax credits.
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to (loss) income before income tax benefitexpense (benefit) is as follows:
| | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | | 21 | % | | 21 | % |
| State income tax, net of federal income tax benefit | State income tax, net of federal income tax benefit | 4 | | | 4 | | | 3 | | | 4 | | State income tax, net of federal income tax benefit | | 4 | | | 3 | |
| Federal income tax credits | Federal income tax credits | (25) | | | (19) | | | (21) | | | (19) | | Federal income tax credits | | 13 | | | (20) | |
Effects of ratemaking(1) | Effects of ratemaking(1) | (13) | | | (15) | | | (11) | | | (14) | | Effects of ratemaking(1) | | 6 | | | (11) | |
| | Valuation allowance | Valuation allowance | — | | | — | | | 4 | | | — | | Valuation allowance | | 5 | | | 6 | |
| Other | Other | 2 | | | — | | | 1 | | | — | | Other | | (1) | | | 3 | |
| Effective income tax rate | Effective income tax rate | (11) | % | | (9) | % | | (3) | % | | (8) | % | Effective income tax rate | | 48 | % | | 2 | % |
(1)Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
Income tax credits relate primarily to production tax credits ("PTCs"PTC") earned byfrom 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 recognized for the three-month periods endedJune 30, March 31, 2023 and 2022, and 2021 totaled $18$29 million and $40$26 million, respectively. PTCs for the six-month periods ended June 30, 2022 and 2021 totaled $44 million and $71 million, respectively.
For the six-monththree-month period ended June 30,March 31, 2023, PacifiCorp released an $11 million valuation allowance related to state net operating loss carryforwards. For the three-month period ended March 31, 2022, PacifiCorp recorded aan $8 million valuation allowance related to state net operating loss carryforwards.
Berkshire Hathaway includes BHE and its subsidiaries in its U.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 six-month periods ended June 30, As of March 31, 2023 and December 31, 2022, and 2021, PacifiCorp received net cash payments for federal and state income taxtaxes receivable from BHE totaling $150were $119 million and $93$84 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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Pension: | Pension: | | | | | | | | Pension: | | | | |
| Service cost | $ | — | | | $ | — | | | $ | — | | | $ | — | | |
| | Interest cost | Interest cost | 7 | | | 7 | | | 14 | | | 14 | | Interest cost | | $ | 10 | | | $ | 7 | |
| Expected return on plan assets | Expected return on plan assets | (11) | | | (14) | | | (21) | | | (27) | | Expected return on plan assets | | (12) | | | (10) | |
| | Net amortization | Net amortization | 4 | | | 5 | | | 8 | | | 10 | | Net amortization | | 3 | | | 4 | |
| Net periodic benefit cost (credit) | $ | — | | | $ | (2) | | | $ | 1 | | | $ | (3) | | |
| Net periodic benefit cost | | Net periodic benefit cost | | $ | 1 | | | $ | 1 | |
| | Other postretirement: | Other postretirement: | | Other postretirement: | | |
| Service cost | Service cost | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | Service cost | | $ | — | | | $ | — | |
| Interest cost | Interest cost | 2 | | | 2 | | | 4 | | | 4 | | Interest cost | | 3 | | | 2 | |
| Expected return on plan assets | Expected return on plan assets | (3) | | | (2) | | | (5) | | | (4) | | Expected return on plan assets | | (3) | | | (2) | |
| Net amortization | Net amortization | — | | | — | | | — | | | — | | Net amortization | | (1) | | | — | |
| Net periodic benefit cost (credit) | $ | — | | | $ | 1 | | | $ | — | | | $ | 1 | | |
| Net periodic benefit credit | | Net periodic benefit credit | | $ | (1) | | | $ | — | |
Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other,other, net inon the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $— million, respectively, during 2022.2023. As of June 30, 2022, $2March 31, 2023, $1 million of contributions had been made to the pension plans.
(7) Risk Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.
PacifiCorp has established a risk management process that is designed to identify, 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):
| | | Derivative | | | Derivative | |
| | Contracts - | | Other | | Other | | | | Contracts - | | Other | | Other | | |
| | Current | | Other | | Current | | Long-term | | | Current | | Other | | Current | | Long-term | |
| | Assets | | Assets | | Liabilities | | Liabilities | | Total | | Assets | | Assets | | Liabilities | | Liabilities | | Total |
| As of June 30, 2022 | | | | | | | | | | |
| As of March 31, 2023 | | As of March 31, 2023 | | | | | | | | | |
Not designated as hedging contracts(1): | Not designated as hedging contracts(1): | | Not designated as hedging contracts(1): | |
| Commodity assets | Commodity assets | $ | 183 | | | $ | 80 | | | $ | 9 | | | $ | — | | | $ | 272 | | Commodity assets | $ | 133 | | | $ | 15 | | | $ | 15 | | | $ | 3 | | | $ | 166 | |
| Commodity liabilities | Commodity liabilities | (1) | | | — | | | (44) | | | (4) | | | (49) | | Commodity liabilities | (7) | | | (7) | | | (39) | | | (4) | | | (57) | |
| Total | Total | 182 | | | 80 | | | (35) | | | (4) | | | 223 | | Total | 126 | | | 8 | | | (24) | | | (1) | | | 109 | |
| | | | | | | | | | | | | | | | | | | | |
| Total derivatives | Total derivatives | 182 | | | 80 | | | (35) | | | (4) | | | 223 | | Total derivatives | 126 | | | 8 | | | (24) | | | (1) | | | 109 | |
| Cash collateral payable | Cash collateral payable | (55) | | | (9) | | | — | | | — | | | (64) | | Cash collateral payable | (12) | | | — | | | — | | | — | | | (12) | |
| Total derivatives - net basis | Total derivatives - net basis | $ | 127 | | | $ | 71 | | | $ | (35) | | | $ | (4) | | | $ | 159 | | Total derivatives - net basis | $ | 114 | | | $ | 8 | | | $ | (24) | | | $ | (1) | | | $ | 97 | |
| | As of December 31, 2021 | | |
| As of December 31, 2022 | | As of December 31, 2022 | |
Not designated as hedging contracts(1): | Not designated as hedging contracts(1): | | Not designated as hedging contracts(1): | |
| Commodity assets | Commodity assets | $ | 81 | | | $ | 21 | | | $ | 2 | | | $ | — | | | $ | 104 | | Commodity assets | $ | 279 | | | $ | 27 | | | $ | 9 | | | $ | 3 | | | $ | 318 | |
| Commodity liabilities | Commodity liabilities | (5) | | | (1) | | | (38) | | | (7) | | | (51) | | Commodity liabilities | (22) | | | (7) | | | (14) | | | (5) | | | (48) | |
| Total | Total | 76 | | | 20 | | | (36) | | | (7) | | | 53 | | Total | 257 | | | 20 | | | (5) | | | (2) | | | 270 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total derivatives | Total derivatives | 76 | | | 20 | | | (36) | | | (7) | | | 53 | | Total derivatives | 257 | | | 20 | | | (5) | | | (2) | | | 270 | |
| Cash collateral receivable | — | | | — | | | 5 | | | — | | | 5 | | |
Cash collateral payable(2) | | Cash collateral payable(2) | (73) | | | (5) | | | — | | | — | | | (78) | |
| Total derivatives - net basis | Total derivatives - net basis | $ | 76 | | | $ | 20 | | | $ | (31) | | | $ | (7) | | | $ | 58 | | Total derivatives - net basis | $ | 184 | | | $ | 15 | | | $ | (5) | | | $ | (2) | | | $ | 192 | |
(1)PacifiCorp's commodity derivatives are generally included in rates. As of June 30, 2022March 31, 2023, a regulatory liability of $223$109 million was recorded related to the net derivative asset of $223$109 million. As of December 31, 20212022, a regulatory liability of $53$270 million was recorded related to the net derivative asset of $53$270 million.
(2)As of December 31, 2022, PacifiCorp had an additional $12 million cash collateral payable that was not required to be netted against total derivatives.
The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory (liabilities) assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory (liabilities) assets, as well as amounts reclassified to earnings (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| 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) | |
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2023 | | 2022 |
| | | | | | | |
| Beginning balance | | | | | $ | (270) | | | $ | (53) | |
| Changes in fair value recognized in regulatory (liabilities) assets | | | | | (10) | | | (168) | |
| Net losses reclassified to operating revenue | | | | | (6) | | | (3) | |
| Net gains reclassified to energy costs | | | | | 177 | | | 29 | |
| Ending balance | | | | | $ | (109) | | | $ | (195) | |
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, net | Megawatt hours | | 2 | | | 2 | |
| Natural gas purchases | Decatherms | | 105 | | | 106 | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| Unit of | | March 31, | | December 31, |
| Measure | | 2023 | | 2022 |
| | | | | |
| Electricity purchases, net | Megawatt hours | | 3 | | | 2 | |
| Natural gas purchases | Decatherms | | 158 | | | 127 | |
| | | | | |
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third‑party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2022,March 31, 2023, 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 $47$56 million and $37$48 million as of June 30, 2022March 31, 2023 and December 31, 2021,2022, respectively, for which PacifiCorp had posted collateral of $— million, and $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 June 30, 2022March 31, 2023 and December 31, 2021,2022, PacifiCorp would have been required to post $33$20 million and $23$3 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 | | | | 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 June 30, 2022: | | | | | | | | | | |
| As of March 31, 2023: | | As of March 31, 2023: | | | | | | | | | |
| Assets: | Assets: | | | | | | | | | | Assets: | | | | | | | | | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | 272 | | | $ | — | | | $ | (74) | | | $ | 198 | | Commodity derivatives | $ | — | | | $ | 166 | | | $ | — | | | $ | (44) | | | $ | 122 | |
| Money market mutual funds | Money market mutual funds | 374 | | | — | | | — | | | — | | | 374 | | Money market mutual funds | 44 | | | — | | | — | | | — | | | 44 | |
| Investment funds | Investment funds | 26 | | | — | | | — | | | — | | | 26 | | Investment funds | 28 | | | — | | | — | | | — | | | 28 | |
| | | $ | 400 | | | $ | 272 | | | $ | — | | | $ | (74) | | | $ | 598 | | | $ | 72 | | | $ | 166 | | | $ | — | | | $ | (44) | | | $ | 194 | |
| | Liabilities - Commodity derivatives | Liabilities - Commodity derivatives | $ | — | | | $ | (49) | | | $ | — | | | $ | 10 | | | $ | (39) | | Liabilities - Commodity derivatives | $ | — | | | $ | (57) | | | $ | — | | | $ | 32 | | | $ | (25) | |
| | As of December 31, 2021: | | |
| As of December 31, 2022: | | As of December 31, 2022: | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | 104 | | | $ | — | | | $ | (8) | | | $ | 96 | | Commodity derivatives | $ | — | | | $ | 318 | | | $ | — | | | $ | (119) | | | $ | 199 | |
| Money market mutual funds | Money market mutual funds | 181 | | | — | | | — | | | — | | | 181 | | Money market mutual funds | 649 | | | — | | | — | | | — | | | 649 | |
| Investment funds | Investment funds | 27 | | | — | | | — | | | — | | | 27 | | Investment funds | 23 | | | — | | | — | | | — | | | 23 | |
| | $ | 208 | | | $ | 104 | | | $ | — | | | $ | (8) | | | $ | 304 | | | $ | 672 | | | $ | 318 | | | $ | — | | | $ | (119) | | | $ | 871 | |
| | Liabilities - Commodity derivatives | Liabilities - Commodity derivatives | $ | — | | | $ | (51) | | | $ | — | | | $ | 13 | | | $ | (38) | | Liabilities - Commodity derivatives | $ | — | | | $ | (48) | | | $ | — | | | $ | 41 | | | $ | (7) | |
(1)Represents netting under master netting arrangements and a net cash collateral payable of $64$12 million and a net cash collateral receivable of $5$78 million as of June 30, 2022March 31, 2023 and December 31, 2021,2022, respectively. As of December 31, 2022, PacifiCorp had an additional $12 million cash collateral payable that was not required to be netted against total derivatives.
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. A discounted cash flow valuation method was used to estimate fair value. 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 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | As of March 31, 2023 | | As of December 31, 2022 |
| | | Carrying | | Fair | | Carrying | | Fair |
| | | Value | | Value | | Value | | Value |
| | | | | | | | | |
| Long-term debt | | $ | 9,658 | | | $ | 9,350 | | | $ | 9,666 | | | $ | 9,045 | |
(9) Commitments and Contingencies
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Consolidated Balance Sheets.
Construction Commitments
During the six-month period ended June 30, 2022,In April 2023, PacifiCorp entered into a procurement and construction services agreement for $849 millionbuild transfer agreements totaling $1.2 billion through 20242025 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.certain wind-powered generating facilities in Wyoming.
Fuel Contracts
During the six-monththree-month period ended June 30, 2022,March 31, 2023, PacifiCorp entered into certain coal supply and transportation agreements totaling approximately$247 million through 2025.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, wildfire prevention and mitigation and other environmental matters that have the potential to impact its current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Lower Klamath Hydroelectric Project
In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility is anticipated to begin in 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has $450 million in funding available for dam removal and restoration; $200 million through 2024.collected from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $45 million contingency fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete.
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.
2020 Wildfires Overview
In September 2020,A provision for a severe weather event resulting in high winds, low humidityloss contingency is recorded when it is probable that a liability has been incurred and warm temperatures contributed to several major wildfires, realthe amount of loss can be reasonably estimated. PacifiCorp evaluates the related range of reasonably estimated losses and personal property and natural resource damage, personal injuries andrecords a loss based on its best estimate within that range or the lower end of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures 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.
Multiple 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.range if there is no better estimate.
In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires 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;damages; fire suppression costs; personal injury and loss of life damages; and interest.
During2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over 500,000 acres in aggregate. Third-party reports for these wildfires indicate over 2,000 structures 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 three-month period ended June 30, 2022,cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
As of the date of this filing, numerous lawsuits have been filed in Oregon and California, including a class action complaint in Oregon, on behalf of plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.
Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of litigation and recent settlements, PacifiCorp has accrued $64 million ofcumulative estimated probable losses net of expected insurance recoveries associated with the 2020 Wildfires resulting in an overall lossof $877 million through March 31, 2023. PacifiCorp's cumulative accrual net of expected insurance recoveries of $200 million as of June 30, 2022 compared to $136 million as of December 31, 2021. These accruals include PacifiCorp's estimateincludes estimates of losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life 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 certain areas of 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 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.
The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires (in millions):
| | | | | | | | | | | |
| |
| Three-Month Periods |
| Ended March 31, |
| 2023 | | 2022 |
| Beginning balance | $ | 424 | | | $ | 252 | |
| Accrued losses | 400 | | | — | |
| | | |
| Ending balance | $ | 824 | | | $ | 252 | |
PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $277$287 million and $246 million, respectively, as of June 30,March 31, 2023 and December 31, 2022. During the three-month periods ended March 31, 2023 and 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $359 million and $— million, respectively, and are recorded in operations and maintenance on the Consolidated Statements of Operations.
Environmental Laws and Regulations2022 McKinney Fire
PacifiCorpAccording to the California Department of Forestry and Fire Protection, on July 29, 2022, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and four fatalities and consumed 60,000 acres. The cause of the 2022 McKinney Fire is subject to federal, stateundetermined 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 haveremains under investigation by the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.U.S. Forest Service.
Hydroelectric Relicensing
Due to the preliminary nature of the investigation PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $31 million, net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp is unable to estimate the total potential loss, including losses for natural resource damages, because there are a partynumber of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intendedbe $103 million, 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.cover potential losses.
In September 2016,As of the KRRC and PacifiCorpdate of this filing, multiple lawsuits have been filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorpin California on behalf of plaintiffs related to the KRRC.2022 McKinney Fire. The FERC approved partial transferplaintiffs seek damages that include property damages, economic and noneconomic losses, punitive damages, exemplary damages, attorneys' fees and other damages but the amount of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp diddamages sought are not agree to remain co-licensee during the surrender and removal process given concerns aboutspecified. Final determinations of 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 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. 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. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property 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 only be effective within 30 daysmade following the issuancecompletion 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.comprehensive investigations and litigation processes.
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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Customer Revenue: | Customer Revenue: | | | | | | | | Customer Revenue: | | | | |
| Retail: | Retail: | | Retail: | | |
| Residential | Residential | $ | 417 | | | $ | 429 | | | $ | 922 | | | $ | 912 | | Residential | | $ | 585 | | | $ | 505 | |
| Commercial | Commercial | 393 | | | 393 | | | 763 | | | 752 | | Commercial | | 430 | | | 370 | |
| Industrial | Industrial | 277 | | | 282 | | | 550 | | | 553 | | Industrial | | 290 | | | 273 | |
| Other retail | Other retail | 80 | | | 84 | | | 117 | | | 116 | | Other retail | | 44 | | | 37 | |
| Total retail | Total retail | 1,167 | | | 1,188 | | | 2,352 | | | 2,333 | | Total retail | | 1,349 | | | 1,185 | |
Wholesale | Wholesale | 55 | | | 30 | | | 110 | | | 66 | | Wholesale | | 61 | | | 55 | |
| Transmission | Transmission | 45 | | | 37 | | | 77 | | | 62 | | Transmission | | 38 | | | 32 | |
| Other Customer Revenue | Other Customer Revenue | 28 | | | 31 | | | 48 | | | 54 | | Other Customer Revenue | | 32 | | | 20 | |
| Total Customer Revenue | Total Customer Revenue | 1,295 | | | 1,286 | | | 2,587 | | | 2,515 | | Total Customer Revenue | | 1,480 | | | 1,292 | |
| Other revenue | Other revenue | 19 | | | 12 | | | 24 | | | 25 | | Other revenue | | 4 | | | 5 | |
| Total operating revenue | Total operating revenue | $ | 1,314 | | | $ | 1,298 | | | $ | 2,611 | | | $ | 2,540 | | Total operating revenue | | $ | 1,484 | | | $ | 1,297 | |
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 SecondFirst Quarter of 2023 and First Six Months of 2022 and 2021
Overview
Net incomeloss for the secondfirst quarter of 20222023 was $82$120 million, a decrease of $143$250 million or 64%, compared to 2021. Net2022 net income decreasedof $130 million. The decrease in net income was primarily due to higherincreased operations and maintenance expense, of $120 million, lower income tax benefit of $11 million, higher property and other taxes of $8 million and higher other expense of $6 million, partially offset by higher utility margin of $6 million. Operations and maintenance expense increased primarilylargely due to an increase in the loss accruals, net of expected insurance recoveries, associated with the September 2020 wildfires, netWildfires of estimated insurance recoveries,$359 million, higher wildfire mitigation costs, including vegetation management and higher generalplant operations and plant maintenance costs.costs, partially offset by higher income tax benefit, higher utility margin and lower other expense. Utility margin increased primarily due to lower purchased electricity prices, higher retail rates,prices and volumes, higher net power cost deferrals, higher average wholesale market prices and lower thermalcoal-fueled generation volumes, partially offset by higher purchased electricity costs from higher prices and volumes, higher natural gas-fueled generation costs from higher prices and volumes, lower wholesale volumes and higher coal-fueled generation prices. Retail customer volumes increased 3.3% primarily due to favorable impacts of weather, an increase in the average number of customers and an increase in commercial and residential customer usage, partially offset by a decrease in industrial customer usage. Energy generated decreased 7% for the first quarter of 2023 compared to 2022 primarily due to lower coal-fueled, wind-powered and hydroelectric 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. Retail customer volumes 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. Energy generated decreased 7% for the second quarter of 2022 compared to 2021 primarily due to lower coal-fueled and natural gas-fueled generation, partially offset by higher wind-powered and hydroelectric generation.volumes. Wholesale electricity sales volumes were essentially flatdecreased 47% and purchased electricity volumes increased 12%.
Net income for the first six months of 2022 was $212 million, a decrease of $182 million, or 46%, compared to 2021 primarily due to higher operations and maintenance expense of $138 million, lower income tax benefit of $24 million, higher depreciation and amortization expense of $20 million and 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 September 2020 wildfires, net of estimated insurance recoveries, and higher general and plant maintenance costs. Utility margin increased primarily due to lower purchased electricity prices, higher retail rates, higher average wholesale market prices, lower thermal generation volumes, and higher wheeling revenue, partially offset by higher natural gas-fueled generation prices, higher purchased electricity volumes and lower retail volumes. Retail customer volumes decreased 0.7%, primarily due to the unfavorable impact of weather and lower customer usage, partially offset by an increase in the average number of customers. Energy generated decreased 4% for the first six months of 2022 compared to 2021 primarily due to lower coal-fueled and natural gas-fueled generation, partially offset by higher wind-powered and hydroelectric generation. Wholesale electricity sales volumes decreased 1% and purchased electricity volumes increased 9%28%.
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):
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Utility margin: | Utility margin: | | | | | | | | | | | | Utility margin: | | | | | | |
| Operating revenue | Operating revenue | $ | 1,314 | | | $ | 1,298 | | | $ | 16 | | | 1 | % | | $ | 2,611 | | | $ | 2,540 | | | $ | 71 | | | 3 | % | Operating revenue | $ | 1,484 | | | $ | 1,297 | | | $ | 187 | | | 14 | % | |
| Cost of fuel and energy | Cost of fuel and energy | 451 | | | 441 | | | 10 | | | 2 | | | 916 | | | 865 | | | 51 | | | 6 | | Cost of fuel and energy | 614 | | | 465 | | | 149 | | | 32 | | |
| Utility margin | Utility margin | 863 | | | 857 | | | 6 | | | 1 | | | 1,695 | | | 1,675 | | | 20 | | | 1 | | Utility margin | 870 | | | 832 | | | 38 | | | 5 | | |
| Operations and maintenance | Operations and maintenance | 375 | | | 255 | | | 120 | | | 47 | | | 652 | | | 514 | | | 138 | | | 27 | | Operations and maintenance | 705 | | | 277 | | | 428 | | | 155 | | |
| Depreciation and amortization | Depreciation and amortization | 279 | | | 275 | | | 4 | | | 1 | | | 559 | | | 539 | | | 20 | | | 4 | | Depreciation and amortization | 279 | | | 280 | | | (1) | | | — | | |
| Property and other taxes | Property and other taxes | 51 | | | 43 | | | 8 | | | 19 | | | 110 | | | 104 | | | 6 | | | 6 | | Property and other taxes | 53 | | | 59 | | | (6) | | | (10) | | |
| Operating income | $ | 158 | | | $ | 284 | | | $ | (126) | | | (44) | % | | $ | 374 | | | $ | 518 | | | $ | (144) | | | (28) | % | |
| Operating (loss) income | | Operating (loss) income | $ | (167) | | | $ | 216 | | | $ | (383) | | | (177) | % | |
Utility Margin
A comparison of key operating results related to utility margin is as follows:
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | Utility margin (in millions): | | | | | | |
| Operating revenue | Operating revenue | $ | 1,314 | | | $ | 1,298 | | | $ | 16 | | | 1 | % | | $ | 2,611 | | | $ | 2,540 | | | $ | 71 | | | 3 | % | Operating revenue | $ | 1,484 | | | $ | 1,297 | | | $ | 187 | | | 14 | % | |
| Cost of fuel and energy | Cost of fuel and energy | 451 | | | 441 | | | 10 | | | 2 | | | 916 | | | 865 | | | 51 | | | 6 | | Cost of fuel and energy | 614 | | | 465 | | | 149 | | | 32 | | |
| Utility margin | Utility margin | $ | 863 | | | $ | 857 | | | $ | 6 | | | 1 | % | | $ | 1,695 | | | $ | 1,675 | | | $ | 20 | | | 1 | % | Utility margin | $ | 870 | | | $ | 832 | | | $ | 38 | | | 5 | % | |
| | Sales (GWhs): | Sales (GWhs): | | Sales (GWhs): | | |
| Residential | Residential | 3,854 | | | 4,032 | | | (178) | | | (4) | % | | 8,618 | | | 8,664 | | | (46) | | | (1) | % | Residential | 5,102 | | | 4,764 | | | 338 | | | 7 | % | |
| Commercial | Commercial | 4,633 | | | 4,633 | | | — | | | — | | | 9,183 | | | 9,103 | | | 80 | | | 1 | | Commercial | 4,983 | | | 4,550 | | | 433 | | | 10 | | |
| Industrial, irrigation and other | Industrial, irrigation and other | 4,849 | | | 5,127 | | | (278) | | | (5) | | | 9,372 | | | 9,601 | | | (229) | | | (2) | | Industrial, irrigation and other | 4,209 | | | 4,523 | | | (314) | | | (7) | | |
| Total retail | Total retail | 13,336 | | | 13,792 | | | (456) | | | (3) | | | 27,173 | | | 27,368 | | | (195) | | | (1) | | Total retail | 14,294 | | | 13,837 | | | 457 | | | 3 | | |
| Wholesale | Wholesale | 1,245 | | | 1,244 | | | 1 | | | — | | | 2,798 | | | 2,835 | | | (37) | | | (1) | | Wholesale | 825 | | | 1,553 | | | (728) | | | (47) | | |
| Total sales | Total sales | 14,581 | | | 15,036 | | | (455) | | | (3) | % | | 29,971 | | | 30,203 | | | (232) | | | (1) | % | Total sales | 15,119 | | | 15,390 | | | (271) | | | (2) | % | |
| | Average number of retail customers
(in thousands) | Average number of retail customers
(in thousands) | 2,033 | | | 1,998 | | | 35 | | | 2 | % | | 2,029 | | | 1,994 | | | 35 | | | 2 | % | Average number of retail customers
(in thousands) | 2,057 | | | 2,025 | | | 32 | | | 2 | % | |
| | Average revenue per MWh: | Average revenue per MWh: | | Average revenue per MWh: | | |
| Retail | Retail | $ | 88.14 | | | $ | 86.26 | | | $ | 1.88 | | | 2 | % | | $ | 86.77 | | | $ | 85.21 | | | $ | 1.56 | | | 2 | % | Retail | $ | 93.82 | | | $ | 85.46 | | | $ | 8.36 | | | 10 | % | |
| Wholesale | Wholesale | $ | 51.53 | | | $ | 31.08 | | | $ | 20.45 | | | 66 | % | | $ | 44.64 | | | $ | 30.97 | | | $ | 13.67 | | | 44 | % | Wholesale | $ | 86.45 | | | $ | 39.12 | | | $ | 47.33 | | | 121 | % | |
| | Heating degree days | Heating degree days | 1,736 | | | 1,228 | | | 508 | | | 41 | % | | 6,481 | | | 5,915 | | | 566 | | | 10 | % | Heating degree days | 5,205 | | | 4,745 | | | 460 | | | 10 | % | |
| | Cooling degree days | Cooling degree days | 406 | | | 746 | | | (340) | | | (46) | % | | 411 | | | 746 | | | (335) | | | (45) | % | Cooling degree days | — | | | 5 | | | (5) | | | (100) | % | |
| Sources of energy (GWhs)(1): | Sources of energy (GWhs)(1): | | Sources of energy (GWhs)(1): | | |
| Coal | Coal | 6,260 | | | 7,502 | | | (1,242) | | | (17) | % | | 13,171 | | | 15,146 | | | (1,975) | | | (13) | % | Coal | 5,555 | | | 6,911 | | | (1,356) | | | (20) | % | |
| Natural gas | Natural gas | 2,747 | | | 3,223 | | | (476) | | | (15) | | | 5,862 | | | 6,288 | | | (426) | | | (7) | | Natural gas | 3,955 | | | 3,115 | | | 840 | | | 27 | | |
Wind(2) | Wind(2) | 1,817 | | | 1,383 | | | 434 | | | 31 | | | 4,209 | | | 3,121 | | | 1,088 | | | 35 | | Wind(2) | 2,083 | | | 2,392 | | | (309) | | | (13) | | |
Hydroelectric and other(2) | Hydroelectric and other(2) | 1,033 | | | 703 | | | 330 | | | 47 | | | 2,017 | | | 1,691 | | | 326 | | | 19 | | Hydroelectric and other(2) | 812 | | | 984 | | | (172) | | | (17) | | |
| Total energy generated | Total energy generated | 11,857 | | | 12,811 | | | (954) | | | (7) | | | 25,259 | | | 26,246 | | | (987) | | | (4) | | Total energy generated | 12,405 | | | 13,402 | | | (997) | | | (7) | | |
| Energy purchased | Energy purchased | 3,717 | | | 3,321 | | | 396 | | | 12 | | | 6,940 | | | 6,349 | | | 591 | | | 9 | | Energy purchased | 4,128 | | | 3,223 | | | 905 | | | 28 | | |
| Total | Total | 15,574 | | | 16,132 | | | (558) | | | (3) | % | | 32,199 | | | 32,595 | | | (396) | | | (1) | % | Total | 16,533 | | | 16,625 | | | (92) | | | (1) | % | |
| | Average cost of energy per MWh: | Average cost of energy per MWh: | | Average cost of energy per MWh: | | |
Energy generated(3) | Energy generated(3) | $ | 21.90 | | | $ | 17.84 | | | $ | 4.06 | | | 23 | % | | $ | 20.27 | | | $ | 17.75 | | | $ | 2.52 | | | 14 | % | Energy generated(3) | $ | 28.35 | | | $ | 18.83 | | | $ | 9.52 | | | 51 | % | |
| Energy purchased | Energy purchased | $ | 48.92 | | | $ | 65.62 | | | $ | (16.70) | | | (25) | % | | $ | 51.97 | | | $ | 56.80 | | | $ | (4.83) | | | (9) | % | Energy purchased | $ | 77.72 | | | $ | 55.49 | | | $ | 22.23 | | | 40 | % | |
(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 Renewable 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 June 30, 2022March 31, 2023 compared to Quarter Ended June 30, 2021March 31, 2022
Utility margin increased $6$38 million, or 1%5%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to:
•$36159 million increase in retail revenue due to higher average prices and higher volumes. Retail customer volumes increased 3.3% primarily due to favorable impacts of lower purchased electricity costs from lowerweather, mainly in Oregon, an increase in the average market prices,number of customers and an increase in commercial and residential customer usage, partially offset by higher purchased volumes;a decrease in industrial customer usage across all states except Idaho;
•$2597 million of higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms;
•$17 million of higher other revenue primarily due to higher wheeling revenue and higher revenues associated with sales of greenhouse gas allowances;
•$11 million increase in wholesale revenue primarily due to higher average market prices;prices, partially offset by lower volumes; and
•$229 million of lower coal-fueled generation costs primarily due to lower volumes; and
•$7 million of favorable wheeling activities.volumes, partially offset by higher average prices.
The increases above were partially offset by:
•$54142 million of higher purchased electricity costs from higher average market prices and higher volumes; and
•$109 million of higher natural gas-fueled generation costs due to higher average market prices partially offset by lower volumes;and higher 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.
Operations and maintenance increased $120$428 million or 47%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to a $64$359 million increase in the loss accruals, net of expected insurance recoveries, associated with the September 2020 wildfires netWildfires, $23 million of estimated insurance recoveries, $27higher wildfire mitigation costs, including vegetation management and amortization of amounts previously deferred in Oregon, $21 million of higher general and plant maintenance costs, higher insurance premiums due to cost increases related to wildfire coverage and$10 million of higher labor and employee expenses.
Depreciationbenefit expenses, and $8 million of higher demand-side management amortization increased $4 million, or 1%, for the second quarter of 2022 compared to 2021 primarily due to prior year deferralsexpense (offset 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.retail revenue).
Property and other taxes increased $8decreased $6 million, or 19%10%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to lower property tax rates in Utah.
Interest expense increased $18 million, or 17%, for the first quarter of 2023 compared to 2022 primarily due to higher assessed property values in Utahaverage long-term debt balances.
Allowance for borrowed and Wyoming.equity funds increased $21 million for the first quarter of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.
Interest and dividend income increased $12 million for the first quarter of 2023 compared to 2022 primarily due to higher investment income due to higher average interest rates and the recording of interest on higher deferred net power cost balances.
Other, net decreased $9increased $6 million for the secondfirst quarter of 20222023 compared to 20212022 primarily due to lowerhigher cash surrender valuevalues of corporate-ownedSupplemental Executive Retirement Plan life insurance policies associated with PacifiCorp's supplemental executive retirement plan.driven by market increases and a favorable change in deferred compensation and long-term incentive plan primarily due to market movements (offset in operations and maintenance expense).
Income tax benefit(benefit) expense decreased $11$112 million or 58%to a benefit of $110 million for the secondfirst quarter of 2023 compared to an expense of $2 million for the first quarter of 2022 compared to 2021. Theand the effective tax rate was (11)%48% for the second quarter of 20222023 and (9)%2% for the second quarter of 2021.2022. The effective$112 million decrease in income tax rate decreasedexpense to an income tax benefit is primarily due to the relative impactincrease in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires during the first quarter of 2023 and the release of a valuation allowance on a percentage basis of PTCs on the lower pre-tax book incomestate net operating loss carryforwards in the secondfirst quarter of 20222023 compared to thatthe establishment of 2021, which resultsa state valuation allowance 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:
•$37 million increase in wholesale revenue due to higher average market prices, partially offset by lower volumes;
•$34 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices;
•$26 million increase in retail revenue due to higher average prices, partially offset by lower volumes. Retail customer volumes 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 Oregon;
•$24 million of lower purchased electricity costs due to lower average market prices; and
•$15 million of favorable wheeling activities.
The increases above were partially offset by:
•$80 million of higher natural gas-fueled generation costs due to higher average prices, partially offset by lower volumes;
•$24 million of higher purchased electricity costs due to higher volumes;
•$5 million of lower deferred net power costs in accordance with established adjustment mechanisms; and
•$5 million of lower wind-based ancillary revenue.
Operations and maintenance increased $138 million, or 27%, for the first six months 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, $37 million of higher general and plant maintenance costs, higher insurance premiums due to cost increases related to wildfire coverage and higher bad debt expense.
Depreciation and amortization increased $20 million, or 4% for the first six months 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 year and higher plant in-service balances in the current year, 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 $6 million, or 6% for the first six months of 2022 compared to 2021 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 cash surrender value of corporate-owned life insurance policies associated with PacifiCorp's supplemental executive retirement plan.
Income tax benefit decreased $24 million, or 80% for the first six months of 2022 compared to the first six months of 2021. The effective tax rate was (3)% for the first six months of 2022 and (8)% for the first six months of 2021. The effective tax rate increased primarily due to a valuation allowance PacifiCorp recorded in the first quarter of 2022 against state net operating loss carryforwards.
Liquidity and Capital Resources
As of June 30, 2022,March 31, 2023, PacifiCorp's total net liquidity was as follows (in millions):
| | | | | | | | |
| Cash and cash equivalents | | $ | 39019 | |
| | | |
| Credit facilities | | 1,2002,000 | |
| Less: | | |
| | |
| Tax-exempt bond support and letters of credit | | (218)(249) | |
| Net credit facilities | | 9821,751 | |
| | | |
| Total net liquidity | | $ | 1,3721,770 | |
| | |
| Credit facilities: | | |
| Maturity dates | | 2024, 2025 | |
Operating Activities
Net cash flows from operating activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $1,213$339 million and $1,046$537 million, respectively. The change wasdecrease is primarily due to timing of operating payables, higher transmission deposits, cash received for income taxeswholesale and fuel purchases, collateral received fromreturned to counterparties and operations and maintenance expenses, partially offset by higher fuel and wholesale purchases.collections from retail customers.
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 made for each payment date.
