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.

Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).

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.

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.

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.

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of ~~June~~September 30, 2022, the related consolidated statements of operations, comprehensive income, and changes in equity for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2022 and 2021, and of cash flows for the ~~six-month~~nine-month periods ended ~~June~~September 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 the Company as of December 31, 2021, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

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

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, the largest residential real estate brokerage firm in the U.S. and 1one 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~~September 30, 2022 and for the three- and ~~six-month~~nine-month periods ended ~~June~~September 30, 2022 and 2021. The results of operations for the three- and ~~six-month~~nine-month periods ended ~~June~~September 30, 2022 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2021 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-month~~nine-month period ended ~~June~~September 30, 2022, other than the updates associated with the Company's estimates of loss contingencies related to the Oregon and California 2020 wildfires (the "2020 Wildfires") as discussed in Note 8.

Property, plant and equipment, net consists of the following (in millions):

Construction work-in-progress includes ~~$4.4~~$4.8 billion as of ~~June~~September 30, 2022 and $3.8 billion as of December 31, 2021, related to the construction of regulated assets.

Investments and restricted cash, cash equivalents and investments consists of the following (in millions):

~~Gains~~(Losses) gains on marketable securities, net recognized during the period consists of the following (in millions):

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 in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):

In October 2022, Nevada Power issued $400 million of 5.90% General and Refunding Mortgage bonds, Series GG, due 2053. The net proceeds were used to repay amounts outstanding under its existing revolving credit facility, to fund capital expenditures and for general corporate purposes.

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.

In June 2022, BHE amended and restated its existing $3.5 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 ("LIBOR") to SOFR.

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 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.

The effective income tax rate for the three-month period ended September 30, 2022, is 64% and results from a $1,213 million income tax benefit associated with a $1,895 million pre-tax loss, primarily relating to a pre-tax loss of $3,259 million on the Company's investment in BYD Company Limited. The $1,213 million income tax benefit is primarily comprised of a $398 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss and a $680 million benefit (36%) from income tax credits.

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax benefit is as follows:

Income tax credits relate primarily to PTCs from ~~wind-powered~~wind- and solar-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity PTCs are earned as energy from qualifying ~~wind-powered~~wind- 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-powered~~Wind- 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-month~~nine-month periods ended ~~June~~September 30, 2022 and 2021 totaled ~~$734~~$1,414 million and ~~$678~~$1,188 million, respectively.

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

The Company's provision for income taxes has been 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 cash payments for federal income taxes from Berkshire Hathaway for the ~~six-month~~nine-month periods ended ~~June~~September 30, 2022 and 2021 totaling ~~$1,249~~$1,742 million and ~~$943~~$1,259 million, respectively.

15In July 2022, the Company amended its tax allocation agreement with Berkshire Hathaway, which changed how state tax attributes will be settled. 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 has reclassified $744 million to retained earnings.

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $5 million, respectively, during 2022. As of ~~June~~September 30, 2022, $7$10 million and $5 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Net periodic benefit credit for the United Kingdom pension plan included the following components (in millions):

Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £12 million during 2022. As of ~~June~~September 30, 2022, £6£9 million, or $8$12 million, of contributions had been made to the United Kingdom pension plan.

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:

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):

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.

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):

During the ~~six-month~~nine-month period ended ~~June~~September 30, 2022, PacifiCorp entered into certain coal supply and transportation agreements totaling approximately ~~$200~~$214 million through ~~2024.~~2028.

During the nine-month period ended September 30, 2022, PacifiCorp entered into a purchased electricity contract for a solar generating facility including battery storage with minimum obligations totaling approximately $238 million through 2045. The facility associated with this contract has not yet achieved commercial operation. To the extent this facility does not achieve commercial operation, PacifiCorp has no obligation to the counterparty.

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.

A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PacifiCorp evaluates which potential liabilities are probable and the related range of reasonably estimated losses and records a charge that reflects its best estimate or the lower end of the 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 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.

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.

As of the date of this filing, 60 lawsuits have been filed in Oregon and California, including a ~~putative~~ class action complaint in Oregon, on behalf of ~~citizens~~plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and ~~businesses who suffered damages from fires allegedly caused by PacifiCorp.~~other damages. 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 the completion of comprehensive investigations and litigation processes.

~~In California, under inverse condemnation, courts have held that investor-owned utilities can~~As of the date of this filing, PacifiCorp estimates the probable loss to be ~~liable for real~~$200 million, net of expected insurance recoveries and ~~personal property damages without the utility being found negligent and regardless~~has accrued such amount as of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including real and personal property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.

According to California Department of Forestry and Fire Protection ("Cal Fire"), on July 29, 2022, at approximately 2:16 p.m. Pacific Time, 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. The Cal Fire McKinney Fire incident report last updated September 8, 2022 (the "Cal Fire incident report") indicates that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and 4 fatalities. According to InciWeb, an interagency all-risk incident information management system, the 2022 McKinney Fire consumed 60,138 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the United States Forest Service.

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 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.

As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages but the amount of damages sought are not specified. The final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.