Investing Activities
Net cash flows from investing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $(888)$(644) million and $(819)$(371) million, respectively. The change is primarily due to an increase in capital expenditures of $75$269 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the six-monththree-month period ended June 30, 2022March 31, 2023, were $(111)$(311) million. Uses of cash consisted primarily of $100$300 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-monththree-month period ended June 30, 2021March 31, 2022, were $(196)$(11) million. Sources of cash consisted of $208 million from the borrowing of short-term debt. Uses of cash consisted substantially of $400$9 million for the repayment of long-term debt.
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5$2.0 billion of short-term debt. As of June 30, 2022March 31, 2023, and December 31, 2021,2022, PacifiCorp had no short-term debt outstanding.
Debt Authorizations
PacifiCorp currently has regulatory authority from the OPUC and the Idaho Public Utilities Commission to issue an additional $2$5 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 Shareholders' Equity
In May 2022,January 2023, PacifiCorp declared a common stock dividend of $100$300 million, paid in June 2022,February 2023, 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'customer rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings;proceedings, including regulatory filings for Certificates of Public Convenience and Necessity; changes in income tax laws; general business conditions; new customer requests; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
HistoricalPacifiCorp's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | Six-Month Periods | | Annual | | Three-Month Periods | | Annual |
| | Ended June 30, | | Forecast | | Ended March 31, | | Forecast |
| | 2021 | | 2022 | | 2022 | | 2022 | | 2023 | | 2023 |
| | Wind generation | Wind generation | $ | 82 | | | $ | 14 | | | $ | 66 | | Wind generation | $ | 8 | | | $ | 17 | | | $ | 833 | |
| Electric distribution | Electric distribution | 326 | | | 303 | | | 682 | | Electric distribution | 139 | | | 177 | | | 781 | |
| Electric transmission | Electric transmission | 136 | | | 405 | | | 1,185 | | Electric transmission | 156 | | | 169 | | | 1,484 | |
| Solar generation | | Solar generation | — | | | — | | | 19 | |
| Electric battery and pumped hydro storage | | Electric battery and pumped hydro storage | 1 | | | 1 | | | 24 | |
| Other | Other | 275 | | | 172 | | | 346 | | Other | 70 | | | 279 | | | 521 | |
| Total | Total | $ | 819 | | | $ | 894 | | | $ | 2,279 | | Total | $ | 374 | | | $ | 643 | | | $ | 3,662 | |
PacifiCorp's 2021 IRP identified a roadmapPacifiCorp has included estimates for a significant increase innew renewable and carbon free generation resources, coal to natural gas conversion of certain coal-fueled units to natural gas-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 resourcesassets and associated transmission assets in its forecast capital expenditures for 2022 through 2024.based on its 2021 IRP. These estimates are likely to change as a result of the associated 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 $4 million and $79 million for the six-month periods ended June 30, 2022 and 2021, respectively. Construction includes 516 MWsinclude construction of new wind-powered generating facilities that were placed in-service in 2021.and construction at existing wind-powered generating facility sites acquired from third parties totaling $14 million and $6 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $24$807 million for the remainder of 2022.
◦Planned acquisition2023 and repowering of two wind-powered generating facilities by PacifiCorp totaling $7 million and $2 million (excluding the 2021 sale of wind turbines)is primarily for the six-month periods ended June 30, 2022Rock Creek I and 2021, respectively. In 2021, PacifiCorp sold wind turbines previously acquired from a third partyRock Creek II projects to BHE Wind, LLC, an indirect wholly owned subsidiary of BHE, for $6 million. The repowered facilitiesbe constructed in Wyoming totaling 590 MWs that are expected to be placed in-service in 20232024 and 2024. Planned spending for acquiring and repowering generating facilities totals $14 million for the remainder of 2022.2025.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes spend on wildfire mitigation and wildfire and storm damage restoration.mitigation. Expenditures for these itemswildfire mitigation totaled $59$33 million and $117$22 million for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, respectively. Planned spending for wildfire mitigation and wildfire and storm damage restoration totals $97$162 million for the remainder of 2022. Remaining2023. The remaining investments primarily relate to expenditures for new connections and distribution operations.
•Electric transmission includes both growth projects and operating expenditures. Transmission investmentgrowth investments primarily reflects plannedreflect costs for the 416-mile, 500-kV high-voltage transmission line 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, Oregonassociated with Energy Gateway Transmission segments that are expected to the Hemingway substation near Boise, Idaho.be placed in-service in 2024 through 2028. Expenditures for these segmentsprojects totaled $296$110 million and $35$96 million for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, respectively. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $614$898 million for the remainder of 2022.2023.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $77$46 million and $47$45 million for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, respectively. Planned information technology spending totals $87$180 million for the remainder of 2022. Remaining2023. The 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. AcknowledgementAcknowledgment 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 and subsequently filed its 2021 IRP Update 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 natural 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 by the Wyoming Public Service Commission and the WUTC and the Idaho Public Utilities Commission are ongoing.
In March 2023, PacifiCorp filed its 2023 IRP in Idaho, Oregon and Wyoming. A 60-day post-filing extended comment period has been added to the 2023 IRP to provide opportunity for additional stakeholder feedback. PacifiCorp will consider feedback during the first 30 days and then prepare an addendum, if warranted, to the filed IRP on May 30, 2023.
The 2023 IRP is off cycle with regard to Washington's four-year IRP cycle and has instead been filed in that state as the "Washington Two-Year Progress Report," aligned with the Clean Energy Transformation Act requirements. The March 2023 filing is considered informational in Utah, pending the potential addendum to be filed in May 2023.
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.
A 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 2022ASAll-Source RFP was issued to market in April 2022. PacifiCorp-ownedIn December 2022, PacifiCorp bid 12 eligible self-build (benchmark) resources and in March 2023, PacifiCorp received 302 bids are due late November 2022from 74 developers and market bids are due February93 different projects sites across six states. A final shortlist is expected later in 2023 with resources contracted by December 2023. PacifiCorp anticipates a similar all-source RFP will be required in connection with the 2023 IRP.
Material Cash Requirements
As of June 30, 2022,March 31, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2021,2022, 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 air quality, climate change, wildfire prevention and mitigation, RPS, air and water quality, emissions performance standards, water quality, coal combustion byproductash 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, pension and other postretirement benefits, income taxes, and revenue recognition-unbilled revenue.revenue and wildfire loss contingencies. 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, 2021.2022. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2021.2022.
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 June 30, 2022,March 31, 2023, the related statements of operations, and changes in shareholder's equity, for the three-month and six-month periods ended June 30, 2022 and 2021, and of cash flows for the six-monththree-month periods ended June 30,March 31, 2023 and 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 balance sheet of MidAmerican Energy as of December 31, 2021,2022, 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 25, 2022,24, 2023, 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, 2021,2022, 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
AugustMay 5, 20222023
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | As of | | As of |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 495 | | | $ | 232 | | Cash and cash equivalents | $ | 57 | | | $ | 258 | |
| Trade receivables, net | Trade receivables, net | 525 | | | 526 | | Trade receivables, net | 387 | | | 536 | |
| Income tax receivable | Income tax receivable | 19 | | | 79 | | Income tax receivable | 275 | | | 42 | |
| Inventories | Inventories | 226 | | | 234 | | Inventories | 280 | | | 277 | |
| Prepayments | | Prepayments | 123 | | | 91 | |
| Other current assets | Other current assets | 186 | | | 123 | | Other current assets | 36 | | | 66 | |
| Total current assets | Total current assets | 1,451 | | | 1,194 | | Total current assets | 1,158 | | | 1,270 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 20,504 | | | 20,301 | | Property, plant and equipment, net | 20,981 | | | 21,091 | |
| Regulatory assets | Regulatory assets | 509 | | | 473 | | Regulatory assets | 571 | | | 550 | |
| Investments and restricted investments | Investments and restricted investments | 893 | | | 1,026 | | Investments and restricted investments | 942 | | | 902 | |
| Other assets | Other assets | 278 | | | 263 | | Other assets | 155 | | | 165 | |
| | Total assets | Total assets | $ | 23,635 | | | $ | 23,257 | | Total assets | $ | 23,807 | | | $ | 23,978 | |
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 |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| 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 | $ | 415 | | | $ | 531 | | Accounts payable | $ | 395 | | | $ | 536 | |
| Accrued interest | Accrued interest | 84 | | | 84 | | Accrued interest | 88 | | | 85 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 206 | | | 158 | | Accrued property, income and other taxes | 142 | | | 170 | |
| | Current portion of long-term debt | Current portion of long-term debt | 64 | | | — | | Current portion of long-term debt | 310 | | | 317 | |
| Other current liabilities | Other current liabilities | 181 | | | 145 | | Other current liabilities | 106 | | | 93 | |
| Total current liabilities | Total current liabilities | 950 | | | 918 | | Total current liabilities | 1,041 | | | 1,201 | |
| | Long-term debt | Long-term debt | 7,661 | | | 7,721 | | Long-term debt | 7,412 | | | 7,412 | |
| Regulatory liabilities | Regulatory liabilities | 1,026 | | | 1,080 | | Regulatory liabilities | 836 | | | 1,119 | |
| Deferred income taxes | Deferred income taxes | 3,413 | | | 3,389 | | Deferred income taxes | 3,452 | | | 3,433 | |
| Asset retirement obligations | Asset retirement obligations | 698 | | | 714 | | Asset retirement obligations | 778 | | | 683 | |
| Other long-term liabilities | Other long-term liabilities | 476 | | | 475 | | Other long-term liabilities | 500 | | | 485 | |
| Total liabilities | Total liabilities | 14,224 | | | 14,297 | | Total liabilities | 14,019 | | | 14,333 | |
| | Commitments and contingencies (Note 8) | Commitments and contingencies (Note 8) | 0 | | 0 | Commitments and contingencies (Note 8) | |
| | 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 | 8,850 | | | 8,399 | | Retained earnings | 9,227 | | | 9,084 | |
| | Total shareholder's equity | Total shareholder's equity | 9,411 | | | 8,960 | | Total shareholder's equity | 9,788 | | | 9,645 | |
| | Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 23,635 | | | $ | 23,257 | | Total liabilities and shareholder's equity | $ | 23,807 | | | $ | 23,978 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | |
| Regulated electric | Regulated electric | $ | 725 | | | $ | 586 | | | $ | 1,333 | | | $ | 1,131 | | Regulated electric | | $ | 591 | | | $ | 608 | |
| Regulated natural gas and other | Regulated natural gas and other | 172 | | | 107 | | | 569 | | | 629 | | Regulated natural gas and other | | 329 | | | 397 | |
| Total operating revenue | Total operating revenue | 897 | | | 693 | | | 1,902 | | | 1,760 | | Total operating revenue | | 920 | | | 1,005 | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | | |
| Cost of fuel and energy | Cost of fuel and energy | 174 | | | 103 | | | 299 | | | 254 | | Cost of fuel and energy | | 115 | | | 125 | |
| Cost of natural gas purchased for resale and other | Cost of natural gas purchased for resale and other | 120 | | | 57 | | | 418 | | | 489 | | Cost of natural gas purchased for resale and other | | 236 | | | 298 | |
| Operations and maintenance | Operations and maintenance | 200 | | | 184 | | | 392 | | | 377 | | Operations and maintenance | | 205 | | | 192 | |
| Depreciation and amortization | Depreciation and amortization | 277 | | | 209 | | | 527 | | | 416 | | Depreciation and amortization | | 234 | | | 250 | |
| Property and other taxes | Property and other taxes | 36 | | | 37 | | | 76 | | | 73 | | Property and other taxes | | 42 | | | 40 | |
| Total operating expenses | Total operating expenses | 807 | | | 590 | | | 1,712 | | | 1,609 | | Total operating expenses | | 832 | | | 905 | |
| | Operating income | Operating income | 90 | | | 103 | | | 190 | | | 151 | | Operating income | | 88 | | | 100 | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | | |
| Interest expense | Interest expense | (78) | | | (74) | | | (156) | | | (148) | | Interest expense | | (80) | | | (78) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 5 | | | 2 | | | 9 | | | 4 | | Allowance for borrowed funds | | 4 | | | 4 | |
| Allowance for equity funds | Allowance for equity funds | 14 | | | 8 | | | 29 | | | 14 | | Allowance for equity funds | | 11 | | | 15 | |
| Other, net | Other, net | (12) | | | 15 | | | (15) | | | 26 | | Other, net | | 16 | | | (3) | |
| Total other income (expense) | Total other income (expense) | (71) | | | (49) | | | (133) | | | (104) | | Total other income (expense) | | (49) | | | (62) | |
| | Income before income tax benefit | 19 | | | 54 | | | 57 | | | 47 | | |
| Income tax benefit | (188) | | | (159) | | | (394) | | | (313) | | |
| Income before income tax expense (benefit) | | Income before income tax expense (benefit) | | 39 | | | 38 | |
| Income tax expense (benefit) | | Income tax expense (benefit) | | (203) | | | (206) | |
| | Net income | Net income | $ | 207 | | | $ | 213 | | | $ | 451 | | | $ | 360 | | Net income | | $ | 242 | | | $ | 244 | |
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, March 31, 2021 | $ | — | | | $ | 561 | | | $ | 7,651 | | | $ | 8,212 | | |
| Net income | — | | | — | | | 213 | | | 213 | | |
| Other equity transactions | — | | | — | | | 1 | | | 1 | | |
| Balance, June 30, 2021 | $ | — | | | $ | 561 | | | $ | 7,865 | | | $ | 8,426 | | |
| | Balance, December 31, 2020 | $ | — | | | $ | 561 | | | $ | 7,504 | | | $ | 8,065 | | |
| Net income | — | | | — | | | 360 | | | 360 | | |
| Other equity transactions | — | | | — | | | 1 | | | 1 | | |
| Balance, June 30, 2021 | $ | — | | | $ | 561 | | | $ | 7,865 | | | $ | 8,426 | | |
| | Balance, March 31, 2022 | $ | — | | | $ | 561 | | | $ | 8,643 | | | $ | 9,204 | | |
| Net income | — | | | — | | | 207 | | | 207 | | |
| | Balance, June 30, 2022 | $ | — | | | $ | 561 | | | $ | 8,850 | | | $ | 9,411 | | |
| | | Balance, December 31, 2021 | Balance, December 31, 2021 | $ | — | | | $ | 561 | | | $ | 8,399 | | | $ | 8,960 | | Balance, December 31, 2021 | $ | — | | | $ | 561 | | | $ | 8,399 | | | $ | 8,960 | |
| Net income | Net income | — | | | — | | | 451 | | | 451 | | Net income | — | | | — | | | 244 | | | 244 | |
| | Balance, June 30, 2022 | $ | — | | | $ | 561 | | | $ | 8,850 | | | $ | 9,411 | | |
| Balance, March 31, 2022 | | Balance, March 31, 2022 | $ | — | | | $ | 561 | | | $ | 8,643 | | | $ | 9,204 | |
| | | Balance, December 31, 2022 | | Balance, December 31, 2022 | $ | — | | | $ | 561 | | | $ | 9,084 | | | $ | 9,645 | |
| Net income | | Net income | — | | | — | | | 242 | | | 242 | |
| Common stock dividend | | Common stock dividend | — | | | — | | | (100) | | | (100) | |
| Other equity transactions | | Other equity transactions | — | | | — | | | 1 | | | 1 | |
| Balance, March 31, 2023 | | Balance, March 31, 2023 | $ | — | | | $ | 561 | | | $ | 9,227 | | | $ | 9,788 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | Six-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended March 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 451 | | | $ | 360 | | Net income | $ | 242 | | | $ | 244 | |
| 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 | 527 | | | 416 | | Depreciation and amortization | 234 | | | 250 | |
| Amortization of utility plant to other operating expenses | Amortization of utility plant to other operating expenses | 19 | | | 17�� | | Amortization of utility plant to other operating expenses | 8 | | | 9 | |
| Allowance for equity funds | Allowance for equity funds | (29) | | | (14) | | Allowance for equity funds | (11) | | | (15) | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 58 | | | 196 | | Deferred income taxes and investment tax credits, net | 32 | | | 16 | |
| Settlements of asset retirement obligations | Settlements of asset retirement obligations | (28) | | | (19) | | Settlements of asset retirement obligations | (6) | | | (7) | |
| Other, net | Other, net | 33 | | | 11 | | Other, net | 8 | | | 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 | 2 | | | (275) | | Trade receivables and other assets | 131 | | | 42 | |
| Inventories | Inventories | 8 | | | 41 | | Inventories | (3) | | | 49 | |
| | Pension and other postretirement benefit plans | | Pension and other postretirement benefit plans | (3) | | | 3 | |
| Accrued property, income and other taxes, net | Accrued property, income and other taxes, net | 94 | | | 56 | | Accrued property, income and other taxes, net | (263) | | | (244) | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | (10) | | | (68) | | Accounts payable and other liabilities | (81) | | | 3 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 1,125 | | | 721 | | Net cash flows from operating activities | 288 | | | 360 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (862) | | | (720) | | Capital expenditures | (382) | | | (459) | |
| Purchases of marketable securities | Purchases of marketable securities | (214) | | | (109) | | Purchases of marketable securities | (48) | | | (105) | |
| Proceeds from sales of marketable securities | Proceeds from sales of marketable securities | 210 | | | 105 | | Proceeds from sales of marketable securities | 42 | | | 102 | |
| Other, net | Other, net | 6 | | | (2) | | Other, net | 4 | | | 1 | |
| Net cash flows from investing activities | Net cash flows from investing activities | (860) | | | (726) | | Net cash flows from investing activities | (384) | | | (461) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| Common stock dividend | | Common stock dividend | (100) | | | — | |
| | Repayments of long-term debt | | Repayments of long-term debt | (7) | | | (1) | |
| | Other, net | Other, net | (1) | | | (2) | | Other, net | (1) | | | 1 | |
| Net cash flows from financing activities | Net cash flows from financing activities | (1) | | | (2) | | Net cash flows from financing activities | (108) | | | — | |
| | 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 | 264 | | | (7) | | Net change in cash and cash equivalents and restricted cash and cash equivalents | (204) | | | (101) | |
| 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 | 239 | | | 45 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 268 | | | 239 | |
| 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 | $ | 503 | | | $ | 38 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 64 | | | $ | 138 | |
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 June 30, 2022,March 31, 2023, and for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The results of operations for the three- and six-month periodsthree-month period ended June 30, 2022,March 31, 2023, 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, 2021,2022, 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 accounting policies or its assumptions regarding significant accounting estimates and policies during the six-monththree-month period ended June 30, 2022.March 31, 2023.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.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 restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented inon 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 |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| | Cash and cash equivalents | Cash and cash equivalents | $ | 495 | | | $ | 232 | | Cash and cash equivalents | $ | 57 | | | $ | 258 | |
| Restricted cash and cash equivalents in other current assets | Restricted cash and cash equivalents in other current assets | 8 | | | 7 | | Restricted cash and cash equivalents in other current assets | 7 | | | 10 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 503 | | | $ | 239 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 64 | | | $ | 268 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | As of | | As of |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | Depreciable Life | | 2022 | | 2021 | | Depreciable Life | | 2023 | | 2022 |
| Utility plant in-service, net: | | | | | | |
| Utility plant: | | Utility plant: | | | | | |
| Generation | Generation | 20-70 years | | $ | 17,737 | | | $ | 17,397 | | Generation | 20-62 years | | $ | 18,385 | | | $ | 18,582 | |
| Transmission | Transmission | 52-75 years | | 2,583 | | | 2,474 | | Transmission | 55-80 years | | 2,672 | | | 2,662 | |
| Electric distribution | Electric distribution | 20-75 years | | 4,725 | | | 4,661 | | Electric distribution | 15-80 years | | 4,983 | | | 4,931 | |
| Natural gas distribution | Natural gas distribution | 29-75 years | | 2,049 | | | 2,039 | | Natural gas distribution | 30-75 years | | 2,166 | | | 2,144 | |
| Utility plant in-service | Utility plant in-service | | 27,094 | | | 26,571 | | Utility plant in-service | | 28,206 | | | 28,319 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (7,658) | | | (7,376) | | Accumulated depreciation and amortization | | (8,210) | | | (8,024) | |
| Utility plant in-service, net | Utility plant in-service, net | | 19,436 | | | 19,195 | | Utility plant in-service, net | | 19,996 | | | 20,295 | |
| Nonregulated property, net: | | | | | |
| Nonregulated property, gross | 20-50 years | | 7 | | | 7 | | |
| Accumulated depreciation and amortization | | (1) | | | (1) | | |
| Nonregulated property, net | | 6 | | | 6 | | |
| | Nonregulated property, net of accumulated depreciation and amortization | | Nonregulated property, net of accumulated depreciation and amortization | 20-50 years | | 6 | | | 6 | |
| | 19,442 | | | 19,201 | | | 20,002 | | | 20,301 | |
| Construction work-in-progress | Construction work-in-progress | | 1,062 | | | 1,100 | | Construction work-in-progress | | 979 | | | 790 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 20,504 | | | $ | 20,301 | | Property, plant and equipment, net | | $ | 20,981 | | | $ | 21,091 | |
Under a revenue sharing arrangement in Iowa, MidAmerican Energy accrues throughout the year a regulatory liability based on the extent to which its anticipated annual equity return exceeds specified thresholds, with an equal amount recorded in depreciation and amortization expense. The annual regulatory liability accrual reduces utility plant upon final determination of the amount. For the three-month periods ended March 31, 2023 and 2022, $20 million and $42 million, respectively, is reflected in depreciation and amortization expense on the Statement of Operations.
(4) Recent Financing Transactions
Credit Facilities
In June 2022, MidAmerican Energy amended and restated its existing $1.5 billion unsecured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from the London Interbank Offered Rate to the Secured Overnight Financing Rate.
(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 benefitexpense (benefit) is as follows:
| | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | | 21 | % | | 21 | % |
| Income tax credits | Income tax credits | (973) | | | (271) | | | (682) | | | (634) | | Income tax credits | | (518) | | | (534) | |
| State income tax, net of federal income tax impacts | State income tax, net of federal income tax impacts | (26) | | | (31) | | | (23) | | | (32) | | State income tax, net of federal income tax impacts | | (18) | | | (21) | |
| Effects of ratemaking | Effects of ratemaking | (11) | | | (15) | | | (9) | | | (21) | | Effects of ratemaking | | (8) | | | (8) | |
| Other, net | Other, net | — | | | 2 | | | 2 | | | — | | Other, net | | 2 | | | — | |
| Effective income tax rate | Effective income tax rate | (989) | % | | (294) | % | | (691) | % | | (666) | % | Effective income tax rate | | (521) | % | | (542) | % |
Income tax credits relate primarily to production tax credits ("PTCs"PTC") from MidAmerican Energy's wind-poweredwind- and solar-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-poweredwind- and solar-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-poweredWind- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 totaled $388$202 million and $297$203 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its U.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. MidAmerican Energy receivedmade net cash payments for income tax fromto BHE totaling $541$1 million and $558$— million for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, respectively.
(6)(5) 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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Pension: | Pension: | | | | | | | | Pension: | | | | |
| Service cost | Service cost | $ | 4 | | | $ | 5 | | | $ | 9 | | | $ | 10 | | Service cost | | $ | 3 | | | $ | 5 | |
| Interest cost | Interest cost | 5 | | | 5 | | | 10 | | | 11 | | Interest cost | | 8 | | | 5 | |
| Expected return on plan assets | Expected return on plan assets | (7) | | | (10) | | | (14) | | | (19) | | Expected return on plan assets | | (8) | | | (7) | |
| Settlement | Settlement | — | | | — | | | 2 | | | — | | Settlement | | (5) | | | 2 | |
| Net amortization | 1 | | | 1 | | | 1 | | | 1 | | |
| Net periodic benefit cost | $ | 3 | | | $ | 1 | | | $ | 8 | | | $ | 3 | | |
| | Net periodic benefit cost (credit) | | Net periodic benefit cost (credit) | | $ | (2) | | | $ | 5 | |
| | Other postretirement: | Other postretirement: | | Other postretirement: | | |
| Service cost | Service cost | $ | 2 | | | $ | 2 | | | $ | 4 | | | $ | 4 | | Service cost | | $ | 1 | | | $ | 2 | |
| Interest cost | Interest cost | 2 | | | 2 | | | 4 | | | 4 | | Interest cost | | 3 | | | 2 | |
| Expected return on plan assets | Expected return on plan assets | (3) | | | (3) | | | (7) | | | (5) | | Expected return on plan assets | | (4) | | | (4) | |
| Net amortization | (1) | | | (1) | | | (1) | | | (2) | | |
| Net periodic benefit cost | $ | — | | | $ | — | | | $ | — | | | $ | 1 | | |
| | Net periodic benefit cost (credit) | | Net periodic benefit cost (credit) | | $ | — | | | $ | — | |
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 during 2023 are expected to be $7 million and $3$2 million, respectively, during 2022.respectively. As of June 30, 2022, $4March 31, 2023, $2 million and $2$1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.
(6) Asset Retirement Obligations
MidAmerican Energy estimates its asset retirement obligation ("ARO") liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of expected work. During the three-month period ended March 31, 2023, MidAmerican Energy recorded an increase of $88 million for decommissioning its wind-generating facilities due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.
(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 | | | 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 June 30, 2022: | | | | | | | | | | | |
| As of March 31, 2023: | | As of March 31, 2023: | | | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | | $ | 1 | | | $ | 66 | | | $ | 28 | | | $ | (22) | | | $ | 73 | | Commodity derivatives | | $ | 2 | | | $ | 7 | | | $ | — | | | $ | (5) | | | $ | 4 | |
| Money market mutual funds | Money market mutual funds | | 498 | | | — | | | — | | | — | | | 498 | | Money market mutual funds | | 67 | | | — | | | — | | | — | | | 67 | |
| Debt securities: | Debt securities: | | Debt securities: | |
| U.S. government obligations | U.S. government obligations | | 220 | | | — | | | — | | | — | | | 220 | | U.S. government obligations | | 225 | | | — | | | — | | | — | | | 225 | |
| International government obligations | International government obligations | | — | | | 1 | | | — | | | — | | | 1 | | International government obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Corporate obligations | Corporate obligations | | — | | | 75 | | | — | | | — | | | 75 | | Corporate obligations | | — | | | 70 | | | — | | | — | | | 70 | |
| Municipal obligations | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | | Municipal obligations | | — | | | 4 | | | — | | | — | | | 4 | |
| Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | | |
| | Equity securities: | Equity securities: | | Equity securities: | |
| U.S. companies | U.S. companies | | 348 | | | — | | | — | | | — | | | 348 | | U.S. companies | | 385 | | | — | | | — | | | — | | | 385 | |
| International companies | International companies | | 8 | | | — | | | — | | | — | | | 8 | | International companies | | 8 | | | — | | | — | | | — | | | 8 | |
| Investment funds | Investment funds | | 21 | | | — | | | — | | | — | | | 21 | | Investment funds | | 22 | | | — | | | — | | | — | | | 22 | |
| | $ | 1,096 | | | $ | 146 | | | $ | 28 | | | $ | (22) | | | $ | 1,248 | | | $ | 709 | | | $ | 82 | | | $ | — | | | $ | (5) | | | $ | 786 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | | $ | (1) | | | $ | (10) | | | $ | (2) | | | $ | 7 | | | $ | (6) | | Liabilities - commodity derivatives | | $ | — | | | $ | (10) | | | $ | (5) | | | $ | 10 | | | $ | (5) | |
| | | 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, 2021: | | | | | | | | | | | |
| As of December 31, 2022: | | As of December 31, 2022: | | | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | | $ | — | | | $ | 32 | | | $ | 3 | | | $ | (7) | | | $ | 28 | | Commodity derivatives | | $ | 1 | | | $ | 37 | | | $ | 6 | | | $ | (10) | | | $ | 34 | |
| Money market mutual funds | Money market mutual funds | | 228 | | | — | | | — | | | — | | | 228 | | Money market mutual funds | | 225 | | | — | | | — | | | — | | | 225 | |
| Debt securities: | Debt securities: | | Debt securities: | |
| U.S. government obligations | U.S. government obligations | | 232 | | | — | | | — | | | — | | | 232 | | U.S. government obligations | | 215 | | | — | | | — | | | — | | | 215 | |
| International government obligations | International government obligations | | — | | | 2 | | | — | | | — | | | 2 | | International government obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Corporate obligations | Corporate obligations | | — | | | 90 | | | — | | | — | | | 90 | | Corporate obligations | | — | | | 70 | | | — | | | — | | | 70 | |
| Municipal obligations | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | | Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
| Agency, asset and mortgage-backed obligations | Agency, asset and mortgage-backed obligations | | — | | | 2 | | | — | | | — | | | 2 | | Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | |
| Equity securities: | Equity securities: | | Equity securities: | |
| U.S. companies | U.S. companies | | 428 | | | — | | | — | | | — | | | 428 | | U.S. companies | | 360 | | | — | | | — | | | — | | | 360 | |
| International companies | International companies | | 10 | | | — | | | — | | | — | | | 10 | | International companies | | 8 | | | — | | | — | | | — | | | 8 | |
| Investment funds | Investment funds | | 18 | | | — | | | — | | | — | | | 18 | | Investment funds | | 16 | | | — | | | — | | | — | | | 16 | |
| | $ | 916 | | | $ | 129 | | | $ | 3 | | | $ | (7) | | | $ | 1,041 | | | $ | 825 | | | $ | 112 | | | $ | 6 | | | $ | (10) | | | $ | 933 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | | $ | — | | | $ | (6) | | | $ | (8) | | | $ | 12 | | | $ | (2) | | Liabilities - commodity derivatives | | $ | — | | | $ | (12) | | | $ | (1) | | | $ | 10 | | | $ | (3) | |
(1)Represents netting under master netting arrangements and a net cash collateral payable of $15 million as of June 30, 2022 and a net cash collateral receivable of $5 million and $— million as of March 31, 2023 and December 31, 2021.2022, respectively.
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 | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| | Beginning balance | Beginning balance | $ | 4 | | | $ | 1 | | | $ | (5) | | | $ | 2 | | Beginning balance | | $ | 5 | | | $ | (5) | |
| Changes in fair value recognized in regulatory assets | 31 | | | — | | | 44 | | | — | | |
| Changes in fair value recognized in net regulatory assets | | Changes in fair value recognized in net regulatory assets | | (13) | | | 13 | |
| Settlements | Settlements | (9) | | | (2) | | | (13) | | | (3) | | Settlements | | 3 | | | (4) | |
| Ending balance | Ending balance | $ | 26 | | | $ | (1) | | | $ | 26 | | | $ | (1) | | Ending balance | | $ | (5) | | | $ | 4 | |
MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 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 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of March 31, 2023 | | As of December 31, 2022 |
| Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value |
| | | | | | | |
| Long-term debt | $ | 7,722 | | | $ | 7,127 | | | $ | 7,729 | | | $ | 6,964 | |
(8) Commitments and Contingencies
Commitments
MidAmerican Energy has the following firm commitments that are not reflected on the Balance Sheets.
Construction Commitments
During the three-month period ended March 31, 2023, MidAmerican Energy entered into firm construction commitments totaling $183 million for the remainder of 2023 through 2024 related to the construction of wind-powered generating facilities in Iowa.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal 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.
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 formula rates approved by the 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% ROEbase return on equity ("ROE") used to determine rates in effect prior to September 2016 no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively.ROE. In September 2016,August 2022, the FERCU.S. Court of Appeals for the District of Columbia Circuit 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 relativeopinion vacating all orders related to the first complaint occurred in February 2017. In November 2019, the FERC issued an order addressing the second complaintcomplaints 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 2016remanding them back to the date of the May 2020 order. These orders continue to be subject to judicial appeal.FERC. MidAmerican Energy cannot predict the ultimate outcome of these matters or the amount of refunds, if any, and as of June 30, 2022,accordingly, has reversed its previously accrued an $8 million liability for potential refunds of amounts collected under the higher ROE during the periods covered by boththe complaints.
(9) Revenue from Contracts with Customers
The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 1011 (in millions):
| | | For the Three-Month Period Ended June 30, 2022 | | For the Six-Month Period Ended June 30, 2022 | | | For the Three-Month Period Ended March 31, 2023 |
| | 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 | $ | 185 | | | $ | 87 | | | $ | — | | | $ | 272 | | | $ | 353 | | | $ | 312 | | | $ | — | | | $ | 665 | | Residential | | $ | 167 | | | $ | 199 | | | $ | — | | | $ | 366 | |
| Commercial | Commercial | 91 | | | 31 | | | — | | | 122 | | | 165 | | | 119 | | | — | | | 284 | | Commercial | | 75 | | | 78 | | | — | | | 153 | |
| Industrial | Industrial | 277 | | | 9 | | | — | | | 286 | | | 475 | | | 18 | | | — | | | 493 | | Industrial | | 214 | | | 7 | | | — | | | 221 | |
| Natural gas transportation services | Natural gas transportation services | — | | | 9 | | | — | | | 9 | | | — | | | 23 | | | — | | | 23 | | Natural gas transportation services | | — | | | 13 | | | — | | | 13 | |
Other retail(1) | Other retail(1) | 41 | | | — | | | — | | | 41 | | | 73 | | | 1 | | | — | | | 74 | | Other retail(1) | | 35 | | | (1) | | | — | | | 34 | |
| Total retail | Total retail | 594 | | | 136 | | | — | | | 730 | | | 1,066 | | | 473 | | | — | | | 1,539 | | Total retail | | 491 | | | 296 | | | — | | | 787 | |
| Wholesale | Wholesale | 84 | | | 34 | | | — | | | 118 | | | 188 | | | 92 | | | — | | | 280 | | Wholesale | | 71 | | | 29 | | | — | | | 100 | |
| Multi-value transmission projects | Multi-value transmission projects | 13 | | | — | | | — | | | 13 | | | 28 | | | — | | | — | | | 28 | | Multi-value transmission projects | | 14 | | | — | | | — | | | 14 | |
| Other Customer Revenue | Other Customer Revenue | — | | | — | | | 1 | | | 1 | | | — | | | — | | | 2 | | | 2 | | Other Customer Revenue | | — | | | — | | | 3 | | | 3 | |
| Total Customer Revenue | Total Customer Revenue | 691 | | | 170 | | | 1 | | | 862 | | | 1,282 | | | 565 | | | 2 | | | 1,849 | | Total Customer Revenue | | 576 | | | 325 | | | 3 | | | 904 | |
| Other revenue | Other revenue | 34 | | | 1 | | | — | | | 35 | | | 51 | | | 2 | | | — | | | 53 | | Other revenue | | 15 | | | 1 | | | — | | | 16 | |
| Total operating revenue | Total operating revenue | $ | 725 | | | $ | 171 | | | $ | 1 | | | $ | 897 | | | $ | 1,333 | | | $ | 567 | | | $ | 2 | | | $ | 1,902 | | Total operating revenue | | $ | 591 | | | $ | 326 | | | $ | 3 | | | $ | 920 | |
| | | For the Three-Month Period Ended June 30, 2021 | | For the Six-Month Period Ended June 30, 2021 | | | For the Three-Month Period Ended March 31, 2022 |
| | 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 | $ | 170 | | | $ | 59 | | | $ | — | | | $ | 229 | | | $ | 331 | | | $ | 367 | | | $ | — | | | $ | 698 | | Residential | | $ | 168 | | | $ | 225 | | | $ | — | | | $ | 393 | |
| Commercial | Commercial | 80 | | | 18 | | | — | | | 98 | | | 151 | | | 147 | | | — | | | 298 | | Commercial | | 74 | | | 88 | | | — | | | 162 | |
| Industrial | Industrial | 230 | | | 3 | | | — | | | 233 | | | 420 | | | 15 | | | — | | | 435 | | Industrial | | 198 | | | 9 | | | — | | | 207 | |
| Natural gas transportation services | Natural gas transportation services | — | | | 9 | | | — | | | 9 | | | — | | | 19 | | | — | | | 19 | | Natural gas transportation services | | — | | | 14 | | | — | | | 14 | |
Other retail(1) | Other retail(1) | 36 | | | — | | | — | | | 36 | | | 66 | | | 1 | | | — | | | 67 | | Other retail(1) | | 32 | | | 1 | | | — | | | 33 | |
| Total retail | Total retail | 516 | | | 89 | | | — | | | 605 | | | 968 | | | 549 | | | — | | | 1,517 | | Total retail | | 472 | | | 337 | | | — | | | 809 | |
| Wholesale | Wholesale | 52 | | | 17 | | | — | | | 69 | | | 126 | | | 68 | | | — | | | 194 | | Wholesale | | 104 | | | 58 | | | — | | | 162 | |
| Multi-value transmission projects | Multi-value transmission projects | 15 | | | — | | | — | | | 15 | | | 30 | | | — | | | — | | | 30 | | Multi-value transmission projects | | 15 | | | — | | | — | | | 15 | |
| Other Customer Revenue | Other Customer Revenue | — | | | — | | | 1 | | | 1 | | | — | | | — | | | 11 | | | 11 | | Other Customer Revenue | | — | | | — | | | 1 | | | 1 | |
| Total Customer Revenue | Total Customer Revenue | 583 | | | 106 | | | 1 | | | 690 | | | 1,124 | | | 617 | | | 11 | | | 1,752 | | Total Customer Revenue | | 591 | | | 395 | | | 1 | | | 987 | |
| Other revenue | Other revenue | 3 | | | — | | | — | | | 3 | | | 7 | | | 1 | | | — | | | 8 | | Other revenue | | 17 | | | 1 | | | — | | | 18 | |
| Total operating revenue | Total operating revenue | $ | 586 | | | $ | 106 | | | $ | 1 | | | $ | 693 | | | $ | 1,131 | | | $ | 618 | | | $ | 11 | | | $ | 1,760 | | Total operating revenue | | $ | 608 | | | $ | 396 | | | $ | 1 | | | $ | 1,005 | |
(1) Other retail includes provisions for rate refunds, for which any actual refunds will be reflected
(10) Shareholder's Equity
In January 2023, MidAmerican Energy paid $100 million in the applicable customer classes upon resolution of the related regulatory proceeding.cash dividends to its parent company, MHC.
(10)(11) Segment Information
MidAmerican Energy has identified 2two 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 | | Six-Month Periods | | | Three-Month Periods |
| | | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | |
| Regulated electric | Regulated electric | $ | 725 | | | $ | 586 | | | $ | 1,333 | | | $ | 1,131 | | Regulated electric | | $ | 591 | | | $ | 608 | |
| Regulated natural gas | Regulated natural gas | 171 | | | 106 | | | 567 | | | 618 | | Regulated natural gas | | 326 | | | 396 | |
| Other | Other | 1 | | | 1 | | | 2 | | | 11 | | Other | | 3 | | | 1 | |
| Total operating revenue | Total operating revenue | $ | 897 | | | $ | 693 | | | $ | 1,902 | | | $ | 1,760 | | Total operating revenue | | $ | 920 | | | $ | 1,005 | |
| | Operating income: | Operating income: | | Operating income: | | |
| Regulated electric | Regulated electric | $ | 87 | | | $ | 103 | | | $ | 138 | | | $ | 112 | | Regulated electric | | $ | 50 | | | $ | 51 | |
| Regulated natural gas | Regulated natural gas | 3 | | | — | | | 52 | | | 39 | | Regulated natural gas | | 38 | | | 49 | |
| | Total operating income | Total operating income | 90 | | | 103 | | | 190 | | | 151 | | Total operating income | | 88 | | | 100 | |
| Interest expense | Interest expense | (78) | | | (74) | | | (156) | | | (148) | | Interest expense | | (80) | | | (78) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 5 | | | 2 | | | 9 | | | 4 | | Allowance for borrowed funds | | 4 | | | 4 | |
| Allowance for equity funds | Allowance for equity funds | 14 | | | 8 | | | 29 | | | 14 | | Allowance for equity funds | | 11 | | | 15 | |
| Other, net | Other, net | (12) | | | 15 | | | (15) | | | 26 | | Other, net | | 16 | | | (3) | |
| Income before income tax benefit | $ | 19 | | | $ | 54 | | | $ | 57 | | | $ | 47 | | |
| Total income before income tax expense (benefit) | | Total income before income tax expense (benefit) | | $ | 39 | | | $ | 38 | |
| | | As of | | As of |
| | June 30,
2022 | | December 31,
2021 | | March 31,
2023 | | December 31,
2022 |
| Assets: | Assets: | | | | Assets: | | | |
| Regulated electric | Regulated electric | $ | 21,967 | | | $ | 21,385 | | Regulated electric | $ | 22,091 | | | $ | 22,092 | |
| Regulated natural gas | Regulated natural gas | 1,667 | | | 1,871 | | Regulated natural gas | 1,716 | | | 1,885 | |
| Other | Other | 1 | | | 1 | | Other | — | | | 1 | |
| Total assets | Total assets | $ | 23,635 | | | $ | 23,257 | | Total assets | $ | 23,807 | | | $ | 23,978 | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers and Member of
MidAmerican Funding, LLC
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of June 30, 2022,March 31, 2023, the related consolidated statements of operations, and changes in member's equity, for the three-month and six-month periods ended June 30, 2022 and 2021, and of cash flows for the six-monththree-month periods ended June 30,March 31, 2023 and 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) 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, 2021,2022, 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 25, 2022,24, 2023, 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, 2021,2022, 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
AugustMay 5, 20222023
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | As of | | As of |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 497 | | | $ | 233 | | Cash and cash equivalents | $ | 58 | | | $ | 261 | |
| Trade receivables, net | Trade receivables, net | 525 | | | 526 | | Trade receivables, net | 387 | | | 536 | |
| Income tax receivable | Income tax receivable | 20 | | | 80 | | Income tax receivable | 274 | | | 43 | |
| Inventories | Inventories | 226 | | | 234 | | Inventories | 280 | | | 277 | |
| Prepayments | | Prepayments | 123 | | | 91 | |
| Other current assets | Other current assets | 187 | | | 123 | | Other current assets | 44 | | | 66 | |
| Total current assets | Total current assets | 1,455 | | | 1,196 | | Total current assets | 1,166 | | | 1,274 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 20,505 | | | 20,302 | | Property, plant and equipment, net | 20,982 | | | 21,092 | |
| Goodwill | Goodwill | 1,270 | | | 1,270 | | Goodwill | 1,270 | | | 1,270 | |
| Regulatory assets | Regulatory assets | 509 | | | 473 | | Regulatory assets | 571 | | | 550 | |
| Investments and restricted investments | Investments and restricted investments | 895 | | | 1,028 | | Investments and restricted investments | 944 | | | 904 | |
| Other assets | Other assets | 277 | | | 262 | | Other assets | 154 | | | 164 | |
| | Total assets | Total assets | $ | 24,911 | | | $ | 24,531 | | Total assets | $ | 25,087 | | | $ | 25,254 | |
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 |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| 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 | $ | 415 | | | $ | 531 | | Accounts payable | $ | 395 | | | $ | 536 | |
| Accrued interest | Accrued interest | 89 | | | 89 | | Accrued interest | 89 | | | 90 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 206 | | | 158 | | Accrued property, income and other taxes | 142 | | | 170 | |
| Note payable to affiliate | 197 | | | 189 | | |
| | | Current portion of long-term debt | Current portion of long-term debt | 64 | | | — | | Current portion of long-term debt | 310 | | | 317 | |
| Other current liabilities | Other current liabilities | 181 | | | 146 | | Other current liabilities | 106 | | | 93 | |
| Total current liabilities | Total current liabilities | 1,152 | | | 1,113 | | Total current liabilities | 1,042 | | | 1,206 | |
| | Long-term debt | Long-term debt | 7,901 | | | 7,961 | | Long-term debt | 7,652 | | | 7,652 | |
| Regulatory liabilities | Regulatory liabilities | 1,026 | | | 1,080 | | Regulatory liabilities | 836 | | | 1,119 | |
| Deferred income taxes | Deferred income taxes | 3,411 | | | 3,387 | | Deferred income taxes | 3,451 | | | 3,431 | |
| Asset retirement obligations | Asset retirement obligations | 698 | | | 714 | | Asset retirement obligations | 778 | | | 683 | |
| Other long-term liabilities | Other long-term liabilities | 477 | | | 475 | | Other long-term liabilities | 500 | | | 484 | |
| Total liabilities | Total liabilities | 14,665 | | | 14,730 | | Total liabilities | 14,259 | | | 14,575 | |
| | Commitments and contingencies (Note 8) | Commitments and contingencies (Note 8) | 0 | | 0 | Commitments and contingencies (Note 8) | |
| | 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 | 8,567 | | | 8,122 | | Retained earnings | 9,149 | | | 9,000 | |
| | Total member's equity | Total member's equity | 10,246 | | | 9,801 | | Total member's equity | 10,828 | | | 10,679 | |
| | Total liabilities and member's equity | Total liabilities and member's equity | $ | 24,911 | | | $ | 24,531 | | Total liabilities and member's equity | $ | 25,087 | | | $ | 25,254 | |
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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | |
| Regulated electric | Regulated electric | $ | 725 | | | $ | 586 | | | $ | 1,333 | | | $ | 1,131 | | Regulated electric | | $ | 591 | | | $ | 608 | |
| Regulated natural gas and other | Regulated natural gas and other | 172 | | | 107 | | | 569 | | | 629 | | Regulated natural gas and other | | 329 | | | 397 | |
| Total operating revenue | Total operating revenue | 897 | | | 693 | | | 1,902 | | | 1,760 | | Total operating revenue | | 920 | | | 1,005 | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | | |
| Cost of fuel and energy | Cost of fuel and energy | 174 | | | 103 | | | 299 | | | 254 | | Cost of fuel and energy | | 115 | | | 125 | |
| Cost of natural gas purchased for resale and other | Cost of natural gas purchased for resale and other | 120 | | | 57 | | | 418 | | | 489 | | Cost of natural gas purchased for resale and other | | 236 | | | 298 | |
| Operations and maintenance | Operations and maintenance | 200 | | | 184 | | | 392 | | | 377 | | Operations and maintenance | | 205 | | | 192 | |
| Depreciation and amortization | Depreciation and amortization | 277 | | | 209 | | | 527 | | | 416 | | Depreciation and amortization | | 234 | | | 250 | |
| Property and other taxes | Property and other taxes | 36 | | | 37 | | | 76 | | | 73 | | Property and other taxes | | 42 | | | 40 | |
| Total operating expenses | Total operating expenses | 807 | | | 590 | | | 1,712 | | | 1,609 | | Total operating expenses | | 832 | | | 905 | |
| | Operating income | Operating income | 90 | | | 103 | | | 190 | | | 151 | | Operating income | | 88 | | | 100 | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | | |
| Interest expense | Interest expense | (83) | | | (78) | | | (165) | | | (156) | | Interest expense | | (84) | | | (82) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 5 | | | 2 | | | 9 | | | 4 | | Allowance for borrowed funds | | 4 | | | 4 | |
| Allowance for equity funds | Allowance for equity funds | 14 | | | 8 | | | 29 | | | 14 | | Allowance for equity funds | | 11 | | | 15 | |
| Other, net | Other, net | (10) | | | 16 | | | (14) | | | 26 | | Other, net | | 28 | | | (4) | |
| Total other income (expense) | Total other income (expense) | (74) | | | (52) | | | (141) | | | (112) | | Total other income (expense) | | (41) | | | (67) | |
| | Income before income tax benefit | 16 | | | 51 | | | 49 | | | 39 | | |
| Income tax benefit | (188) | | | (160) | | | (396) | | | (316) | | |
| Income before income tax expense (benefit) | | Income before income tax expense (benefit) | | 47 | | | 33 | |
| Income tax expense (benefit) | | Income tax expense (benefit) | | (202) | | | (208) | |
| | Net income | Net income | $ | 204 | | | $ | 211 | | | $ | 445 | | | $ | 355 | | Net income | | $ | 249 | | | $ | 241 | |
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Paid-in
Capital | | Retained
Earnings | | Total Member's
Equity |
| | | | | |
| Balance, March 31, 2021 | $ | 1,679 | | | $ | 7,384 | | | $ | 9,063 | |
| Net income | — | | | 211 | | | 211 | |
| Other equity transactions | — | | | (1) | | | (1) | |
| Balance, June 30, 2021 | $ | 1,679 | | | $ | 7,594 | | | $ | 9,273 | |
| | | | | |
| Balance, December 31, 2020 | $ | 1,679 | | | $ | 7,240 | | | $ | 8,919 | |
| Net income | — | | | 355 | | | 355 | |
| Other equity transactions | — | | | (1) | | | (1) | |
| Balance, June 30, 2021 | $ | 1,679 | | | $ | 7,594 | | | $ | 9,273 | |
| | | | | |
| Balance, March 31, 2022 | $ | 1,679 | | | $ | 8,363 | | | $ | 10,042 | |
| Net income | — | | | 204 | | | 204 | |
| | | | | |
| Balance, June 30, 2022 | $ | 1,679 | | | $ | 8,567 | | | $ | 10,246 | |
| | | | | |
| Balance, December 31, 2021 | $ | 1,679 | | | $ | 8,122 | | | $ | 9,801 | |
| Net income | — | | | 445 | | | 445 | |
| | | | | |
| Balance, June 30, 2022 | $ | 1,679 | | | $ | 8,567 | | | $ | 10,246 | |
| | | | | | | | | | | | | | | | | |
| Paid-in
Capital | | Retained
Earnings | | Total Member's
Equity |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Balance, December 31, 2021 | $ | 1,679 | | | $ | 8,122 | | | $ | 9,801 | |
| Net income | — | | | 241 | | | 241 | |
| | | | | |
| Balance, March 31, 2022 | $ | 1,679 | | | $ | 8,363 | | | $ | 10,042 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Balance, December 31, 2022 | $ | 1,679 | | | $ | 9,000 | | | $ | 10,679 | |
| Net income | — | | | 249 | | | 249 | |
| Distribution to member | — | | | (100) | | | (100) | |
| | | | | |
| Balance, March 31, 2023 | $ | 1,679 | | | $ | 9,149 | | | $ | 10,828 | |
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)
| | | Six-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended March 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 445 | | | $ | 355 | | Net income | $ | 249 | | | $ | 241 | |
| 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 | 527 | | | 416 | | Depreciation and amortization | 234 | | | 250 | |
| Amortization of utility plant to other operating expenses | Amortization of utility plant to other operating expenses | 19 | | | 17 | | Amortization of utility plant to other operating expenses | 8 | | | 9 | |
| Allowance for equity funds | Allowance for equity funds | (29) | | | (14) | | Allowance for equity funds | (11) | | | (15) | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 58 | | | 195 | | Deferred income taxes and investment tax credits, net | 32 | | | 16 | |
| | Settlements of asset retirement obligations | Settlements of asset retirement obligations | (28) | | | (19) | | Settlements of asset retirement obligations | (6) | | | (7) | |
| Other, net | Other, net | 32 | | | 11 | | Other, net | (5) | | | 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 | 1 | | | (275) | | Trade receivables and other assets | 123 | | | 43 | |
| Inventories | Inventories | 8 | | | 41 | | Inventories | (3) | | | 49 | |
| | Pension and other postretirement benefit plans | | Pension and other postretirement benefit plans | (3) | | | 3 | |
| Accrued property, income and other taxes, net | Accrued property, income and other taxes, net | 95 | | | 56 | | Accrued property, income and other taxes, net | (261) | | | (245) | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | (10) | | | (68) | | Accounts payable and other liabilities | (85) | | | (1) | |
| Net cash flows from operating activities | Net cash flows from operating activities | 1,118 | | | 715 | | Net cash flows from operating activities | 272 | | | 353 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (862) | | | (721) | | Capital expenditures | (382) | | | (459) | |
| Purchases of marketable securities | Purchases of marketable securities | (214) | | | (109) | | Purchases of marketable securities | (48) | | | (105) | |
| Proceeds from sales of marketable securities | Proceeds from sales of marketable securities | 210 | | | 105 | | Proceeds from sales of marketable securities | 42 | | | 102 | |
| | Proceeds from sale of investment | | Proceeds from sale of investment | 12 | | | — | |
| Other, net | Other, net | 6 | | | (1) | | Other, net | 5 | | | 1 | |
| Net cash flows from investing activities | Net cash flows from investing activities | (860) | | | (726) | | Net cash flows from investing activities | (371) | | | (461) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| Distribution to member | | Distribution to member | (100) | | | — | |
| | Repayments of long-term debt | | Repayments of long-term debt | (7) | | | (1) | |
| Net change in note payable to affiliate | Net change in note payable to affiliate | 8 | | | 6 | | Net change in note payable to affiliate | — | | | 8 | |
| | Other, net | Other, net | (1) | | | (2) | | Other, net | (1) | | | — | |
| Net cash flows from financing activities | Net cash flows from financing activities | 7 | | | 4 | | Net cash flows from financing activities | (108) | | | 7 | |
| | 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 | 265 | | | (7) | | Net change in cash and cash equivalents and restricted cash and cash equivalents | (207) | | | (101) | |
| 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 | 240 | | | 46 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 271 | | | 240 | |
| 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 | $ | 505 | | | $ | 39 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 64 | | | $ | 139 | |
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 June 30, 2022,March 31, 2023, and for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The results of operations for the three- and six-month periodsthree-month period ended June 30, 2022,March 31, 2023, 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, 2021,2022, 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 accounting policies or its assumptions regarding significant accounting estimates and policies during the six-monththree-month period ended June 30, 2022.March 31, 2023.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.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 restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented inon 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 |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| | Cash and cash equivalents | Cash and cash equivalents | $ | 497 | | | $ | 233 | | Cash and cash equivalents | $ | 58 | | | $ | 261 | |
| Restricted cash and cash equivalents in other current assets | Restricted cash and cash equivalents in other current assets | 8 | | | 7 | | Restricted cash and cash equivalents in other current assets | 6 | | | 10 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 505 | | | $ | 240 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 64 | | | $ | 271 | |
(3) Property, Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.
(4) Recent Financing Transactions
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
(5)(4) 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 benefitexpense (benefit) is as follows:
| | | Three-Month Periods | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | | 21 | % | | 21 | % |
| Income tax credits | Income tax credits | (1,150) | | | (286) | | | (793) | | | (764) | | Income tax credits | | (430) | | | (618) | |
| State income tax, net of federal income tax impacts | State income tax, net of federal income tax impacts | (38) | | | (33) | | | (29) | | | (41) | | State income tax, net of federal income tax impacts | | (13) | | | (24) | |
| Effects of ratemaking | Effects of ratemaking | (12) | | | (16) | | | (10) | | | (26) | | Effects of ratemaking | | (6) | | | (9) | |
| Other, net | Other, net | 4 | | | — | | | 3 | | | — | | Other, net | | (2) | | | — | |
| Effective income tax rate | Effective income tax rate | (1,175) | % | | (314) | % | | (808) | % | | (810) | % | Effective income tax rate | | (430) | % | | (630) | % |
Income tax credits relate primarily to production tax credits ("PTCs"PTC") from MidAmerican Energy's wind-poweredwind- and solar-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-poweredwind- and solar-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-poweredWind- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 totaled $388$202 million and $297$203 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its U.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. MidAmerican Funding received netmade no cash payments for income tax fromto BHE totaling $544 million and $560 million for each of the six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021. respectively.2022.
(5) Employee Benefit Plans
Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.
(6) Employee Benefit PlansAsset Retirement Obligations
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.
(7) Fair Value Measurements
Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of 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 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of March 31, 2023 | | As of December 31, 2022 |
| Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value |
| | | | | | | |
| Long-term debt | $ | 7,962 | | | $ | 7,386 | | | $ | 7,969 | | | $ | 7,219 | |
(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) Member's Equity
In January 2023, MidAmerican Funding paid a $100 million cash distribution to its parent company, BHE.
(10)
(11) Segment Information
MidAmerican Funding has identified 2two 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 | | Six-Month Periods | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | |
| Regulated electric | Regulated electric | $ | 725 | | | $ | 586 | | | $ | 1,333 | | | $ | 1,131 | | Regulated electric | | $ | 591 | | | $ | 608 | |
| Regulated natural gas | Regulated natural gas | 171 | | | 106 | | | 567 | | | 618 | | Regulated natural gas | | 326 | | | 396 | |
| Other | Other | 1 | | | 1 | | | 2 | | | 11 | | Other | | 3 | | | 1 | |
| Total operating revenue | Total operating revenue | $ | 897 | | | $ | 693 | | | $ | 1,902 | | | $ | 1,760 | | Total operating revenue | | $ | 920 | | | $ | 1,005 | |
| | Operating income: | Operating income: | | Operating income: | | |
| Regulated electric | Regulated electric | $ | 87 | | | $ | 103 | | | $ | 138 | | | $ | 112 | | Regulated electric | | $ | 50 | | | $ | 51 | |
| Regulated natural gas | Regulated natural gas | 3 | | | — | | | 52 | | | 39 | | Regulated natural gas | | 38 | | | 49 | |
| | Total operating income | Total operating income | 90 | | | 103 | | | 190 | | | 151 | | Total operating income | | 88 | | | 100 | |
| Interest expense | Interest expense | (83) | | | (78) | | | (165) | | | (156) | | Interest expense | | (84) | | | (82) | |
| Allowance for borrowed funds | Allowance for borrowed funds | 5 | | | 2 | | | 9 | | | 4 | | Allowance for borrowed funds | | 4 | | | 4 | |
| Allowance for equity funds | Allowance for equity funds | 14 | | | 8 | | | 29 | | | 14 | | Allowance for equity funds | | 11 | | | 15 | |
| Other, net | Other, net | (10) | | | 16 | | | (14) | | | 26 | | Other, net | | 28 | | | (4) | |
| Income before income tax benefit | $ | 16 | | | $ | 51 | | | $ | 49 | | | $ | 39 | | |
| Total income before income tax expense (benefit) | | Total income before income tax expense (benefit) | | $ | 47 | | | $ | 33 | |
| | | As of | | As of |
| | June 30,
2022 | | December 31,
2021 | | March 31,
2023 | | December 31,
2022 |
Assets(1): | Assets(1): | | | | Assets(1): | | | |
| Regulated electric | Regulated electric | $ | 23,158 | | | $ | 22,576 | | Regulated electric | $ | 23,282 | | | $ | 23,283 | |
| Regulated natural gas | Regulated natural gas | 1,746 | | | 1,950 | | Regulated natural gas | 1,795 | | | 1,963 | |
| Other | Other | 7 | | | 5 | | Other | 10 | | | 8 | |
| Total assets | Total assets | $ | 24,911 | | | $ | 24,531 | | Total assets | $ | 25,087 | | | $ | 25,254 | |
| | | | | |
| (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 SecondFirst Quarter of 2023 and First Six Months of 2022 and 2021
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the secondfirst quarter of 20222023 was $207$242 million, a decrease of $6$2 million, or 3%1%, compared to 2021,2022, primarily due to higher depreciation and amortization expense of $68 million, unfavorable other, net of $27 million, higher operations and maintenance expense, of $16 millionlower natural gas utility margin, lower electric utility margin, lower allowance for equity funds, lower income tax benefit, higher property and other taxes and higher interest expense, of $4 million, offset by higher electric utility margin of $68 million, higher income tax benefit of $29 million, higher allowances for equityfavorable other, net and borrowed funds of $9 millionlower depreciation and higher natural gas utility margin of $2 million.amortization expense. Electric retail customer volumes increased 3%1% primarily due to higher customer usage andfor certain industrial customers, partially offset by the favorableunfavorable impact of weather. Energy generated decreased 9%, due to lower wind-powered and coal-fueled generation, and energy purchased increased 17%. Wholesale electricity sales volumes increased 7%decreased 18% due to favorableunfavorable market conditions. Natural gas retail customer volumes increased 21%decreased 10% due to the favorable impact of weather.
MidAmerican Energy's net income for the first six months of 2022 was $451 million, an increase of $91 million, or 25%, compared to 2021, primarily due to higher electric utility margin of $157 million, higher income tax benefit of $81 million, higher natural gas utility margin of $20 million and higher allowances for equity and borrowed funds of $20 million, offset by higher depreciation and amortization expense of $111 million, unfavorable other, net of $41 million, higher operations and maintenance expense of $15 million, higher interest expense of $8 million, lower nonregulated utility margins of $8 million and higher property and other taxes of $3 million. Electric retail customer volumes increased 4% primarily due to higher customer usage and the favorable impact of weather. Wholesale electricity sales volumes increased 20% due to favorable market conditions. Natural gas retail customer volumes increased 11% due to the favorable impact of weather.
MidAmerican Funding -
MidAmerican Funding's net income for the secondfirst quarter of 20222023 was $204$249 million, a decreasean increase of $7$8 million, or 3%, compared to 2021. MidAmerican Funding's net income for the first six months of 2022 was $445 million, an increase of $90 million, or 25%, compared to 2021.2022. The variancesvariance in net income werewas primarily due to a one-time gain on the sale of an investment of $10 million, partially offset by 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):
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Electric utility margin: | Electric utility margin: | | | | | | | | | | | | | Electric utility margin: | | | | | | | |
| Operating revenue | Operating revenue | | $ | 725 | | | $ | 586 | | | $ | 139 | | 24 | % | | $ | 1,333 | | | $ | 1,131 | | | $ | 202 | | 18 | % | Operating revenue | | $ | 591 | | | $ | 608 | | | $ | (17) | | (3) | % | |
| Cost of fuel and energy | Cost of fuel and energy | | 174 | | | 103 | | | 71 | | 69 | | | 299 | | | 254 | | | 45 | | 18 | | Cost of fuel and energy | | 115 | | | 125 | | | (10) | | (8) | | |
| Electric utility margin | Electric utility margin | | 551 | | | 483 | | | 68 | | 14 | % | | 1,034 | | | 877 | | | 157 | | 18 | % | Electric utility margin | | 476 | | | 483 | | | (7) | | (1) | % | |
| | Natural gas utility margin: | Natural gas utility margin: | | Natural gas utility margin: | | |
| Operating revenue | Operating revenue | | 171 | | | 106 | | | 65 | | 61 | % | | 567 | | | 618 | | | (51) | | (8) | % | Operating revenue | | 326 | | | 396 | | | (70) | | (18) | % | |
| Natural gas purchased for resale | Natural gas purchased for resale | | 120 | | | 57 | | | 63 | | * | | 418 | | | 489 | | | (71) | | (15) | | Natural gas purchased for resale | | 236 | | | 298 | | | (62) | | (21) | | |
| Natural gas utility margin | Natural gas utility margin | | 51 | | | 49 | | | 2 | | 4 | % | | 149 | | | 129 | | | 20 | | 16 | % | Natural gas utility margin | | 90 | | | 98 | | | (8) | | (8) | % | |
| | Utility margin | Utility margin | | 602 | | | 532 | | | 70 | | 13 | % | | 1,183 | | | 1,006 | | | 177 | | 18 | % | Utility margin | | 566 | | | 581 | | | (15) | | (3) | % | |
| | Other operating revenue | Other operating revenue | | 1 | | | 1 | | | — | | — | % | | 2 | | | 11 | | | (9) | | (82) | % | Other operating revenue | | 3 | | | 1 | | | 2 | | * | |
| | Operations and maintenance | Operations and maintenance | | 200 | | | 184 | | | 16 | | 9 | | | 392 | | | 377 | | | 15 | | 4 | | Operations and maintenance | | 205 | | | 192 | | | 13 | | 7 | | |
| Depreciation and amortization | Depreciation and amortization | | 277 | | | 209 | | | 68 | | 33 | | | 527 | | | 416 | | | 111 | | 27 | | Depreciation and amortization | | 234 | | | 250 | | | (16) | | (6) | | |
| Property and other taxes | Property and other taxes | | 36 | | | 37 | | | (1) | | (3) | | | 76 | | | 73 | | | 3 | | 4 | | Property and other taxes | | 42 | | | 40 | | | 2 | | 5 | | |
| | Operating income | Operating income | | $ | 90 | | | $ | 103 | | | $ | (13) | | (13) | % | | $ | 190 | | | $ | 151 | | | $ | 39 | | 26 | % | Operating income | | $ | 88 | | | $ | 100 | | | $ | (12) | | (12) | % | |
* Not meaningful.
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter | | First Six Months |
| 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin (in millions): | | | | | | | | | | | | | | | |
| Operating revenue | $ | 725 | | | $ | 586 | | | $ | 139 | | | 24 | % | | $ | 1,333 | | | $ | 1,131 | | | $ | 202 | | | 18 | % |
| Cost of fuel and energy | 174 | | | 103 | | | 71 | | | 69 | | | 299 | | | 254 | | | 45 | | | 18 | |
| Utility margin | $ | 551 | | | $ | 483 | | | $ | 68 | | | 14 | % | | $ | 1,034 | | | $ | 877 | | | $ | 157 | | | 18 | % |
| | | | | | | | | | | | | | | |
| Sales (GWhs): | | | | | | | | | | | | | | | |
| Residential | 1,552 | | | 1,486 | | | 66 | | | 4 | % | | 3,405 | | | 3,224 | | | 181 | | | 6 | % |
| Commercial | 953 | | | 894 | | | 59 | | | 7 | | | 1,966 | | | 1,832 | | | 134 | | | 7 | |
| Industrial | 4,149 | | | 4,056 | | | 93 | | | 2 | | | 8,128 | | | 7,875 | | | 253 | | | 3 | |
| Other | 406 | | | 401 | | | 5 | | | 1 | | | 809 | | | 771 | | | 38 | | | 5 | |
| Total retail | 7,060 | | | 6,837 | | | 223 | | | 3 | | | 14,308 | | | 13,702 | | | 606 | | | 4 | |
| Wholesale | 4,146 | | | 3,872 | | | 274 | | | 7 | | | 9,471 | | | 7,923 | | | 1,548 | | | 20 | |
| Total sales | 11,206 | | | 10,709 | | | 497 | | | 5 | % | | 23,779 | | | 21,625 | | | 2,154 | | | 10 | % |
| | | | | | | | | | | | | | | |
| Average number of retail customers (in thousands) | 812 | | 803 | | 9 | | | 1 | % | | 811 | | 802 | | 9 | | | 1 | % |
| | | | | | | | | | | | | | | |
| Average revenue per MWh: | | | | | | | | | | | | | | | |
| Retail | $ | 84.18 | | | $ | 75.62 | | | $ | 8.56 | | | 11 | % | | $ | 74.52 | | | $ | 70.71 | | | $ | 3.81 | | | 5 | % |
| Wholesale | $ | 25.23 | | | $ | 12.06 | | | $ | 13.17 | | | * | | $ | 22.65 | | | $ | 14.40 | | | $ | 8.25 | | | 57 | % |
| | | | | | | | | | | | | | | |
| Heating degree days | 677 | | | 588 | | | 89 | | | 15 | % | | 3,992 | | | 3,799 | | | 193 | | | 5 | % |
| Cooling degree days | 421 | | | 426 | | | (5) | | | (1) | % | | 421 | | | 426 | | | (5) | | | (1) | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Wind and other(2) | 7,364 | | | 5,877 | | | 1,487 | | | 25 | % | | 15,654 | | | 11,999 | | | 3,655 | | | 30 | % |
| Coal | 1,481 | | | 2,791 | | | (1,310) | | | (47) | | | 3,840 | | | 5,693 | | | (1,853) | | | (33) | |
| Nuclear | 863 | | | 1,009 | | | (146) | | | (14) | | | 1,783 | | | 1,904 | | | (121) | | | (6) | |
| Natural gas | 397 | | | 336 | | | 61 | | | 18 | | | 631 | | | 479 | | | 152 | | | 32 | |
| Total energy generated | 10,105 | | | 10,013 | | | 92 | | | 1 | | | 21,908 | | | 20,075 | | | 1,833 | | | 9 | |
| Energy purchased | 1,315 | | | 842 | | | 473 | | | 56 | | | 2,277 | | | 1,860 | | | 417 | | | 22 | |
| Total | 11,420 | | | 10,855 | | | 565 | | | 5 | % | | 24,185 | | | 21,935 | | | 2,250 | | | 10 | % |
| | | | | | | | | | | | | | | |
| Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 6.34 | | | $ | 6.43 | | | $ | (0.09) | | | (1) | % | | $ | 5.92 | | | $ | 6.29 | | | $ | (0.37) | | | (6) | % |
| Energy purchased | $ | 83.45 | | | $ | 45.70 | | | $ | 37.75 | | | 83 | % | | $ | 74.41 | | | $ | 68.55 | | | $ | 5.86 | | | 9 | % |
* Not meaningful. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter | | |
| 2023 | | 2022 | | Change | | | | | | |
| Utility margin (in millions): | | | | | | | | | | | | | | | |
| Operating revenue | $ | 591 | | | $ | 608 | | | $ | (17) | | | (3) | % | | | | | | | | |
| Cost of fuel and energy | 115 | | | 125 | | | (10) | | | (8) | | | | | | | | | |
| Utility margin | $ | 476 | | | $ | 483 | | | $ | (7) | | | (1) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Sales (GWhs): | | | | | | | | | | | | | | | |
| Residential | 1,793 | | | 1,853 | | | (60) | | | (3) | % | | | | | | | | |
| Commercial | 1,018 | | | 1,013 | | | 5 | | | — | | | | | | | | | |
| Industrial | 4,102 | | | 3,979 | | | 123 | | | 3 | | | | | | | | | |
| Other | 409 | | | 403 | | | 6 | | | 1 | | | | | | | | | |
| Total retail | 7,322 | | | 7,248 | | | 74 | | | 1 | | | | | | | | | |
| Wholesale | 4,352 | | | 5,325 | | | (973) | | | (18) | | | | | | | | | |
| Total sales | 11,674 | | | 12,573 | | | (899) | | | (7) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Average number of retail customers (in thousands) | 818 | | 810 | | 8 | | | 1 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Average revenue per MWh: | | | | | | | | | | | | | | | |
| Retail | $ | 67.02 | | | $ | 65.10 | | | $ | 1.92 | | | 3 | % | | | | | | | | |
| Wholesale | $ | 17.56 | | | $ | 20.65 | | | $ | (3.09) | | | (15) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Heating degree days | 2,992 | | | 3,315 | | | (323) | | | (10) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Wind and other(2) | 7,377 | | | 8,290 | | | (913) | | | (11) | % | | | | | | | | |
| Coal | 2,116 | | | 2,359 | | | (243) | | | (10) | | | | | | | | | |
| Nuclear | 927 | | | 920 | | | 7 | | | 1 | | | | | | | | | |
| Natural gas | 344 | | | 234 | | | 110 | | | 47 | | | | | | | | | |
| Total energy generated | 10,764 | | | 11,803 | | | (1,039) | | | (9) | | | | | | | | | |
| Energy purchased | 1,123 | | | 962 | | | 161 | | | 17 | | | | | | | | | |
| Total | 11,887 | | | 12,765 | | | (878) | | | (7) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 6.09 | | | $ | 5.56 | | | $ | 0.53 | | | 10 | % | | | | | | | | |
| Energy purchased | $ | 43.72 | | | $ | 62.04 | | | $ | (18.32) | | | (30) | % | | | | | | | | |
(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 facilitiessources 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 renewable 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter | | First Six Months |
| 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change |
| Utility margin (in millions): | | | | | | | | | | | | | | | |
| Operating revenue | $ | 171 | | | $ | 106 | | | $ | 65 | | | 61 | % | | $ | 567 | | | $ | 618 | | | $ | (51) | | | (8) | % |
| Natural gas purchased for resale | 120 | | | 57 | | | 63 | | | * | | 418 | | | 489 | | | (71) | | | (15) | |
| Utility margin | $ | 51 | | | $ | 49 | | | $ | 2 | | | 4 | % | | $ | 149 | | | $ | 129 | | | $ | 20 | | | 16 | % |
| | | | | | | | | | | | | | | |
| Throughput (000's Dths): | | | | | | | | | | | | | | | |
| Residential | 7,500 | | | 6,272 | | | 1,228 | | | 20 | % | | 34,599 | | | 31,554 | | | 3,045 | | | 10 | % |
| Commercial | 3,599 | | | 3,011 | | | 588 | | | 20 | | | 16,059 | | | 14,744 | | | 1,315 | | | 9 | |
| Industrial | 1,465 | | | 1,069 | | | 396 | | | 37 | | | 3,309 | | | 2,506 | | | 803 | | | 32 | |
| Other | 16 | | | 11 | | | 5 | | | 45 | | | 51 | | | 48 | | | 3 | | | 6 | |
| Total retail sales | 12,580 | | | 10,363 | | | 2,217 | | | 21 | | | 54,018 | | | 48,852 | | | 5,166 | | | 11 | |
| Wholesale sales | 4,912 | | | 5,817 | | | (905) | | | (16) | | | 17,144 | | | 16,590 | | | 554 | | | 3 | |
| Total sales | 17,492 | | | 16,180 | | | 1,312 | | | 8 | | | 71,162 | | | 65,442 | | | 5,720 | | | 9 | |
| Natural gas transportation service | 22,491 | | | 26,853 | | | (4,362) | | | (16) | | | 53,804 | | | 56,493 | | | (2,689) | | | (5) | |
| Total throughput | 39,983 | | | 43,033 | | | (3,050) | | | (7) | % | | 124,966 | | | 121,935 | | | 3,031 | | | 2 | % |
| | | | | | | | | | | | | | | |
| Average number of retail customers (in thousands) | 781 | | | 776 | | | 5 | | | 1 | % | | 784 | | | 777 | | | 7 | | | 1 | % |
| | | | | | | | | | | | | | | |
| Average revenue per retail Dth sold | $ | 10.08 | | | $ | 7.81 | | | $ | 2.27 | | | 29 | % | | $ | 8.36 | | | $ | 10.88 | | | $ | (2.52) | | | (23) | % |
| | | | | | | | | | | | | | | |
| Heating degree days | 734 | | | 625 | | | 109 | | | 17 | % | | 4,219 | | | 3,926 | | | 293 | | | 7 | % |
| | | | | | | | | | | | | | | |
| 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 | $ | 6.86 | | | $ | 3.54 | | | $ | 3.32 | | | 94 | % | | $ | 5.87 | | | $ | 7.47 | | | $ | (1.60) | | | (21) | % |
* Not meaningful. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter | | |
| 2023 | | 2022 | | Change | | | | | | |
| Utility margin (in millions): | | | | | | | | | | | | | | | |
| Operating revenue | $ | 326 | | | $ | 396 | | | $ | (70) | | | (18) | % | | | | | | | | |
| Natural gas purchased for resale | 236 | | | 298 | | | (62) | | | (21) | | | | | | | | | |
| Utility margin | $ | 90 | | | $ | 98 | | | $ | (8) | | | (8) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Throughput (000's Dths): | | | | | | | | | | | | | | | |
| Residential | 24,393 | | | 27,099 | | | (2,706) | | | (10) | % | | | | | | | | |
| Commercial | 11,352 | | | 12,460 | | | (1,108) | | | (9) | | | | | | | | | |
| Industrial | 1,483 | | | 1,844 | | | (361) | | | (20) | | | | | | | | | |
| Other | 34 | | | 35 | | | (1) | | | (3) | | | | | | | | | |
| Total retail sales | 37,262 | | | 41,438 | | | (4,176) | | | (10) | | | | | | | | | |
| Wholesale sales | 10,407 | | | 12,232 | | | (1,825) | | | (15) | | | | | | | | | |
| Total sales | 47,669 | | | 53,670 | | | (6,001) | | | (11) | | | | | | | | | |
| Natural gas transportation service | 29,585 | | | 31,313 | | | (1,728) | | | (6) | | | | | | | | | |
| Total throughput | 77,254 | | | 84,983 | | | (7,729) | | | (9) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Average number of retail customers (in thousands) | 793 | | | 785 | | | 8 | | | 1 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Average revenue per retail Dth sold | $ | 7.63 | | | $ | 7.84 | | | $ | (0.21) | | | (3) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Heating degree days | 3,132 | | | 3,485 | | | (353) | | | (10) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Average cost of natural gas per retail Dth sold | $ | 5.58 | | | $ | 5.80 | | | $ | (0.22) | | | (4) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| Combined retail and wholesale average cost of natural gas per Dth sold | $ | 4.96 | | | $ | 5.55 | | | $ | (0.59) | | | (11) | % | | | | | | | | |
Quarter Ended June 30, 2022March 31, 2023 Compared to Quarter Ended June 30, 2021March 31, 2022
MidAmerican Energy -
Electric utility margin increased $68decreased $7 million, or 14%(1)%, for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to:
•a $63$23 million increasedecrease in wholesale utility margin due to higherlower volumes of 18.3% and lower margins per unit of $61$7 million, reflecting higherlower market prices and lower energy costs, and higher volumes of 7.1%; andprices; partially offset by
•a $6$17 million increase in retail utility margin primarily due to $11 million from higher customer usage; $6 million due to price impacts from changes in sales mix; and $1 million from the favorable impact of weather; partially offset by $12$14 million, net of energy costs, from lowerhigher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit).; and $7 million from higher customer usage; partially offset by $5 million from the unfavorable impact of weather. Retail customer volumes increased 3.3%1.0%.