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

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

In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application 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 be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending. In ~~February~~August 2022, the FERC staff issued a ~~draft~~final environmental impact statement for the project, concluding that dam removal is the preferred ~~alternative. A final environmental impact statement is expected later in 2022.~~action.

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.

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):

The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):

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~~September 30, 2022, by reportable segment (in millions):

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):

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. Information related to the Company's reportable segments is shown below (in millions):

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

BHE is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway. As of ~~August 4,~~November 3, 2022, Berkshire Hathaway and family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, beneficially owned 92% and 8%, respectively, of BHE's common stock.

Berkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE Transmission (which consists of BHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies, one of which owns a liquefied natural gas ("LNG") export, import and storage facility, in the 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, the largest residential real estate brokerage firm 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 entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.

Operating revenue and (loss) earnings on common shares for the Company's reportable segments are summarized as follows (in millions):

Earnings on common shares ~~increased $640~~decreased $2,746 million for the ~~second~~third quarter of 2022 compared to 2021. The ~~second~~third quarter of 2022 included a pre-tax ~~unrealized gain~~loss of ~~$2,557~~$3,259 million ($~~2,020~~2,574 million after-tax) compared to a pre-tax ~~unrealized~~ gain in the ~~second~~third quarter of 2021 of ~~$1,954~~$296 million ($~~1,420~~253 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the ~~second~~third quarter of 2022 was ~~$864~~$1,724 million, an increase of ~~$40~~$81 million, or 5%, compared to adjusted earnings on common shares in the ~~second~~third quarter of 2021 of ~~$824~~$1,643 million.

Earnings on common shares ~~increased $529~~decreased $2,217 million for the first ~~six~~nine months of 2022 compared to 2021. The first ~~six~~nine months of 2022 included a pre-tax ~~unrealized gain~~loss of ~~$1,310~~$1,948 million ($~~1,035~~1,539 million after-tax) compared to a pre-tax ~~unrealized~~ gain in the first ~~six~~nine months of 2021 of ~~$830~~$1,126 million ($~~602~~855 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~~nine months of 2022 was ~~$1,704~~$3,428 million, an increase of ~~$96~~$177 million, or 6%5%, compared to adjusted earnings on ~~commons~~common shares in the first ~~six~~nine months of 2021 of ~~$1,608~~$3,251 million.

The ~~increases~~decreases in earnings on common shares for the ~~second~~third quarter and for the first ~~six~~nine months of 2022 compared to 2021 were primarily due to the following:

Operating revenue increased ~~$16~~$144 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to higher ~~wholesale and other revenue~~retail revenues of $30 million, partially offset by lower retail revenue of $14 million. Wholesale and other 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 million from higher average retail rates primarily due to tariff changes. 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.

Earnings ~~decreased $182~~increased $76 million for the third quarter of 2022 compared to 2021, primarily due to higher utility margin of $67 million and a favorable income tax benefit, partially offset by higher operations and maintenance expense of $22 million and higher depreciation and amortization expense of $5 million, mainly from additional assets placed in-service. Utility margin increased primarily due to higher retail rates and volumes, favorable deferred net power costs and higher average wholesale prices, partially offset by higher purchased power and thermal generation costs. The favorable income tax benefit was largely due to higher PTCs recognized of $21 million and the effects of ratemaking.

Operating revenue increased $215 million for the first ~~six~~nine months of 2022 compared to 2021, primarily due to higher retail revenues of $143 million and higher wholesale and other revenue of $72 million, largely from higher average wholesale prices. Retail revenue increased primarily due to price impacts of $104 million from higher average retail rates largely due to tariff changes and $40 million from higher retail volumes. Retail customer volumes increased 0.8%, primarily due to an increase in the average number of customers and the favorable impact of weather, partially offset by lower customer usage.

Earnings decreased $106 million for the first nine months of 2022 compared to 2021, primarily due to higher operations and maintenance expense of ~~$138~~$160 million, an unfavorable income tax benefit, higher depreciation and amortization expense of ~~$20~~$25 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~~$88 million. Operations and maintenance expense increased mainly due to an increase in loss accruals ~~related to~~associated with the September 2020 wildfires, net of estimated insurance recoveries, and higher general and plant maintenance ~~costs.~~costs, Utility margin increased primarily due to ~~the~~ higher retail rates and volumes, higher average wholesale prices and ~~other revenues,~~favorable deferred net power costs, partially offset by higher purchased power and thermal generation costs. The unfavorable income tax benefit was largely due to the effects of ratemaking and lower PTCs recognized of ~~$27 million and the effects of ratemaking of $27~~$6 million.

Earnings decreased $7$73 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to higher depreciation and amortization expense of ~~$68~~$120 million, an unfavorable income tax benefit, higher operations and maintenance expense of $10 million and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, ~~higher operations and maintenance expense of $16 million and higher interest expense of $5 million,~~ partially offset by higher electric utility margin of ~~$68 million, a favorable income tax benefit and higher allowances for equity and borrowed funds used during construction of $9~~$83 million. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service. Electric utility margin increased primarily due to the higher ~~retail~~wholesale and ~~wholesale~~retail revenues, partially offset by higher purchased power costs. The ~~favorable~~unfavorable income tax benefit was largely due to the effects of ratemaking, partially offset by higher PTCs recognized of ~~$39~~$14 million from higher ~~wind-powered generation, partially offset by the effects of ratemaking.~~wind- and solar-powered generation.