Natural gas utility margin increased $2decreased $8 million, or 4%8%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to:
•a $5 million increasedecrease from higher average prices;lower recoveries through a capital tracker mechanism;
•a $5 million decrease due to the unfavorable impact of weather; partially offset by
•a $3 million decreaseincrease due to price impacts from changes in sales mix.
Operations and maintenance increased $13 million, or 7%, for the first quarter of 2023 compared to 2022 primarily due to higher refunds related to amortizationtechnology and other administrative costs of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit).$6 million, higher other power and steam power generation costs of $5 million, higher property insurance costs of $3 million and higher benefit costs of $2 million, partially offset by lower nuclear power generation costs of $4 million.
Operations and maintenance increased $16 million, or 9%, for the second quarter of 2022 compared to 2021 primarily due to higher steam generation maintenance costs of $9 million and higher electric distribution and transmission costs of $10 million, partially offset by lower gas distribution costs of $3 million.
Depreciation and amortization increased $68decreased $16 million, or 33%6%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to $54$22 million from higherlower Iowa revenue sharing accruals, $18and $16 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, and $8partially offset by $19 million from wind-powered generating facilities and other plant placed in-service partially offset by $12and $3 million from a regulatory mechanism deferring certainlower depreciation expense deferrals in 2022.2023.
Property and other taxes increased $2 million, or 5%, for the first quarter of 2023 compared to 2022 primarily due to $1 million from higher wind turbine property taxes and $1 million from higher replacement taxes.
Interest expense increased $4$2 million, or 5%3%, for the secondfirst quarter of 20222023 compared to 20212022 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 $9decreased $4 million, or 90%27%, for the secondfirst quarter of 20222023 compared to 2021 primarily2022 due to higherlower construction work-in-progress balances related to wind- and solar-powered generation.
Other, net decreased $27increased $19 million, or 180%633%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to unfavorablefavorable investment earnings, largely attributable to lowerhigher cash surrender values of corporate-owned life insurance policies, and higherlower non-service costs of employee benefit plans.
Income tax benefit increased $29decreased $3 million, or 18%1%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to higherlower PTCs and lower pretax income, partially offset by state income tax impacts and the effects of ratemaking.impacts. PTCs for the secondfirst quarter of 2023 and 2022 and 2021 totaled $185$202 million and $146$203 million, respectively.
MidAmerican Funding -
Income tax benefit increased $28decreased $6 million, or 18%, for the second quarter of 2022 compared to 2021 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%3%, for the first six monthsquarter of 20222023 compared to 2021, due to:
•a $127 million increase in wholesale utility margin2022 principally due to higher margins per unitpretax income from a one-time gain on the sale of $119 million, reflecting higher market pricesan investment 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 fromthe 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 andMidAmerican Energy's 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.above.
Liquidity and Capital Resources
As of June 30, 2022,March 31, 2023, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
| | | | | | | | |
| MidAmerican Energy: | | |
| Cash and cash equivalents | | $ | 49557 | |
| | | |
| Credit facilities, maturing 2023 and 2025 | | 1,505 | |
| Less: | | |
| | |
| Tax-exempt bond support | | (370)(363) | |
| Net credit facilities | | 1,1351,142 | |
| | | |
| MidAmerican Energy total net liquidity | | $ | 1,6301,199 | |
| | | |
| MidAmerican Funding: | | |
| MidAmerican Energy total net liquidity | | $ | 1,6301,199 | |
| Cash and cash equivalents | | 21 | |
| MHC, Inc. credit facility, maturing 2023 | | 4 | |
| MidAmerican Funding total net liquidity | | $ | 1,6361,204 | |
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, were $1,125$288 million and $721$360 million, respectively. MidAmerican Funding's net cash flows from operating activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, were $1,118$272 million and $715$353 million, respectively. Cash flows from operating activities reflect higher payments to vendors, higher derivative collateral posted, higher property tax payments and lower utility margins for MidAmerican Energy's regulated electric and natural gas businesses and 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 caused by the February 2021 polar vortex weather event.businesses.
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 made for each payment date.
Investing Activities
MidAmerican Energy's net cash flows from investing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, were $(860)$(384) million and $(726)$(461) million, respectively. MidAmerican Funding's net cash flows from investing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, were $(860)$(371) million and $(726)$(461) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures. Refer to "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.
Financing Activities
MidAmerican Energy's net cash flows from financing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022 and 2021 were $(1)$(108) million and $(2)$— million, respectively. MidAmerican Funding's net cash flows from financing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, were $(108) million and 2021, were $7 million, and $4respectively. In January 2023, MidAmerican Funding made a $100 million respectively.distribution to its sole member, BHE. MidAmerican Funding paid $— million and received $8 million in 2023 and $6 million in 2022, and 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, 2024, commercial paper and bank notes aggregating $1.5 billion. MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 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 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 automaticshelf registration statement with the SEC to issue an indeterminate amountup to $3.25 billion of long-term debt securities and preferred stock through June 13, 2024.March 10, 2026. 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 andmillion. MidAmerican Energy has authorization from the Illinois Commerce Commission to issue,ICC through May 25, 2025, to issue long-term debt securities up to an aggregate of $2.2 billion and preferred stock up to an aggregate of $500 million. Additionally, MidAmerican Energy has authority from the Illinois Commerce Commissionmillion; through October 15, 2024, to issue $750 million 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 2024.2024; and through January 1, 2025, to issue $105 million of long-term debt securities for the purpose of refinancing three of its variable-rate tax-exempt bond series, including $57 million due in May 2023, $35 million due in October 2024 and $13 million due in January 2025.
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'customer rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
|
|
| Six-Month Periods | | Annual |
| Three-Month Periods | | Annual |
| | Ended June 30, | | Forecast | | Ended March 31, | | Forecast |
| | 2021 | | 2022 | | 2022 | | 2022 | | 2023 | | 2023 |
| | Wind generation | Wind generation | $ | 286 | | | $ | 244 | | | $ | 734 | | Wind generation | $ | 133 | | | $ | 88 | | | $ | 1,222 | |
| Electric distribution | Electric distribution | 96 | | | 125 | | | 274 | | Electric distribution | 54 | | | 73 | | | 296 | |
| Electric transmission | Electric transmission | 54 | | | 46 | | | 158 | | Electric transmission | 21 | | | 33 | | | 187 | |
| Solar generation | Solar generation | 63 | | | 77 | | | 140 | | Solar generation | 44 | | | 9 | | | 10 | |
| Other | Other | 221 | | | 370 | | | 607 | | Other | 207 | | | 179 | | | 609 | |
| Total | Total | $ | 720 | | | $ | 862 | | | $ | 1,913 | | Total | $ | 459 | | | $ | 382 | | | $ | 2,324 | |
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 of wind-powered generating facilities totaling $5$75 million and $172$3 million for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, respectively. The timing and 2021, respectively.amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $106$1,025 million for the remainder of 2022.2023.
◦Repowering of wind-powered generating facilities totaling $214$5 million and $82$120 million for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, respectively. Planned spending for the repowering of wind-powered generating facilities totals $314$16 million for the remainder of 2022.2023. 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 593 MWs of current repowering projects not in-service as of June 30, 2022, 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 generation includes the construction and operation of solar-powered generating facilities, totalingprimarily consisting of 141 MWs of small- and utility-scale solar generation, with totalall of which were placed in-service in 2022. For the three-month periods ended March 31, 2023 and 2022 solar generation spend of $77totaled $9 million and $63$44 million, for the six-month periods ended June 30, 2022 and 2021, respectively and plannedrespectively. Planned spending of $63totals $1 million for the remainder of 2022.2023.
•Remaining expendituresOther includes primarily relate to routine expendituresprojects for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.
Material Cash Requirements
As of June 30, 2022,March 31, 2023, there have been no material changes in MidAmerican Energy's and MidAmerican Funding's cash requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2021.2022.
Quad Cities Generating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, which was a subsidiary of Exelon 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 ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Constellation 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, 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 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. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and 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, Constellation 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 air quality, climate change, RPS, air and water quality, emissions performance standards, water quality, coal combustion byproductash disposal hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact MidAmerican Energy'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. MidAmerican Energy 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 MidAmerican Energy 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 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, 2021.2022. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2021.2022.
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 June 30, 2022,March 31, 2023, the related consolidated statements of operations, and changes in shareholder's equity, for the three-month and six-month periods ended June 30, 2022 and 2021, and of cash flows for the six-monththree-month periods ended June 30,March 31, 2023 and 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 Nevada Power as of December 31, 2021,2022, 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 25, 2022,24, 2023, 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, 2021,2022, 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
AugustMay 5, 20222023
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | As of | | As of |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 42 | | | $ | 33 | | Cash and cash equivalents | $ | 23 | | | $ | 43 | |
| Trade receivables, net | Trade receivables, net | 369 | | | 227 | | Trade receivables, net | 301 | | | 388 | |
| Note receivable from affiliate | | Note receivable from affiliate | — | | | 100 | |
| Inventories | Inventories | 68 | | | 64 | | Inventories | 106 | | | 93 | |
| | Regulatory assets | Regulatory assets | 401 | | | 291 | | Regulatory assets | 983 | | | 666 | |
| | Other current assets | Other current assets | 62 | | | 86 | | Other current assets | 83 | | | 89 | |
| Total current assets | Total current assets | 942 | | | 701 | | Total current assets | 1,496 | | | 1,379 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 7,115 | | | 6,891 | | Property, plant and equipment, net | 7,649 | | | 7,406 | |
| | Regulatory assets | Regulatory assets | 748 | | | 728 | | Regulatory assets | 655 | | | 628 | |
| Other assets | Other assets | 414 | | | 432 | | Other assets | 390 | | | 388 | |
| | Total assets | Total assets | $ | 9,219 | | | $ | 8,752 | | Total assets | $ | 10,190 | | | $ | 9,801 | |
| | 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 | $ | 433 | | | $ | 242 | | Accounts payable | $ | 334 | | | $ | 422 | |
| Accrued interest | Accrued interest | 33 | | | 32 | | Accrued interest | 51 | | | 40 | |
| | Accrued property, income and other taxes | | Accrued property, income and other taxes | 35 | | | 32 | |
| Short-term debt | Short-term debt | — | | | 180 | | Short-term debt | 33 | | | — | |
| Current portion of long-term debt | | Current portion of long-term debt | 300 | | | — | |
| Regulatory liabilities | Regulatory liabilities | 46 | | | 49 | | Regulatory liabilities | 45 | | | 45 | |
| Customer deposits | Customer deposits | 44 | | | 44 | | Customer deposits | 52 | | | 51 | |
| | Derivative contracts | Derivative contracts | 122 | | | 55 | | Derivative contracts | 90 | | | 51 | |
| Other current liabilities | Other current liabilities | 91 | | | 91 | | Other current liabilities | 52 | | | 49 | |
| Total current liabilities | Total current liabilities | 769 | | | 693 | | Total current liabilities | 992 | | | 690 | |
| | Long-term debt | Long-term debt | 2,800 | | | 2,499 | | Long-term debt | 2,895 | | | 3,195 | |
| Finance lease obligations | Finance lease obligations | 302 | | | 310 | | Finance lease obligations | 290 | | | 295 | |
| Regulatory liabilities | Regulatory liabilities | 1,075 | | | 1,100 | | Regulatory liabilities | 1,059 | | | 1,093 | |
| Deferred income taxes | Deferred income taxes | 816 | | | 782 | | Deferred income taxes | 878 | | | 875 | |
| Other long-term liabilities | Other long-term liabilities | 328 | | | 338 | | Other long-term liabilities | 318 | | | 299 | |
| Total liabilities | Total liabilities | 6,090 | | | 5,722 | | Total liabilities | 6,432 | | | 6,447 | |
| | Commitments and contingencies (Note 9) | Commitments and contingencies (Note 9) | 0 | | 0 | Commitments and contingencies (Note 9) | |
| | 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 | 2,333 | | | 2,308 | | Additional paid-in capital | 2,733 | | | 2,333 | |
| Retained earnings | Retained earnings | 798 | | | 724 | | Retained earnings | 1,026 | | | 1,022 | |
| Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | (2) | | | (2) | | Accumulated other comprehensive loss, net | (1) | | | (1) | |
| Total shareholder's equity | Total shareholder's equity | 3,129 | | | 3,030 | | Total shareholder's equity | 3,758 | | | 3,354 | |
| | Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 9,219 | | | $ | 8,752 | | Total liabilities and shareholder's equity | $ | 10,190 | | | $ | 9,801 | |
| | 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 | | Six-Month Periods | | Three-Month Periods | |
| | Ended June 30, | | Ended June 30, | | Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| | Operating revenue | Operating revenue | $ | 639 | | | $ | 559 | | | $ | 1,054 | | | $ | 929 | | Operating revenue | $ | 599 | | | $ | 415 | | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | | |
| Cost of fuel and energy | Cost of fuel and energy | 336 | | | 252 | | | 548 | | | 417 | | Cost of fuel and energy | 384 | | | 212 | | |
| Operations and maintenance | Operations and maintenance | 75 | | | 77 | | | 140 | | | 140 | | Operations and maintenance | 73 | | | 65 | | |
| Depreciation and amortization | Depreciation and amortization | 103 | | | 100 | | | 206 | | | 201 | | Depreciation and amortization | 106 | | | 103 | | |
| Property and other taxes | Property and other taxes | 12 | | | 12 | | | 25 | | | 24 | | Property and other taxes | 14 | | | 13 | | |
| Total operating expenses | Total operating expenses | 526 | | | 441 | | | 919 | | | 782 | | Total operating expenses | 577 | | | 393 | | |
| | Operating income | Operating income | 113 | | | 118 | | | 135 | | | 147 | | Operating income | 22 | | | 22 | | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | | |
| Interest expense | Interest expense | (39) | | | (39) | | | (77) | | | (77) | | Interest expense | (49) | | | (38) | | |
| Allowance for borrowed funds | 2 | | | 1 | | | 3 | | | 2 | | |
| Capitalized interest | | Capitalized interest | 2 | | | 1 | | |
| Allowance for equity funds | Allowance for equity funds | 2 | | | 2 | | | 5 | | | 3 | | Allowance for equity funds | 4 | | | 3 | | |
| Interest and dividend income | Interest and dividend income | 9 | | | 3 | | | 18 | | | 8 | | Interest and dividend income | 22 | | | 9 | | |
| Other, net | Other, net | (1) | | | 6 | | | — | | | 10 | | Other, net | 4 | | | 1 | | |
| Total other income (expense) | Total other income (expense) | (27) | | | (27) | | | (51) | | | (54) | | Total other income (expense) | (17) | | | (24) | | |
| | Income before income tax expense | 86 | | | 91 | | | 84 | | | 93 | | |
| Income tax expense | 10 | | | 9 | | | 10 | | | 9 | | |
| Net income | $ | 76 | | | $ | 82 | | | $ | 74 | | | $ | 84 | | |
| Income (loss) before income tax expense (benefit) | | Income (loss) before income tax expense (benefit) | 5 | | | (2) | | |
| Income tax expense (benefit) | | Income tax expense (benefit) | 1 | | | — | | |
| Net income (loss) | | Net income (loss) | $ | 4 | | | $ | (2) | | |
| | 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, March 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 636 | | | $ | (3) | | | $ | 2,941 | | |
| Net income | | — | | | — | | | — | | | 82 | | | — | | | 82 | | |
| Dividends declared | | — | | | — | | | — | | | (13) | | | — | | | (13) | | |
| | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 705 | | | $ | (3) | | | $ | 3,010 | | |
| | Balance, December 31, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 634 | | | $ | (3) | | | $ | 2,939 | | |
| Net income | | — | | | — | | | — | | | 84 | | | — | | | 84 | | |
| Dividends declared | | — | | | — | | | — | | | (13) | | | — | | | (13) | | |
| | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 705 | | | $ | (3) | | | $ | 3,010 | | |
| | Balance, December 31, 2021 | | Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 724 | | | $ | (2) | | | $ | 3,030 | |
| Net loss | | Net loss | | — | | | — | | | — | | | (2) | | | — | | | (2) | |
| | | Balance, March 31, 2022 | Balance, March 31, 2022 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 722 | | | $ | (2) | | | $ | 3,028 | | Balance, March 31, 2022 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 722 | | | $ | (2) | | | $ | 3,028 | |
| | | Balance, December 31, 2022 | | Balance, December 31, 2022 | | 1,000 | | | $ | — | | | $ | 2,333 | | | $ | 1,022 | | | $ | (1) | | | $ | 3,354 | |
| Net income | Net income | | — | | | — | | | — | | | 76 | | | — | | | 76 | | Net income | | — | | | — | | | — | | | 4 | | | — | | | 4 | |
| | Contributions | Contributions | | — | | | — | | | 25 | | | — | | | — | | | 25 | | Contributions | | — | | | — | | | 400 | | | — | | | — | | | 400 | |
| | Balance, June 30, 2022 | | 1,000 | | | $ | — | | | $ | 2,333 | | | $ | 798 | | | $ | (2) | | | $ | 3,129 | | |
| | Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 724 | | | $ | (2) | | | $ | 3,030 | | |
| Net income | | — | | | — | | | — | | | 74 | | | — | | | 74 | | |
| | Contributions | | — | | | — | | | 25 | | | — | | | — | | | 25 | | |
| | Balance, June 30, 2022 | | 1,000 | | | $ | — | | | $ | 2,333 | | | $ | 798 | | | $ | (2) | | | $ | 3,129 | | |
| Balance, March 31, 2023 | | Balance, March 31, 2023 | | 1,000 | | | $ | — | | | $ | 2,733 | | | $ | 1,026 | | | $ | (1) | | | $ | 3,758 | |
| | 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)
| | | Six-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended March 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | $ | 74 | | | $ | 84 | | |
| Adjustments to reconcile net income to net cash flows from operating activities: | | |
| Net income (loss) | | Net income (loss) | $ | 4 | | | $ | (2) | |
| Adjustments to reconcile net income (loss) to net cash flows from operating activities: | | Adjustments to reconcile net income (loss) to net cash flows from operating activities: | |
| | Depreciation and amortization | Depreciation and amortization | 206 | | | 201 | | Depreciation and amortization | 106 | | | 103 | |
| 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 | (14) | | | (17) | | Changes in regulatory assets and liabilities | (9) | | | (8) | |
| Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 12 | | | (20) | | Deferred income taxes and amortization of investment tax credits | (10) | | | 5 | |
| Deferred energy | Deferred energy | (159) | | | (1) | | Deferred energy | (370) | | | (51) | |
| Amortization of deferred energy | Amortization of deferred energy | 46 | | | 7 | | Amortization of deferred energy | 52 | | | 13 | |
| Other, net | Other, net | 10 | | | — | | Other, net | 1 | | | 4 | |
| 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 | (154) | | | (83) | | Trade receivables and other assets | 74 | | | 33 | |
| Inventories | Inventories | (4) | | | 5 | | Inventories | (13) | | | 3 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 18 | | | 21 | | Accrued property, income and other taxes | 1 | | | (15) | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 194 | | | 116 | | Accounts payable and other liabilities | (44) | | | 3 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 224 | | | 310 | | Net cash flows from operating activities | (212) | | | 85 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (350) | | | (237) | | Capital expenditures | (333) | | | (189) | |
| Proceeds from repayment of affiliate note receivable | | Proceeds from repayment of affiliate note receivable | 100 | | | — | |
| | Net cash flows from investing activities | Net cash flows from investing activities | (350) | | | (237) | | Net cash flows from investing activities | (233) | | | (189) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| Proceeds from long-term debt | 300 | | | — | | |
| Net (repayments of) proceeds from long-term debt | | Net (repayments of) proceeds from long-term debt | (1) | | | 200 | |
| | Net repayment of short-term debt | (180) | | | — | | |
| Net (repayments of) proceeds from short-term debt | | Net (repayments of) proceeds from short-term debt | 33 | | | (76) | |
| | Contributions from parent | Contributions from parent | 25 | | | — | | Contributions from parent | 400 | | | — | |
| Dividends paid | — | | | (13) | | |
| | Other, net | Other, net | (9) | | | (8) | | Other, net | (5) | | | (4) | |
| Net cash flows from financing activities | Net cash flows from financing activities | 136 | | | (21) | | Net cash flows from financing activities | 427 | | | 120 | |
| | 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 | 10 | | | 52 | | Net change in cash and cash equivalents and restricted cash and cash equivalents | (18) | | | 16 | |
| 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 | | | 36 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 60 | | | 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 | $ | 55 | | | $ | 88 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 42 | | | $ | 61 | |
| | 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 U.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 June 30, 2022March 31, 2023, and for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The results of operations for the three- and six-month periodsthree-month period ended June 30, 2022March 31, 2023, 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, 20212022, 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 accounting policies or its assumptions regarding significant accounting estimates and policies during the six-monththree-month period ended June 30, 2022.March 31, 2023.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.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 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 presented inon 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 | | March 31, | | December 31, |
| | June 30, | | December 31, | | 2023 | | 2022 |
| | 2022 | | 2021 | | | | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 42 | | | $ | 33 | | Cash and cash equivalents | $ | 23 | | | $ | 43 | |
| Restricted cash and cash equivalents included in other current assets | Restricted cash and cash equivalents included in other current assets | 13 | | | 12 | | Restricted cash and cash equivalents included in other current assets | 19 | | | 17 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 55 | | | $ | 45 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 42 | | | $ | 60 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | As of | | As of |
| | Depreciable Life | | June 30, | | December 31, | | Depreciable Life | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Utility plant: | Utility plant: | | | | | | Utility plant: | | | | | |
| Generation | Generation | 30 - 55 years | | $ | 3,879 | | | $ | 3,793 | | Generation | 30 - 55 years | | $ | 3,977 | | | $ | 3,977 | |
| Transmission | Transmission | 45 - 70 years | | 1,527 | | | 1,503 | | Transmission | 45 - 70 years | | 1,569 | | | 1,562 | |
| Distribution | Distribution | 20 - 65 years | | 4,021 | | | 3,920 | | Distribution | 20 - 65 years | | 4,189 | | | 4,134 | |
| General and intangible plant | General and intangible plant | 5 - 65 years | | 834 | | | 836 | | General and intangible plant | 5 - 65 years | | 887 | | | 871 | |
| Utility plant | Utility plant | | 10,261 | | | 10,052 | | Utility plant | | 10,622 | | | 10,544 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (3,517) | | | (3,406) | | Accumulated depreciation and amortization | | (3,677) | | | (3,624) | |
| Utility plant, net | Utility plant, net | | 6,744 | | | 6,646 | | Utility plant, net | | 6,945 | | | 6,920 | |
| Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | | |
| Plant, net | | 6,745 | | | 6,647 | | |
| Non-regulated, net of accumulated depreciation and amortization | | Non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | |
| | | | 6,946 | | | 6,921 | |
| Construction work-in-progress | Construction work-in-progress | | 370 | | | 244 | | Construction work-in-progress | | 703 | | | 485 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 7,115 | | | $ | 6,891 | | Property, plant and equipment, net | | $ | 7,649 | | | $ | 7,406 | |
(4) Recent Financing Transactions
Long-Term Debt
In January 2022,March 2023, Nevada Power repurchased and entered into a $300re-offering of the following series of fixed-rate tax-exempt bonds: $40 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interestof its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County, Nevada Revenue Bonds, Series 2017, due 2036. The Coconino Series 2017A bond was offered 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 interestfixed rate of 0.55%. In May 2022, Nevada Power drew4.125% and the remaining $100 million available under the facilityCoconino Series 2017B and Clark Series 2017 bonds were offered at an initial interesta fixed rate of 1.24%3.750%. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
Credit Facilities
In June 2022, Nevada Power amended and restated its existing $400 million secured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from the London Interbank Offered Rate to SOFR.
(5) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income (loss) before income tax benefitexpense (benefit) is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Six-Month Periods |
| Ended June 30, | | Ended June 30, |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | | |
| Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| Effects of ratemaking | (10) | | | (11) | | | (10) | | | (11) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Other | 1 | | | — | | | 1 | | | — | |
| Effective income tax rate | 12 | % | | 10 | % | | 12 | % | | 10 | % |
| | | | | | | | | | | |
| Three-Month Period | | |
| Ended March 31, | | |
| 2023 | | | | | | |
| | | | | | | |
| Federal statutory income tax rate | 21 | % | | | | | | |
| Effects of ratemaking | (9) | | | | | | | |
| | | | | | | |
| Income tax credits | (2) | | | | | | | |
| | | | | | | |
| Other | 10 | | | | | | | |
| Effective income tax rate | 20 | % | | | | | | |
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 periodthree-month periods ended June 30,March 31, 2023 and 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 netno cash payments for federal income tax to BHE totaling $15 million.BHE.
(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 |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Qualified Pension Plan: | Qualified Pension Plan: | | | | Qualified Pension Plan: | | | |
| Other non-current assets | Other non-current assets | $ | 42 | | | $ | 42 | | Other non-current assets | $ | 26 | | | $ | 27 | |
| | | 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 | (6) | | | (6) | |
| | Other Postretirement Plans: | Other Postretirement Plans: | | Other Postretirement Plans: | |
| Other non-current assets | Other non-current assets | 8 | | | 8 | | Other non-current assets | 7 | | | 7 | |
|
(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 and 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 | | | | | Derivative | |
| | Other | | Contracts - | | Other | | | Other | | | Contracts - | | Other | |
| | Current | | Other | | Current | | Long-term | | | Current | | | Current | | Long-term | |
| | Assets | | Assets | | Liabilities | | Liabilities | | Total | | Assets | | | Liabilities | | Liabilities | | Total |
| | As of June 30, 2022 | | |
| As of March, 31 2023 | | As of March, 31 2023 | | | |
Not designated as hedging contracts(1): | Not designated as hedging contracts(1): | | Not designated as hedging contracts(1): | | | |
| Commodity assets | Commodity assets | $ | — | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | Commodity assets | $ | 4 | | | | $ | — | | | $ | — | | | $ | 4 | |
| Commodity liabilities | Commodity liabilities | — | | | — | | | (122) | | | (54) | | | (176) | | Commodity liabilities | — | | | | (90) | | | (30) | | | (120) | |
| | Total derivative - net basis | $ | — | | | $ | 1 | | | $ | (122) | | | $ | (54) | | | $ | (175) | | |
| Total derivatives - net basis | | Total derivatives - net basis | $ | 4 | | | | $ | (90) | | | $ | (30) | | | $ | (116) | |
| | As of December 31, 2021 | | |
| As of December 31, 2022 | | As of December 31, 2022 | | | |
Not designated as hedging contracts(1): | Not designated as hedging contracts(1): | | Not designated as hedging contracts(1): | | | |
| Commodity assets | Commodity assets | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 4 | | Commodity assets | $ | 23 | | | | $ | — | | | $ | — | | | $ | 23 | |
| Commodity liabilities | Commodity liabilities | — | | | — | | | (55) | | | (62) | | | (117) | | Commodity liabilities | — | | | | (51) | | | (24) | | | (75) | |
| | Total derivative - net basis | $ | 4 | | | $ | — | | | $ | (55) | | | $ | (62) | | | $ | (113) | | |
| Total derivatives - net basis | | Total derivatives - net basis | $ | 23 | | | | $ | (51) | | | $ | (24) | | | $ | (52) | |
(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of June 30, 2022March 31, 2023 a regulatory asset of $175$116 million was recorded related to the net derivative liability of $175$116 million. As of December 31, 20212022 a regulatory asset of $113$52 million was recorded related to the net derivative liability of $113$52 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, | | Unit of | | March 31, | | December 31, |
| | Measure | | 2022 | | 2021 | | Measure | | 2023 | | 2022 |
| | Electricity purchases | Electricity purchases | Megawatt hours | | 3 | | | 1 | | Electricity purchases | Megawatt hours | | 2 | | | 2 | |
| Natural gas purchases | Natural gas purchases | Decatherms | | 113 | | | 119 | | Natural gas purchases | Decatherms | | 155 | | | 109 | |
|
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,March 31, 2023, 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$10 million and $6$5 million as of June 30, 2022March 31, 2023 and December 31, 2021,2022, 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 SheetsFinancial 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 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 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 June 30, 2022: | | | | | | | | |
| As of March 31, 2023: | | As of March 31, 2023: | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | | Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | |
| Money market mutual funds | Money market mutual funds | 34 | | | — | | | — | | | 34 | | Money market mutual funds | 21 | | | — | | | — | | | 21 | |
| Investment funds | Investment funds | 3 | | | — | | | — | | | 3 | | Investment funds | 3 | | | — | | | — | | | 3 | |
| | $ | 37 | | | $ | — | | | $ | 1 | | | $ | 38 | | | $ | 24 | | | $ | — | | | $ | 4 | | | $ | 28 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (176) | | | $ | (176) | | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (120) | | | $ | (120) | |
| | As of December 31, 2021: | | |
| As of December 31, 2022: | | As of December 31, 2022: | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | | Commodity derivatives | $ | — | | | $ | — | | | $ | 23 | | | $ | 23 | |
| Money market mutual funds | Money market mutual funds | 34 | | | — | | | — | | | 34 | | Money market mutual funds | 34 | | | — | | | — | | | 34 | |
| Investment funds | Investment funds | 3 | | | — | | | — | | | 3 | | Investment funds | 3 | | | — | | | — | | | 3 | |
| | $ | 37 | | | $ | — | | | $ | 4 | | | $ | 41 | | | $ | 37 | | | $ | — | | | $ | 23 | | | $ | 60 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (117) | | | $ | (117) | | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (75) | | | $ | (75) | |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of June 30, 2022March 31, 2023 and December 31, 2021,2022, 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 | | Six-Month Periods | | Three-Month Periods | |
| | Ended June 30, | | Ended June 30, | | Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| | Beginning balance | Beginning balance | $ | (168) | | | $ | 27 | | | $ | (113) | | | $ | 15 | | Beginning balance | $ | (52) | | | $ | (113) | | |
| Changes in fair value recognized in regulatory assets | Changes in fair value recognized in regulatory assets | (21) | | | (6) | | | (77) | | | 5 | | Changes in fair value recognized in regulatory assets | (65) | | | (56) | | |
| | Settlements | Settlements | 14 | | | 4 | | | 15 | | | 5 | | Settlements | 1 | | | 1 | | |
| Ending balance | Ending balance | $ | (175) | | | $ | 25 | | | $ | (175) | | | $ | 25 | | Ending balance | $ | (116) | | | $ | (168) | | |
Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long‑term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 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 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of March 31, 2023 | | As of December 31, 2022 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
| Long-term debt | $ | 3,195 | | | $ | 3,241 | | | $ | 3,195 | | | $ | 3,114 | |
(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.
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.
(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 | | Six-Month Periods | | Three-Month Periods | |
| | Ended June 30, | | Ended June 30, | | Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| Customer Revenue: | Customer Revenue: | | | | | | | | Customer Revenue: | | | | |
| Retail: | Retail: | | Retail: | | |
| Residential | Residential | $ | 353 | | | $ | 326 | | | $ | 566 | | | $ | 521 | | Residential | $ | 293 | | | $ | 214 | | |
| Commercial | Commercial | 131 | | | 110 | | | 226 | | | 194 | | Commercial | 136 | | | 96 | | |
| Industrial | Industrial | 124 | | | 95 | | | 203 | | | 158 | | Industrial | 138 | | | 78 | | |
| Other | Other | 3 | | | 3 | | | 4 | | | 6 | | Other | 6 | | | 1 | | |
| Total fully bundled | Total fully bundled | 611 | | | 534 | | | 999 | | | 879 | | Total fully bundled | 573 | | | 389 | | |
| Distribution only service | Distribution only service | 5 | | | 5 | | | 10 | | | 10 | | Distribution only service | 3 | | | 5 | | |
| Total retail | Total retail | 616 | | | 539 | | | 1,009 | | | 889 | | Total retail | 576 | | | 394 | | |
| Wholesale, transmission and other | Wholesale, transmission and other | 18 | | | 15 | | | 34 | | | 29 | | Wholesale, transmission and other | 18 | | | 16 | | |
| Total Customer Revenue | Total Customer Revenue | 634 | | | 554 | | | 1,043 | | | 918 | | Total Customer Revenue | 594 | | | 410 | | |
| Other revenue | Other revenue | 5 | | | 5 | | | 11 | | | 11 | | Other revenue | 5 | | | 5 | | |
| Total revenue | $ | 639 | | | $ | 559 | | | $ | 1,054 | | | $ | 929 | | |
| Total operating revenue | | Total operating revenue | $ | 599 | | | $ | 415 | | |
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 SecondFirst Quarter of 2023 and First Six Months of 2022 and 2021
Overview
Net income for the secondfirst quarter of 20222023 was $76$4 million, a decreasean increase of $6 million, or 7%, compared to 20212022 primarily due to $7 million of unfavorable other, net,higher interest and dividend income, mainly due to lowerfrom higher carrying charges on regulatory balances, higher utility margin and higher cash surrender value of corporate-owned life insurance policies, $4 million of lower utility marginpartially offset by higher interest expense, primarily due to higher long-term debt, higher operations and $3 million ofmaintenance expenses, mainly due to higher customer service operations expenses and higher plant operations and maintenance expenses, and higher depreciation and amortization, mainly due to higher plant placed in-service. Utility margin decreasedincreased primarily due to unfavorable price impacts from changes in sales mix, the unfavorable impact of weather and lowerhigher retail customer volumes, higher other retail revenue partially offset byand higher regulatory-related revenue deferrals,deferrals. Retail customer volumes, including distribution only service customers, increased 3.3% primarily due to an increase in the average number of customers and the favorable changes in customer usage patterns. These decreases are offset by $6 millionimpact of higher interest and dividend income, mainly from carrying charges on regulatory balances, and $2 millionweather. Energy generated increased 37% for the first quarter of lower operations and maintenance expenses, mainly2023 compared to 2022 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%decreased 50% 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 higher plant placed in-service. Utility margin decreased primarily due to unfavorable 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 $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%35%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as electric operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
Nevada Power's cost of fuel and energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Utility margin: | Utility margin: | | | | | | | | | | | | | Utility margin: | | | | | | | |
| Operating revenue | Operating revenue | | $ | 639 | | | $ | 559 | | | $ | 80 | | 14 | % | | $ | 1,054 | | | $ | 929 | | | $ | 125 | | 13 | % | Operating revenue | | $ | 599 | | | $ | 415 | | | $ | 184 | | 44 | % | |
| Cost of fuel and energy | Cost of fuel and energy | | 336 | | | 252 | | | 84 | | 33 | | | 548 | | | 417 | | | 131 | | 31 | | Cost of fuel and energy | | 384 | | | 212 | | | 172 | | 81 | | |
| Utility margin | Utility margin | | 303 | | | 307 | | | (4) | | (1) | | | 506 | | | 512 | | | (6) | | (1) | | Utility margin | | 215 | | | 203 | | | 12 | | 6 | | |
| Operations and maintenance | Operations and maintenance | | 75 | | | 77 | | | (2) | | (3) | | | 140 | | | 140 | | | — | | — | | Operations and maintenance | | 73 | | | 65 | | | 8 | | 12 | | |
| Depreciation and amortization | Depreciation and amortization | | 103 | | | 100 | | | 3 | | 3 | | | 206 | | | 201 | | | 5 | | 2 | | Depreciation and amortization | | 106 | | | 103 | | | 3 | | 3 | | |
| Property and other taxes | Property and other taxes | | 12 | | | 12 | | | — | | — | | | 25 | | | 24 | | | 1 | | 4 | | Property and other taxes | | 14 | | | 13 | | | 1 | | 8 | | |
| Operating income | Operating income | | $ | 113 | | | $ | 118 | | | $ | (5) | | (4) | % | | $ | 135 | | | $ | 147 | | | $ | (12) | | (8) | % | Operating income | | $ | 22 | | | $ | 22 | | | $ | — | | — | % | |
Utility Margin
A comparison of key operating results related to utility margin is as follows:
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | | Utility margin (in millions): | | | | | | | |
| Operating revenue | Operating revenue | | $ | 639 | | | $ | 559 | | | $ | 80 | | 14 | % | | $ | 1,054 | | | $ | 929 | | | $ | 125 | | 13 | % | Operating revenue | | $ | 599 | | | $ | 415 | | | $ | 184 | | 44 | % | |
| Cost of fuel and energy | Cost of fuel and energy | | 336 | | | 252 | | | 84 | | 33 | | | 548 | | | 417 | | | 131 | | 31 | | Cost of fuel and energy | | 384 | | | 212 | | | 172 | | 81 | | |
| Utility margin | Utility margin | | $ | 303 | | | $ | 307 | | | $ | (4) | | (1) | % | | $ | 506 | | | $ | 512 | | | $ | (6) | | (1) | % | Utility margin | | $ | 215 | | | $ | 203 | | | $ | 12 | | 6 | % | |
| | Sales (GWhs): | Sales (GWhs): | | Sales (GWhs): | | |
| Residential | Residential | | 2,612 | | | 2,807 | | | (195) | | (7) | % | | 4,197 | | | 4,394 | | | (197) | | (4) | % | Residential | | 1,636 | | | 1,585 | | | 51 | | 3 | % | |
| Commercial | Commercial | | 1,272 | | | 1,271 | | | 1 | | — | | | 2,270 | | | 2,225 | | | 45 | | 2 | | Commercial | | 997 | | | 998 | | | (1) | | — | | |
| Industrial | Industrial | | 1,409 | | | 1,310 | | | 99 | | 8 | | | 2,584 | | | 2,367 | | | 217 | | 9 | | Industrial | | 1,242 | | | 1,175 | | | 67 | | 6 | | |
| Other | Other | | 46 | | | 45 | | | 1 | | 2 | | | 92 | | | 92 | | | — | | — | | Other | | 43 | | | 46 | | | (3) | | (7) | | |
Total fully bundled(1) | Total fully bundled(1) | | 5,339 | | | 5,433 | | | (94) | | (2) | | | 9,143 | | | 9,078 | | | 65 | | 1 | | Total fully bundled(1) | | 3,918 | | | 3,804 | | | 114 | | 3 | | |
| Distribution only service | Distribution only service | | 661 | | | 620 | | | 41 | | 7 | | | 1,230 | | | 1,136 | | | 94 | | 8 | | Distribution only service | | 598 | | | 569 | | | 29 | | 5 | | |
| Total retail | Total retail | | 6,000 | | | 6,053 | | | (53) | | (1) | | | 10,373 | | | 10,214 | | | 159 | | 2 | | Total retail | | 4,516 | | | 4,373 | | | 143 | | 3 | | |
| Wholesale | Wholesale | | 210 | | | 89 | | | 121 | | * | | 335 | | | 173 | | | 162 | | 94 | | Wholesale | | 63 | | | 125 | | | (62) | | (50) | | |
| Total GWhs sold | Total GWhs sold | | 6,210 | | | 6,142 | | | 68 | | 1 | % | | 10,708 | | | 10,387 | | | 321 | | 3 | % | Total GWhs sold | | 4,579 | | | 4,498 | | | 81 | | 2 | % | |
| | Average number of retail customers (in thousands) | Average number of retail customers (in thousands) | | 1,000 | | | 982 | | | 18 | | 2 | % | | 997 | | | 980 | | | 17 | | 2 | % | Average number of retail customers (in thousands) | | 999 | | | 995 | | | 4 | | — | % | |
| | | Average revenue per MWh: | Average revenue per MWh: | | Average revenue per MWh: | | |
Retail - fully bundled(1) | Retail - fully bundled(1) | | $ | 114.36 | | | $ | 98.10 | | | $ | 16.26 | | 17 | % | | $ | 109.26 | | | $ | 96.86 | | | $ | 12.40 | | 13 | % | Retail - fully bundled(1) | | $ | 146.17 | | | $ | 102.11 | | | $ | 44.06 | | 43 | % | |
| | Wholesale | Wholesale | | $ | 34.36 | | | $ | 42.94 | | | $ | (8.58) | | (20) | % | | $ | 37.55 | | | $ | 46.09 | | | $ | (8.54) | | (19) | % | Wholesale | | $ | 98.31 | | | $ | 42.91 | | | $ | 55.40 | | * | |
| | Heating degree days | Heating degree days | | 31 | | | 14 | | | 17 | | * | | 985 | | | 1,008 | | | (23) | | (2) | % | Heating degree days | | 1,310 | | | 954 | | | 356 | | 37 | % | |
| Cooling degree days | Cooling degree days | | 1,322 | | | 1,477 | | | (155) | | (10) | % | | 1,371 | | | 1,483 | | | (112) | | (8) | % | Cooling degree days | | 3 | | | 49 | | | (46) | | (94) | % | |
| Sources of energy (GWhs)(2)(3): | Sources of energy (GWhs)(2)(3): | | Sources of energy (GWhs)(2)(3): | | |
| Natural gas | Natural gas | | 2,935 | | | 3,547 | | | (612) | | (17) | % | | 5,313 | | | 6,081 | | | (768) | | (13) | % | Natural gas | | 3,263 | | | 2,378 | | | 885 | | 37 | % | |
| | Renewables | Renewables | | 20 | | | 20 | | | — | | — | | | 34 | | | 36 | | | (2) | | (6) | | Renewables | | 15 | | | 14 | | | 1 | | 7 | | |
| Total energy generated | Total energy generated | | 2,955 | | | 3,567 | | | (612) | | (17) | | | 5,347 | | | 6,117 | | | (770) | | (13) | | Total energy generated | | 3,278 | | | 2,392 | | | 886 | | 37 | | |
| Energy purchased | Energy purchased | | 2,472 | | | 2,104 | | | 368 | | 17 | | | 4,233 | | | 3,459 | | | 774 | | 22 | | Energy purchased | | 1,137 | | | 1,761 | | | (624) | | (35) | | |
| Total | Total | | 5,427 | | | 5,671 | | | (244) | | (4) | % | | 9,580 | | | 9,576 | | | 4 | | — | % | Total | | 4,415 | | | 4,153 | | | 262 | | 6 | % | |
| 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 | | $ | 49.65 | | | $ | 21.82 | | | $ | 27.83 | | * | | $ | 46.19 | | | $ | 18.96 | | | $ | 27.23 | | * | Energy generated | | $ | 90.64 | | | $ | 41.92 | | | $ | 48.72 | | * | |
| Energy purchased | Energy purchased | | $ | 76.63 | | | $ | 82.70 | | | $ | (6.07) | | (7) | % | | $ | 71.07 | | | $ | 87.07 | | | $ | (16.00) | | (18) | % | Energy purchased | | $ | 76.11 | | | $ | 63.27 | | | $ | 12.84 | | 20 | % | |
* 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 360283 GWhs and 249 GWhs of gas generated energy that is purchased at cost by related parties for the second quarter of 2022 and 2021, respectively. The average cost of energy per MWh and sources of energy excludes 784 GWhs and 932424 GWhs of gas generated energy that is purchased at cost by related parties for the first six monthsquarter of 20222023 and 2021,2022, 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.
Quarter Ended June 30, 2022March 31, 2023 Compared to Quarter Ended June 30, 2021March 31, 2022
Utility margin decreased $4increased $12 million, or 1%6%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to:
•$73 million of lowerhigher electric retail utility margin due to unfavorable price impacts from changes in sales mix and lowerhigher retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 0.9%increased 3.3% primarily due to the unfavorable impact of weather, offset by an increase in the average number of customers and the favorable changes in customer usage patterns;impact of weather;
•$3 million of lowerhigher energy efficiency program rates (offset in operations and maintenance expense);
•$3 million of higher other retail revenue; and
•$1 million of lower other retail revenue.
The decrease in utility margin was offset by:
•$72 million of higher regulatory-related revenue deferrals.
Operations and maintenance decreased $2increased $8 million, or 3%12%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to lowerhigher customer service operations expenses, higher energy efficiency program costs (offset in operating revenue) and lowerhigher plant operations and maintenance expenses, partially offset by higher earnings sharing.expenses.
Depreciation and amortization increased $3 million, or 3%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to higher plant placed in-service.
Interest expense increased $11 million, or 29%, for the first quarter of 2023 compared to 2022 primarily due to higher long-term debt.
Interest and dividend income increased $6$13 million for the secondfirst quarter of 20222023 compared to 20212022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net is unfavorable $7increased $3 million for the secondfirst quarter of 20222023 compared to 20212022 primarily due to lowerhigher cash surrender value of corporate-owned life insurance policies.
First Six Months Ended June 30, 2022 Compared to First Six Months Ended June 30, 2021
Utility margin decreased $6 million, or 1%, for the first six months of 2022 compared to 2021 primarily due to:
•$5 million of lower energy efficiency program rates (offset in operations and maintenance expense);
•$4 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 increase in the average number of customers and favorable changes in customer usage patterns, offset by the unfavorable impact of weather; and
•$3 million of lower other retail revenue.
The decrease in utility margin was offset by:
•$5 million of higher regulatory-related revenue deferrals; and
•$1 million of higher transmission and wholesale revenue.
Operations and maintenance was consistent for the first six months of 2022 compared to 2021 primarily due to higher earnings sharing and higher plant operations and maintenance expenses, offset by lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $5 million, or 2%, for the first six months of 2022 compared to 2021 primarily due to higher plant placed in-service.
Interest and dividend income increased $10 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 is unfavorable $10 million for the first six months of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies.
Liquidity and Capital Resources
As of June 30, 2022,March 31, 2023, Nevada Power's total net liquidity was as follows (in millions):
| | | | | | | | |
| Cash and cash equivalents | | $ | 4223 | |
| | |
| Credit facility | | 400 | |
| Less - | | |
| Short-term debt | | (33) | |
| | |
| Net credit facility | | 367 | |
| | |
| Total net liquidity | | 442 $ | |
| | |
| 390 | |
| Credit facility: | | |
| Maturity date | | 2025 |
Operating Activities
Net cash flows from operating activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $224$(212) million and $310$85 million, respectively. The change was primarily due to higher payments related to fuel and energy costs, and the timing of payments for operating costs, partially offset by higher collections from customerscustomers.
The timing of Nevada Power's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and lower paymentsassumptions made for income taxes.each payment date.
Investing Activities
Net cash flows from investing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $(350)$(233) million and $(237)$(189) million, respectively. The change was primarily due to increased capital expenditures.expenditures, offset by the repayment of an affiliate note receivable. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $136$427 million and $(21)$120 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and higher proceeds from short-term debt, partially offset by lower proceeds from the issuance of long-term debt and contributions from NV Energy, Inc., partially offset by higher repayments of short-term debt.
Long-Term Debt
In January 2022,March 2023, Nevada Power repurchased and entered into a $300re-offering of the following series of fixed-rate tax-exempt bonds: $40 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interestof its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County, Nevada Revenue Bonds, Series 2017, due 2036. The Coconino Series 2017A bond was offered 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 interestfixed rate of 0.55%. In May 2022, Nevada Power drew4.125% and the remaining $100 million available under the facilityCoconino Series 2017B and Clark Series 2017 bonds were offered at an initial interesta fixed rate of 1.24%. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.3.750%
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 $3.8 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 amountup to $2.6 billion of general and refunding mortgage securities through October 2022.November 2025.
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'customer 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.
HistoricalNevada Power's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
| | | Six-Month Periods | | Annual | | Three-Month Periods | | Annual |
| | Ended June 30, | | Forecast | | Ended March 31, | | Forecast |
| | 2021 | | 2022 | | 2022 | | 2022 | | 2023 | | 2023 |
| | Electric distribution | Electric distribution | $ | 87 | | | $ | 108 | | | $ | 234 | | Electric distribution | $ | 51 | | | $ | 69 | | | $ | 285 | |
| Electric transmission | Electric transmission | 25 | | | 39 | | | 141 | | Electric transmission | 21 | | | 34 | | | 130 | |
| Solar generation | Solar generation | 5 | | | 23 | | | 90 | | Solar generation | 7 | | | 30 | | | 205 | |
| Electric battery storage | | Electric battery storage | — | | | 39 | | | 190 | |
| Other | Other | 120 | | | 180 | | | 359 | | Other | 110 | | | 161 | | | 528 | |
| Total | Total | $ | 237 | | | $ | 350 | | | $ | 824 | | Total | $ | 189 | | | $ | 333 | | | $ | 1,338 | |
Nevada Power received PUCN approval through its recentprevious IRP filings for an increase in solar generation and electric transmission.transmission and through the fourth amendment to its 2021 Joint IRP filing for the addition of peaking turbines at a generating facility. Nevada Power has included estimates from its previous and latest IRP filingfilings in its forecast capital expenditures for 2022.2023. 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. In this project, the companyNevada Power 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;substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations.substation. 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-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Electric battery storage includes two growth projects consisting of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 220-MW grid-tied battery energy storage system that will be developed on the site of the retired Reid Gardner generating facility in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Other includes both growth projects and operating expenditures. Growth projects primarily consist of an additional 400 MW of peaking combustion turbines that will be developed at the Silverhawk generating facility in Clark County, Nevada. Commercial operation is expected by the third quarter of 2024. Operating expenditures consistingconsist of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of June 30, 2022,March 31, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2021,2022, 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
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 air quality, climate change, RPS, air and water quality, emissions performance standards, water quality, coal combustion byproductash 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, 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. Nevada Power 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 Nevada Power 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, 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, 2021.2022. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2021.2022.
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 June 30, 2022,March 31, 2023, the related consolidated statements of operations, and changes in shareholder's equity, for the three-month and six-month periods ended June 30, 2022 and 2021, and of cash flows for the six-monththree-month periods ended June 30,March 31, 2023 and 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 Sierra Pacific as of December 31, 2021,2022, 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 25, 2022,24, 2023, 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, 2021,2022, 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
AugustMay 5, 20222023
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | As of | | As of |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 17 | | | $ | 10 | | Cash and cash equivalents | $ | 8 | | | $ | 49 | |
| Trade receivables, net | Trade receivables, net | 127 | | | 128 | | Trade receivables, net | 181 | | | 175 | |
| | Inventories | Inventories | 75 | | | 65 | | Inventories | 83 | | | 79 | |
| | Regulatory assets | Regulatory assets | 207 | | | 177 | | Regulatory assets | 310 | | | 357 | |
| | Other current assets | Other current assets | 25 | | | 35 | | Other current assets | 34 | | | 50 | |
| Total current assets | Total current assets | 451 | | | 415 | | Total current assets | 616 | | | 710 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 3,476 | | | 3,340 | | Property, plant and equipment, net | 3,622 | | | 3,587 | |
| | Regulatory assets | Regulatory assets | 282 | | | 263 | | Regulatory assets | 261 | | | 254 | |
| Other assets | Other assets | 206 | | | 205 | | Other assets | 184 | | | 181 | |
| | Total assets | Total assets | $ | 4,415 | | | $ | 4,223 | | Total assets | $ | 4,683 | | | $ | 4,732 | |
| | 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 | $ | 177 | | | $ | 147 | | Accounts payable | $ | 162 | | | $ | 224 | |
| | Accrued property, income and other taxes | 18 | | | 16 | | |
| Short-term debt | — | | | 159 | | |
| Note payable to affiliate | | Note payable to affiliate | — | | | 70 | |
| | Regulatory liabilities | 18 | | | 19 | | |
| Customer deposits | 16 | | | 15 | | |
| Derivative contracts | 38 | | | 16 | | |
| Short-term debt | | Short-term debt | 50 | | | — | |
| Current portion of long-term debt | | Current portion of long-term debt | 250 | | | 250 | |
| | Other current liabilities | Other current liabilities | 48 | | | 42 | | Other current liabilities | 140 | | | 108 | |
| Total current liabilities | Total current liabilities | 315 | | | 414 | | Total current liabilities | 602 | | | 652 | |
| | Long-term debt | Long-term debt | 1,148 | | | 1,164 | | Long-term debt | 898 | | | 898 | |
| | Finance lease obligations | | Finance lease obligations | 98 | | | 100 | |
| Regulatory liabilities | Regulatory liabilities | 435 | | | 444 | | Regulatory liabilities | 428 | | | 436 | |
| Deferred income taxes | Deferred income taxes | 413 | | | 402 | | Deferred income taxes | 438 | | | 445 | |
| Other long-term liabilities | Other long-term liabilities | 258 | | | 264 | | Other long-term liabilities | 144 | | | 153 | |
| Total liabilities | Total liabilities | 2,569 | | | 2,688 | | Total liabilities | 2,608 | | | 2,684 | |
| | Commitments and contingencies (Note 9) | 0 | | 0 | |
| Commitments and contingencies (Note 8) | | Commitments and contingencies (Note 8) | |
| | 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 | 1,451 | | | 1,111 | | Additional paid-in capital | 1,576 | | | 1,576 | |
| Retained earnings | Retained earnings | 396 | | | 425 | | Retained earnings | 500 | | | 473 | |
| 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 | 1,846 | | | 1,535 | | Total shareholder's equity | 2,075 | | | 2,048 | |
| | Total liabilities and shareholder's equity | Total liabilities and shareholder's equity | $ | 4,415 | | | $ | 4,223 | | Total liabilities and shareholder's equity | $ | 4,683 | | | $ | 4,732 | |
| | 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 | | Six-Month Periods | | Three-Month Periods | |
| | Ended June 30, | | Ended June 30, | | Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | |
| Regulated electric | Regulated electric | $ | 230 | | | $ | 189 | | | $ | 457 | | | $ | 370 | | Regulated electric | $ | 304 | | | $ | 227 | | |
| Regulated natural gas | Regulated natural gas | 28 | | | 20 | | | 80 | | | 59 | | Regulated natural gas | 96 | | | 52 | | |
| Total operating revenue | Total operating revenue | 258 | | | 209 | | | 537 | | | 429 | | Total operating revenue | 400 | | | 279 | | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | | |
| Cost of fuel and energy | Cost of fuel and energy | 129 | | | 93 | | | 253 | | | 175 | | Cost of fuel and energy | 181 | | | 124 | | |
| Cost of natural gas purchased for resale | Cost of natural gas purchased for resale | 16 | | | 8 | | | 50 | | | 29 | | Cost of natural gas purchased for resale | 75 | | | 34 | | |
| Operations and maintenance | Operations and maintenance | 47 | | | 41 | | | 88 | | | 77 | | Operations and maintenance | 56 | | | 41 | | |
| Depreciation and amortization | Depreciation and amortization | 37 | | | 36 | | | 73 | | | 72 | | Depreciation and amortization | 46 | | | 36 | | |
| Property and other taxes | Property and other taxes | 6 | | | 6 | | | 12 | | | 12 | | Property and other taxes | 7 | | | 6 | | |
| Total operating expenses | Total operating expenses | 235 | | | 184 | | | 476 | | | 365 | | Total operating expenses | 365 | | | 241 | | |
| | Operating income | Operating income | 23 | | | 25 | | | 61 | | | 64 | | Operating income | 35 | | | 38 | | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | | |
| Interest expense | Interest expense | (14) | | | (13) | | | (27) | | | (27) | | Interest expense | (16) | | | (13) | | |
| Allowance for borrowed funds | Allowance for borrowed funds | — | | | 1 | | | 1 | | | 1 | | Allowance for borrowed funds | 2 | | | 1 | | |
| Allowance for equity funds | Allowance for equity funds | 2 | | | 2 | | | 4 | | | 3 | | Allowance for equity funds | 2 | | | 2 | | |
| Interest and dividend income | Interest and dividend income | 4 | | | 1 | | | 7 | | | 3 | | Interest and dividend income | 7 | | | 3 | | |
| Other, net | Other, net | — | | | 2 | | | 2 | | | 6 | | Other, net | 1 | | | 2 | | |
| Total other income (expense) | Total other income (expense) | (8) | | | (7) | | | (13) | | | (14) | | Total other income (expense) | (4) | | | (5) | | |
| | Income before income tax expense | 15 | | | 18 | | | 48 | | | 50 | | |
| Income tax expense | 2 | | | 1 | | | 7 | | | 5 | | |
| Income before income tax expense (benefit) | | Income before income tax expense (benefit) | 31 | | | 33 | | |
| Income tax expense (benefit) | | Income tax expense (benefit) | 4 | | | 5 | | |
| Net income | Net income | $ | 13 | | | $ | 17 | | | $ | 41 | | | $ | 45 | | Net income | $ | 27 | | | $ | 28 | | |
| | 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, March 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 329 | | | $ | (1) | | | $ | 1,439 | | |
| | | Balance, December 31, 2021 | | Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 425 | | | $ | (1) | | | $ | 1,535 | |
| Net income | | Net income | | — | | | — | | | — | | | 28 | | | — | | | 28 | |
| | Contributions | | Contributions | | — | | | — | | | 130 | | | — | | | — | | | 130 | |
| | Balance, March 31, 2022 | | Balance, March 31, 2022 | | 1,000 | | | $ | — | | | $ | 1,241 | | | $ | 453 | | | $ | (1) | | | $ | 1,693 | |
| | | Balance, December 31, 2022 | | Balance, December 31, 2022 | | 1,000 | | | $ | — | | | $ | 1,576 | | | $ | 473 | | | $ | (1) | | | $ | 2,048 | |
| Net income | Net income | | — | | | — | | | — | | | 17 | | | — | | | 17 | | Net income | | — | | | — | | | — | | | 27 | | | — | | | 27 | |
| | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 346 | | | $ | (1) | | | $ | 1,456 | | |
| | Balance, December 31, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 301 | | | $ | (1) | | | $ | 1,411 | | |
| Net income | | — | | | — | | | — | | | 45 | | | — | | | 45 | | |
| | Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 346 | | | $ | (1) | | | $ | 1,456 | | |
| | Balance, March 31, 2022 | | 1,000 | | | $ | — | | | $ | 1,241 | | | $ | 453 | | | $ | (1) | | | $ | 1,693 | | |
| Net income | | — | | | — | | | — | | | 13 | | | — | | | 13 | | |
| Dividends declared | | — | | | — | | | — | | | (70) | | | — | | | (70) | | |
| Contributions | | — | | | — | | | 210 | | | — | | | — | | | 210 | | |
| | Balance, June 30, 2022 | | 1,000 | | | $ | — | | | $ | 1,451 | | | $ | 396 | | | $ | (1) | | | $ | 1,846 | | |
| | Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 425 | | | $ | (1) | | | $ | 1,535 | | |
| Net income | | — | | | — | | | — | | | 41 | | | — | | | 41 | | |
| Dividends declared | | — | | | — | | | — | | | (70) | | | — | | | (70) | | |
| Contributions | | — | | | — | | | 340 | | | — | | | — | | | 340 | | |
| | Balance, June 30, 2022 | | 1,000 | | | $ | — | | | $ | 1,451 | | | $ | 396 | | | $ | (1) | | | $ | 1,846 | | |
| Balance, March 31, 2023 | | Balance, March 31, 2023 | | 1,000 | | | $ | — | | | $ | 1,576 | | | $ | 500 | | | $ | (1) | | | $ | 2,075 | |
| | 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)
| | | Six-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended March 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 41 | | | $ | 45 | | Net income | $ | 27 | | | $ | 28 | |
| 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 | 73 | | | 72 | | Depreciation and amortization | 46 | | | 36 | |
| Allowance for equity funds | Allowance for equity funds | (4) | | | (3) | | Allowance for equity funds | (2) | | | (2) | |
| Changes in regulatory assets and liabilities | Changes in regulatory assets and liabilities | (8) | | | (20) | | Changes in regulatory assets and liabilities | 6 | | | (4) | |
| Deferred income taxes and amortization of investment tax credits | Deferred income taxes and amortization of investment tax credits | 5 | | | 8 | | Deferred income taxes and amortization of investment tax credits | (11) | | | (3) | |
| Deferred energy | Deferred energy | (67) | | | (47) | | Deferred energy | 2 | | | (7) | |
| Amortization of deferred energy | Amortization of deferred energy | 46 | | | 2 | | Amortization of deferred energy | 42 | | | 23 | |
| 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 | (1) | | | (1) | | Trade receivables and other assets | (5) | | | 12 | |
| Inventories | Inventories | (10) | | | 10 | | Inventories | (4) | | | (6) | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 3 | | | (1) | | Accrued property, income and other taxes | 17 | | | 7 | |
| Accounts payable and other liabilities | Accounts payable and other liabilities | 28 | | | 29 | | Accounts payable and other liabilities | (31) | | | (21) | |
| Net cash flows from operating activities | Net cash flows from operating activities | 108 | | | 92 | | Net cash flows from operating activities | 87 | | | 63 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (191) | | | (128) | | Capital expenditures | (104) | | | (83) | |
| | Net cash flows from investing activities | Net cash flows from investing activities | (191) | | | (128) | | Net cash flows from investing activities | (104) | | | (83) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| Proceeds from long-term debt | 249 | | | — | | |
| | Long-term debt reacquired | (265) | | | — | | |
| Net (repayment of) proceeds from short-term debt | (159) | | | 29 | | |
| Dividends paid | (70) | | | — | | |
| | Net (repayments of) proceeds from short-term debt | | Net (repayments of) proceeds from short-term debt | 50 | | | (102) | |
| | Contributions from parent | Contributions from parent | 340 | | | — | | Contributions from parent | — | | | 130 | |
| Repayments of affiliate note payable | | Repayments of affiliate note payable | (70) | | | — | |
| Other, net | Other, net | (4) | | | (4) | | Other, net | (2) | | | (2) | |
| Net cash flows from financing activities | Net cash flows from financing activities | 91 | | | 25 | | Net cash flows from financing activities | (22) | | | 26 | |
| | 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 | 8 | | | (11) | | Net change in cash and cash equivalents and restricted cash and cash equivalents | (39) | | | 6 | |
| 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 | 16 | | | 26 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 56 | | | 16 | |
| 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 | $ | 24 | | | $ | 15 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 17 | | | $ | 22 | |
| | 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 U.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 June 30, 2022March 31, 2023, and for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The results of operations for the three- and six-month periodsthree-month period ended June 30, 2022March 31, 2023, 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, 20212022, 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 accounting policies or its assumptions regarding significant accounting estimates and policies during the six-monththree-month period ended June 30, 2022.March 31, 2023.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.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 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 presented inon 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 | | March 31, | | December 31, |
| | June 30, | | December 31, | | 2023 | | 2022 |
| | 2022 | | 2021 | | | | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 17 | | | $ | 10 | | Cash and cash equivalents | $ | 8 | | | $ | 49 | |
| Restricted cash and cash equivalents included in other current assets | Restricted cash and cash equivalents included in other current assets | 7 | | | 6 | | Restricted cash and cash equivalents included in other current assets | 9 | | | 7 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 24 | | | $ | 16 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 17 | | | $ | 56 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | As of | | As of |
| | Depreciable Life | | June 30, | | December 31, | | Depreciable Life | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Utility plant: | Utility plant: | | | | | | Utility plant: | | | | | |
| Electric generation | Electric generation | 25 - 60 years | | $ | 1,297 | | | $ | 1,163 | | Electric generation | 25 - 70 years | | $ | 1,301 | | | $ | 1,298 | |
| Electric transmission | Electric transmission | 50 - 100 years | | 976 | | | 940 | | Electric transmission | 50 - 76 years | | 995 | | | 993 | |
| Electric distribution | Electric distribution | 20 - 100 years | | 1,905 | | | 1,846 | | Electric distribution | 20 - 76 years | | 1,999 | | | 1,983 | |
| Electric general and intangible plant | Electric general and intangible plant | 5 - 70 years | | 213 | | | 204 | | Electric general and intangible plant | 5 - 65 years | | 221 | | | 219 | |
| Natural gas distribution | Natural gas distribution | 35 - 70 years | | 447 | | | 438 | | Natural gas distribution | 35 - 70 years | | 459 | | | 455 | |
| Natural gas general and intangible plant | Natural gas general and intangible plant | 5 - 70 years | | 15 | | | 14 | | Natural gas general and intangible plant | 5 - 65 years | | 16 | | | 15 | |
| Common general | Common general | 5 - 70 years | | 376 | | | 370 | | Common general | 5 - 65 years | | 380 | | | 380 | |
| Utility plant | Utility plant | | 5,229 | | | 4,975 | | Utility plant | | 5,371 | | | 5,343 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (1,936) | | | (1,854) | | Accumulated depreciation and amortization | | (2,024) | | | (1,992) | |
| Utility plant, net | | 3,293 | | | 3,121 | | |
| | | | 3,347 | | | 3,351 | |
| | Construction work-in-progress | Construction work-in-progress | | 183 | | | 219 | | Construction work-in-progress | | 275 | | | 236 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 3,476 | | | $ | 3,340 | | Property, plant and equipment, net | | $ | 3,622 | | | $ | 3,587 | |
During 2022, Sierra Pacific revised its electric and gas depreciation rates effective January 2023 based on the results of a new depreciation study, the most significant impact of which was shorter average service lives for intangible software. The net effect of this change along with various changes to the average service lives of other utility plant groups will increase depreciation and amortization expense by $19 million annually based on depreciable plant balances at the time of the change.