Operating revenue increased ~~$142~~$324 million for the first ~~six~~nine months of 2022 compared to 2021, primarily due to higher electric operating revenue of ~~$202~~$357 million, partially offset by lower natural gas operating revenue of ~~$51~~$22 million and lower nonregulated operating revenue of $10 million. Electric operating revenue increased due to higher wholesale and other revenue of ~~$105~~$192 million and higher retail revenue of ~~$97~~$165 million. Electric wholesale and other revenue increased mainly due to higher average wholesale per-unit prices of ~~$78~~$174 million and higher wholesale volumes of ~~$28~~$23 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of ~~$63~~$110 million (fully offset in expense, primarily cost of sales) and higher customer volumes of ~~$28~~$45 million. Electric retail customer volumes increased ~~4.4%~~4.0%, primarily due to higher customer ~~usage and the favorable impact of weather.~~usage. Natural gas operating revenue decreased due to lower purchased gas adjustment recoveries of ~~$71~~$37 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$6 million, ~~and~~ the favorable impact of weather of $5 million and higher customer usage of $4 million.

Earnings increased ~~$90~~$17 million for the first ~~six~~nine months of 2022 compared to 2021, primarily due to higher electric utility margin of ~~$157~~$240 million, a favorable income tax benefit and higher natural gas utility margin of ~~$20 million and higher allowances for equity and borrowed funds used during construction of $20~~$15 million, partially offset by higher depreciation and amortization expense of ~~$111~~$231 million, unfavorable changes in the cash surrender value of corporate-owned life insurance policies, higher operations and maintenance expense of ~~$15~~$25 million, higher interest expense of $9$12 million and lower nonregulated utility margin of $8$10 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~~$106 million from higher ~~wind-powered~~wind- and solar-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.

Operating revenue increased ~~$132~~$249 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to higher electric operating revenue of ~~$123~~$244 million ~~and higher natural gas operating revenue of $8 million. Electric operating revenue increased primarily due to~~from higher fully-bundled energy rates (fully offset in cost of sales) of ~~$121 million and higher regulatory-related revenue deferrals of $11 million, partially offset by unfavorable price impacts from changes in sales mix of $12~~$243 million. Electric retail customer volumes increased ~~0.4%~~0.3%.

Earnings decreased $12 million for the third quarter of 2022 compared to 2021, primarily due to higher operations and maintenance expense of $11 million, higher depreciation and amortization expense of $6 million, mainly from additional plant placed in-service, and lower cash surrender value of corporate-owned life insurance policies, partially offset by higher interest and dividend income of $10 million from carrying charges on regulatory balances. Operations and maintenance expense increased mainly due to higher plant operations and maintenance expenses and an unfavorable change in earnings sharing at the Nevada Utilities.

Operating revenue increased $483 million for the first nine months of 2022 compared to 2021, primarily due to higher electric operating revenue of $457 million, from higher fully-bundled energy rates (fully offset in cost of sales) of $452 million, and higher natural gas operating revenue of $26 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric retail customer volumes increased 1.3%, 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$24 million for the ~~second quarter~~first nine months of 2022 compared to 2021, ~~mainly~~primarily due to higher operations and maintenance expense of $19 million, 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 ~~$65~~$82 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to higher ~~distribution~~ revenue at CE Gas of ~~$60~~$72 million ~~and revenue~~ from a gas project that commenced commercial operation in March 2022 ~~totaling $40~~and a solar project that commenced commercial operation in July 2022 and higher distribution revenue of $63 million, partially offset by ~~$40~~$60 million from the stronger U.S. dollar. Distribution revenue increased due to the recovery of Supplier of Last Resort payments totaling $45 million (fully offset in cost of sales) and higher tariff rates of ~~$25~~$28 million, partially offset by a ~~4.0%~~5.5% decline in units distributed of $9$10 million.

Earnings increased ~~$96~~$17 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to ~~a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023 and~~ the higher distribution tariff rates and improved earnings at CE Gas of $19 million from the new gas and solar projects, partially offset by $17 million from the stronger U.S. dollar, the decline in units distributed and higher distribution-related operating and depreciation expenses of ~~$27 million, including higher storm-related costs, $9 million from the stronger U.S. dollar and the decline in units distributed.~~$6 million.

Operating revenue increased ~~$80~~$162 million for the first ~~six~~nine months of 2022 compared to 2021, primarily due to higher distribution revenue of ~~$70~~$133 million and higher revenue at CE Gas of $122 million from athe new gas ~~project that commenced commercial operation in March 2022 totaling $50 million,~~and solar projects, partially offset by ~~$45~~$105 million from the stronger U.S. dollar. Distribution revenue increased due to the recovery of Supplier of Last Resort payments totaling ~~$45~~$90 million (fully offset in cost of sales) and higher tariff rates of ~~$39~~$67 million, partially offset by a ~~3.3%~~4.0% decline in units distributed of ~~$12~~$22 million.