(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 2022, Sierra Pacific amended and restated its existing $250 million secured credit facility expiring in June 2024. The amendment extended the expiration date to June 2025 and amended pricing from LIBOR to the 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 (benefit) is as follows:
| | | Three-Month Periods | | Six-Month Periods | | Three-Month Periods | |
| | Ended June 30, | | Ended June 30, | | Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % | |
| Effects of ratemaking | Effects of ratemaking | (8) | | | (11) | | | (7) | | | (9) | | Effects of ratemaking | (9) | | | (7) | | |
| | Income tax credits | — | | | (1) | | | — | | | — | | |
| | | Other | Other | — | | | (3) | | | 1 | | | (2) | | Other | 1 | | | 1 | | |
| Effective income tax rate | Effective income tax rate | 13 | % | | 6 | % | | 15 | % | | 10 | % | Effective income tax rate | 13 | % | | 15 | % | |
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.
Berkshire 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-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, Sierra Pacific made no net cash payments for federal income tax to BHE.
(6)
(5) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific contributed $2 million to the Other Postretirement Plans for the six-month period ended June 30, 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 |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Qualified Pension Plan: | Qualified Pension Plan: | | | | Qualified Pension Plan: | | | |
| | Other non-current assets | Other non-current assets | $ | 64 | | | $ | 62 | | Other non-current assets | $ | 44 | | | $ | 43 | |
| | | 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 | (7) | | | (7) | | Other long-term liabilities | (5) | | | (5) | |
| | Other Postretirement Plans: | Other Postretirement Plans: | | Other Postretirement Plans: | |
| | Other long-term liabilities | Other long-term liabilities | (8) | | | (10) | | Other long-term liabilities | (2) | | | (2) | |
(7)(6) 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 87 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 | | | Other | | | | Other | |
| | Current | | Other | | Current | | Long-term | | | Current | | | Current | | Long-term | |
| | Assets | | Assets | | Liabilities | | Liabilities | | Total | | Assets | | | Liabilities | | Liabilities | | Total |
| | As of June 30, 2022 | | |
| As of March, 31 2023 | | As of March, 31 2023 | | | |
Not designated as hedging contracts(1): | Not designated as hedging contracts(1): | | Not designated as hedging contracts(1): | | | |
| Commodity assets | Commodity assets | $ | — | | | $ | 1 | | | $ | — | | | $ | — | | | $ | 1 | | Commodity assets | $ | 1 | | | | $ | — | | | $ | — | | | $ | 1 | |
| Commodity liabilities | Commodity liabilities | — | | | — | | | (38) | | | (17) | | | (55) | | Commodity liabilities | — | | | | (27) | | | (7) | | | (34) | |
| | Total derivative - net basis | $ | — | | | $ | 1 | | | $ | (38) | | | $ | (17) | | | $ | (54) | | |
| Total derivatives - net basis | | Total derivatives - net basis | $ | 1 | | | | $ | (27) | | | $ | (7) | | | $ | (33) | |
| | As of December 31, 2021 | | |
| As of December 31, 2022 | | As of December 31, 2022 | | | |
Not designated as hedging contracts(1): | Not designated as hedging contracts(1): | | Not designated as hedging contracts(1): | | | |
| Commodity assets | Commodity assets | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2 | | Commodity assets | $ | 8 | | | | $ | — | | | $ | — | | | $ | 8 | |
| Commodity liabilities | Commodity liabilities | — | | | — | | | (16) | | | (19) | | | (35) | | Commodity liabilities | — | | | | (14) | | | (7) | | | (21) | |
| | Total derivative - net basis | $ | 2 | | | $ | — | | | $ | (16) | | | $ | (19) | | | $ | (33) | | |
| Total derivatives - net basis | | Total derivatives - net basis | $ | 8 | | | | $ | (14) | | | $ | (7) | | | $ | (13) | |
(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 DecemberMarch 31, 20212023 a net regulatory asset of $33 million was recorded related to the net derivative liability of $33 million. As of December 31, 2022 a net regulatory asset of $13 million was recorded related to the net derivative liability of $13 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, | | Unit of | | March 31, | | December 31, |
| | Measure | | 2022 | | 2021 | | Measure | | 2023 | | 2022 |
| | Electricity purchases | Electricity purchases | Megawatt hours | | 1 | | | 1 | | Electricity purchases | Megawatt hours | | 1 | | | 1 | |
| Natural gas purchases | Natural gas purchases | Decatherms | | 50 | | | 53 | | Natural gas purchases | Decatherms | | 67 | | | 52 | |
|
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,March 31, 2023, 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 $1 million and $— million as of June 30, 2022March 31, 2023 and December 31, 2021,2022, 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. 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.
(8)(7) Fair Value Measurements
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Consolidated Balance SheetsFinancial 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 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 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 June 30, 2022: | | | | | | | | |
| As of March 31, 2023: | | As of March 31, 2023: | | | | | | | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | | Commodity derivatives | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | |
| Money market mutual funds | Money market mutual funds | 14 | | | — | | | — | | | 14 | | Money market mutual funds | 7 | | | — | | | — | | | 7 | |
| Investment funds | Investment funds | 1 | | | — | | | — | | | 1 | | Investment funds | 1 | | | — | | | — | | | 1 | |
| | $ | 15 | | | $ | — | | | $ | 1 | | | $ | 16 | | | $ | 8 | | | $ | — | | | $ | 1 | | | $ | 9 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (55) | | | $ | (55) | | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (34) | | | $ | (34) | |
| | As of December 31, 2021: | | |
| As of December 31, 2022: | | As of December 31, 2022: | |
| Assets: | Assets: | | Assets: | |
| Commodity derivatives | Commodity derivatives | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | | Commodity derivatives | $ | — | | | $ | — | | | $ | 8 | | | $ | 8 | |
| Money market mutual funds | Money market mutual funds | 10 | | | — | | | — | | | 10 | | Money market mutual funds | 49 | | | — | | | — | | | 49 | |
| Investment funds | Investment funds | 1 | | | — | | | — | | | 1 | | Investment funds | 1 | | | — | | | — | | | 1 | |
| | $ | 11 | | | $ | — | | | $ | 2 | | | $ | 13 | | | $ | 50 | | | $ | — | | | $ | 8 | | | $ | 58 | |
| | Liabilities - commodity derivatives | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (35) | | | $ | (35) | | Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (21) | | | $ | (21) | |
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 Sierra Pacific transacts. When quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific 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, Sierra Pacific 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 Sierra Pacific's nonperformance risk on its liabilities, which as of March 31, 2023 and December 31, 2022, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.
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 | | Three-Month Periods | |
| | Ended June 30, | | Ended June 30, | | Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| | Beginning balance | Beginning balance | $ | (52) | | | $ | 12 | | | $ | (33) | | | $ | 7 | | Beginning balance | $ | (13) | | | $ | (33) | | |
| Changes in fair value recognized in regulatory assets | Changes in fair value recognized in regulatory assets | (7) | | | (1) | | | (26) | | | 4 | | Changes in fair value recognized in regulatory assets | (20) | | | (19) | | |
| | Settlements | 5 | | | 1 | | | 5 | | | 1 | | |
| | Ending balance | Ending balance | $ | (54) | | | $ | 12 | | | $ | (54) | | | $ | 12 | | Ending balance | $ | (33) | | | $ | (52) | | |
Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Sierra Pacific's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 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 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| As of March 31, 2023 | | As of December 31, 2022 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
| Long-term debt | $ | 1,148 | | | $ | 1,148 | | | $ | 1,148 | | | $ | 1,111 | |
(9)(8) Commitments and Contingencies
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
(10)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.
(9) Revenue from Contracts with Customers
The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 1110 (in millions):
| | | Three-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended March 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| | 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 | $ | 79 | | | $ | 19 | | | $ | 98 | | | $ | 68 | | | $ | 13 | | | $ | 81 | | Residential | $ | 115 | | | $ | 60 | | | $ | 175 | | | $ | 85 | | | $ | 32 | | | $ | 117 | |
| Commercial | Commercial | 82 | | | 6 | | | 88 | | | 64 | | | 5 | | | 69 | | Commercial | 91 | | | 27 | | | 118 | | | 70 | | | 15 | | | 85 | |
| Industrial | Industrial | 53 | | | 3 | | | 56 | | | 42 | | | 2 | | | 44 | | Industrial | 63 | | | 9 | | | 72 | | | 49 | | | 4 | | | 53 | |
| Other | Other | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | | Other | 2 | | | — | | | 2 | | | 1 | | | — | | | 1 | |
| Total fully bundled | Total fully bundled | 215 | | | 28 | | | 243 | | | 175 | | | 20 | | | 195 | | Total fully bundled | 271 | | | 96 | | | 367 | | | 205 | | | 51 | | | 256 | |
| Distribution only service | Distribution only service | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | | Distribution only service | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | |
| Total retail | Total retail | 216 | | | 28 | | | 244 | | | 176 | | | 20 | | | 196 | | Total retail | 272 | | | 96 | | | 368 | | | 206 | | | 51 | | | 257 | |
| Wholesale, transmission and other | Wholesale, transmission and other | 14 | | | — | | | 14 | | | 12 | | | — | | | 12 | | Wholesale, transmission and other | 32 | | | — | | | 32 | | | 21 | | | — | | | 21 | |
| Total Customer Revenue | Total Customer Revenue | 230 | | | 28 | | | 258 | | | 188 | | | 20 | | | 208 | | Total Customer Revenue | 304 | | | 96 | | | 400 | | | 227 | | | 51 | | | 278 | |
| Other revenue | Other revenue | — | | | — | | | — | | | 1 | | | — | | | 1 | | Other revenue | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| Total revenue | $ | 230 | | | $ | 28 | | | $ | 258 | | | $ | 189 | | | $ | 20 | | | $ | 209 | | |
| Total operating revenue | | Total operating revenue | $ | 304 | | | $ | 96 | | | $ | 400 | | | $ | 227 | | | $ | 52 | | | $ | 279 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
(11)(10) Segment Information
Sierra Pacific has identified 2two 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 | | Six-Month Periods | | | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | | | 2023 | | 2022 |
| Operating revenue: | Operating revenue: | | | | | | | | Operating revenue: | | | | | |
| Regulated electric | Regulated electric | $ | 230 | | | $ | 189 | | | $ | 457 | | | $ | 370 | | Regulated electric | | | $ | 304 | | | $ | 227 | |
| Regulated natural gas | Regulated natural gas | 28 | | | 20 | | | 80 | | | 59 | | Regulated natural gas | | | 96 | | | 52 | |
| Total operating revenue | Total operating revenue | $ | 258 | | | $ | 209 | | | $ | 537 | | | $ | 429 | | Total operating revenue | | | $ | 400 | | | $ | 279 | |
| | | Operating income: | Operating income: | | Operating income: | | |
| Regulated electric | Regulated electric | $ | 19 | | | $ | 21 | | | $ | 49 | | | $ | 52 | | Regulated electric | | | $ | 25 | | | $ | 30 | |
| Regulated natural gas | Regulated natural gas | 4 | | | 4 | | | 12 | | | 12 | | Regulated natural gas | | | 10 | | | 8 | |
| Total operating income | Total operating income | 23 | | | 25 | | | 61 | | | 64 | | Total operating income | | | 35 | | | 38 | |
| Interest expense | Interest expense | (14) | | | (13) | | | (27) | | | (27) | | Interest expense | | | (16) | | | (13) | |
| Allowance for borrowed funds | Allowance for borrowed funds | — | | | 1 | | | 1 | | | 1 | | Allowance for borrowed funds | | | 2 | | | 1 | |
| Allowance for equity funds | Allowance for equity funds | 2 | | | 2 | | | 4 | | | 3 | | Allowance for equity funds | | | 2 | | | 2 | |
| Interest and dividend income | Interest and dividend income | 4 | | | 1 | | | 7 | | | 3 | | Interest and dividend income | | | 7 | | | 3 | |
| Other, net | Other, net | — | | | 2 | | | 2 | | | 6 | | Other, net | | | 1 | | | 2 | |
| Income before income tax expense | $ | 15 | | | $ | 18 | | | $ | 48 | | | $ | 50 | | |
| Total income before income tax expense (benefit) | | Total income before income tax expense (benefit) | | | $ | 31 | | | $ | 33 | |
|
| | | | | | As of | | | As of |
| | | June 30, | | December 31, | | | March 31, | | December 31, |
| | | 2022 | | 2021 | | | 2023 | | 2022 |
| Assets: | Assets: | | | | | Assets: | | | | |
| Regulated electric | Regulated electric | | $ | 3,995 | | | $ | 3,829 | | Regulated electric | | $ | 4,193 | | | $ | 4,224 | |
| Regulated natural gas | Regulated natural gas | | 385 | | | 365 | | Regulated natural gas | | 460 | | | 441 | |
Other(1) | Other(1) | | 35 | | | 29 | | Other(1) | | 30 | | | 67 | |
| Total assets | Total assets | | $ | 4,415 | | | $ | 4,223 | | Total assets | | $ | 4,683 | | | $ | 4,732 | |
(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 SecondFirst Quarter and First Six Months of 20222023 and 20212022
Overview
Net income for the secondfirst quarter of 20222023 was $13$27 million, a decrease of $4$1 million, or 24%4%, compared to 20212022 primarily due to $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 and 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 six months of 2022 was $41 million, a decrease of $4 million, or 9%, compared to 2021 primarily due to $11 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher earnings sharing, $4 million of unfavorable other, net,customer service operations expenses, higher depreciation and amortization, mainly due to lower cash surrender value of corporate-owned life insurance policies,higher plant placed in-service and higher income taxregulatory amortizations, and higher interest expense, primarily due to higher interest rates and debt, partially offset by $9 million of higher electric utility margin $4 million ofand higher interest and dividend income, mainlyprimarily from carrying charges on regulatory balances, and higher allowance for equity funds, mainly due to higher construction work-in-progress.balances. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, higher customer volumes and higher transmission and wholesale revenue, higher regulatory-related revenue deferralsrevenue. Electric retail customer volumes, including distribution only service customers, increased by 2.3% primarily due to the favorable impact of weather and an increase in the average number of customers, partially offset bycustomers. Natural gas utility margin increased primarily due to higher customer volumes from the unfavorablefavorable impact of weather, unfavorable price impacts from changes in sales mix and unfavorable changes in customer usage patterns.weather. Energy generated decreased 18%increased 11% for the first six monthsquarter of 20222023 compared to 20212022 primarily due to lowerhigher natural gas-fueled generation, partially offset by highergas- and coal-fueled generation. Wholesale electricity sales volumes increased 35%decreased 21% and purchased electricity volumes increased 4%decreased 20%.
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):
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Electric utility margin: | Electric utility margin: | | | | | | | | | | | | | Electric utility margin: | | | | | | | |
| Operating revenue | Operating revenue | | $ | 230 | | | $ | 189 | | | $ | 41 | | 22 | % | | $ | 457 | | | $ | 370 | | | $ | 87 | | 24 | % | Operating revenue | | $ | 304 | | | $ | 227 | | | $ | 77 | | 34 | % | |
| Cost of fuel and energy | Cost of fuel and energy | | 129 | | | 93 | | | 36 | | 39 | | | 253 | | | 175 | | | 78 | | 45 | | Cost of fuel and energy | | 181 | | | 124 | | | 57 | | 46 | | |
| Electric utility margin | Electric utility margin | | 101 | | | 96 | | | 5 | | 5 | % | | 204 | | | 195 | | | 9 | | 5 | % | Electric utility margin | | 123 | | | 103 | | | 20 | | 19 | % | |
| | Natural gas utility margin: | Natural gas utility margin: | | Natural gas utility margin: | | |
| Operating revenue | Operating revenue | | 28 | | | 20 | | | 8 | | 40 | % | | 80 | | | 59 | | | 21 | | 36 | % | Operating revenue | | 96 | | | 52 | | | 44 | | 85 | % | |
| Natural gas purchased for resale | Natural gas purchased for resale | | 16 | | | 8 | | | 8 | | 100 | | | 50 | | | 29 | | | 21 | | 72 | | Natural gas purchased for resale | | 75 | | | 34 | | | 41 | | * | |
| Natural gas utility margin | Natural gas utility margin | | 12 | | | 12 | | | — | | — | % | | 30 | | | 30 | | | — | | — | % | Natural gas utility margin | | 21 | | | 18 | | | 3 | | 17 | % | |
| | Utility margin | Utility margin | | 113 | | | 108 | | | 5 | | 5 | % | | 234 | | | 225 | | | 9 | | 4 | % | Utility margin | | 144 | | | 121 | | | 23 | | 19 | % | |
| | Operations and maintenance | Operations and maintenance | | 47 | | | 41 | | | 6 | | 15 | % | | 88 | | | 77 | | | 11 | | 14 | % | Operations and maintenance | | 56 | | | 41 | | | 15 | | 37 | % | |
| Depreciation and amortization | Depreciation and amortization | | 37 | | | 36 | | | 1 | | 3 | | | 73 | | | 72 | | | 1 | | 1 | | Depreciation and amortization | | 46 | | | 36 | | | 10 | | 28 | | |
| Property and other taxes | Property and other taxes | | 6 | | | 6 | | | — | | — | | | 12 | | | 12 | | | — | | — | | Property and other taxes | | 7 | | | 6 | | | 1 | | 17 | | |
| Operating income | Operating income | | $ | 23 | | | $ | 25 | | | $ | (2) | | (8) | % | | $ | 61 | | | $ | 64 | | | $ | (3) | | (5) | % | Operating income | | $ | 35 | | | $ | 38 | | | $ | (3) | | (8) | % | |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | | Utility margin (in millions): | | | | | | | |
| Operating revenue | Operating revenue | | $ | 230 | | | $ | 189 | | | $ | 41 | | 22 | % | | $ | 457 | | | $ | 370 | | | $ | 87 | | 24 | % | Operating revenue | | $ | 304 | | | $ | 227 | | | $ | 77 | | 34 | % | |
| Cost of fuel and energy | Cost of fuel and energy | | 129 | | | 93 | | | 36 | | 39 | | | 253 | | | 175 | | | 78 | | 45 | | Cost of fuel and energy | | 181 | | | 124 | | | 57 | | 46 | | |
| Utility margin | Utility margin | | $ | 101 | | | $ | 96 | | | $ | 5 | | 5 | % | | $ | 204 | | | $ | 195 | | | $ | 9 | | 5 | % | Utility margin | | $ | 123 | | | $ | 103 | | | $ | 20 | | 19 | % | |
| | Sales (GWhs): | Sales (GWhs): | | Sales (GWhs): | | |
| Residential | Residential | | 573 | | | 626 | | | (53) | | (8) | % | | 1,236 | | | 1,297 | | | (61) | | (5) | % | Residential | | 732 | | | 663 | | | 69 | | 10 | % | |
| Commercial | Commercial | | 778 | | | 788 | | | (10) | | (1) | | | 1,478 | | | 1,465 | | | 13 | | 1 | | Commercial | | 721 | | | 700 | | | 21 | | 3 | | |
| Industrial | Industrial | | 721 | | | 900 | | | (179) | | (20) | | | 1,476 | | | 1,797 | | | (321) | | (18) | | Industrial | | 646 | | | 755 | | | (109) | | (14) | | |
| Other | Other | | 3 | | | 3 | | | — | | — | | | 7 | | | 7 | | | — | | — | | Other | | 3 | | | 4 | | | (1) | | (25) | | |
Total fully bundled(1) | Total fully bundled(1) | | 2,075 | | | 2,317 | | | (242) | | (10) | | | 4,197 | | | 4,566 | | | (369) | | (8) | | Total fully bundled(1) | | 2,102 | | | 2,122 | | | (20) | | (1) | | |
| Distribution only service | Distribution only service | | 752 | | | 420 | | | 332 | | 79 | | | 1,337 | | | 817 | | | 520 | | 64 | | Distribution only service | | 668 | | | 585 | | | 83 | | 14 | | |
| Total retail | Total retail | | 2,827 | | | 2,737 | | | 90 | | 3 | | | 5,534 | | | 5,383 | | | 151 | | 3 | | Total retail | | 2,770 | | | 2,707 | | | 63 | | 2 | | |
| Wholesale | Wholesale | | 114 | | | 125 | | | (11) | | (9) | | | 405 | | | 300 | | | 105 | | 35 | | Wholesale | | 229 | | | 291 | | | (62) | | (21) | | |
| Total GWhs sold | Total GWhs sold | | 2,941 | | | 2,862 | | | 79 | | 3 | % | | 5,939 | | | 5,683 | | | 256 | | 5 | % | Total GWhs sold | | 2,999 | | | 2,998 | | | 1 | | — | % | |
| | Average number of retail customers (in thousands) | Average number of retail customers (in thousands) | | 370 | | | 365 | | | 5 | | 1 | % | | 370 | | | 364 | | | 6 | | 2 | % | Average number of retail customers (in thousands) | | 372 | | | 369 | | | 3 | | 1 | % | |
| | | Average revenue per MWh: | Average revenue per MWh: | | Average revenue per MWh: | | |
Retail - fully bundled(1) | Retail - fully bundled(1) | | $ | 103.25 | | | $ | 75.42 | | | $ | 27.83 | | 37 | % | | $ | 99.79 | | | $ | 74.31 | | | $ | 25.48 | | 34 | % | Retail - fully bundled(1) | | $ | 128.99 | | | $ | 96.40 | | | $ | 32.59 | | 34 | % | |
| | Wholesale | Wholesale | | $ | 65.84 | | | $ | 52.18 | | | $ | 13.66 | | 26 | % | | $ | 55.28 | | | $ | 56.84 | | | $ | (1.56) | | (3) | % | Wholesale | | $ | 107.76 | | | $ | 51.14 | | | $ | 56.62 | | * | |
| | Heating degree days | Heating degree days | | 661 | | 498 | | 163 | | 33 | % | | 2,698 | | | 2,696 | | | 2 | | — | % | Heating degree days | | 2,652 | | 2,037 | | 615 | | 30 | % | |
| Cooling degree days | | 214 | | | 369 | | | (155) | | (42) | % | | 214 | | | 369 | | | (155) | | (42) | % | |
| | Sources of energy (GWhs)(2): | Sources of energy (GWhs)(2): | | Sources of energy (GWhs)(2): | | |
| Natural gas | Natural gas | | 707 | | | 1,133 | | | (426) | | (38) | % | | 1,697 | | | 2,215 | | | (518) | | (23) | % | Natural gas | | 1,066 | | | 990 | | | 76 | | 8 | % | |
| Coal | Coal | | 352 | | | 436 | | | (84) | | (19) | | | 505 | | | 465 | | | 40 | | 9 | | Coal | | 201 | | | 153 | | | 48 | | 31 | | |
Renewables(3) | Renewables(3) | | 8 | | | 13 | | | (5) | | (38) | | | 13 | | | 19 | | | (6) | | (32) | | Renewables(3) | | 4 | | | 5 | | | (1) | | (20) | | |
| Total energy generated | Total energy generated | | 1,067 | | | 1,582 | | | (515) | | (33) | | | 2,215 | | | 2,699 | | | (484) | | (18) | | Total energy generated | | 1,271 | | | 1,148 | | | 123 | | 11 | | |
| Energy purchased | Energy purchased | | 1,590 | | | 1,149 | | | 441 | | 38 | | | 2,623 | | | 2,522 | | | 101 | | 4 | | Energy purchased | | 823 | | | 1,033 | | | (210) | | (20) | | |
| Total | Total | | 2,657 | | | 2,731 | | | (74) | | (3) | % | | 4,838 | | | 5,221 | | | (383) | | (7) | % | Total | | 2,094 | | | 2,181 | | | (87) | | (4) | % | |
| Average cost of energy per MWh(4): | | |
Average cost of energy per MWh(3): | | Average cost of energy per MWh(3): | | |
| Energy generated | Energy generated | | $ | 47.59 | | | $ | 23.88 | | | $ | 23.71 | | 99 | % | | $ | 53.95 | | | $ | 24.44 | | | $ | 29.51 | | * | Energy generated | | $ | 102.35 | | | $ | 59.86 | | | $ | 42.49 | | 71 | % | |
| Energy purchased | Energy purchased | | $ | 49.73 | | | $ | 48.21 | | | $ | 1.52 | | 3 | % | | $ | 51.09 | | | $ | 43.16 | | | $ | 7.93 | | 18 | % | Energy purchased | | $ | 61.37 | | | $ | 53.19 | | | $ | 8.18 | | 15 | % | |
* Not meaningful
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) GWh amounts are net of energy used by the related generating facilities.
(3) Includes the Fort Churchill Solar Array which was under lease by Sierra Pacific until it was acquired in December 2021.
(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
| | | Second Quarter | | First Six Months | | First Quarter | |
| | 2022 | | 2021 | | Change | | 2022 | | 2021 | | Change | | 2023 | | 2022 | | Change | |
| Utility margin (in millions): | Utility margin (in millions): | | | | | | | | | | | | | Utility margin (in millions): | | | | | | | |
| Operating revenue | Operating revenue | | $ | 28 | | | $ | 20 | | | $ | 8 | | 40 | % | | $ | 80 | | | $ | 59 | | | $ | 21 | | 36 | % | Operating revenue | | $ | 96 | | | $ | 52 | | | $ | 44 | | 85 | % | |
| Natural gas purchased for resale | Natural gas purchased for resale | | 16 | | | 8 | | | 8 | | * | | 50 | | | 29 | | | 21 | | 72 | | Natural gas purchased for resale | | 75 | | | 34 | | | 41 | | * | |
| Utility margin | Utility margin | | $ | 12 | | | $ | 12 | | | $ | — | | — | % | | $ | 30 | | | $ | 30 | | | $ | — | | — | % | Utility margin | | $ | 21 | | | $ | 18 | | | $ | 3 | | 17 | % | |
| | Sold (000's Dths): | Sold (000's Dths): | | Sold (000's Dths): | | |
| Residential | Residential | | 1,797 | | | 1,450 | | | 347 | | 24 | % | | 6,349 | | | 6,108 | | | 241 | | 4 | % | Residential | | 5,866 | | | 4,552 | | | 1,314 | | 29 | % | |
| Commercial | Commercial | | 751 | | | 775 | | | (24) | | (3) | | | 3,263 | | | 3,079 | | | 184 | | 6 | | Commercial | | 2,938 | | | 2,512 | | | 426 | | 17 | | |
| Industrial | Industrial | | 402 | | | 395 | | | 7 | | 2 | | | 1,055 | | | 1,140 | | | (85) | | (7) | | Industrial | | 1,066 | | | 653 | | | 413 | | 63 | | |
| Total retail | Total retail | | 2,950 | | | 2,620 | | | 330 | | 13 | % | | 10,667 | | | 10,327 | | | 340 | | 3 | % | Total retail | | 9,870 | | | 7,717 | | | 2,153 | | 28 | % | |
| | Average number of retail customers (in thousands) | Average number of retail customers (in thousands) | | 179 | | | 177 | | | 2 | | 1 | % | | 179 | | | 176 | | | 3 | | 2 | % | Average number of retail customers (in thousands) | | 182 | | | 179 | | | 3 | | 2 | % | |
| | Average revenue per retail Dth sold | Average revenue per retail Dth sold | | $ | 9.47 | | | $ | 7.62 | | | $ | 1.85 | | 24 | % | | $ | 7.46 | | | $ | 5.69 | | | $ | 1.77 | | 31 | % | Average revenue per retail Dth sold | | $ | 9.74 | | | $ | 6.69 | | | $ | 3.05 | | 46 | % | |
| | Heating degree days | Heating degree days | | 661 | | | 498 | | | 163 | | 33 | % | | 2,698 | | | 2,696 | | | 2 | | — | % | Heating degree days | | 2,652 | | | 2,037 | | | 615 | | 30 | % | |
| | Average cost of natural gas per retail Dth sold | Average cost of natural gas per retail Dth sold | | $ | 5.48 | | | $ | 3.21 | | | $ | 2.27 | | 71 | % | | $ | 4.67 | | | $ | 2.86 | | | $ | 1.81 | | 63 | % | Average cost of natural gas per retail Dth sold | | $ | 7.63 | | | $ | 4.36 | | | $ | 3.27 | | 75 | % | |
|
* Not meaningful
Quarter Ended June 30, 2022March 31, 2023 Compared to Quarter Ended June 30, 2021March 31, 2022
Electric utility margin increased $520 million, or 5%19%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to:
•$514 million of higher ON Line temporary rider (offset in operations and maintenance expense) for the recovery of deferred costs for the ON Line leaseretail rates due to the regulatory-directed reallocation of costs between Nevada Power2022 regulatory rate review with new rates effective January 2023 and Sierra Pacific and
•$4 million of higher regulatory-related revenue deferrals.
The increase in utility margin was offset by:
•$3 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 3.3%by 2.3% primarily due to the favorable impact of weather and an increase in the average number of customers, offset by the unfavorable impact of weather and unfavorable changes in customer usage patternscustomers; and
•$16 million of lower energy efficiency programs rates (offset in operationshigher transmission and maintenance expense).wholesale revenue.
Operations and maintenance increased $6$15 million, or 15%37%, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to higher plant operations and maintenance expenses, higher regulatory-approved cost recovery for the ON Line lease of $5 millionreallocation (offset in operating revenue) and higher customer service operations expenses.
Depreciation and amortization increased $10 million, or 28%, for the first quarter of 2023 compared to 2022 primarily due to higher plant operationsplaced in-service and maintenance expenses, partially offset by lower energy efficiency program costs (offset in operating revenue).higher regulatory amortizations.
Interest expense increased $3 million, or 23%, for the first quarter of 2023 compared to 2022 primarily due to higher interest rates and debt.
Interest and dividend income increased $3$4 million, for the secondfirst quarter of 20222023 compared to 20212022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net is unfavorable $2 million, for the second quarter 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 $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 $2 million, or 40%, for the first six months of 2022 compared to 2021 primarily due to the effects of ratemaking, offset by lower pretax income. The effective tax rate was 15% in 2022 and 10% in 2021.
Liquidity and Capital Resources
As of June 30, 2022,March 31, 2023, Sierra Pacific's total net liquidity was as follows (in millions):
| | | | | | | | |
| Cash and cash equivalents | | $ | 178 | |
| | |
| Credit facility | | 250 | |
| Less: | | |
| | |
| Short-term debt | | (50) | |
| Net credit facility | | 200 | |
| | |
| Total net liquidity | | $ | 267208 | |
| Credit facility: | | |
| Maturity date | | 2025 |
Operating Activities
Net cash flows from operating activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $108$87 million and $92$63 million, respectively. The change was primarily due to higher collections from customers, partially offset by higher payments related to fuel and energy costs and thecosts.
The timing of paymentsSierra Pacific's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions made for operating costs.each payment date.
Investing Activities
Net cash flows from investing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $(191)$(104) million and $(128)$(83) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021 were $91$(22) million and $25$26 million, respectively. The change was primarily due to lower contributions from NV Energy, Inc. and higher proceeds from the issuancerepayments of long-term debt,an affiliate note payable, partially offset by higher long-term debt reacquired, higher repayments ofproceeds from short-term debt and higher dividends paid to NV Energy, Inc.
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 Offered Rate 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.debt.
Debt Authorizations
Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $1.9 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'customer 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.
HistoricalSierra Pacific's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
| | | Six-Month Periods | | Annual | | Three-Month Periods | | Annual |
| | Ended June 30, | | Forecast | | Ended March 31, | | Forecast |
| | 2021 | | 2022 | | 2022 | | 2022 | | 2023 | | 2023 |
| | | Electric distribution | Electric distribution | $ | 42 | | | $ | 46 | | | $ | 114 | | Electric distribution | $ | 20 | | | $ | 32 | | | $ | 164 | |
| Electric transmission | Electric transmission | 31 | | | 45 | | | 104 | | Electric transmission | 20 | | | 19 | | | 73 | |
| | Solar generation | | Solar generation | — | | | — | | | 3 | |
| Electric battery storage | | Electric battery storage | — | | | — | | | 8 | |
| Other | Other | 55 | | | 100 | | | 186 | | Other | 43 | | | 53 | | | 165 | |
| Total | Total | $ | 128 | | | $ | 191 | | | $ | 404 | | Total | $ | 83 | | | $ | 104 | | | $ | 413 | |
Sierra Pacific received PUCN approval through its recentprevious IRP filings 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 2022.2023. 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. In this project, the companySierra Pacific 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;substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substations.substation. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Other includes 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.
Material Cash Requirements
As of June 30, 2022,March 31, 2023, there have been no material changes outside the normal course of business in material cash requirements from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 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.2022.
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 air quality, climate change, RPS, air and water quality, emissions performance standards, water quality, coal combustion byproductash 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, 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. Sierra Pacific 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 Sierra Pacific 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, 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, 2021.2022. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2021.2022.
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 June 30, 2022,March 31, 2023, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and six-month periods ended June 30, 2022 and 2021, and of cash flows for the six-monththree-month periods ended June 30,March 31, 2023 and 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 Eastern Energy Gas as of December 31, 2021,2022, 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 25, 2022,24, 2023, 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, 2021,2022, 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
AugustMay 5, 20222023
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | As of |
| | As of | | March 31, | | December 31, |
| | June 30, 2022 | | December 31, 2021 | | 2023 | | 2022 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 106 | | | $ | 22 | | Cash and cash equivalents | $ | 103 | | | $ | 65 | |
| | Trade receivables, net | Trade receivables, net | 174 | | | 183 | | Trade receivables, net | 177 | | | 202 | |
| Receivables from affiliates | Receivables from affiliates | 26 | | | 47 | | Receivables from affiliates | 29 | | | 30 | |
| | Notes receivable from affiliates | Notes receivable from affiliates | 198 | | | 7 | | Notes receivable from affiliates | 629 | | | 536 | |
| | Inventories | Inventories | 127 | | | 122 | | Inventories | 130 | | | 127 | |
| | Prepayments and other deferred charges | | Prepayments and other deferred charges | 57 | | | 78 | |
| Natural gas imbalances | Natural gas imbalances | 194 | | | 100 | | Natural gas imbalances | 60 | | | 193 | |
| Other current assets | Other current assets | 126 | | | 140 | | Other current assets | 54 | | | 72 | |
| Total current assets | Total current assets | 951 | | | 621 | | Total current assets | 1,239 | | | 1,303 | |
| | Property, plant and equipment, net | Property, plant and equipment, net | 10,131 | | | 10,200 | | Property, plant and equipment, net | 10,281 | | | 10,202 | |
| Goodwill | Goodwill | 1,286 | | | 1,286 | | Goodwill | 1,286 | | | 1,286 | |
| | Investments | Investments | 419 | | | 412 | | Investments | 285 | | | 278 | |
| | Other assets | Other assets | 140 | | | 129 | | Other assets | 94 | | | 95 | |
| | Total assets | Total assets | $ | 12,927 | | | $ | 12,648 | | Total assets | $ | 13,185 | | | $ | 13,164 | |
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 |
| | June 30, 2022 | | December 31, 2021 | | March 31, 2023 | | December 31, 2022 |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| Current liabilities: | Current liabilities: | | Current liabilities: | |
| Accounts payable | Accounts payable | $ | 45 | | | $ | 79 | | Accounts payable | $ | 42 | | | $ | 86 | |
| Accounts payable to affiliates | Accounts payable to affiliates | 20 | | | 38 | | Accounts payable to affiliates | 8 | | | 10 | |
| Accrued interest | Accrued interest | 14 | | | 19 | | Accrued interest | 54 | | | 19 | |
| Accrued property, income and other taxes | Accrued property, income and other taxes | 78 | | | 89 | | Accrued property, income and other taxes | 69 | | | 77 | |
| | Regulatory liabilities | Regulatory liabilities | 49 | | | 40 | | Regulatory liabilities | 34 | | | 126 | |
| | Current portion of long-term debt | Current portion of long-term debt | 250 | | | — | | Current portion of long-term debt | 650 | | | 649 | |
| Other current liabilities | Other current liabilities | 187 | | | 100 | | Other current liabilities | 144 | | | 146 | |
| Total current liabilities | Total current liabilities | 643 | | | 365 | | Total current liabilities | 1,001 | | | 1,113 | |
| | Long-term debt | Long-term debt | 3,636 | | | 3,906 | | Long-term debt | 3,247 | | | 3,243 | |
| | Regulatory liabilities | Regulatory liabilities | 640 | | | 645 | | Regulatory liabilities | 592 | | | 596 | |
| | Other long-term liabilities | Other long-term liabilities | 291 | | | 238 | | Other long-term liabilities | 340 | | | 324 | |
| Total liabilities | Total liabilities | 5,210 | | | 5,154 | | Total liabilities | 5,180 | | | 5,276 | |
| | Commitments and contingencies (Note 8) | Commitments and contingencies (Note 8) | 0 | | 0 | Commitments and contingencies (Note 8) | |
| | Equity: | Equity: | | Equity: | |
| Member's equity: | Member's equity: | | Member's equity: | |
| | Membership interests | Membership interests | 3,733 | | | 3,501 | | Membership interests | 4,109 | | | 3,983 | |
| | Accumulated other comprehensive loss, net | Accumulated other comprehensive loss, net | (39) | | | (43) | | Accumulated other comprehensive loss, net | (45) | | | (42) | |
| Total member's equity | Total member's equity | 3,694 | | | 3,458 | | Total member's equity | 4,064 | | | 3,941 | |
| Noncontrolling interests | Noncontrolling interests | 4,023 | | | 4,036 | | Noncontrolling interests | 3,941 | | | 3,947 | |
| Total equity | Total equity | 7,717 | | | 7,494 | | Total equity | 8,005 | | | 7,888 | |
| | Total liabilities and equity | Total liabilities and equity | $ | 12,927 | | | $ | 12,648 | | Total liabilities and equity | $ | 13,185 | | | $ | 13,164 | |
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 | | Six-Month Periods | | Three-Month Periods | |
| | Ended June 30, | | Ended June 30, | | Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| | | Operating revenue | Operating revenue | $ | 504 | | | $ | 437 | | | $ | 986 | | | $ | 923 | | Operating revenue | $ | 553 | | | $ | 482 | | |
| | Operating expenses: | Operating expenses: | | Operating expenses: | | |
| | Excess gas | (21) | | | (10) | | | (22) | | | (10) | | |
| Cost of (excess) gas | | Cost of (excess) gas | 20 | | | (1) | | |
| Operations and maintenance | Operations and maintenance | 124 | | | 113 | | | 242 | | | 237 | | Operations and maintenance | 143 | | | 118 | | |
| Depreciation and amortization | Depreciation and amortization | 80 | | | 81 | | | 165 | | | 161 | | Depreciation and amortization | 80 | | | 85 | | |
| Property and other taxes | Property and other taxes | 37 | | | 38 | | | 66 | | | 77 | | Property and other taxes | 37 | | | 29 | | |
| | Total operating expenses | Total operating expenses | 220 | | | 222 | | | 451 | | | 465 | | Total operating expenses | 280 | | | 231 | | |
| | Operating income | Operating income | 284 | | | 215 | | | 535 | | | 458 | | Operating income | 273 | | | 251 | | |
| | Other income (expense): | Other income (expense): | | Other income (expense): | | |
| Interest expense | Interest expense | (36) | | | (42) | | | (72) | | | (86) | | Interest expense | (37) | | | (36) | | |
| | Allowance for equity funds | Allowance for equity funds | 1 | | | 1 | | | 3 | | | 3 | | Allowance for equity funds | 2 | | | 2 | | |
| | Interest and dividend income | | Interest and dividend income | 9 | | | — | | |
| | Other, net | Other, net | — | | | 1 | | | (1) | | | 2 | | Other, net | — | | | (1) | | |
| Total other income (expense) | Total other income (expense) | (35) | | | (40) | | | (70) | | | (81) | | Total other income (expense) | (26) | | | (35) | | |
| | Income before income tax expense and equity income | 249 | | | 175 | | | 465 | | | 377 | | |
| Income tax expense | 37 | | | 22 | | | 67 | | | 49 | | |
| Equity income | 9 | | | 7 | | | 28 | | | 23 | | |
| Income before income tax expense (benefit) and equity income (loss) | | Income before income tax expense (benefit) and equity income (loss) | 247 | | | 216 | | |
| Income tax expense (benefit) | | Income tax expense (benefit) | 39 | | | 30 | | |
| Equity income (loss) | | Equity income (loss) | 32 | | | 19 | | |
| | Net income | Net income | 221 | | | 160 | | | 426 | | | 351 | | Net income | 240 | | | 205 | | |
| Net income attributable to noncontrolling interests | Net income attributable to noncontrolling interests | 118 | | | 100 | | | 229 | | | 202 | | Net income attributable to noncontrolling interests | 118 | | | 111 | | |
| Net income attributable to Eastern Energy Gas | Net income attributable to Eastern Energy Gas | $ | 103 | | | $ | 60 | | | $ | 197 | | | $ | 149 | | Net income attributable to Eastern Energy Gas | $ | 122 | | | $ | 94 | | |
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 | | Six-Month Periods | | Three-Month Periods | |
| | Ended June 30, | | Ended June 30, | | Ended March 31, | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | |
| | Net income | Net income | $ | 221 | | | $ | 160 | | | $ | 426 | | | $ | 351 | | Net income | $ | 240 | | | $ | 205 | | |
| | | | | | | | | | | | | | |
| 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 $—, $—, $— and $— | — | | | 2 | | | 1 | | | 4 | | |
| Unrecognized amounts on retirement benefits, net of tax of $— and $— | | Unrecognized amounts on retirement benefits, net of tax of $— and $— | (1) | | | 1 | | |
| | Unrealized (losses) gains on cash flow hedges, net of tax of $—, $—, $1 and $3 | (1) | | | 3 | | | 3 | | | 13 | | |
| Unrealized (losses) gains on cash flow hedges, net of tax of $(1) and $1 | | Unrealized (losses) gains on cash flow hedges, net of tax of $(1) and $1 | (2) | | | 4 | | |
| Total other comprehensive (loss) income, net of tax | Total other comprehensive (loss) income, net of tax | (1) | | | 5 | | | 4 | | | 17 | | Total other comprehensive (loss) income, net of tax | (3) | | | 5 | | |
| | | | | | | | | | | | | | |
| Comprehensive income | Comprehensive income | 220 | | | 165 | | | 430 | | | 368 | | Comprehensive income | 237 | | | 210 | | |
| Comprehensive income attributable to noncontrolling interests | Comprehensive income attributable to noncontrolling interests | 118 | | | 100 | | | 229 | | | 206 | | Comprehensive income attributable to noncontrolling interests | 118 | | | 111 | | |
| Comprehensive income attributable to Eastern Energy Gas | Comprehensive income attributable to Eastern Energy Gas | $ | 102 | | | $ | 65 | | | $ | 201 | | | $ | 162 | | Comprehensive income attributable to Eastern Energy Gas | $ | 119 | | | $ | 99 | | |
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, March 31, 2021 | | $ | 3,035 | | | $ | (45) | | | $ | 4,088 | | | $ | 7,078 | | |
| Net income | | 60 | | | — | | | 100 | | | 160 | | |
| Other comprehensive income | | — | | | 5 | | | — | | | 5 | | |
| Contributions | | 271 | | | — | | | — | | | 271 | | |
| Distributions | | — | | | — | | | (116) | | | (116) | | |
| Balance, June 30, 2021 | | $ | 3,366 | | | $ | (40) | | | $ | 4,072 | | | $ | 7,398 | | |
| | Balance, December 31, 2020 | | $ | 2,957 | | | $ | (53) | | | $ | 4,091 | | | $ | 6,995 | | |
| | Balance, December 31, 2021 | | Balance, December 31, 2021 | | $ | 3,501 | | | $ | (43) | | | $ | 4,036 | | | $ | 7,494 | |
| Net income | Net income | | 149 | | | — | | | 202 | | | 351 | | Net income | | 94 | | | — | | | 111 | | | 205 | |
| Other comprehensive income | Other comprehensive income | | — | | | 13 | | | 4 | | | 17 | | Other comprehensive income | | — | | | 5 | | | — | | | 5 | |
| | Contributions | | 282 | | | — | | | — | | | 282 | | |
| | Distributions | Distributions | | (22) | | | — | | | (225) | | | (247) | | Distributions | | — | | | — | | | (114) | | | (114) | |
| | 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 | | Balance, March 31, 2022 | | $ | 3,595 | | | $ | (38) | | | $ | 4,033 | | | $ | 7,590 | |
| Net income | | 103 | | | — | | | 118 | | | 221 | | |
| Other comprehensive loss | | — | | | (1) | | | — | | | (1) | | |
| Contributions | | 68 | | | — | | | — | | | 68 | | |
| Distributions | | (33) | | | — | | | (128) | | | (161) | | |
| Balance, June 30, 2022 | | $ | 3,733 | | | $ | (39) | | | $ | 4,023 | | | $ | 7,717 | | |
| | Balance, December 31, 2021 | | $ | 3,501 | | | $ | (43) | | | $ | 4,036 | | | $ | 7,494 | | |
| Net income | | 197 | | | — | | | 229 | | | 426 | | |
| Other comprehensive income | | — | | | 4 | | | — | | | 4 | | |
| Contributions | | 68 | | | — | | | — | | | 68 | | |
| Distributions | | (33) | | | — | | | (242) | | | (275) | | |
| | Balance, June 30, 2022 | | $ | 3,733 | | | $ | (39) | | | $ | 4,023 | | | $ | 7,717 | | |
| | Balance, December 31, 2022 | | Balance, December 31, 2022 | | $ | 3,983 | | | $ | (42) | | | $ | 3,947 | | | $ | 7,888 | |
| Net income | | Net income | | 122 | | | — | | | 118 | | | 240 | |
| Other comprehensive loss | | Other comprehensive loss | | — | | | (3) | | | — | | | (3) | |
| Distributions | | Distributions | | (6) | | | — | | | (124) | | | (130) | |
| Contributions | | Contributions | | 10 | | | — | | | — | | | 10 | |
| | Balance, March 31, 2023 | | Balance, March 31, 2023 | | $ | 4,109 | | | $ | (45) | | | $ | 3,941 | | | $ | 8,005 | |
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)
| | | Six-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended March 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Cash flows from operating activities: | Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | Net income | $ | 426 | | | $ | 351 | | Net income | $ | 240 | | | $ | 205 | |
| 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: | |
| | Losses on other items, net | Losses on other items, net | 2 | | | 3 | | Losses on other items, net | 1 | | | 1 | |
| Depreciation and amortization | Depreciation and amortization | 165 | | | 161 | | Depreciation and amortization | 80 | | | 85 | |
| Allowance for equity funds | Allowance for equity funds | (3) | | | (3) | | Allowance for equity funds | (2) | | | (2) | |
| Equity income, net of distributions | (5) | | | (3) | | |
| Equity (income) loss, net of distributions | | Equity (income) loss, net of distributions | (6) | | | (8) | |
| Changes in regulatory assets and liabilities | Changes in regulatory assets and liabilities | (2) | | | 1 | | Changes in regulatory assets and liabilities | (92) | | | (14) | |
| Deferred income taxes | Deferred income taxes | 52 | | | 118 | | Deferred income taxes | 20 | | | 27 | |
| Other, net | Other, net | 5 | | | (9) | | 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 | 4 | | | 65 | | Trade receivables and other assets | 40 | | | 40 | |
| | Gas balancing activities | | Gas balancing activities | 19 | | | 4 | |
| Derivative collateral, net | Derivative collateral, net | (3) | | | (1) | | Derivative collateral, net | 1 | | | 2 | |
| | Accrued property, income and other taxes | Accrued property, income and other taxes | (3) | | | (63) | | Accrued property, income and other taxes | 9 | | | (29) | |
| | Accounts payable and other liabilities | Accounts payable and other liabilities | 43 | | | (39) | | Accounts payable and other liabilities | 7 | | | 28 | |
| Net cash flows from operating activities | Net cash flows from operating activities | 681 | | | 581 | | Net cash flows from operating activities | 319 | | | 341 | |
| | Cash flows from investing activities: | Cash flows from investing activities: | | Cash flows from investing activities: | |
| Capital expenditures | Capital expenditures | (151) | | | (150) | | Capital expenditures | (59) | | | (75) | |
| | Repayment of notes by affiliates | Repayment of notes by affiliates | 15 | | | 268 | | Repayment of notes by affiliates | 40 | | | 3 | |
| Notes to affiliates | Notes to affiliates | (204) | | | (158) | | Notes to affiliates | (134) | | | (117) | |
| | Other, net | Other, net | (7) | | | (12) | | Other, net | (3) | | | (5) | |
| Net cash flows from investing activities | Net cash flows from investing activities | (347) | | | (52) | | Net cash flows from investing activities | (156) | | | (194) | |
| | Cash flows from financing activities: | Cash flows from financing activities: | | Cash flows from financing activities: | |
| | Repayments of long-term debt | — | | | (500) | | |
| | Repayment of notes payable, net | — | | | (9) | | |
| | Proceeds from equity contributions | — | | | 256 | | |
| Distributions | (242) | | | (225) | | |
| | Other, net | — | | | (2) | | |
| | Distributions to noncontrolling interests | | Distributions to noncontrolling interests | (124) | | | (114) | |
| | Net cash flows from financing activities | Net cash flows from financing activities | (242) | | | (480) | | Net cash flows from financing activities | (124) | | | (114) | |
| | | 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 | 92 | | | 49 | | Net change in cash and cash equivalents and restricted cash and cash equivalents | 39 | | | 33 | |
| 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 | 39 | | | 48 | | Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 95 | | | 39 | |
| 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 | $ | 131 | | | $ | 97 | | Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 134 | | | $ | 72 | |
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") conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transportation pipelinetransmission systems and underground storage operations in the eastern region of the U.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.transmission system. Eastern Energy Gas 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 the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of June 30, 2022March 31, 2023 and for the three- and six-monththree-month periods ended June 30, 2022March 31, 2023 and 2021.2022. The results of operations for the three- and six-month periodsthree-month period ended June 30, 2022March 31, 2023 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, 20212022 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' accounting policies or its assumptions regarding significant accounting estimates and policies during the six-monththree-month period ended June 30, 2022.March 31, 2023.
(2) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions): | | | As of | | As of |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | Depreciable Life | | 2022 | | 2021 | | Depreciable Life | | 2023 | | 2022 |
| Utility Plant: | | | | | | |
| Utility plant: | | Utility plant: | | | | | |
| | Interstate natural gas pipeline assets | 21 - 44 years | | $ | 8,728 | | | $ | 8,675 | | |
| Interstate natural gas transmission and storage assets | | Interstate natural gas transmission and storage assets | 21 - 52 years | | $ | 9,053 | | | $ | 8,922 | |
| Intangible plant | Intangible plant | 5 - 10 years | | 106 | | | 110 | | Intangible plant | 5 - 18 years | | 116 | | | 113 | |
| Utility plant in-service | Utility plant in-service | | 8,834 | | | 8,785 | | Utility plant in-service | | 9,169 | | | 9,035 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (2,962) | | | (2,901) | | Accumulated depreciation and amortization | | (3,075) | | | (3,039) | |
| Utility plant in-service, net | Utility plant in-service, net | | 5,872 | | | 5,884 | | Utility plant in-service, net | | 6,094 | | | 5,996 | |
| | Nonutility Plant: | | |
| Nonutility plant: | | Nonutility plant: | |
| | LNG facility | LNG facility | 40 years | | 4,484 | | | 4,475 | | LNG facility | 40 years | | 4,526 | | | 4,522 | |
| Intangible plant | Intangible plant | 14 years | | 25 | | | 25 | | Intangible plant | 14 years | | 25 | | | 25 | |
| Nonutility plant in-service | | 4,509 | | | 4,500 | | |
| Nonutility plant | | Nonutility plant | | 4,551 | | | 4,547 | |
| Accumulated depreciation and amortization | Accumulated depreciation and amortization | | (484) | | | (423) | | Accumulated depreciation and amortization | | (574) | | | (542) | |
| Nonutility plant in-service, net | | 4,025 | | | 4,077 | | |
| Nonutility plant, net | | Nonutility plant, net | | 3,977 | | | 4,005 | |
| | Plant, net | | 9,897 | | | 9,961 | | |
| | | 10,071 | | | 10,001 | |
| Construction work-in-progress | Construction work-in-progress | | 234 | | | 239 | | Construction work-in-progress | | 210 | | | 201 | |
| Property, plant and equipment, net | Property, plant and equipment, net | | $ | 10,131 | | | $ | 10,200 | | Property, plant and equipment, net | | $ | 10,281 | | | $ | 10,202 | |
Construction work-in-progress includes $200$192 million and $209$181 million as of June 30, 2022March 31, 2023 and December 31, 2021,2022, respectively, related to the construction of utility plant.
(3) Regulatory Matters
In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportationtransmission 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 refundrefund. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the outcometerms of hearing procedures. In June 2022, the parties reachedsettlement agreement, EGTS' rates result in an agreementincrease to annual firm transmission and storage services revenues of approximately $160 million and a decrease in principle andannual depreciation expense of approximately $30 million, compared to the litigation procedural schedule was ordered heldrates in abeyance for 90 dayseffect prior to enable the parties to finalize a settlement. The settlement is expected to be filed by September 30,April 1, 2022. As of June 30, 2022, EGTS' provision for rate refund for April 2022 through JuneFebruary 2023, including accrued interest, totaled $91 million. In November 2022, totaled $35 millionthe FERC approved the settlement agreement and was includedthe rate refunds to customers were processed in other current liabilities on the Consolidated Balance Sheet.late February 2023.
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 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.
(4) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following (in millions):
| | | As of | | As of |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Investments: | Investments: | | | | Investments: | | | |
| Investment funds | Investment funds | $ | 13 | | | $ | 13 | | Investment funds | $ | 17 | | | $ | 14 | |
| | | Equity method investments: | Equity method investments: | | Equity method investments: | |
| Iroquois | Iroquois | 406 | | | 399 | | Iroquois | 268 | | | 264 | |
| | Total investments | Total investments | 419 | | | 412 | | Total investments | 285 | | | 278 | |
| | Restricted cash and cash equivalents: | Restricted cash and cash equivalents: | | Restricted cash and cash equivalents: | |
| Customer deposits | Customer deposits | 25 | | | 17 | | Customer deposits | 31 | | | 30 | |
| Total restricted cash and cash equivalents | Total restricted cash and cash equivalents | 25 | | | 17 | | Total restricted cash and cash equivalents | 31 | | | 30 | |
| | Total investments and restricted cash and cash equivalents | Total investments and restricted cash and cash equivalents | $ | 444 | | | $ | 429 | | Total investments and restricted cash and cash equivalents | $ | 316 | | | $ | 308 | |
| | Reflected as: | Reflected as: | | Reflected as: | |
| Current assets | Current assets | $ | 25 | | | $ | 17 | | Current assets | $ | 31 | | | $ | 30 | |
| Noncurrent assets | Noncurrent assets | 419 | | | 412 | | Noncurrent assets | 285 | | | 278 | |
| Total investments and restricted cash and cash equivalents | Total investments and restricted cash and cash equivalents | $ | 444 | | | $ | 429 | | Total investments and restricted cash and cash equivalents | $ | 316 | | | $ | 308 | |
Equity Method Investments
Eastern Energy Gas, through a subsidiary,subsidiaries, owns 50% of Iroquois, which owns and operates an interstate natural gas pipelinetransmission system located in the states of New York and Connecticut.
As of both June 30, 2022March 31, 2023 and December 31, 2021,2022, 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 $23$26 million and $20$11 million for the six-monththree-month periods ended June 30,March 31, 2023 and 2022, and 2021, respectively.
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.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 of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented inon 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 |
| | June 30, | | December 31, | | March 31, | | December 31, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| | Cash and cash equivalents | Cash and cash equivalents | $ | 106 | | | $ | 22 | | Cash and cash equivalents | $ | 103 | | | $ | 65 | |
| Restricted cash and cash equivalents included in other current assets | Restricted cash and cash equivalents included in other current assets | 25 | | | 17 | | Restricted cash and cash equivalents included in other current assets | 31 | | | 30 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 131 | | | $ | 39 | | Total cash and cash equivalents and restricted cash and cash equivalents | $ | 134 | | | $ | 95 | |
(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 (benefit) is as follows:
| | | Three-Month Periods | | Six-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 |
| | Federal statutory income tax rate | Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | Federal statutory income tax rate | 21 | % | | 21 | % |
| State income tax, net of federal income tax benefit | State income tax, net of federal income tax benefit | 3 | | | 2 | | | 4 | | | 3 | | State income tax, net of federal income tax benefit | 2 | | | 5 | |
| | Equity interest | Equity interest | 1 | | | 1 | | | 1 | | | 1 | | Equity interest | 3 | | | 2 | |
| Effects of ratemaking | Effects of ratemaking | — | | | (1) | | | (2) | | | (1) | | Effects of ratemaking | — | | | (4) | |
| | Noncontrolling interest | Noncontrolling interest | (10) | | | (12) | | | (10) | | | (11) | | Noncontrolling interest | (10) | | | (11) | |
| | Other, net | Other, net | — | | | 2 | | | — | | | — | | Other, net | — | | | 1 | |
| Effective income tax rate | Effective income tax rate | 15 | % | | 13 | % | | 14 | % | | 13 | % | Effective income tax rate | 16 | % | | 14 | % |
For the period ended June 30, 2022,March 31, 2023, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by an absence of tax on income attributable to Cove Point's 75% noncontrolling interest.
(6) Employee Benefit Plans
Eastern Energy Gas is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of Eastern Energy Gas. Eastern Energy Gas contributed $6$2 million and $3 million to the MidAmerican Energy Company Retirement Plan for the three-month periods ended March 31, 2023 and 2022, respectively, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the six-month periodthree-month periods ended June 30,March 31, 2023 and 2022. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to Eastern Energy Gas were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. 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. As of both June 30, 2022March 31, 2023 and December 31, 2021,2022, 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 $95$51 million.
(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 June 30, 2022: | | | | | | | | | |
| As of March 31, 2023: | | As of March 31, 2023: | | | | | | | | |
| Assets: | Assets: | | Assets: | |
| | Money market mutual funds | Money market mutual funds | | $ | 66 | | | $ | — | | | $ | — | | | $ | 66 | | Money market mutual funds | | $ | 95 | | | $ | — | | | $ | — | | | $ | 95 | |
| Equity securities: | Equity securities: | | Equity securities: | |
| Investment funds | Investment funds | | 13 | | | — | | | — | | | 13 | | Investment funds | | 17 | | | — | | | — | | | 17 | |
| | $ | 79 | | | $ | — | | | $ | — | | | $ | 79 | | | $ | 112 | | | $ | — | | | $ | — | | | $ | 112 | |
| | Liabilities: | Liabilities: | | Liabilities: | |
| Commodity derivatives | | $ | — | | | $ | (1) | | | $ | — | | | $ | (1) | | |
| | Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | — | | | (19) | | | — | | | (19) | | Foreign currency exchange rate derivatives | | $ | — | | | $ | (20) | | | $ | — | | | $ | (20) | |
| | | $ | — | | | $ | (20) | | | $ | — | | | $ | (20) | | | $ | — | | | $ | (20) | | | $ | — | | | $ | (20) | |
| | As of December 31, 2021: | | |
| As of December 31, 2022: | | As of December 31, 2022: | |
| Assets: | Assets: | | Assets: | |
| | Foreign currency exchange rate derivatives | | $ | — | | | $ | 3 | | | $ | — | | | $ | 3 | | |
| Commodity derivatives | | Commodity derivatives | | $ | — | | | $ | 1 | | | $ | — | | | $ | 1 | |
| Money market mutual funds | | Money market mutual funds | | 42 | | | — | | | — | | | 42 | |
| Equity securities: | Equity securities: | | Equity securities: | |
| Investment funds | Investment funds | | 13 | | | — | | | — | | | 13 | | Investment funds | | 14 | | | — | | | — | | | 14 | |
| | $ | 13 | | | $ | 3 | | | $ | — | | | $ | 16 | | | $ | 56 | | | $ | 1 | | | $ | — | | | $ | 57 | |
| | Liabilities: | Liabilities: | | Liabilities: | |
| | Foreign currency exchange rate derivatives | Foreign currency exchange rate derivatives | | $ | — | | | $ | (3) | | | $ | — | | | $ | (3) | | Foreign currency exchange rate derivatives | | $ | — | | | $ | (20) | | | $ | — | | | $ | (20) | |
| | | $ | — | | | $ | (3) | | | $ | — | | | $ | (3) | | | $ | — | | | $ | (20) | | | $ | — | | | $ | (20) | |
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 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 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of March 31, 2023 | | As of December 31, 2022 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
| Long-term debt | | $ | 3,897 | | | $ | 3,604 | | | $ | 3,892 | | | $ | 3,510 | |
(8) Commitments and Contingencies
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
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 Eastern Energy Gas' current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
(9) Revenue from Contracts with Customers
The following table summarizes Eastern Energy Gas' 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 | | Six-Month Periods | | Three-Month Periods |
| | Ended June 30, | | Ended June 30, | | Ended March 31, |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 |
| Customer Revenue: | Customer Revenue: | | | | | | | | Customer Revenue: | | | |
| Regulated: | Regulated: | | Regulated: | |
| Gas transportation and storage | $ | 286 | | | $ | 246 | | | $ | 571 | | | $ | 525 | | |
| Wholesale | — | | | — | | | — | | | 17 | | |
| Gas transmission and storage | | Gas transmission and storage | $ | 332 | | | $ | 285 | |
| | Other | | Other | 2 | | | — | |
| Total regulated | Total regulated | 286 | | | 246 | | | 571 | | | 542 | | Total regulated | 334 | | | 285 | |
| | Nonregulated | Nonregulated | 216 | | | 190 | | | 419 | | | 380 | | Nonregulated | 217 | | | 203 | |
| Total Customer Revenue | Total Customer Revenue | 502 | | | 436 | | | 990 | | | 922 | | Total Customer Revenue | 551 | | | 488 | |
Other revenue(1) | Other revenue(1) | 2 | | | 1 | | | (4) | | | 1 | | Other revenue(1) | 2 | | | (6) | |
| Total operating revenue | Total operating revenue | $ | 504 | | | $ | 437 | | | $ | 986 | | | $ | 923 | | Total operating revenue | $ | 553 | | | $ | 482 | |
(1)Other revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" and includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts.
Eastern Energy Gas has recognized contract liabilities of $70 million and $80 million as of March 31, 2023 and December 31, 2022, respectively, due to the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern Energy Gas recognizes revenue as it fulfills its obligations to provide services to its customers. During the three-month period ended March 31, 2023, Eastern Energy Gas recognized revenue of $22 million from the beginning contract liability balance.
Remaining Performance Obligations
The following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of June 30, 2022March 31, 2023 (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
| Eastern Energy Gas | $ | 2,228 | | | $ | 16,609 | | | $ | 18,837 | |
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
| | | | | |
| Eastern Energy Gas | $ | 1,657 | | | $ | 15,340 | | | $ | 16,997 | |
(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, 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) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Unrecognized | | | | | | Accumulated |
| | Amounts On | | Unrealized | | | | Other |
| | Retirement | | Losses on Cash | | Noncontrolling | | Comprehensive |
| | Benefits | | Flow Hedges | | Interests | | Loss, Net |
| | | | | | | | |
| Balance, December 31, 2021 | | $ | (6) | | | $ | (42) | | | $ | 5 | | | $ | (43) | |
| Other comprehensive income | | 1 | | | 4 | | | — | | | 5 | |
| Balance, March 31, 2022 | | $ | (5) | | | $ | (38) | | | $ | 5 | | | $ | (38) | |
| | | | | | | | |
| Balance, December 31, 2022 | | $ | (1) | | | $ | (43) | | | $ | 2 | | | $ | (42) | |
| Other comprehensive loss | | (1) | | | (2) | | | — | | | (3) | |
| Balance, March 31, 2023 | | $ | (2) | | | $ | (45) | | | $ | 2 | | | $ | (45) | |
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 SecondFirst Quarter of 2023 and First Six Months of 2022 and 2021
Overview
Net income attributable to Eastern Energy Gas for the secondfirst quarter of 20222023 was $103$122 million, an increase of $43$28 million compared to 2021.2022. Net income increased primarily due to higher marginsmargin from EGTS' regulated gas transportationtransmission and storage operations of $52$32 million and higher earnings from Iroquois due to favorable fixed negotiated rate agreements and hedges, partially offset by an increase in income tax expense of $15 million primarily due to higher pre-tax income.
Net income attributable to Eastern Energy Gas for the first six months of 2022 was $197 million, an increase of $48 million compared to 2021. Net income increased primarily due to higher margins from regulated gas transportationoperations and storage operations of $37 million, lower interest expense of $13 million primarily due to the repayment of long-term debt in the second quarter of 2021 and lower than estimated 2021 tax assessments of $11 million, partially offset by an increase in income tax expense of $18 million primarily due to higher pre-tax income.maintenance expenses.
Quarter Ended June 30, 2022March 31, 2023 Compared to Quarter Ended June 30, 2021March 31, 2022
Operating revenue increased $67$71 million, or 15%, for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to an increase in regulated gas transportationtransmission and storage services ratesrevenues due to an agreement in principle forthe settlement of EGTS' general rate case of $25$42 million, an increaseincreased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in Cove Point liquefied natural gas variable revenue2022 of $25$19 million, an increase in variable revenue related to park and loan activity of $6$10 million and a $4 million increase from the West Loop transmission pipeline being placed into servicederivative losses in the third quarter2022 of 2021.
Excess gas increased $11 million for the second quarter of 2022 compared to 2021, primarily due to favorable valuations of system gas of $27$7 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $6 million.
Cost of (excess) gas was an expense of $20 million for the first quarter of 2023 compared to a credit of $1 million for the first quarter of 2022. The change is primarily from the unfavorable revaluation of the volumes retained volumesprior to the effective date of $16 million.the new fuel tracker, due to lower natural gas prices.
Operations and maintenance increased $11$25 million, or 10%21%, for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to a 2021 benefit from the finalizationhigher corporate charges of entries for the disallowance$10 million, an increase in salaries, wages and benefits of capitalized AFUDC of $11$6 million and an increase in post-retirement benefit related costs of $6 million, partially offset by bank and legal fees recorded in 2021 related to Eastern Energy Gas' debt exchangeCove Point outside services of $4 million.
Depreciation and amortization decreased $1$5 million, or 1%6%, for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to a decrease due to an agreementthe settlement of depreciation rates in principle for EGTS' general rate case of $6$8 million, partially offset by higher plant placed in-service of $5$3 million.
Interest expense decreasedProperty and other taxes $6increased $8 million, or 14%28%, for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to lower 2021 tax assessments that were finalized in 2022.
Interest and dividend income increased $9 million for the repayment of $500 million of long-term debt in the secondfirst quarter of 2021.2023 compared to 2022, primarily due to higher outstanding borrowings and higher interest rates from BHE GT&S' intercompany revolving credit agreement with Eastern Energy Gas.
Income tax expense increased $15$9 million, or 68%30%, for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to higher pre-tax income. The effective tax rate was 15%16% for 2023 and 14% for 2022.
Equity income increased $13 million, or 68%, for the secondfirst quarter of 2023 compared to 2022, primarily due to higher earnings from Iroquois due to favorable fixed negotiated rate agreements and 13% for the second quarter of 2021.hedges.
Net income attributable to noncontrolling interests increased $18$7 million, or 18%6%, for the secondfirst quarter of 20222023 compared to 2021,2022, primarily due to increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022, partially offset by an increase in Cove Point liquefied natural gas variable revenue.outside services.
First Six Months Ended June 30, 2022 Compared to First Six Months Ended June 30, 2021
Operating revenue increased $63 million, or 7%, for the first six months of 2022 compared to 2021, primarily due to an increase in Cove Point liquefied natural gas variable revenue of $38 million, 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 due to decreased volumes.
Excess gas increased $12 million for the first six months of 2022 compared to 2021, primarily due to a decrease in volumes sold of $14 million and favorable valuations of system gas of $18 million, partially offset by an unfavorable change to volumes of $20 million.
Operations and maintenance increased $5 million, or 2%, for the first six months of 2022 compared to 2021, primarily due to a 2021 benefit from the finalization of entries for the disallowance of capitalized AFUDC of $11 million, partially offset by bank and legal fees recorded in 2021 related to Eastern Energy Gas' debt exchange of $4 million.
Depreciation and amortization increased $4 million, or 2%, for the first six months of 2022 compared to 2021, primarily due to higher plant placed in-service of $10 million, partially offset by a decrease due to an agreement in principle for EGTS' general rate case of $6 million.
Property and other taxes decreased $11 million, or 14%, for the first six months of 2022 compared to 2021, primarily due to lower than estimated 2021 tax assessments.
Interest expense decreased$14 million, or 16%, for the first six months of 2022 compared to 2021, primarily due to the repayment of $500 million of long-term debt in the second quarter of 2021.
Income tax expense increased $18 million, or 37%, for the first six months of 2022 compared to 2021, primarily due to higher pre-tax income. The effective tax rate was 14% for the first six months of 2022 and 13% for the first six months of 2021.
Net income attributable to noncontrolling interests increased $27 million, or 13%, for the first six months of 2022 compared to 2021, primarily due to an increase in Cove Point liquefied natural gas variable revenue.
Liquidity and Capital Resources
As of June 30, 2022,March 31, 2023, Eastern Energy Gas' total net liquidity was $506 million as follows (in millions):
| | | | | | | | |
| Cash and cash equivalents | | $ | 106103 | |
| | |
| Intercompany revolving credit agreement | | 400 | |
| | |
| | |
| | |
| | |
| | |
| Total net liquidity | | $ | 506503 | |
| | |
| Intercompany revolving credit agreement: | | |
| Maturity date | | 20222024 |
Operating Activities
Net cash flows from operating activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022 and 2021 were $681$319 million and $581$341 million, respectively. The change is primarily due to the timingrepayment of income tax payments,EGTS rate refunds to customers, partially offset by the impacts from the proposed ratesrate increase in effect April 1, 2022 for the EGTS general rate case and other changes in working capital adjustments.capital.
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 made for each payment date.
Investing Activities
Net cash flows from investing activities for the six-monththree-month periods ended June 30,March 31, 2023 and 2022 and 2021 were $(347)$(156) million and $(52)$(194) million, respectively. The increasechange is primarily due to a decreasean increase in repayments of loans by affiliates of $253$37 million and a decrease in capital expenditures of $16 million, partially offset by an increase in loans to its parent under an intercompany revolving credit agreement of $46$17 million.
Financing Activities
Net cash flows from financing activities for the six-monththree-month period ended June 30, 2022March 31, 2023 were $(242)$(124) million and consisted of distributions to noncontrolling interests from Cove Point.