Earnings increased ~~$103~~$120 million for the first ~~six~~nine months of 2022 compared to 2021, primarily due to a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, ~~and~~ the higher distribution tariff rates and improved earnings at CE Gas of $28 million from the new gas and solar projects, partially offset by higher distribution-related operating and depreciation expenses of ~~$27~~$33 million, including higher storm-related costs, the decline in units distributed and $8$25 million from the stronger U.S. dollar.

Operating revenue increased ~~$150~~$179 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to higher operating revenue of $151 million at BHE GT&S and higher operating revenue of $27 million at Northern Natural Gas. The increase in operating revenue at BHE GT&S was primarily due to higher non-regulated revenue of ~~$58~~$61 million (largely offset in cost of sales) ~~at BHE GT&S~~ from favorable ~~pricing, an increase in regulated gas transportation and storage services rates due to an agreement in principle for EGTS' general rate case of $25 million,~~commodity prices, higher LNG ~~variable~~ revenue of ~~$25~~$59 million at Cove Point, ~~higher transportation~~from favorable variable revenue ~~of $17 million at Northern Natural Gas~~and additional services due to ~~higher volumes and rates and higher gas sales of $9 million (largely offset~~a decrease in ~~cost of sales) related to system balancing activities at Northern Natural Gas.~~

Earnings increased $90 million for the third quarter of 2022 compared to 2021, primarily due to higher earnings of $95 million at BHE GT&S largely due to the impacts of the EGTS general rate case of $50 million, favorable income tax adjustments, lower operations and maintenance expense of $18 million and higher earnings at Cove Point of $15 million from the higher operating revenue.

Operating revenue increased $271 million for the first nine months of 2022 compared to 2021, primarily due to higher operating revenue of $280 million at BHE GT&S, partially offset by lower operating revenue of $17 million at Northern Natural Gas. The increase in operating revenue at BHE GT&S was primarily due to higher non-regulated revenue of $130 million (largely offset in cost of sales) from favorable commodity prices, higher LNG revenue of $97 million at Cove Point, from favorable variable revenue and additional services due to a decrease in scheduled outage days, and an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $66 million, partially offset by lower gas sales of $31 million at EGTS used for operational and system balancing activities. The decrease in operating revenue at Northern Natural Gas was mainly due to lower gas sales of $27 million related to system balancing activities offset by higher transportation revenue of $19 million. 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~~$50 million (largely offset in cost of sales) and transportation revenue increased ~~$46~~$68 million due to higher volumes and rates.

Earnings increased ~~$38~~$128 million for the first ~~six~~nine months of 2022 compared to 2021, primarily due to higher earnings of ~~$99~~$194 million at BHE GT&S, partially offset by lower earnings of ~~$60~~$62 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 of $81 million, favorable income tax adjustments, lower operations and maintenance and property and other tax expense ~~favorable property tax assessments,~~of $47 million, increased earnings at Cove Point of $24 million from the higher operating revenue and higher margin of $22 million from non-regulated activities. Earnings at Northern Natural Gas decreased as the higher gross margin on gas sales and higher transportation revenue in the first quarter of 2021 from the February 2021 polar vortex weather event were partially offset by the favorable transportation revenue in 2022 due to higher volumes and rates.

Operating revenue ~~increased $1~~decreased $8 million for the ~~second~~third quarter and $4 million for the first six months of 2022 compared to 2021, primarily due to higher non-regulated revenue and higher revenue at AltaLink from recovery of higher costs, partially offset by $7 million from the weaker U.S. dollar.

Earnings decreased $6 million for the third quarter and $1 million for the first nine months of 2022 compared to 2021, primarily due to lower earnings from the Montana-Alberta Tie Line, higher non-regulated interest expense and the stronger U.S. dollar of $2 million and $3 million, respectively, partially offset by improved equity earnings at Electric Transmission Texas, LLC ~~partially offset by $2 million from~~and the ~~weaker U.S. dollar.~~higher non-regulated revenue.

Operating revenue ~~increased $27~~decreased $14 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to higher wind, geothermal and solar revenues of ~~$51~~$37 million, from higher generation and pricing, ~~partially offset by unfavorable~~and favorable changes in the valuation of certain derivative contracts totaling ~~$14~~$6 million, ~~and~~partially offset by lower natural gas revenues of ~~$13 million from lower generation.~~

Operating revenue decreased $10 million for the first nine months of 2022 compared to 2021, primarily due to lower natural gas revenues of $55 million from lower generation and hedge losses, unfavorable changes in the valuation of certain derivative contracts totaling $51 million and lower hydro revenues of $19 million due to the Casecnan generating facility transfer, partially offset by higher wind, geothermal and solar revenues of $114 million from higher generation and pricing.

Earnings increased $166 million for the first nine months of 2022 compared to 2021, primarily due to higher wind earnings of $179 million, higher geothermal earnings of $18 million, largely due to the higher operating revenue and lower maintenance costs, and higher solar earnings of $13 million, mainly due to the higher operating revenue, partially offset by lower natural gas earnings of $20 million largely due to the lower operating revenue and lower hydro earnings of ~~$10~~$19 million due to the Casecnan generating facility transfer. Wind earnings increased primarily due to higher earnings from tax equity investments of ~~$123~~$136 million, mainly as a result of the unfavorable impacts recognized in the first quarter of 2021 from the February 2021 polar vortex weather event and higher production tax credits offset by unfavorable operating performance, and higher earnings from owned projects of ~~$27~~$43 million, largely from the higher operating revenue and favorable production tax credits offset by the unfavorable derivative contract valuations.

Operating revenue decreased ~~$91~~$338 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to lower brokerage and settlement services revenue of $252 million, from a 16% decrease in closed transaction volume, and lower mortgage revenue of ~~$63~~$82 million from a ~~29%~~39% decrease in funded volume, primarily due to a decline in refinance ~~activity and lower brokerage and settlement services revenue of $26 million from a~~activity. The decrease in brokerage volume was due to 24% fewer closed ~~transaction volumes.~~units at existing companies offset by acquisitions and a 5% increase in average sales price at existing companies.

Earnings decreased ~~$51~~$73 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to lower earnings from brokerage and settlement services of ~~$33~~$49 million, largely attributable to the decrease in closed units at existing companies, and lower earnings from mortgage services of ~~$22~~$30 million from the decrease in funded volume.

Operating revenue decreased ~~$116~~$454 million for the first ~~six~~nine months of 2022 compared to 2021, primarily due to lower mortgage revenue of ~~$160~~$242 million from a ~~34%~~36% decrease in funded volume, primarily due to a decline in refinance activity, ~~partially offset by higher~~and lower brokerage and settlement services revenue of ~~$67~~$212 million from a ~~3% increase~~4% decrease in closed transaction volume. The ~~increase~~decrease in brokerage volume was due to 19% fewer closed units at existing companies offset by acquisitions and ~~a 10%~~an 8% increase in average sales price ~~at existing companies offset by 15% fewer closed units~~ at existing companies.

Earnings decreased ~~$114~~$187 million for the first ~~six~~nine months of 2022 compared to 2021, primarily due to lower earnings from mortgage services of ~~$71~~$101 million, largely from the decrease in funded volumes, and lower earnings from brokerage and settlement services of ~~$49~~$98 million due to the decrease in closed units at existing ~~companies. Earnings from mortgage services were lower primarily due to the decrease in funded volumes,~~companies, partially offset by favorable operating expense variances.

Operating revenue increased ~~$44~~$56 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to higher ~~electricity~~electric and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing, including changes in unrealized positions on natural gas derivative contracts, and higher ~~electricity~~electric volumes, partially offset by lower natural gas volumes.

Earnings ~~increased $583~~decreased $2,775 million for the ~~second~~third quarter of 2022 compared to 2021, primarily due to the ~~$600~~$2,827 million ~~favorable~~unfavorable comparative change in ~~the after-tax unrealized position of~~ the Company's investment in BYD Company Limited, lower earnings of $16 million at MidAmerican Energy Services, LLC, mainly due to unfavorable changes in unrealized positions on derivative contracts, higher BHE corporate interest expense from an April 2022 debt issuance and higher corporate costs, partially offset by $77 million of higher federal income tax credits recognized on a consolidated basis and ~~$25~~$18 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire ~~Hathaway,~~Hathaway.

Operating revenue increased $42 million for the first nine months of 2022 compared to 2021, primarily due to higher natural gas and electric sales revenue at MidAmerican Energy Services, LLC, from favorable natural gas pricing, including changes in unrealized positions on derivative contracts, and higher electric volumes, partially offset by ~~$41~~unfavorable electric pricing and lower natural gas volumes.

Earnings decreased $2,330 million for the first nine months of ~~lower federal income tax credits recognized on a consolidated basis,~~2022 compared to 2021, primarily due to the $2,394 million unfavorable comparative change in the Company's investment in BYD Company Limited, 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.~~

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, 2021 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of ~~June~~September 30, 2022, the Company's total net liquidity was as follows (in millions):

Net cash flows from operating activities for the ~~six-month~~nine-month periods ended ~~June~~September 30, 2022 and 2021 were ~~$5.1~~$7.9 billion and ~~$4.2~~$7.0 billion, respectively. The increase was primarily due to ~~changes in working capital and~~ favorable income tax cash ~~flows.~~flows, improved operating results and changes in working capital.

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

Net cash flows from investing activities for the ~~six-month~~nine-month periods ended ~~June~~September 30, 2022 and 2021 were ~~$(3.5)~~$(5.5) billion and ~~$(3.0)~~$(3.5) billion, respectively. The change was primarily due to higher capital expenditures of ~~$534~~$791 million, higher other investment purchases of $628 million, including $614 million of U.S. Treasury Bills, and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement, partially offset by higher net sales of marketable securities of $607 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Net cash flows from financing activities for the ~~six-month~~nine-month period ended ~~June~~September 30, 2022 was ~~$(605) million.~~$(1.6) billion. Sources of cash totaled ~~$2,188 million~~$2.2 billion and consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and proceeds from BHE senior debt issuances totaling ~~$987 million.~~$1.0 billion. Uses of cash totaled ~~$2,793 million~~$3.8 billion and consisted mainly of repayments of subsidiary debt totaling $882 million, 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~~$540 million and distributions to noncontrolling interests of $395 million.

For discussions of recent financing and BHE shareholders' equity transactions, refer to Notes 4 and 10 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the ~~six-month~~nine-month period ended ~~June~~September 30, 2021 was ~~$(1.2)~~$(2.0) 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.~~$2.0 billion. Uses of cash totaled ~~$2.0~~$4.0 billion and consisted mainly of preferred stock redemptions of $1.5 billion, repayments of subsidiary debt totaling ~~$1.2~~$1.3 billion, repayments of BHE senior debt totaling $450 million, ~~and~~ distributions to noncontrolling interests of ~~$234~~$366 million and net repayments of short-term debt totaling $316 million.

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.

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'~~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):

As of ~~June~~September 30, 2022, 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, 2021, other than those disclosed in Notes 4 and 8 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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.

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.

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.

In March 2022, PacifiCorp filed a general rate case requesting an overall rate change of $82 million, or 6.6%, to become effective January 1, 2023, that includes cost increases associated with the implementation of PacifiCorp's wildfire mitigation and vegetation management plans. Parties 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~~PacifiCorp and parties to the case settled various aspects of the general rate case in multiple settlement stipulations. In August 2022, the first partial stipulation was filed resolving issues related to wildfire mitigation and vegetation management, including addressing the associated costs increases. Also in August 2022, a second partial stipulation was filed representing the settlement of certain revenue requirement issues among the stipulating parties, including the extension of Oregon's recovery period for Jim Bridger Units 1 and 2 that will be converted to natural gas-fueled units and certain other issues. In September 2022, a third stipulation was filed resolving most of the remaining issues in the general rate case ~~will be held~~following the first and second partial stipulations. The stipulations together result in a total rate increase of $49 million, or 3.9%, effective January 1, 2023. The stipulating parties also agreed to amortize certain deferrals totaling approximately $10 million, or 0.8 %, in the first year of amortization, effective April 1, 2023. Further, in the third stipulation, PacifiCorp agreed to a general rate case stay-out provision under which it agreed not to file a general rate case with rates effective any earlier than January 1, 2025. In September 2022, ~~with an order expected~~the fourth and final partial stipulation was filed resolving technical issues related to a voluntary renewable energy tariff that will allow non-residential customers to purchase energy from renewable resources not currently in ~~December 2022.~~PacifiCorp's rates. A commission decision on the stipulations is pending.

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~~requested 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. In September 2022, a settlement stipulation was filed agreeing to the recovery of the requested $52 million over a four-year period beginning April 1, 2023. A commission decision on the stipulation is pending.

In July 2022, PacifiCorp filed an application requesting approval of an automatic adjustment clause with a balancing account to recover costs associated with implementing PacifiCorp's wildfire protection plan in Oregon. Oregon Senate Bill 762 provides for utilities to timely recover these costs through an automatic adjustment clause. The filing requests a rate increase of $20 million, or 1.6%, to recover incremental costs in ~~2022.~~2022 and is incremental to costs addressed in PacifiCorp's wildfire mitigation and vegetation management mechanism through the general rate case stipulation described above. While PacifiCorp requested an effective date of August 24, 2022, the OPUC has suspended the filing for further review. A decision is expected in 2023.

In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. PacifiCorp requested a $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 approved in the 2021 general rate case. For the 2021 PCAM, PacifiCorp is requesting a recovery 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 proposal 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.

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.

40In August 2022, PacifiCorp filed an Energy Cost Adjustment Clause ("ECAC") application requesting an overall rate increase of $15 million, or 13.6%, effective January 1, 2023. Approximately $4 million of the increase, or 3.6%, is attributed to the ECAC rate and $11 million of the increase, or 10.0%, to the Greenhouse Gas rate.

~~South Dakota~~Operating revenue decreased $8 million for the third quarter and $4 million for the first nine months of 2022 compared to 2021, primarily due to the stronger U.S. dollar of $6 million and $13 million, respectively, and lower revenue from the Montana-Alberta Tie Line, partially offset by higher non-regulated revenue from a wind-powered generating facility.

Earnings decreased $6 million for the third quarter and $1 million for the first nine months of 2022 compared to 2021, primarily due to lower earnings from the Montana-Alberta Tie Line, higher non-regulated interest expense and the stronger U.S. dollar of $2 million and $3 million, respectively, partially offset by improved equity earnings at Electric Transmission Texas, LLC and the higher non-regulated revenue.

Operating revenue decreased $14 million for the third quarter of 2022 compared to 2021, primarily due to higher wind, geothermal and solar revenues of $37 million, from higher generation and pricing, and favorable changes in the valuation of certain derivative contracts totaling $6 million, partially offset by lower natural gas revenues of $45 million from lower generation and hedge losses and lower hydro earnings of $13 million due to the transfer of the Casecnan generating facility to the Philippine National Irrigation Administration in December 2021.

Operating revenue decreased $10 million for the first nine months of 2022 compared to 2021, primarily due to lower natural gas revenues of $55 million from lower generation and hedge losses, unfavorable changes in the valuation of certain derivative contracts totaling $51 million and lower hydro revenues of $19 million due to the Casecnan generating facility transfer, partially offset by higher wind, geothermal and solar revenues of $114 million from higher generation and pricing.

Earnings increased $166 million for the first nine months of 2022 compared to 2021, primarily due to higher wind earnings of $179 million, higher geothermal earnings of $18 million, largely due to the higher operating revenue and lower maintenance costs, and higher solar earnings of $13 million, mainly due to the higher operating revenue, partially offset by lower natural gas earnings of $20 million largely due to the lower operating revenue and lower hydro earnings of $19 million due to the Casecnan generating facility transfer. Wind earnings increased primarily due to higher earnings from tax equity investments of $136 million, mainly as a result of the unfavorable impacts recognized in the first quarter of 2021 from the February 2021 polar vortex weather event and higher production tax credits offset by unfavorable operating performance, and higher earnings from owned projects of $43 million, largely from the higher operating revenue and favorable production tax credits offset by the unfavorable derivative contract valuations.

Operating revenue decreased $338 million for the third quarter of 2022 compared to 2021, primarily due to lower brokerage and settlement services revenue of $252 million, from a 16% decrease in closed transaction volume, and lower mortgage revenue of $82 million from a 39% decrease in funded volume, primarily due to a decline in refinance activity. The decrease in brokerage volume was due to 24% fewer closed units at existing companies offset by acquisitions and a 5% increase in average sales price at existing companies.

Earnings decreased $73 million for the third quarter of 2022 compared to 2021, primarily due to lower earnings from brokerage and settlement services of $49 million, largely attributable to the decrease in closed units at existing companies, and lower earnings from mortgage services of $30 million from the decrease in funded volume.

Operating revenue decreased $454 million for the first nine months of 2022 compared to 2021, primarily due to lower mortgage revenue of $242 million from a 36% decrease in funded volume, primarily due to a decline in refinance activity, and lower brokerage and settlement services revenue of $212 million from a 4% decrease in closed transaction volume. The decrease in brokerage volume was due to 19% fewer closed units at existing companies offset by acquisitions and an 8% increase in average sales price at existing companies.

Earnings decreased $187 million for the first nine months of 2022 compared to 2021, primarily due to lower earnings from mortgage services of $101 million, largely from the decrease in funded volumes, and lower earnings from brokerage and settlement services of $98 million due to the decrease in closed units at existing companies, partially offset by favorable operating expense variances.

Operating revenue increased $56 million for the third quarter of 2022 compared to 2021, primarily due to higher electric and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing, including changes in unrealized positions on natural gas derivative contracts, and higher electric volumes, partially offset by lower natural gas volumes.

Earnings decreased $2,775 million for the third quarter of 2022 compared to 2021, primarily due to the $2,827 million unfavorable comparative change in the Company's investment in BYD Company Limited, lower earnings of $16 million at MidAmerican Energy Services, LLC, mainly due to unfavorable changes in unrealized positions on derivative contracts, higher BHE corporate interest expense from an April 2022 debt issuance and higher corporate costs, partially offset by $77 million of higher federal income tax credits recognized on a consolidated basis and $18 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.

Operating revenue increased $42 million for the first nine months of 2022 compared to 2021, primarily due to higher natural gas and electric sales revenue at MidAmerican Energy Services, LLC, from favorable natural gas pricing, including changes in unrealized positions on derivative contracts, and higher electric volumes, partially offset by unfavorable electric pricing and lower natural gas volumes.

Earnings decreased $2,330 million for the first nine months of 2022 compared to 2021, primarily due to the $2,394 million unfavorable comparative change in the Company's investment in BYD Company Limited, 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, partially offset by $64 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway, lower corporate costs and higher earnings of $29 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts.

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, 2021 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of September 30, 2022, the Company's total net liquidity was as follows (in millions):

Net cash flows from operating activities for the nine-month periods ended September 30, 2022 and 2021 were $7.9 billion and $7.0 billion, respectively. The increase was primarily due to favorable income tax cash flows, improved operating results and changes in working capital.

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

Net cash flows from investing activities for the nine-month periods ended September 30, 2022 and 2021 were $(5.5) billion and $(3.5) billion, respectively. The change was primarily due to higher capital expenditures of $791 million, higher other investment purchases of $628 million, including $614 million of U.S. Treasury Bills, and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement, partially offset by higher net sales of marketable securities of $607 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Net cash flows from financing activities for the nine-month period ended September 30, 2022 was $(1.6) billion. Sources of cash totaled $2.2 billion and consisted of proceeds from subsidiary debt issuances totaling $1.2 billion and proceeds from BHE senior debt issuances totaling $1.0 billion. Uses of cash totaled $3.8 billion and consisted mainly of repayments of subsidiary debt totaling $882 million, purchases of common stock totaling $870 million, preferred stock redemptions of $800 million, net repayments of short-term debt totaling $540 million and distributions to noncontrolling interests of $395 million.

For discussions of recent financing and BHE shareholders' equity transactions, refer to Notes 4 and 10 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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

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.

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):

As of September 30, 2022, 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, 2021, other than those disclosed in Notes 4 and 8 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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.

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.

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.

In March 2022, PacifiCorp filed a general rate case requesting an overall rate change of $82 million, or 6.6%, to become effective January 1, 2023, that includes cost increases associated with the implementation of PacifiCorp's wildfire mitigation and vegetation management plans. Parties 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. PacifiCorp and parties to the case settled various aspects of the general rate case in multiple settlement stipulations. In August 2022, the first partial stipulation was filed resolving issues related to wildfire mitigation and vegetation management, including addressing the associated costs increases. Also in August 2022, a second partial stipulation was filed representing the settlement of certain revenue requirement issues among the stipulating parties, including the extension of Oregon's recovery period for Jim Bridger Units 1 and 2 that will be converted to natural gas-fueled units and certain other issues. In September 2022, a third stipulation was filed resolving most of the remaining issues in the general rate case following the first and second partial stipulations. The stipulations together result in a total rate increase of $49 million, or 3.9%, effective January 1, 2023. The stipulating parties also agreed to amortize certain deferrals totaling approximately $10 million, or 0.8 %, in the first year of amortization, effective April 1, 2023. Further, in the third stipulation, PacifiCorp agreed to a general rate case stay-out provision under which it agreed not to file a general rate case with rates effective any earlier than January 1, 2025. In September 2022, the fourth and final partial stipulation was filed resolving technical issues related to a voluntary renewable energy tariff that will allow non-residential customers to purchase energy from renewable resources not currently in PacifiCorp's rates. A commission decision on the stipulations is pending.

In May 2022, ~~MidAmerican Energy~~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 requested recovery of $52 million, or a 4.2% increase, to become effective January 1, 2023. This request ~~with~~is incremental to the ~~South Dakota Public Utilities Commission ("SDPUC") for an increase~~rate change sought in ~~its South Dakota retail natural gas rates, which would increase revenue by $7 million annually. If approved,~~the general rate case. In September 2022, a settlement stipulation was filed agreeing to the recovery of the requested ~~rates would increase retail customers' bills by an average of 6.4%.~~

In ~~January~~July 2022, ~~MidAmerican Energy~~PacifiCorp filed an application requesting approval of an automatic adjustment clause with a balancing account to recover costs associated with implementing PacifiCorp's wildfire protection plan in Oregon. Oregon Senate Bill 762 provides for utilities to timely recover these costs through an automatic adjustment clause. The filing requests a rate increase of $20 million, or 1.6%, to recover incremental costs in 2022 and is incremental to costs addressed in PacifiCorp's wildfire mitigation and vegetation management mechanism through the ~~IUB~~general rate case stipulation described above. While PacifiCorp requested an effective date of August 24, 2022, the OPUC has suspended the filing 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 generationfurther review. A decision 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 beginexpected in ~~October 2022.~~2023.

In June ~~2022, Sierra Pacific~~2021, PacifiCorp filed a ~~regulatory~~power cost only rate ~~review with the PUCN that~~case to update baseline net power costs for 2022. PacifiCorp requested ~~an annual revenue increase of $88~~a $13 million, or ~~9.7%. In addition, a filing was made to revise depreciation rates based on a study, the results~~3.7%, rate increase with an effective date of ~~which are reflected in the proposed revenue requirement. An order is expected by the end of 2022 and, if approved, would be effective~~ January 1, ~~2023.~~

In June 2022, PacifiCorp filed its 2021 PCAM and the new tracking mechanism for PTCs approved in the 2021 general rate case. For the 2021 PCAM, PacifiCorp is requesting a recovery 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 proposal 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.

In ~~March~~May 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 ~~July~~August 2022, ~~Northern Natural Gas~~PacifiCorp filed ~~a general rate case that proposed~~an Energy Cost Adjustment Clause ("ECAC") application requesting an overall ~~annual cost-of-service of $1.3 billion. This is an~~rate increase of ~~$323~~$15 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~~or 13.6%, effective January 1, 2023. Approximately $4 million of the ~~$323~~increase, or 3.6%, is attributed to the ECAC rate and $11 million of the increase, inor 10.0%, to the ~~filed cost of service. Northern Natural~~Greenhouse Gas has requested increases in various rates, including transportation reservation rates ranging from approximately 45% in the Field Area to 120% in the Market Area to be implemented, subject to refund, on August 1, 2022. In July 2022, the FERC issued an order that suspended the rates proposed for five months following the proposed effective date, until January 1, 2023, subject to refund and the outcome of hearing procedures.rate.

Operating revenue decreased $8 million for the third quarter and $4 million for the first nine months of 2022 compared to 2021, primarily due to the stronger U.S. dollar of $6 million and $13 million, respectively, and lower revenue from the Montana-Alberta Tie Line, partially offset by higher non-regulated revenue from a wind-powered generating facility.