Net cash flows from financing activities for the six-monththree-month period ended June 30, 2021March 31, 2022 were $(480) million. Sources of cash totaled $256$(114) million and consisted of proceeds from equity contributions, that primarily included a contribution from its indirect parent, BHE, to Eastern Energy Gas to assist in the repayment of $500 million of debt. Uses of cash totaled $736 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $225 million and repayment of notes to affiliates of $9 million.Point.
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, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, 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 natural gas transportation pipelinetransmission 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, new growth projects and the timing of growth projects; changes in environmental and other rules and regulations; impacts to customers'customer 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.
Eastern Energy Gas' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Six-Month Periods | | Annual |
| Ended June 30, | | Forecast |
| 2021 | | 2022 | | 2022 |
| | | | | |
| Natural gas transmission and storage | $ | 11 | | | $ | 23 | | | $ | 51 | |
| Other | 139 | | | 128 | | | 314 | |
| Total | $ | 150 | | | $ | 151 | | | $ | 365 | |
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2022 | | 2023 | | 2023 |
| | | | | |
| Natural gas transmission and storage | $ | 7 | | | $ | 4 | | | $ | 36 | |
| Other | 68 | | | 55 | | | 390 | |
| Total | $ | 75 | | | $ | 59 | | | $ | 426 | |
Eastern Energy Gas' naturalNatural gas transmission and storage capital expenditures primarily includeincludes growth capital expenditures related to planned regulated projects. Eastern Energy Gas' other capital expenditures consistOther includes primarily of non-regulatednonregulated and routine capital expenditures for natural gas transmission, storage and liquefied natural gasLNG terminalling infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of June 30, 2022,March 31, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2021, other than natural gas supply and transportation cash requirements increasing $87 million, primarily due to rate increases for pipeline transportation and storage purchase obligations as a result of a recent rate case.2022.
Regulatory Matters
Eastern Energy Gas 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 Eastern Energy Gas' current regulatory matters.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding air quality, climate change, RPS, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected specieswater quality and other environmental matters that have the potential to impact Eastern Energy Gas'its 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. Eastern Energy Gas 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 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, 2021.2022. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2022.
Eastern Gas Transmission and Storage, Inc. 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 Gas Transmission and Storage, Inc.
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Eastern Gas Transmission and Storage, Inc. and subsidiaries ("EGTS") as of March 31, 2023, the related consolidated statements of operations, comprehensive income, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2023 and 2022, 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 EGTS as of December 31, 2022 and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023 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, 2022, 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 EGTS' management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to EGTS 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
May 5, 2023
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2023 | | 2022 |
| ASSETS |
| Current assets: | | | |
| Cash and cash equivalents | $ | 46 | | | $ | 16 | |
| Restricted cash and cash equivalents | 29 | | | 29 | |
| Trade receivables, net | 84 | | | 113 | |
| Receivables from affiliates | 13 | | | 13 | |
| | | |
| Inventories | 51 | | | 50 | |
| | | |
| Prepayments and other deferred charges | 34 | | | 36 | |
| Natural gas imbalances | 62 | | | 193 | |
| Other current assets | 12 | | | 30 | |
| Total current assets | 331 | | | 480 | |
| | | |
| Property, plant and equipment, net | 4,604 | | | 4,504 | |
| | | |
| | | |
| | | |
| Other assets | 185 | | | 190 | |
| | | |
| Total assets | $ | 5,120 | | | $ | 5,174 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of |
| March 31, 2023 | | December 31, 2022 |
| LIABILITIES AND SHAREHOLDER'S EQUITY |
| Current liabilities: | | | |
| Accounts payable | $ | 30 | | | $ | 46 | |
| Accounts payable to affiliates | 5 | | | 5 | |
| Accrued interest | 23 | | | 7 | |
| Accrued property, income and other taxes | 59 | | | 71 | |
| Accrued employee expenses | 19 | | | 13 | |
| Notes payable to affiliates | 13 | | | 36 | |
| Regulatory liabilities | 21 | | | 109 | |
| Customer and security deposits | 29 | | | 29 | |
| Asset retirement obligations | 22 | | | 25 | |
| Other current liabilities | 31 | | | 32 | |
| Total current liabilities | 252 | | | 373 | |
| | | |
| Long-term debt | 1,582 | | | 1,582 | |
| Regulatory liabilities | 517 | | | 518 | |
| Other long-term liabilities | 102 | | | 101 | |
| Total liabilities | 2,453 | | | 2,574 | |
| | | |
| Commitments and contingencies (Note 8) | | | |
| | | |
| Shareholder's equity: | | | |
| Common stock - 75,000 shares authorized, $10,000 par value, 60,101 issued and outstanding | 609 | | | 609 | |
| Additional paid-in capital | 1,282 | | | 1,275 | |
| Retained earnings | 805 | | | 746 | |
| Accumulated other comprehensive loss, net | (29) | | | (30) | |
| Total shareholder's equity | 2,667 | | | 2,600 | |
| | | |
| Total liabilities and shareholder's equity | $ | 5,120 | | | $ | 5,174 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2023 | | 2022 |
| | | |
| Operating revenue | $ | 278 | | | $ | 223 | |
| | | |
| Operating expenses: | | | |
| Cost of (excess) gas | 20 | | | (3) | |
| Operations and maintenance | 99 | | | 84 | |
| Depreciation and amortization | 37 | | | 43 | |
| Property and other taxes | 14 | | | 9 | |
| | | |
| Total operating expenses | 170 | | | 133 | |
| | | |
| Operating income | 108 | | | 90 | |
| | | |
| Other income (expense): | | | |
| Interest expense | (18) | | | (17) | |
| | | |
| Allowance for equity funds | 1 | | | 1 | |
| | | |
| | | |
| Total other income (expense) | (17) | | | (16) | |
| | | |
| Income before income tax expense (benefit) | 91 | | | 74 | |
| Income tax expense (benefit) | 23 | | | 19 | |
| Net income | $ | 68 | | | $ | 55 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2023 | | 2022 |
| | | |
| Net income | $ | 68 | | | $ | 55 | |
| | | |
| Other comprehensive income, net of tax: | | | |
| Unrealized gains on cash flow hedges, net of tax of $— and $— | 1 | | | 1 | |
| | | |
| Total other comprehensive income, net of tax | 1 | | | 1 | |
| Comprehensive income | $ | 69 | | | $ | 56 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Accumulated | | |
| | | | | Additional | | | | Other | | Total |
| Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | | | |
| Balance, December 31, 2021 | 60,101 | | | $ | 609 | | | $ | 1,241 | | | $ | 721 | | | $ | (31) | | | $ | 2,540 | |
| Net income | — | | | — | | | — | | | 55 | | | — | | | 55 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Balance, March 31, 2022 | 60,101 | | | $ | 609 | | | $ | 1,241 | | | $ | 776 | | | $ | (30) | | | $ | 2,596 | |
| | | | | | | | | | | |
| Balance, December 31, 2022 | 60,101 | | | $ | 609 | | | $ | 1,275 | | | $ | 746 | | | $ | (30) | | | $ | 2,600 | |
| Net income | — | | | — | | | — | | | 68 | | | — | | | 68 | |
| Other comprehensive income | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| Dividends declared | — | | | — | | | — | | | (9) | | | — | | | (9) | |
| Contributions | — | | | — | | | 7 | | | — | | | — | | | 7 | |
| | | | | | | | | | | |
| Balance, March 31, 2023 | 60,101 | | | $ | 609 | | | $ | 1,282 | | | $ | 805 | | | $ | (29) | | | $ | 2,667 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2023 | | 2022 |
| Cash flows from operating activities: | | | |
| Net income | $ | 68 | | | 55 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
| | | |
| Depreciation and amortization | 37 | | | 43 | |
| Allowance for equity funds | (1) | | | (1) | |
| | | |
| Changes in regulatory assets and liabilities | (85) | | | (6) | |
| Deferred income taxes | 8 | | | 13 | |
| Other, net | 1 | | | 3 | |
| Changes in other operating assets and liabilities: | | | |
| Trade receivables and other assets | 42 | | | 37 | |
| Receivables from affiliates | — | | | (9) | |
| Gas balancing activities | 17 | | | (1) | |
| | | |
| Accrued property, income and other taxes | (15) | | | (18) | |
| Accounts payable and other liabilities | 21 | | | 20 | |
| Accounts payable to affiliates | — | | | (8) | |
| Net cash flows from operating activities | 93 | | | 128 | |
| | | |
| Cash flows from investing activities: | | | |
| Capital expenditures | (37) | | | (53) | |
| | | |
| | | |
| | | |
| | | |
| Other, net | (3) | | | (3) | |
| Net cash flows from investing activities | (40) | | | (56) | |
| | | |
| Cash flows from financing activities: | | | |
| | | |
| | | |
| | | |
| Repayment of notes payable to affiliates, net | (23) | | | (68) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Net cash flows from financing activities | (23) | | | (68) | |
| | | |
| | | |
| | | |
| Net change in cash and cash equivalents and restricted cash and cash equivalents | 30 | | | 4 | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 45 | | | 26 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 75 | | | $ | 30 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Eastern Gas Transmission and Storage, Inc. and its subsidiaries ("EGTS") conduct business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transmission systems and underground storage. EGTS' operations include transmission assets located in Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. EGTS also operates one of the nation's largest underground natural gas storage systems located in New York, Pennsylvania and West Virginia. EGTS is a wholly owned subsidiary of Eastern Energy Gas Holdings, LLC ("Eastern Energy Gas"), which 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 the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc.
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2023 and for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 2023 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 EGTS' Annual Report on Form 10-K for the year ended December 31, 2022 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in EGTS' accounting policies or its assumptions regarding significant accounting estimates during the three-month period ended March 31, 2023.
(2) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
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| | | As of |
| | | March 31, | | December 31, |
| Depreciable Life | | 2023 | | 2022 |
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| Interstate natural gas transmission and storage assets | 28 - 50 years | | $ | 6,842 | | | $ | 6,724 | |
| Intangible plant | 12 - 20 years | | 80 | | | 79 | |
| Plant in-service | | | 6,922 | | | 6,803 | |
| Accumulated depreciation and amortization | | | (2,465) | | | (2,440) | |
| | | 4,457 | | | 4,363 | |
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| Construction work-in-progress | | | 147 | | | 141 | |
| Property, plant and equipment, net | | | $ | 4,604 | | | $ | 4,504 | |
(3) Regulatory Matters
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. 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 transmission 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. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.
(4) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following (in millions):
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| As of |
| March 31, | | December 31, |
| 2023 | | 2022 |
| Investments: | | | |
| Investment funds | $ | 17 | | | $ | 14 | |
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| Restricted cash and cash equivalents: | | | |
| Customer deposits | 29 | | | 29 | |
| Total restricted cash and cash equivalents | 29 | | | 29 | |
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| Total investments and restricted cash and cash equivalents | $ | 46 | | | $ | 43 | |
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| Reflected as: | | | |
| Current assets | $ | 29 | | | $ | 29 | |
| Noncurrent assets | 17 | | | 14 | |
| Total investments and restricted cash and cash equivalents | $ | 46 | | | $ | 43 | |
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.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 of customer deposits as allowed under the FERC gas tariff. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on 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):
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| As of |
| March 31, | | December 31, |
| 2023 | | 2022 |
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| Cash and cash equivalents | $ | 46 | | | $ | 16 | |
| Restricted cash and cash equivalents | 29 | | | 29 | |
| Total cash and cash equivalents and restricted cash and cash equivalents | $ | 75 | | | $ | 45 | |
(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 (benefit) is as follows:
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| Three-Month Periods |
| Ended March 31, |
| 2023 | | 2022 |
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| Federal statutory income tax rate | 21 | % | | 21 | % |
| State income tax, net of federal income tax benefit | 4 | | | 5 | |
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| Effective income tax rate | 25 | % | | 26 | % |
(6) Employee Benefit Plans
EGTS is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of EGTS. EGTS contributed $2 million and $3 million to the MidAmerican Energy Company Retirement Plan for the three-month periods ended March 31, 2023 and 2022, respectively, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the three-month period ended March 31, 2022. Contributions related to these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to EGTS were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. 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. As of March 31, 2023 and December 31, 2022, EGTS' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $47 million.
(7) Fair Value Measurements
The carrying value of EGTS' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. EGTS 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 EGTS 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 EGTS' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. EGTS develops these inputs based on the best information available, including its own data.
The following table presents EGTS' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
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| | Input Levels for Fair Value Measurements | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| As of March 31, 2023: | | | | | | | | |
| Assets: | | | | | | | | |
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| Money market mutual funds | | $ | 40 | | | $ | — | | | $ | — | | | $ | 40 | |
| Equity securities: | | | | | | | | |
| Investment funds | | 17 | | | — | | | — | | | 17 | |
| | $ | 57 | | | $ | — | | | $ | — | | | $ | 57 | |
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| As of December 31, 2022: | | | | | | | | |
| Assets: | | | | | | | | |
| Commodity derivatives | | $ | — | | | $ | 1 | | | $ | — | | | $ | 1 | |
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| Money market mutual funds | | 8 | | | — | | | — | | | 8 | |
| Equity securities: | | | | | | | | |
| Investment funds | | 14 | | | — | | | — | | | 14 | |
| | $ | 22 | | | $ | 1 | | | $ | — | | | $ | 23 | |
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EGTS' 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 EGTS transacts. When quoted prices for identical contracts are not available, EGTS uses forward price curves. Forward price curves represent EGTS' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. EGTS 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 EGTS. Market price quotations are generally readily obtainable for the applicable term of EGTS' outstanding derivative contracts; therefore, EGTS' 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, EGTS 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, related volatility, counterparty creditworthiness and duration of contracts.
EGTS' long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of EGTS' 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 following table presents the carrying value and estimated fair value of EGTS' long-term debt (in millions):
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| As of March 31, 2023 | | As of December 31, 2022 |
| Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value |
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| Long-term debt | $ | 1,582 | | | $ | 1,393 | | | $ | 1,582 | | | $ | 1,337 | |
(8) Commitments and Contingencies
Environmental Laws and Regulations
EGTS is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its current and future operations. EGTS believes it is in material compliance with all applicable laws and regulations.
Legal Matters
EGTS is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. EGTS does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
(9) Revenue from Contracts with Customers
The following table summarizes EGTS' revenue from contracts with customers ("Customer Revenue") by regulated and other, with further disaggregation of regulated by line of business (in millions):
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| Three-Month Periods |
| Ended March 31, |
| 2023 | | 2022 |
| Customer Revenue: | | | |
| Regulated: | | | |
| Gas transmission | $ | 191 | | | $ | 165 | |
| Gas storage | 67 | | | 47 | |
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| Other | 2 | | | — | |
| Total regulated | 260 | | | 212 | |
| Management service and other revenues | 17 | | | 18 | |
| Total Customer Revenue | 277 | | | 230 | |
Other revenue(1) | 1 | | | (7) | |
| Total operating revenue | $ | 278 | | | $ | 223 | |
(1)Other revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" and includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts.
Remaining Performance Obligations
The following table summarizes EGTS' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of March 31, 2023 (in millions):
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| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
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| EGTS | $ | 746 | | | $ | 3,390 | | | $ | 4,136 | |
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 EGTS during the periods included herein. This discussion should be read in conjunction with EGTS' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. EGTS' actual results in the future could differ significantly from the historical results.
Results of Operations for the First Quarter of 2023 and 2022
Overview
Net income for the first quarter of 2023 was $68 million, an increase of $13 million, or 24%, compared to 2022. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $32 million and a decrease due to lower depreciation rates due to the settlement in EGTS' general rate case, partially offset by higher operations and maintenance expenses, lower 2021 tax assessments finalized in 2022 and an increase in income tax expense primarily due to higher pre-tax income.
Quarter Ended March 31, 2023 Compared to Quarter Ended March 31, 2022
Operating revenue increased $55 million, or 25%, for the first quarter of 2023 compared to 2022, primarily due to an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $42 million, an increase in variable revenue related to park and loan activity of $10 million and derivative losses in 2022 of $7 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $6 million.
Cost of (excess) gas was an expense of $20 million for the first quarter of 2023 compared to a credit of $3 million for the first quarter of 2022. The change is primarily from the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker, due to lower natural gas prices.
Operations and maintenance increased $15 million, or 18%, for the first quarter of 2023 compared to 2022, primarily due to higher corporate charges of $6 million and an increase in salaries, wages and benefits of $5 million.
Depreciation and amortization decreased $6 million, or 14%, for the first quarter of 2023 compared to 2022, primarily due to the settlement of deprecation rates in EGTS' general rate case of $8 million, partially offset by higher plant placed in-service of $2 million.
Property and other taxes increased $5 million, or 56%, for the first quarter of 2023 compared to 2022, primarily due to lower 2021 tax assessments that were finalized in 2022.
Income tax expense increased $4 million, or 21%, for the first quarter of 2023 compared to 2022, primarily due to higher pre-tax income. The effective tax rate was 25% for 2023 and 26% for 2022.
Liquidity and Capital Resources
As of March 31, 2023, EGTS' total net liquidity was as follows (in millions):
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| Cash and cash equivalents | | $ | 46 | |
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| Intercompany revolving credit agreement | | 400 | |
| Less: | | |
| Notes payable to affiliates | | 13 | |
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| Net intercompany revolving credit agreement | | 387 | |
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| Total net liquidity | | $ | 433 | |
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| Intercompany credit agreement: | | |
| Maturity date | | 2024 |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022 were $93 million and $128 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers, partially offset by the impacts from the rate increase in effect April 1, 2022 for the EGTS general rate case and other changes in working capital.
The timing of EGTS' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods elected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022 were $(40) million and $(56) million, respectively. The change is primarily due to a decrease in capital expenditures of $16 million.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2023 were $(23) million and consisted of net repayment of notes payable to Eastern Energy Gas.
Net cash flows from financing activities for the three-month period ended March 31, 2022 were $(68) million and consisted of net repayment of notes payable to Eastern Energy Gas.
Future Uses of Cash
EGTS 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, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments, debt retirements and other capital requirements. The availability and terms under which EGTS has access to external financing depends on a variety of factors, including regulatory approvals, EGTS' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the natural gas transmission and storage 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, new growth projects and the timing of growth projects; changes in environmental and other rules and regulations; impacts to customer 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.
EGTS' 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):
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| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2022 | | 2023 | | 2023 |
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| Natural gas transmission and storage | $ | 6 | | | $ | 3 | | | $ | 27 | |
| Other | 47 | | | 34 | | | 225 | |
| Total | $ | 53 | | | $ | 37 | | | $ | 252 | |
Natural gas transmission and storage includes primarily growth capital expenditures related to planned regulated projects. Other includes primarily pipeline integrity work, automation and controls upgrades, underground storage, corrosion control, unit exchanges, compressor modifications and projects related to Pipeline Hazardous Materials Safety Administration natural gas storage rules. The amounts also include EGTS' asset modernization program, which includes projects for vintage pipeline replacement, compression replacement, pipeline assessment and underground storage integrity.
Material Cash Requirements
As of March 31, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of EGTS' Annual Report on Form 10-K for the year ended December 31, 2022.
Regulatory Matters
EGTS 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 EGTS' current regulatory matters.
Environmental Laws and Regulations
EGTS is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its 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. EGTS 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 EGTS 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, impairment of long-lived assets and income taxes. For additional discussion of EGTS' critical accounting estimates, see Item 7 of EGTS' Annual Report on Form 10-K for the year ended December 31, 2022. There have been no significant changes in EGTS' assumptions regarding critical accounting estimates since December 31, 2022.
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, 2021.2022. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2021.2022. 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 76 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 June 30, 2022.March 31, 2023.
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 and Eastern Gas Transmission and Storage, Inc. carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended June 30, 2022March 31, 2023 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
Multiple lawsuits, complaints and demands alleging similar claims totaling approximately $8.0 billion have been filed in Oregon and California related to the 2020 Wildfires. Multiple complaints have also been filed in California for the 2022 McKinney fire. Generally, the complaints filed in California do not specify damages sought. Investigations into the causes and origins of those wildfires are ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 9 of the 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.
On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20cv33885,20CV33885, 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 Complex, 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. In January 2023, the Oregon Court of Appeals denied PacifiCorp's request for appeal. In February 2023, the plaintiffs filed a motion to amend the complaint to add punitive damages in an unspecified amount. On March 23, 2023, the plaintiffs filed an amended complaint seeking punitive damages with permission of the Circuit Court. Plaintiffs seek punitive damages at a five times multiplier to the amount of compensatory damages awarded. On April 24, 2023, the jury trial began in Multnomah County Circuit Court.
On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21cv33595,21CV33595, Multnomah County, Oregon, in which two complaints, Case No. 21cv0933921CV09339 and Case No. 21cv09520,21CV09520, 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,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 Firefire 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.
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, Archie Creek, Susan Creek and Smith Springs Road fires 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 as amended: (i) economic and property damages in excess of $195 million under a determination of negligence or inverse condemnation; (ii) doubling of those economic damages to in excess of $390 million under a determination of gross negligence pursuant to Oregon statutes; (iii) all costs of the lawsuit; (iv) prejudgment interest of $43 million and post-judgment interest as allowed by law; and (v) attorneys' fees of $105 million and other costs.
In May 2022, the Multnomah County Circuit Court granted plaintiffs' motion to consolidate Shylo Salter et al. v. PacifiCorp, Case No. 21cv3359521CV33595 (described above) and Amy Allen, et al. v. PacifiCorp, Case No. 20cv3743020CV37430 ("Allen") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20cv3388520CV33885 (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 JuneOn August 26, 2022, an amendeda putative class action complaint seeking declaratory and equitable relief against PacifiCorp was filed, captioned Tim GoforthMargaret Dietrich et al. v. PacifiCorp, Case No. 20cv37637, Douglas22CV29187, Circuit Court, Multnomah County, Oregon. The complaint was filed by two Oregon residents individually and on behalf of a class initially defined to include residents of, business owners in, whichreal or personal property owners in and any other individuals physically present in specified Oregon counties as of September 7, 2020 who experienced any harm, damage or loss as a previously filed complaint associated withresult of the ArchieSantiam, Beachie Creek, Fire, Susan Creek Fire and Smith Springs Road Fire in Douglas CountyLionshead, Echo Mountain Complex, Two Four Two or South Obenchain fires in September 20202020. The complaint was amended on September 6, 2022, to add punitive damages.seek damages of over $900 million that were originally demanded on August 4, 2022, pursuant to Oregon Rule of Civil Procedure 32 H. The amended complaint allegesalleges: (i) PacifiCorp's conduct not only constituted common law negligence butdue to alleged failure to comply with certain Oregon statutes and administrative rules; (ii) gross negligence and contributeddue to alleged conscious indifference to or wasreckless disregard for the causeprobable consequences of ignition and spreaddefendant's actions or inactions; (iii) private nuisance; (iv) public nuisance; (v) trespass; (vi) inverse condemnation; (vii) accounting/injunction; (viii) negligent infliction of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence, inverse condemnation.emotional distress. The amended complaint seeks the following damages:following: (i) an order certifying the matter as a class action; (ii) economic and property damages not less than $400 million; (iii) double the amount 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 millionthe extent applicable under a determinationOregon statute; (iv) reasonable costs of gross negligence; (iii)reforestation activities; (v) doubling and trebling of certain other damages for injuries in excess of $47 million; (iv) punitiveto the extent applicable under certain Oregon statutes; (vi) noneconomic damages not less than $500 million; (vii) prejudgment interest; (viii) an order requiring an accounting with respect to exceed 10 times the amount of non-economic damages awarded; (v) alldamages; (ix) an order enjoining PacifiCorp from leaving power lines energized in areas of Oregon experiencing extremely critical fire conditions; (x) an award of reasonable attorney fees, costs, ofinvestigation costs, disbursements and expert witness fees; and (xi) other relief the lawsuit; (vi) pre-court finds appropriate. The plaintiffs and post-judgment interest as allowedproposed class demand a trial by law;jury. On December 19, 2022, the Dietrich case was consolidated into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above) and (vii) attorneys' fees and other costs.is currently stayed.
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 8 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,September 1, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources CoMartin Klinger et al. v. PacifiCorp, Case No. 22cv09346, Circuit Court, Douglas22CV29674, Multnomah County, Oregon.Oregon ("Klinger"). The complaint was filed by nine businesses and public pension plans that own and/Oregon residents or operate timberlands or possessOregon property in Douglas Countyowners who allege damages lossesresulting from the September 2020 Echo Mountain Complex fires. The allegations made and injuries associated with their timberlands asdamages sought are described below.
On September 1, 2022, a result of the French Creek Fire, the Archie Creek Fire, the Susan Creek Fire and the Smith Springs Road Fire in Douglascomplaint against PacifiCorp was filed, captioned Jeremiah E. Bowen et al. v. PacifiCorp, Case No. 22CV29681, Multnomah County, in September 2020.Oregon ("Bowen"). The complaint allegeswas filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 1, 2022, a complaint against PacifiCorp was filed, captioned James Weathers et al. v. PacifiCorp, Case No. 22CV29683, Multnomah County, Oregon ("Weathers"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 6, 2022, a complaint against PacifiCorp was filed, captioned Blair Barnholdt et al. v. PacifiCorp, Case No. 22CV30097, Multnomah County, Oregon ("Barnholdt"). The complaint was filed by Oregon residents or Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 7, 2022, a complaint against PacifiCorp was filed, captioned Estate of Nancy Darlene Hunter, et al. v. PacifiCorp, Case No. 22CV30214, Multnomah County, Oregon ("Hunter"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 7, 2022, a complaint against PacifiCorp was filed, captioned Willard K. Pratt et al. v. PacifiCorp, Case No. 22CV30217, Multnomah County, Oregon ("Pratt"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
On September 7, 2022, a complaint against PacifiCorp was filed, captioned April Thompson et al. v. PacifiCorp, Case No. 22CV30451, Multnomah County, Oregon ("Thompson"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.
The Klinger, Bowen, Weathers, Barnholdt, Hunter, Pratt and Thompson cases are in the process of being consolidated with Sparkset al. v. PacifiCorp, Case No. 21CV48022 ("Sparks")and Russieet al. v. PacifiCorp, Case No. 22CV15840 ("Russie") into Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen"). The Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson complaints each allege: (i) PacifiCorp's conduct constituted not only common law negligence but alsodue in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and that such conduct contributedreckless disregard of known risks to or caused the ignitionpublic; (iii) trespass; (iv) nuisance; and spread of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence,(v) inverse condemnation. The complaint seeksKlinger, Bowen, Weathers, Barnholdt, Pratt and Thompson complaints each seek the following damages: (i) economic and property related damages in excess of $175 million under a determination of negligence or inverse condemnation;$83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in excessan amount not less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of $350 million under a determinationwages, loss of gross negligence pursuant to Oregon statutes; (iii) all costs of the lawsuit; (iv) prejudgmentearnings capacity, evacuation expenses, displacement expenses and post-judgment interest as allowed by law; andsimilar damages; (v) attorneys' fees and other costs.costs; and (vii) pre-judgment interest. The plaintiffs for each Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages. The Hunter complaint seeks $50 million in damages and alleges claims for: (i) negligence, (ii) trespass, (iii), nuisance, (iv) inverse condemnation, and (v) wrongful death. The Andersen case was filed by 50 individuals as amended in August 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest. The Sparks case was filed by 17 individuals in December 2021 claiming $125 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- judgment interest. The Russie case was filed by 45 individuals as amended in September 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest.
On September 1, 2022, a complaint against PacifiCorp was filed, captioned Aaron Macy-Wyngarden et al. v. PacifiCorp, Case No. 22CV29684, Multnomah County, Oregon ("Macy-Wyngarden"). The complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.
On September 22, 2022, a complaint against PacifiCorp was filed, captioned Zachary Bogle et al. v. PacifiCorp, Case No. 22CV29717, Multnomah County, Oregon ("Bogle"). The complaint was filed by Oregon residents who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.
The Macy-Wyngarden and Bogle complaints each allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; and (v) inverse condemnation. The Macy-Wyngarden and Bogle complaints each seek the following damages: (i) economic and property related damages of $83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of earnings capacity, evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and (vii) pre-judgment interest. The plaintiffs for each Macy-Wyngarden and Bogle request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages.
On September 2, 2022, a complaint against PacifiCorp was filed, captioned Logan et al. v. PacifiCorp, Case No. 22CV29859, Multnomah County, Oregon ("Logan"). The Logan complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The Logan case is in the process of being consolidated with Cady et al. v. PacifiCorp, Case No. 22CV13946 ("Cady") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The Logan and Cady complaints each allege: (i) negligence; (ii) trespass; (iii) nuisance, and (iv) inverse condemnation. The Logan case was filed by five individuals claiming $10 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. The Cady case was filed by 21 individuals as amended in April 2022 claiming $10 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest.
On October 14, 2022, the Multnomah County Circuit Court consolidated 21st Century Centennial Insurance Company, et al. v. PacifiCorp, Case No. 22CV26326 ("21st Century") and Allstate Vehicle and Property Insurance Company, et al. v. PacifiCorp, Case No. 22CV29976 into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The 21st Century and Allstate complaints were each filed by subrogated insurance carriers alleging claims of (i) negligence, (ii) gross negligence, and (iii) inverse condemnation resulting from the September 2020 Santiam Canyon, Echo Mountain Complex, 242, and South Obenchain fires. The 21st Century case was filed in August 2022 by 177 insurance carriers seeking $20 million in damages. The Allstate case was filed in September 2022 by 11 insurance carriers seeking $40 million in damages.
On October 17, 2022, the Multnomah County Circuit Court consolidated Michael Bell, et al. v. PacifiCorp, Case No. 22CV30450 ("Bell") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The Bell case was filed in Oregon Circuit Court in Multnomah County, Oregon on September 7, 2022, by 59 plaintiffs seeking $35 million in damages for claims of (i) negligence, (ii) trespass, (iii) nuisance, and (iv) inverse condemnation.
On October 19, 2022, the Multnomah County Circuit Court consolidated Freres Timber, Inc. v. PacifiCorp, Case No. 22CV29694 ("Freres") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The Freres case was filed in Oregon Circuit Court in Multnomah County, Oregon on September 1, 2022, by one plaintiff and seeks $40 million for claims of (i) negligence, (ii) gross negligence, and (iii) inverse condemnation.
On November 1, 2022, three complaints were filed against PacifiCorp, captioned Moore et al. v. PacifiCorp, No. 22CV37302; Blodgett et al. v. PacifiCorp, No. 22CV37306; and Ellis et al. v. PacifiCorp, No. 22CV37304. Three additional cases were filed December 5, 2022, captioned Tague et al. v. PacifiCorp, No. 22CV41242; Long, et al. v. PacifiCorp, No. 22CV41283; and Moyers et al. v. PacifiCorp, No. 22CV41293. On January 6, 2023, an additional complaint was filed against PacifiCorp captioned Meyer et al. v. PacifiCorp, No. 23CV00748. On January 17, 2023, seven additional cases were filed, captioned Foster et al. v. PacifiCorp, No. 23CV02142; Hall et al. v. PacifiCorp, No. 23CV02184; Joneset al. v. PacifiCorp, No. 23CV02110; Price et al. v. PacifiCorp, No. 23CV02175; Minottet al. v. PacifiCorp, No. 23CV02203; Webbet al. v. PacifiCorp, No. 23CV02202; and Keithet al. v. PacifiCorp, No. 23CV02200. On January 24, 2023, three additional cases were filed captioned Kiddet al. v. PacifiCorp, No. 23CV03318; Parkeret al. v. PacifiCorp, No. 23CV03317; and Diazet al. v. PacifiCorp, No. 23CV03313. These complaints were filed in Circuit Courts, Douglas County and Multnomah County, Oregon with substantially similar allegations as those of the Roseburg Resources Co case with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral ruling, the Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues, along with the above mentioned Roseburg Resources Co case; the precise scope of the trial will be determined in a later order. Collectively, these eighteen cases seek in excess of $1,300 million in damages, inclusive of the $573 million Roseburg Resources Co case. On February 14, 2023, the Circuit Court ordered that all plaintiffs' claims for inverse condemnation be dismissed; a written order is forthcoming.
On December 6, 2022, CW Specialty Lumber, Inc., et al. v. PacifiCorp, Case No. 22CV41640 ("CW Specialty") was filed in Oregon Circuit Court in Multnomah County, Oregon by two plaintiffs seeking $28.6 million in damages for claims of (i) negligence, (ii) gross negligence, (iii) trespass, and (iv) inverse condemnation. The CW Specialty case is in the process of being consolidated into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above).
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, 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.2022.
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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4.110.1 | Seventeenth Supplemental Indenture,First Amending Agreement to the Credit Agreement, dated April 27, 2021, among AltaLink Investments, L.P., as of April 21, 2022, by and between Berkshire Hathaway Energy Company and Theborrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of New York Mellon Trust Company, N.A.,Canada, as trustee, relating to the 4.600% 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)administrative agent, and Lenders. |
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4.210.2 | Trust Deed,Second Amending Agreement to the Credit Agreement, dated as of April 1,27, 2022, among Northern Powergrid (Northeast) plcAltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and HSBC Corporate Trustee Company (UK) Limited, relating to the £350,000,000 in principal amount of the 3.250% Bonds due Lenders2052 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2022). |
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10.110.3 | $3,500,000,000 Third Amended and RestatedAmending Agreement to the Credit Agreement, dated April 27, 2023, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of June 30, 2022, among Berkshire Hathaway Energy Company,Canada, as Borrower, the Banks, Financial Institutionsadministrative agent, and Other Institutional Lenders as Initial Lenders, MUFG Bank, Ltd. as Administrative Agent and the LC Issuing 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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10.2 | $1,200,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 2022, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JP Morgan Chase Bank, N.A. as Administrative Agent and the LC Issuing Banks. |
| 95 | |
MIDAMERICAN ENERGY
BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY
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10.3 | $1,500,000,000 Third Amended and Restated Credit Agreement, dated as of June 30, 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. |
MIDAMERICAN FUNDING
NEVADA POWER
BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
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10.4 | $400,000,000 Fifth Amended and Restated Credit Agreement, dated as of June 30, 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. |
SIERRA PACIFIC
BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
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4.310.4 | |
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4.4 | |
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4.5 | |
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10.6 | $250,000,000 Fifth Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of June 30, 2022, among Sierra Pacific Power Company, as Borrower, the Banks, Financial InstitutionsMarch 1, 2023, by and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agentbetween BHE GT&S, LLC and the LC Issuing Banks.Eastern Energy Gas Holdings, LLC. |
EASTERN ENERGY GAS
EASTERN GAS TRANSMISSION AND STORAGE
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| 10.5 | |
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| 10.6 | |
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| 31.15 | |
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| 31.16 | |
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| 32.15 | |
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| 32.16 | |
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 June 30, 2022,March 31, 2023, 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: AugustMay 5, 20222023 | /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: AugustMay 5, 20222023 | /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: AugustMay 5, 20222023 | /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: AugustMay 5, 20222023 | /s/ Michael E. ColeJ. Behrens |
| Michael E. ColeJ. Behrens |
| Senior Vice President and Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |
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| SIERRA PACIFIC POWER COMPANY |
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Date: AugustMay 5, 20222023 | /s/ Michael E. ColeJ. Behrens |
| Michael E. ColeJ. Behrens |
| Senior Vice President and Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |
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| EASTERN ENERGY GAS HOLDINGS, LLC |
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Date: AugustMay 5, 20222023 | /s/ Scott C. Miller |
| Scott C. Miller |
| Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |
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| EASTERN GAS TRANSMISSION AND STORAGE, INC. |
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| Date: May 5, 2023 | /s/ Scott C. Miller |
| Scott C. Miller |
| Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |