In June 2022, Sierra Pacific filed a regulatory rate review with the PUCN that requested an annual revenue increase of $88 million, or 9.7%. In addition, a filing was made to revise depreciation rates based on a study, the results of which are reflected in the proposed revenue requirement. In August 2022, Sierra Pacific filed an updated certification filing that requested an annual revenue increase of $77 million, or 8.5%. Parties to the review filed testimony and evidence in August and September 2022. Hearings in the cost of capital and revenue requirement phases were held in September and October 2022, respectively. The hearings in the rate design phase are scheduled for November 2022. An order is expected by the end of 2022 and, if approved, would be effective January 1, 2023.

Transportation Electrification Plan ("TEP")

In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of a Distributed Resource Plan amendment to implement the state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs and schedules to implement the TEP. The 2022 TEP outlines programs, investments and incentives to accelerate transportation electrification across Nevada. The Nevada Utilities ~~anticipate~~proposed a budget of $348 million, which represents the maximum cost over the depreciable life of the TEP's programs and assets, to deploy the TEP in 2023 through 2024. In March 2023, the PUCN issued an order approving certain programs in the TEP, authorizing a lower program budget of $70 million and ordering specific caps on the program management and contingency budget amounts. The unapproved programs have been deferred for approval in future TEP filings. The PUCN also granted regulatory asset treatment of the approved program costs.In April 2023, interveners filed a petition for reconsideration of the PUCN's March 2023 Order. In May 2023, the PUCN granted in part and denied in part the petition for reconsideration and affirmed the March 2023 Order.

Deferred Energy Accounting Adjustment ("DEAA") Rate

In May 2023, the Nevada Utilities filed an application with the PUCN for approval to adjust the DEAA rates in excess of the maximum allowable adjustment to provide a discounted rate to customers effective July 1, 2023. In June 2023, the Nevada Utilities filed a stipulation signed by interveners that resolved all matters in the dockets opened for the application. In June 2023, the PUCN accepted the stipulation and granted the application as modified. The rate reduction for customers was effective July 1, 2023.

Regulatory Rate Review

In June 2023, Nevada Power filed a regulatory rate review with the PUCN that requested an annual revenue increase of $93 million, or 3.3%. In addition, a filing was made to revise depreciation rates based on a study, the results of which are reflected in the proposed revenue requirements. An order is expected by the end of 2023 and, if approved, would be effective January 1, 2024.

Northern Powergrid Distribution Companies

~~GEMA, through~~ Ofgem ~~is undertaking its scheduled review of~~has completed the ~~electricity distribution~~ price control ~~to put~~review that resulted in ~~place~~ a new price control ateffective April 1, 2023. The license modifications that give effect to the ~~end~~price control were published by Ofgem on February 3, 2023, and were subject to appeal to the Competition and Markets Authority ("CMA") if an appeal was filed by March 3, 2023. On March 2, 2023, Northern Powergrid sought permission from the CMA to appeal against the license modifications that give effect to the RIIO-ED2 price control. The appeal relates to two specific areas:

•Ofgem's misallocation of allowances that is inconsistent with efficient costs; and

•Ofgem's approach to determine rewards for the Business Plan Incentive.

The permission for the appeal was granted by the CMA and the appeal is expected to conclude in the third quarter of 2023 in accordance with the timetable required of the ~~current period that ends March 2023.~~CMA. The ~~new~~outcome of this appeal may increase the revenue available to the Company if the CMA amends the price control ("ED2") will run for five years from April 2023 to March 2028. In December 2020 and March 2021, GEMA published its decision on the methodology it will use to set ED2. This confirmed that Ofgem will maintain many aspects of the current price control and that the changes being made will generally follow the template that was set by the price controls implemented in April 2021 for transmission and gas distribution in Great Britain. Specific changes include new service standard incentives and mechanisms to adjust cost allowances in specific circumstances, while others will be discontinued, and partially updating the allowed return on equity within the period for changes in the interest rate on government bonds.determination.

In December 2021, Northern Powergrid published and filed its business plan with Ofgem, setting out its detailed approach for 2023-2028 including the cost allowances this approach would require. In June 2022, Ofgem published its draft determinations, which included an allowed cost of equity of 4.75% plus inflation (calculated using the United Kingdom's consumer price index including owner occupiers' housing costs). When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, this working assumption is approximately two percentage points lower than the current cost of equity for electricity distribution. Ofgem's proposals also set out cost allowances and associated expectations. In August 2022, Northern Powergrid formally responded to Ofgem's consultation on its draft determinations to lobby for a better settlement. Final values from Ofgem are expected in November 2022.

BHE Pipeline Group

BHE GT&S

In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. ~~EGTS' previous general rate case was settled in 1998.~~ EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system ~~transportation~~transmission rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021, effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund. In September 2022, a settlement agreement was filed with the FERC, ~~resolving EGTS' general rate case for its FERC-jurisdictional services and providing~~which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm ~~transportation~~transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. ~~As of September 30, 2022,~~ EGTS' provision for rate refund for April 2022 through ~~September~~February 2023, including accrued interest, totaled $91 million. In November 2022, ~~totaled $56 million and was included in other current liabilities on~~ the ~~Consolidated Balance Sheet.~~ FERC ~~approval of~~approved the settlement ~~is expected~~agreement and the rate refunds to customers were processed in late ~~2022 or early~~February 2023.

Northern Natural Gas

In July 2022, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $1.3 billion. This is an increase of $323 million above the cost of service filed in its 2019 rate case of $1.0 billion. Depreciation on increased rate base and an increase in depreciation and negative salvage rates account for $115 million of the $323 million increase in the filed cost of service. Northern Natural Gas has requested increases in various rates, including transportation and storage reservation ~~rates ranging from approximately 45% in the Field Area to 120% in the Market Area to be implemented, subject to refund, on August 1, 2022.~~rates. In ~~July 2022,~~January 2023, the FERC ~~issued an order that suspended the~~approved Northern Natural Gas filing to implement its interim rates ~~proposed for five months following the proposed~~ effective ~~date, until~~ January 1, 2023, subject to refund and the outcome of hearing procedures. In June 2023, a settlement agreement was filed with the FERC resolving all pending issues in the rate case and providing for increased service rates and increased depreciation rates for onshore transmission plant from 2.30% to 2.49%. Market Area transportation reservation rates increased 32.5% and storage reservation rates increased 13.0% from the rates that were in effect in 2022. The settlement also provides for a Section 4 and Section 5 rate action moratorium through June 30, 2024, subject to certain exceptions. The settlement rates were implemented May 1, 2023, and the Company's provision for rate refunds for January 2023 through April 2023 totaled $88 million. FERC approval of the settlement is expected before the end of 2023.

BHE Transmission

AltaLink

~~2022-2023~~2024-2025 General Tariff Application

In April ~~2021,~~2023, AltaLink filed its ~~2022-2023~~2024-2025 GTA ~~delivering on~~with the ~~last two years~~AUC with total transmission tariffs of ~~its~~C$902.3 million and C$908.6 million for 2024 and 2025, respectively, which extends AltaLink's previous five-year commitment to ~~keep rates flat for customers~~maintain its tariff at or below ~~the 2018 level of~~ C$904 million ~~for the five-year period~~ from 2019 to 2023. The two-year application achieves flat tariffs by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year-over-year increase of approximately 2% in 2022 and 2023 ~~revenue requirements.~~for another year. The application ~~requested~~also requests the approval to reinstate C$98.9 million cost of ~~transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively after proposed refunds. In September 2021, AltaLink provided responses~~removal to rate base which was not previously approved, based on additional information ~~requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates.~~

In January 2022, the AUC issued its decision with respect to AltaLink's 2022-2023 GTA. AltaLink's 2022-2023 GTA reflected its continued commitment to provide rate stability to customers by maintaining flat tariffs and providing additional tariff relief measures, including a proposed tariff refund of C$60 million of accumulated depreciation in each of 2022 and 2023. The AUC did not approve AltaLink's proposed refund due to an anticipated improvement in general economic conditions in Alberta. In March 2022, AltaLink filed a review and variance application requesting the AUC to review and vary its decision to deny AltaLink's proposed C$120 million refund of accumulated depreciation surplus, given material changes in circumstances since the decision was issued in January 2022. In May 2022, the AUC issued a decision with respect to AltaLink's application to review and vary its proposed $120 million refund of accumulated depreciation surplus. The AUC found that a material decline in Alberta's economic circumstances is not sufficient evidence to warrant the refund.filed.

In July ~~2022,~~2023, AltaLink ~~submitted~~requested the AUC to suspend the schedule for its ~~second compliance filing~~2024-2025 GTA until August 31, 2023. AltaLink requires the schedule delay to amend its application. The amendment is in response to the unprecedented wildfire events that AltaLink experienced in Alberta, Canada in May and June 2023. The AUC accepted AltaLink's request to refile its application on August 31, 2023, and directed AltaLink to limit its application updates to its Wildfire Mitigation Plan and related wildfire references. AltaLink plans to file an application with ~~total 2022 and 2023 revenue requirements at C$879 million and C$883 million, respectively. In August 2022,~~ the AUC ~~approved~~later this year to recover all costs incurred as a result of the ~~revised revenue requirements as filed, allowing AltaLink to fully deliver on its flat-for-five commitment to customers.~~recent wildfire events.

~~2023~~ Generic Cost of Capital Proceeding

In January 2022, the AUC initiated the ~~2023~~ generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with respect to the first stage of the ~~2023~~ GCOC proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial ~~markets due to the COVID-19 pandemic.~~markets. In June 2022, the AUC initiated the second stage to explore a formula-based approach to determine the return on equity for 2024 and future test periods.

In February 2023, AltaLink and other stakeholders filed evidence. AltaLink filed expert evidence recommending a 10.3% return on equity, on a recommended equity ratio of 40%. Other utilities filed similar recommendations. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the Industrial Power Consumers Association of Alberta recommended returns on equity ranging from 6.75% to 7.7% and equity ratios ranging from 35% to 37%. AltaLink's expert witness, as well as all other utility experts, submitted that they are generally not in favor of implementing a formulaic adjustment mechanism for allowed return on equity due to the challenges in maintaining the Fair Return Standard through formulaic adjustments. The interveners are generally in favor of a formula. The AUC expects to conclude the second stage of the GCOC proceeding in the fourth quarter of 2023.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, ~~RPS, air and water quality,~~ emissions performance standards, water quality, coal ~~combustion byproduct~~ash disposal ~~hazardous and solid waste disposal, protected species~~ and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2021,~~2022, and new environmental matters occurring in ~~2022.~~2023.

~~Climate Change~~

~~Affordable Clean Energy Rule~~

In June 2014, the EPA released proposed regulations to address greenhouse gas emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "best system of emission reduction." In August 2015, the final Clean Power Plan was released, which established the best system of emission reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the United States Supreme Court in February 2016 while litigation proceeded. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule. In the Affordable Clean Energy rule, the EPA determined that the best system of emission reduction for existing coal-fueled generating facilities is limited to actions that can be taken at a point source facility, specifically heat rate improvements, and identified a set of candidate technologies and measures that could improve heat rates. Measures taken to meet the standards of performance must be achieved at the source itself. The Affordable Clean Energy rule was challenged by environmental and health groups in the D.C. Circuit. On January 19, 2021, the D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA, finding that the rule "rested critically on a mistaken reading of the Clean Air Act" that limited the best system of emission reduction to actions taken at a facility. In October 2021, the United States Supreme Court agreed to hear an appeal of that decision. Arguments in the case were held February 28, 2022, and on June 30, 2022, the United States Supreme Court issued its decision regarding the scope of the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The United States Supreme Court held that the "generation shifting" approach in the Clean Power Plan exceeded the powers granted to the EPA by Congress, although the court did not address whether the EPA may only adopt measures applied at the individual source as it did in the Affordable Clean Energy rule. A key area where the EPA went astray was using the Clean Power Plan to give states the option to promulgate regulations that would encourage "generation shifting," or moving away from higher-polluting power sources like coal to lower-polluting sources like natural gas or renewables. The United States Supreme Court found that type of regulation, which would impact larger economic forces beyond the fence lines of individual generating facilities, is not permitted under Section 111(d) of the Clean Air Act. The United States Supreme Court reversed the D.C. Circuit's vacatur of the Affordable Clean Energy rule and remanded the case for further proceedings. The ruling has no immediate impact on the Registrants, as there is no Section 111(d) rule currently in effect. The Biden administration plans to propose by March 2023 its own rule to replace the Clean Power Plan and Affordable Clean Energy rule.

~~Clean Air Act~~Quality Regulations

The Clean Air Act, ~~is a federal law administered by the EPA that~~as well as state laws and regulations impacting air emissions, provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. ~~The implementation of new standards is generally outlined in SIPs, which are a collection of~~These laws and regulations ~~programs and policies~~continue to be ~~followed. SIPs vary by~~promulgated and implemented and will impact the operation of BHE's generating facilities and require them to reduce emissions at those facilities to comply with the requirements. In addition, the potential adoption of state or federal clean energy standards, which include low-carbon, non-carbon and renewable electricity generating resources, may also impact electricity generators and natural gas providers.

Greenhouse Gas Standards

In May 2023, the EPA proposed rules addressing greenhouse gas emissions from new and reconstructed natural gas-fueled combustion turbines (Clean Air Act Section 111(b) rule) and existing coal- and gas- or oil-fueled steam units and natural gas-fueled combustion turbines (Clean Air Act Section 111(d) rule). The proposed requirements for existing units would take effect January 1, 2030, through state implementation plans. Requirements for new combustion turbines are subcategorized based on capacity factor, where low-load units would be required to meet an emissions limit, intermediate-load units would be required to use a blend of low-emitting hydrogen and natural gas and base-load units would be required to utilize carbon capture and sequestration technology or a high-percentage blend of low-emitting hydrogen. Requirements for existing gas- and oil-fueled steam units are also subcategorized based on capacity factor, where low-load units would be subject to ~~public hearings~~routine maintenance to demonstrate no increase in emissions, intermediate-load units would be subject to an emission limit of 1,500 pounds of CO2 / MWh-gross and ~~EPA approval. Some states may adopt additional~~base-load units would be subject to an emission limit of 1,300 pounds of CO2 / MWh-gross. Control equipment requirements for existing combustion turbines only apply to large, high load turbines that are greater than 300MW in capacity and operate at a greater than 50% capacity factor. These units would be required to begin utilizing carbon capture and sequestration with a 90% capture rate by 2035 or ~~more~~use a blend of low-emitting hydrogen starting in 2032. Requirements for existing coal-fueled units are subcategorized based on retirement date. Units with earlier retirement dates would be subject to less stringent requirements ~~than those implemented by the EPA. The major~~while units that commit to later retirement dates would be subject to annual capacity factor limits or natural gas co-firing requirements. Units that will continue operating after December 31, 2039, would be required to utilize carbon capture and sequestration with a 90% carbon capture rate. Clean Air Act ~~programs most directly affecting~~Section 111 establishes a cooperative approach between the ~~Registrants' operations~~EPA and the states. The EPA establishes nationwide standards based on the best system of emissions reductions it identifies for a source category. States are ~~described below.~~then expected to develop plans to implement those standards at affected units. States may adopt the EPA's standards or develop state-specific standards that achieve the same air quality results. The EPA is accepting comments on the proposal through August 8, 2023. The relevant Registrants operate facilities that may be affected by these proposals. Until the EPA takes final action on the proposals, the states submit any required SIPs and litigation is exhausted, the relevant Registrants cannot determine the impacts of the proposed rule.

Mercury and Air Toxics Standards

In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015, with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects and unit retirements to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.

Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the U.S. Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. In June 2015, the U.S. Supreme Court reversed and remanded the MATS rule, finding that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. In December 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from generating facilities under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled generating facilities from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding, which were stayed pending the EPA's plans to revisit the finding. On January 31, 2022, the EPA proposed several actions relating to the MATS. The EPA proposed to restore the appropriate and necessary finding to regulate generating facilities under Clean Air Act Section 112. The EPA finalized its restoration of the MATS appropriate and necessary finding in February 2023.

On April 5, 2023, the EPA released a proposal to revise several aspects of the MATS rule following the agency's review of the 2020 Residual Risk and Technology Review. The EPA proposes two specific standard changes - one applicable to all covered units and one specific to the existing lignite subcategory. The EPA proposes a more stringent standard for emissions of filterable particulate matter, the surrogate standard for non-mercury metals for coal-fueled electric generating units. The EPA proposes to reduce the filterable particulate matter emission standard by two-thirds based on a demonstration that 91% of coal-based capacity, which has not been identified as retiring before the proposed compliance period, has an emission rate at or below the proposed limit. The EPA also proposes to require continuous emissions monitoring for filterable particulate matter to demonstrate compliance with the revised standard. Compliance would be due no later than three years after the effective date of a final rule and the EPA accepted comments on the proposal through June 23, 2023. The relevant Registrants are not included in the lignite subcategory. The relevant Registrants have identified that compliance can be achieved with existing controls. Until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined.

National Ambient Air Quality Standards

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

On June 4, 2018, the EPA published final ozone designations for much of the U.S. Relevant to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the 2015 ozone standards for contravening the Clean Air Act. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of interstate ozone plans of dozens of states. Relevant to the Registrants, the EPA must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan, Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's SIP after re-analyzing the state's data. ~~The EPA must finalize the proposed rules by December 15, 2022.~~ In addition, the EPA must ~~by December 15, 2022,~~ approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. On April 15, 2022 the EPA issued its final rule approving Iowa's SIP as meeting the good neighbor provisions for the 2015 ozone standard. On May 24, 2022, the EPA ~~disapproved~~proposed to disapprove the Utah and Wyoming interstate ozone SIPs. ~~Until~~On January 30, 2023, the EPA ~~takes final action consistent with this decree, additional impacts~~entered into a stipulated extension to the ~~relevant Registrants cannot be determined.~~

deadline for action on the Wyoming SIP, setting a new deadline of December 15, 2023. The EPA explained that the extra time is needed to fully consider updated air quality information and public comments. The EPA is also reevaluating SIPs for Tennessee and Arizona. On February 13, 2023, the EPA published final disapproval of the 19 SIPs proposed in April 2022, setting the stage to include those states in the federal implementation plan described under the Cross-State Air Pollution Rule. The EPA also deferred action on the SIPs for Wyoming, Tennessee and Arizona in the final rule. Separately, on March 28, 2022, the EPA proposed determinations as to whether certain areas have achieved levels of ground-level ozone pollution that meet the 2008 and 2015 ozone NAAQS. Relevant to ~~the~~ Registrants, the Southern Wasatch Front in Utah and Yuma, Arizona are proposed to have met the 2015 ozone standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch Front in Utah are proposed to have not met the 2015 ozone ~~will~~standard and to be reclassified as Moderate Non-Attainment, and will have until August 3, 2024 to meet the standard. Until the EPA takes final action on the proposal and the affected states submit any required SIPs, the relevant Registrants cannot determine the impacts of the proposed rule.

Cross-State Air Pollution Rule

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

~~The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NO~~x ~~emissions in 2017. The final "CSAPR Update Rule" was published in the~~ ~~Federal Register~~ ~~in October 2016 and required additional reductions in NO~~x emissions beginning in May 2017. On December 6, 2018, the EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. The EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern U.S. in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind states to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update Rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from generating facilities in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update Rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at generating facilities in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update Rule largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule. In June 2021, a new lawsuit was filed that challenges the Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court. Until litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.

In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key industry regulated by the rule ~~focuses~~and will be subject to emissions allowance trading beginning in summer 2023. The final rule shifted the maximum daily backstop rate for coal-fueled generating units, which drives the installation of new controls or curtailment, to take effect in 2030 instead of 2027. PacifiCorp's Hunter Units 1-3 and Huntington Units 1-2, which do not have SCR controls, are impacted by the rule. PacifiCorp's 2023 IRP selected the installation of SNCR on ~~reductions~~the Hunter and Huntington Units by 2026 as part of the preferred portfolio. The level of NOx~~, precursors~~ allowances for the Utah units remains similar to 2021 levels, with significant reductions for the coal units beginning in 2026. The daily limit, which takes effect in 2030, will further restrict operation of coal-fueled units without SCR. NV Energy's fossil-fueled units are also covered by the final rule. North Valmy Units 1 and 2, which do not have SCR, will require additional controls or reduced operations during the ozone ~~formation~~season if operated beyond 2025. Nevada's regional haze SIP has an enforceable retirement date for North Valmy Units 1 and ~~covers 26~~2 of December 31, 2028, and NV Energy's IRP identified a December 31, 2025, retirement date for the units. The EPA's updated modeling suggests that Arizona, Iowa and Kansas may be significantly contributing to nonattainment in downwind states. The EPA intends to undertake additional assessment of its modeling for these states and will determine if it is necessary to address obligations for these states in future actions. The EPA also deferred final action for Wyoming, pending further review of updated air quality and contribution modeling and analysis. Additional notice and comment rulemaking, such as a supplemental rule, would be required to rescind Iowa's approved SIP and incorporate additional states into the program. The states of Nevada, Utah and Wyoming challenged the EPA's denials and deferral, respectively, of their interstate ozone transport SIPs in the Ninth, Tenth and D.C. Circuit Courts of Appeals. PacifiCorp also filed petitions with the court opposing the EPA's action in Utah and Wyoming. At the time of filing, at least 11 other states have challenged the EPA's action to disapprove SIPs in different regional federal courts of appeal. Stays have been granted by four circuit courts for SIP disapprovals in eight states. Relevant to Registrants, the ~~Registrants, four~~ states ~~are included in the cross-state program for the first time - California,~~of Nevada, Texas and Utah ~~and Wyoming. Iowa is not included in the proposal. In a separate but related action in February 2022, the EPA proposed to approve the~~were granted stays. The final good neighbor ~~provisions of Iowa's SIP addressing ozone transport~~rule was published June 5, 2023 and ~~the 2015 ozone standard.~~takes effect August 4, 2023. The EPA ~~proposes to retain emissions allowance trading for generating facilities. Beginning in 2023, emissions budgets would be set at~~issued an interim final rule stating that the level of reductions achievable through immediately available measures such as consistently operating existing emissions controls. Starting in 2026, emissions budgets would be set at levels achievable by the installation of SCR controls at certain generating facilities. The proposal also includes additional industries beyond the power sector for the first time, with a focus on the top NOx emitting stationary source categories. These include natural gas pipeline compressor stations, pulp and paper mills, cement production, iron and steel boilers and furnaces, glass furnaces, chemical manufacturing and petroleum and coal product manufacturing. These sourcesfederal rule will not take effect in states in which the SIP disapprovals have ~~access~~been deferred or stayed. In addition to ~~trading~~litigation over SIP disapprovals, there are numerous appeals of the final good neighbor rule pending in four different circuit courts, and ~~will instead~~at least four motions to stay the final rule have been filed in three different circuit courts. Additional appeals may be ~~subject~~filed prior to ~~rate-based limits that are assigned for each source category. The EPA accepted comments on~~ the ~~proposal through June 21, 2022.~~rule's August 4, 2023, effective date. Until additional rulemaking is completed and litigation is exhausted, the ~~EPA takes final action consistent with this decree,~~potential impacts to the relevant Registrants cannot be determined.

For the first time, the EPA included additional sectors beyond the electric generation sector in the 2023 expanded CSAPR program. Relevant to the Registrants, this includes the pipeline transportation of natural gas. Requirements for that sector focus on emissions reductions from reciprocating internal combustion engines involved in the transport of natural gas and take effect in 2026. There is no access to allowance trading for the non-electric generation sectors. The EPA excluded emergency engines and engines that do not operate during the ozone season, included a facility-wide averaging plan and eased requirements for monitoring in the final rule. Northern Natural Gas operates 18 affected units; BHE GT&S operates 157 affected units; and Kern River is not affected by the final rule.

Regional Haze

The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit periodic SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

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~~The state of Utah issued a regional haze SIP requiring the installation of SO~~2~~, NO~~x ~~and particulate matter controls on Hunter Units 1 and 2 and Huntington Units 1 and 2.~~ In ~~December 2012, the EPA approved the SO~~2 ~~portion of the Utah regional haze SIP and disapproved the NO~~x and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2 and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a FIP requiring the installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14,June 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporatesincorporated a BART alternative into ~~Utah's~~its SIP for regional haze ~~SIP.~~planning period one. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The ~~Utah Division of Air Quality submitted~~EPA approved the SIP revision towith the ~~EPA for approval at the end~~BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of 2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon generating facility federally enforceable and adopts as BART the existing NOx ~~controls and emission limits on the Hunter and Huntington generating facilities. The proposed approval withdraws the FIP requirements to install~~ SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington generating facilities. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. The EPA defended the SIP, and PacifiCorp and the state of Utah ~~moved to intervene~~intervened in the ~~litigation. After review~~litigation in support of the ~~rule~~EPA. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. A final decision from the court is expected by the Biden administration, the EPA determined it would defend the rule, and briefing has been completed. A date for oral arguments has not been scheduled. The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for the regional haze second planning period on June 6, 2022. The SIP sets mass-based NOx ~~emissions limits and rate-based SO~~2 ~~limits for PacifiCorp's Hunter and Huntington generating facilities to ensure reasonable visibility progress for the second planning period.~~fall 2023.

The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. ~~In addition, the EPA initially proposed in June 2012 to disapprove portions of the NO~~x ~~and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NO~~x and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action other parts of on the Wyoming SIP in 2014 approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls ~~within five years (i.e.,~~ by ~~2019). The EPA action became final on March 3, 2014.~~2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental groups also filed an appeal of the EPA's final ~~action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club.~~action. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The ~~EPA, U.S. Department of Justice, state of~~parties worked to mediate claims under the Wyoming ~~and PacifiCorp executed a settlement agreement December 16, 2020, removing~~regional haze requirements until the ~~requirement to install SCR in lieu of monthly and annual NO~~x emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. The EPA did not give final approval to the settlement agreement and parties were unable to reach an agreement through mediation. The abatement on litigation was lifted in September ~~28, 2022, and opening~~2022. Opening briefs ~~are due~~were submitted in October ~~28,~~ 2022. In the litigation, PacifiCorp objects to the EPA's FIP requiring SCR on the Wyodak Unit. That requirement in the agency's plan remains stayed by the court. PacifiCorp has also intervened on behalf of the EPA against claims that Naughton Units 1 and 2 ~~at the Naughton generating facility~~ should have been subject to a SCR requirement. ~~On February 5, 2019,~~Oral argument was held May 16, 2023. PacifiCorp ~~submitted~~argued that the Naughton claims are moot but that a reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of SCR, to be replaced with a permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. In May 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NOx ~~and SO~~2 ~~emission limits~~court ruling on the ~~four Jim Bridger units and submitted a regional haze SIP revision to~~Wyodak claims is necessary because the EPA. The revised SIP would grant approval of PacifiCorp's Jim Bridger reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency suspension order under Section 110(g) ofEPA's federal plan complies with the Clean Air ~~Act, allowing~~Act. A final decision from the operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA proposed to reject the SIP revisions. The EPA took commentcourt is expected by late fall 2023. Separately, on ~~the proposal through February 17, 2022. On~~ February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp ~~under Sections 201 and 209(a) of the Wyoming Environmental Quality Act,~~ resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree, ~~and as forecasted in PacifiCorp's 2021 IRP,~~ PacifiCorp must convert ~~both units~~Jim Bridger Units 1 and 2 to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. In addition, PacifiCorp must propose an RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and 4. Wyoming issued its proposed implementation plan for second planning period reasonable progress on February 18, 2022 and accepted comments through March 23, 2022. The EPA and PacifiCorp executed an administrative order on consent June 9, 2022, covering compliance for Jim Bridger Units 1 and 2 under the regional haze rule. The federal order contains the same emission and operating limits as the Wyoming consent decree and adds federal approval of the compliance pathway outlined in the state consent decree, including revision of the SIP to include conversion of Jim Bridger Units 1 and 2 to natural gas. ~~The order includes a one-year deadline to complete~~On December 30, 2022, the ~~SIP revision. The proposed SIP revision reflecting these agreements is currently being evaluated under parallel processes by the state of~~ Wyoming ~~and the EPA. The Wyoming Department of Environmental~~Air Quality Division submitted the state-approved revised regional haze SIP requiring natural gas conversion of Jim Bridger Units 1 and 2 ~~proposed SIP~~to the EPA for approval. The plan revision ~~to federal land managers~~replaces a previous requirement for ~~a 60-day consultation on June 7, 2022.~~SCR at the units. The Wyoming ~~held a public hearing~~Air Quality Division also issued an air permit for the ~~Bridger~~natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. PacifiCorp submitted a notice of compliance to the EPA on March 9, 2023, to certify completion of the Jim Bridger administrative compliance order through completion of the requirements to comply with Wyoming's consent decree and revised SIP ~~revision on September 14, 2022,~~submission. PacifiCorp remains subject to the compliance terms of the Wyoming consent decree as it works to convert Jim Bridger Units 1 and ~~accepted public comments~~2 to natural gas. The EPA is in on-going discussions with Wyoming to finalize a determination on the ~~plan through September 20, 2022. For the second round of regional haze planning,~~ ~~Wyoming determined that no controls will be necessary on any Wyoming resources to make reasonable progress.~~SIP revisions, with a decision anticipated by fall 2023.

~~In February 2022, NV Energy received 30-day notice letters from the Nevada Division~~The state of ~~Environmental Protection regarding the reopening~~Colorado first planning period regional haze SIP requires SCR equipment at Craig Unit 2 and ~~revision of the Valmy and Tracy Generating Station's Title V air quality operating permits to add federally enforceable retirement dates of December 31, 2028 for Valmy~~Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are in-service. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, ~~2031 for Tracy Unit 4.~~2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021, with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The ~~enforceable retirement dates will implement Nevada's SIP for~~terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze ~~second planning period. The revised permits were received~~SIP in ~~March~~2017 and ~~April 2022. The Nevada Division of Environmental Protection accepted public comment on~~approved by the EPA in August 2018. PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in its ~~SIP through July 25, 2022.~~2023 IRP.

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Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze second planning period to the EPA and received completeness determinations in August 2022. The EPA ~~has 18 months~~is required to ~~approve or disapprove all or parts of~~make final determinations on the ~~states' plans.~~SIPs by August 2023. On August 25, 2022, the EPA promulgated a finding of failure to submit a SIP for the regional haze second planning period for 15 states, including Iowa. The finding establishes a two-year deadline for the agency to promulgate FIPs to address the requirements, unless prior to promulgating a FIP, the state submits, and the agency approves, a SIP meeting the requirements. The finding says the agency intends to continue to work with states in developing approvable SIP submittals in a timely manner. The Iowa Department of Natural Resources continues to work with the EPA on development of its SIP. On February 13, 2023, Iowa issued a draft SIP and accepted comment on the draft plan through March 16, 2023. Iowa proposes to require operational improvements to existing control equipment at MidAmerican Energy's Louisa Generation Station and Walter Scott Jr. Energy Center - Unit 3. Iowa anticipates submitting a final plan to the EPA in fall 2023.

Water Quality Standards

In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. In November 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule took effect in December 2020. The final rule changes the technology-basis for treatment of flue gas desulfurization wastewater and bottom ash transport water, revises the voluntary incentives program for flue gas desulfurization wastewater, and adds subcategories for high-flow units, low utilization units, and those that will transition away from coal combustion by 2028. While most of the issues raised by this rule are already being addressed through the CCR rule and are not expected to impose significant additional requirements, the Dave Johnston generating facility is impacted by the rule's bottom ash handling requirements at Units 1 and 2. The generating facility submitted notice to the Wyoming Department of Environmental Quality that it will either achieve a cessation of coal combustion at Units 1 and 2 by December 31, 2028, or install bottom ash transport treatment technology by December 31, 2025. On March 8, 2023, the EPA proposed additional changes to the effluent limitations guidelines to replace the 2020 rule and provide stricter limits for bottom ash transport water, flue gas desulfurization wastewater and coal combustion residual leachate. The relevant Registrants use a combination of zero discharge, enrollment in cessation-of-coal subcategory and dry bottom ash handling to manage the affected wastestreams. As a result, significant impacts are not anticipated. However, until the EPA takes final action on the proposal, the full impacts of the rule cannot be determined. The EPA accepted public comments through May 30, 2023, and intends to finalize a rule by spring 2024.

In March 2023, the latest changes to the definition of "waters of the U.S.," a rule that determines which waters are regulated under the federal Clean Water Act, took effect. Under this rule, tributaries, many wetlands, intrastate lakes, intrastate ponds, intrastate streams and some impoundments must meet either test from the 2006 Rapanos plurality decision to be considered a water of the U.S. That is, a water must be relatively permanent and have a continuous surface connection to an included waterbody (the "relatively permanent" test) or it must significantly affect the biological, physical or chemical integrity of a traditional navigable water, territorial seas or interstate waters (the "significant nexus" test). The rule was challenged in multiple courts. On May 23, 2023, the U.S. Supreme Court issued a decision in Sackett v. EPA, a case that challenged the Clean Water Act's applicability to certain wetlands. In its decision, the Court significantly narrowed protections for wetlands and intermittent streams under the federal Clean Water Act. The Court unanimously rejected the significant nexus test as unworkable. A divided Court determined that jurisdiction applies to waters that are adjacent to traditional interstate navigable waters and that have a continuous surface connection with that traditional interstate navigable waters. In light of the Sackett decision, the EPA secured stays of litigation over its definitional rule in two of three pending challenges in order to conduct rulemaking to conform to the Court's decision. The EPA sent a new final definition rule to the White House Office of Management and Budget on July 17, 2023, and has stated it intends to issue the new rule by September 1, 2023.

Coal Ash Disposal

In April 2015, the EPA released a final rule to regulate the management and disposal of coal combustion residuals (CCR) under the RCRA. The rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts will need to be closed unless they can meet the more stringent regulatory requirements.

At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017, and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated 10 evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.

Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit, resulting in settlement of some of the issues and subsequent regulatory action by the EPA. The EPA finalized the first phase of the CCR rule amendments in July 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted the EPA's request to remand the rule and left the October 31, 2020, deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 rule has not been finalized. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of 2016. The federal permit rule has not been finalized.

In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking comment on and information related to issues relevant to development of regulations for legacy impoundments. On May 18, 2023, the EPA proposed the legacy surface impoundments rule and accepted comment on the proposal through July 17, 2023. The proposal encompasses legacy surface impoundments, which are inactive surface impoundments at inactive facilities; and CCR management units, which include CCR surface impoundments and landfills that closed prior to October 19, 2015, inactive CCR landfills, and other areas where CCR has been or is managed directly on the land. CCR management units include all units meeting that definition at active CCR facilities, as well as those at inactive facilities with one or more legacy surface impoundment. EPA proposes the impose substantially the same regulatory obligations for both legacy surface impoundments and CCR management units as are applicable to currently regulated units, including groundwater monitoring and corrective action. All legacy surface impoundments and CCR management units would be required to initiate closure, including reclosure, within one year after the rule is finalized. The EPA has indicated it intends to finalize the legacy surface impoundment rule by spring 2024.

The EPA includes lists of potential legacy surface impoundments and CCR management units in the rulemaking docket and those lists include several BHE facilities. The EPA also specifically identifies PacifiCorp's Huntington Power Plant and NV Energy's Reid Gardner Generating Station as potential CCR management unit damage cases based on the EPA's review of compliance information. BHE corrected the record in comments that: (1) The north and south ash ponds at MidAmerican's Riverside Generating Station are incorrectly classified as legacy impoundments rather than CCR management units; (2) historical impoundments, which were closed according to state requirements and no longer contain CCR or liquids, should be removed from the list of CCR management units; (3) the EPA erroneously identified NV Energy's Reid Gardner Generating Station and the Old Landfill at PacifiCorp's Huntington generating facility as potential damage cases; and (4) two impoundments at PacifiCorp's former Carbon generating facility are incorrectly included on the list of legacy impoundments because PacifiCorp never managed or disposed of CCR materials in wastewater ponds at the former Carbon generating facility.

Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.

In August 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule"). This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule established a new deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure. The Part A rule also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023; and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and complete ash pond closure activities by October 17, 2028. PacifiCorp developed a demonstration for the development of alternative capacity for the Jim Bridger facility's FGD Pond 2 and a demonstration for closure of the Naughton facility and ash pond and submitted them to the EPA in November 2020. On January 11, 2022, the EPA deemed these submittals complete but has not taken additional action on them. No other Registrants used the provisions of the Part A rule.

Notwithstanding the status of the final CCR rule, citizens' suits have been filed against regulated entities seeking judicial relief for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately released or connected to surface water. In addition, actions have been filed against regulated entities seeking to require that surface impoundments containing CCR be subject to closure by removal rather than being allowed to effectuate closure in place as provided under the final rule. The Registrants are not a party to these lawsuits and until they are resolved, the Registrants cannot predict the impact on overall compliance obligations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2021.~~2022. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, ~~2021.~~2022.

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PacifiCorp and its subsidiaries

Consolidated Financial Section

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PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of ~~September~~June 30, ~~2022,~~2023, the related consolidated statements of operations, and changes in shareholders' equity for the three-month and six-month periods ended June 30, 2023 and 2022, and of cash flows for the ~~three-month and nine-month~~six-month periods ended ~~September~~June 30, ~~2022~~2023 and ~~2021, and of cash flows for the nine-month periods ended 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 PacifiCorp as of December 31, ~~2021,~~2022, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February ~~25, 2022,~~24, 2023, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, ~~2021,~~2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

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

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

/s/ Deloitte & Touche LLP

Portland, Oregon

~~November~~August 4, ~~2022~~2023

5257

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


		As of					As of
		September 30,		December 31,			June 30,		December 31,
		2022		2021			2023		2022
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	219	$	179	Cash and cash equivalents	$	586	$	641
Trade receivables, net	Trade receivables, net	807		725		Trade receivables, net	736		825
Other receivables, net	Other receivables, net	77		52		Other receivables, net	63		72
Inventories	Inventories	471		474		Inventories	533		474
Derivative contracts	Derivative contracts	108		76		Derivative contracts	51		184

Regulatory assets	Regulatory assets	176		65		Regulatory assets	374		275

Other current assets	Other current assets	124		150		Other current assets	112		213
Total current assets	Total current assets	1,982		1,721		Total current assets	2,455		2,684

Property, plant and equipment, net	Property, plant and equipment, net	23,893		22,914		Property, plant and equipment, net	25,488		24,430
Regulatory assets	Regulatory assets	1,439		1,287		Regulatory assets	1,745		1,605
Other assets	Other assets	699		534		Other assets	864		686

Total assets	Total assets	$	28,013	$	26,456	Total assets	$	30,552	$	29,405

In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility began in June 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has $450 million in funding available for dam removal and restoration; $200 million collected from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $45 million contingency fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete.

Legal Matters

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

~~Wildfire Liability~~

Wildfires Overview

A provision for a loss contingency is recorded when it is probable ~~that~~ a liability has been incurred and the amount of ~~the liability~~loss 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~~loss based on its best estimate within that range 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.~~damages.

2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon, burning over 500,000 acres in aggregate. ~~Third party~~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~~U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.

As of the date of this filing, 60numerous lawsuits on behalf of plaintiffs related to the 2020 Wildfires have been filed in Oregon and California, including a class action complaint in Oregon ~~on behalf of~~for which the jury issued a verdict for the 17 named plaintiffs ~~related to the 2020 Wildfires.~~in June 2023 as described below. The plaintiffs seek damages ~~that include property damages,~~for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, ~~exemplary~~other damages and attorneys' ~~fees and other damages. Additionally, several~~fees. Several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. ~~The final~~Additionally, certain governmental agencies have informed PacifiCorp that they are contemplating filing actions in connection with certain of the Oregon 2020 Wildfires. Amounts sought in the lawsuits, complaints and demands filed in Oregon total over $7 billion, excluding any doubling or trebling of damages included in the complaints. Generally, the complaints filed in California do not specify damages sought and are not included in this amount. Final determinations of liability ~~however,~~ will only be made following the completion of comprehensive investigations, ~~and~~ litigation ~~processes.~~or similar processes, the outcome of which, if adverse, could, in the aggregate, have a material adverse effect on PacifiCorp's financial condition.

AsOn September 30, 2020, a class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al, in Multnomah County Circuit Court, Oregon (the "James case"). The complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. In November 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Santiam Canyon, Echo Mountain Complex, South Obenchain and Two Four Two wildfires. In May 2022, the Multnomah County Circuit Court granted issue class certification and consolidated the James case with several other cases. While PacifiCorp requested an immediate appeal of the issue class certification, the Oregon Court of Appeals denied the request. In April 2023, the jury trial for the James case with respect to 17 named plaintiffs began in Multnomah County Circuit Court. In June 2023, the jury issued its verdict finding PacifiCorp liable to the 17 individual plaintiffs and to the class with respect to the four wildfires. The jury awarded the 17 named plaintiffs $90 million of damages, including $4 million of economic and property damages, $68 million of noneconomic damages and $18 million of punitive damages based on a 0.25 multiplier of the economic and noneconomic damages. No judgment has been entered by the Multnomah County Circuit Court and no determination has been made as to the timing, process and procedures that will be used to adjudicate individual class member damages. PacifiCorp intends to vigorously appeal the jury's findings and damage awards, including whether the case can proceed as a class action. The appeals process and further actions could take several years.

Based on the facts and circumstances available to PacifiCorp as of the date of this filing, ~~PacifiCorp estimates~~which includes the ~~probable loss~~status of the verdict in the James case with respect to ~~be $200 million, net of expected insurance recoveries~~the 17 named plaintiffs, other litigation and recent settlements, PacifiCorp has accrued ~~such amount as of September 30, 2022. During the nine-month period ended September 30, 2022, PacifiCorp accrued $64 million of~~cumulative estimated probable losses ~~net of expected insurance recoveries,~~ associated with the 2020 ~~Wildfires. The~~Wildfires of $1,018 million through June 30, 2023. PacifiCorp's cumulative accrual includes ~~PacifiCorp's estimate~~estimates of probable losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available.

It is reasonably possible PacifiCorp will incur material additional losses beyond the amounts ~~accrued;~~accrued that could have a material adverse effect on PacifiCorp's financial condition; however, PacifiCorp is currently unable to reasonably estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved, ~~and~~including claimants in the class to the James case, the variation in those types of properties and lack of available ~~details. To~~details and the ~~extent~~ultimate outcome of legal actions.

The following table presents changes in PacifiCorp's liability for estimated losses ~~beyond~~associated with the ~~amounts accrued are incurred, additional insurance coverage is expected to be available to cover a portion of the losses.~~ 2020 Wildfires (in millions):


	Three-Month Periods				Six-Month Periods
	Ended June 30,				Ended June 30,
	2023		2022		2023		2022
Beginning balance	$	824	$	252	$	424	$	252
Accrued losses	141		225		541		225
Payments	(17)		—		(17)		—
Ending balance	$	948	$	477	$	948	$	477

PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was ~~$277~~$379 million and $246 million, respectively, as of ~~September~~June 30, 2023 and December 31, 2022. During the three- and six-month periods ended June 30, 2023, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $49 million and $408 million, respectively. During the three- and six-month periods ended June 30, 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $64 million and $64 million, respectively. The net losses are included in operations and maintenance on the Consolidated Statements of Operations. No additional insurance recoveries beyond those accrued to date are expected to be available for the 2020 Wildfires.

2022 McKinney Fire

According to the 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~~Third-party reports indicate 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~~four fatalities and consumed ~~60,138~~60,000 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the ~~United States~~U.S. 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,~~for economic losses, noneconomic losses, including mental suffering, emotional distress, personal injury and loss of life, punitive damages, ~~exemplary~~other damages and attorneys' fees, ~~and other damages~~ but the amount of damages sought ~~are~~is not specified. ~~The final~~Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.

~~Environmental Laws and Regulations~~

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

~~Hydroelectric Relicensing~~

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

6672

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 August 2022, the FERC staff issued a final environmental impact statement for the project, concluding that dam removal is the preferred action.

Guarantees

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

(10) Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):


		Three-Month Periods				Nine-Month Periods					Three-Month Periods				Six-Month Periods
		Ended September 30,				Ended September 30,					Ended June 30,				Ended June 30,
		2022		2021		2022		2021			2023		2022		2023		2022
Customer Revenue:	Customer Revenue:									Customer Revenue:
Retail:	Retail:									Retail:
Residential	Residential	$	576	$	530	$	1,498	$	1,442	Residential	$	450	$	417	$	1,035	$	922
Commercial	Commercial	461		428		1,224		1,180		Commercial	429		393		859		763
Industrial	Industrial	310		296		860		849		Industrial	270		277		560		550
Other retail	Other retail	118		98		235		214		Other retail	83		80		127		117
Total retail	Total retail	1,465		1,352		3,817		3,685		Total retail	1,232		1,167		2,581		2,352
Wholesale	Wholesale	69		58		179		124		Wholesale	26		55		87		110
Transmission	Transmission	54		55		131		117		Transmission	34		45		72		77
Other Customer Revenue	Other Customer Revenue	24		26		72		80		Other Customer Revenue	24		28		56		48
Total Customer Revenue	Total Customer Revenue	1,612		1,491		4,199		4,006		Total Customer Revenue	1,316		1,295		2,796		2,587
Other revenue	Other revenue	23		—		47		25		Other revenue	11		19		15		24
Total operating revenue	Total operating revenue	$	1,635	$	1,491	$	4,246	$	4,031	Total operating revenue	$	1,327	$	1,314	$	2,811	$	2,611


Registrant			Securities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY			None
PACIFICORP			None
MIDAMERICAN FUNDING, LLC			None
MIDAMERICAN ENERGY COMPANY			None
NEVADA POWER COMPANY			None
SIERRA PACIFIC POWER COMPANY			None
EASTERN ENERGY GAS HOLDINGS, LLC			None
EASTERN GAS TRANSMISSION AND STORAGE, INC.			None


Registrant			Name of exchange on which registered:
BERKSHIRE HATHAWAY ENERGY COMPANY			None
PACIFICORP			None
MIDAMERICAN FUNDING, LLC			None
MIDAMERICAN ENERGY COMPANY			None
NEVADA POWER COMPANY			None
SIERRA PACIFIC POWER COMPANY			None
EASTERN ENERGY GAS HOLDINGS, LLC			None
EASTERN GAS TRANSMISSION AND STORAGE, INC.			None


Registrant	Yes	No
BERKSHIRE HATHAWAY ENERGY COMPANY	☒
PACIFICORP	☒
MIDAMERICAN FUNDING, LLC		☒
MIDAMERICAN ENERGY COMPANY	☒
NEVADA POWER COMPANY	☒
SIERRA PACIFIC POWER COMPANY	☒
EASTERN ENERGY GAS HOLDINGS, LLC	☒
EASTERN GAS TRANSMISSION AND STORAGE, INC.	☒


Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	~~192~~194
Item 4.	Controls and Procedures	~~192~~194


Item 1.	Legal Proceedings	~~193~~195
Item 1A.	Risk Factors	~~196~~199
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~196~~199
Item 3.	Defaults Upon Senior Securities	~~196~~199
Item 4.	Mine Safety Disclosures	~~196~~199
Item 5.	Other Information	~~196~~200
Item 6.	Exhibits	~~196~~200
Signatures		~~200~~204


Berkshire Hathaway Energy Company and Related Entities
BHE						Berkshire Hathaway Energy Company
Berkshire Hathaway						Berkshire Hathaway Inc.
Berkshire Hathaway Energy or the Company						Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp						PacifiCorp and its subsidiaries
MidAmerican Funding						MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy						MidAmerican Energy Company
NV Energy						NV Energy, Inc. and its subsidiaries
Nevada Power						Nevada Power Company and its subsidiaries
Sierra Pacific						Sierra Pacific Power Company and its subsidiaries
Nevada Utilities						Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Eastern Energy Gas						Eastern Energy Gas Holdings, LLC and its subsidiaries
EGTS						Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Registrants						Berkshire Hathaway Energy Company, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, Eastern Energy Gas Holdings, LLC and its subsidiaries and Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Northern Powergrid						Northern Powergrid Holdings Company and its subsidiaries
BHE Pipeline Group						BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE GT&S						BHE GT&S, LLC and its subsidiaries
Northern Natural Gas						Northern Natural Gas Company
Kern River						Kern River Gas Transmission Company
BHE Transmission						BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada						BHE Canada Holdings Corporation and its subsidiaries
AltaLink						AltaLink, L.P.
BHE U.S. Transmission						BHE U.S. Transmission, LLC and its subsidiaries
BHE Renewables						BHE Renewables, LLC and its subsidiaries
HomeServices						HomeServices of America, Inc. and its subsidiaries
Utilities						PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries



Certain Industry Terms

~~2017 Tax Reform~~2020 Wildfires						~~The Tax Cuts~~Wildfires in Oregon and ~~Jobs Act enacted on December 22, 2017, effective January 1, 2018~~Northern California that occurred September of 2020


AFUDC						Allowance for Funds Used During Construction
AUC						Alberta Utilities Commission
BART						Best Available Retrofit Technology
CCR						Coal Combustion Residuals


CPUC						California Public Utilities Commission
CSAPR						Cross-State Air Pollution Rule
D.C. Circuit						United States Court of Appeals for the District of Columbia Circuit

Dth						Decatherm


EPA						United States Environmental Protection Agency
FERC						Federal Energy Regulatory Commission
FIP						Federal Implementation Plan

GAAP						Accounting principles generally accepted in the United States of America
~~GEMA~~						~~Gas and Electricity Markets Authority~~

GTA						General Tariff Application
GWh						Gigawatt Hour


IRP						Integrated Resource Plan
IUB						Iowa Utilities Board
kV						Kilovolt

LNG						Liquefied Natural Gas
MATS						Mercury and Air Toxics Standards
MW						Megawatt
MWh						Megawatt Hour
NAAQS						National Ambient Air Quality Standards
NOx						Nitrogen Oxides

Ofgem						Office of Gas and Electric Markets
OPUC						Oregon Public Utility Commission
PTC						Production Tax Credit
PUCN						Public Utilities Commission of Nevada


RFP						Request for Proposals
RPS						Renewable Portfolio Standards

SCR						Selective Catalytic Reduction
SEC						United States Securities and Exchange Commission
SIP						State Implementation Plan
SO2						Sulfur Dioxide

UPSC						Utah Public Service Commission

WUTC						Washington Utilities and Transportation Commission


Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						4
Consolidated Balance Sheets						5
Consolidated Statements of Operations						7
Consolidated Statements of Comprehensive (~~Loss)~~ Income						8
Consolidated Statements of Changes in Equity						9
Consolidated Statements of Cash Flows						10
Notes to Consolidated Financial Statements						11
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm						5257
Consolidated Balance Sheets						5358
Consolidated Statements of Operations						5560
Consolidated Statements of Changes in Shareholders' Equity						5661
Consolidated Statements of Cash Flows						5762
Notes to Consolidated Financial Statements						5863
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm						7884
Balance Sheets						7985
Statements of Operations						8187
Statements of Changes in Shareholder's Equity						8288
Statements of Cash Flows						8389
Notes to Financial Statements						8490
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						9298
Consolidated Balance Sheets						9399
Consolidated Statements of Operations						95101
Consolidated Statements of Changes in Member's Equity						96102
Consolidated Statements of Cash Flows						97103
Notes to Consolidated Financial Statements						98104
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~112~~118
Consolidated Balance Sheets						~~113~~119
Consolidated Statements of Operations						~~114~~120
Consolidated Statements of Changes in Shareholder's Equity						~~115~~121
Consolidated Statements of Cash Flows						~~116~~122
Notes to Consolidated Financial Statements						~~117~~123
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~133~~138
Consolidated Balance Sheets						~~134~~139
Consolidated Statements of Operations						~~135~~140
Consolidated Statements of Changes in Shareholder's Equity						~~136~~141
Consolidated Statements of Cash Flows						~~137~~142
Notes to Consolidated Financial Statements						~~138~~143
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~156~~159
Consolidated Balance Sheets						~~157~~160
Consolidated Statements of Operations						~~159~~162
Consolidated Statements of Comprehensive Income						~~160~~163
Consolidated Statements of Changes in Equity						~~161~~164
Consolidated Statements of Cash Flows						~~162~~165
Notes to Consolidated Financial Statements						~~163~~166
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~175~~178
Consolidated Balance Sheets						~~176~~179
Consolidated Statements of Operations						~~178~~181
Consolidated Statements of Comprehensive Income						~~179~~182
Consolidated Statements of Changes in Shareholder's Equity						~~180~~183
Consolidated Statements of Cash Flows						~~181~~184
Notes to Consolidated Financial Statements						~~182~~185


Berkshire Hathaway Energy Company and its subsidiaries						2931
PacifiCorp and its subsidiaries						6874
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company						~~101~~108
Nevada Power Company and its subsidiaries						~~125~~130
Sierra Pacific Power Company and its subsidiaries						~~147~~151
Eastern Energy Gas Holdings, LLC and its subsidiaries						~~170~~173
Eastern Gas Transmission and Storage, Inc. and its subsidiaries						~~188~~190


		BHE Shareholders' Equity																	BHE Shareholders' Equity
								Long-term				Accumulated													Long-term				Accumulated
						Additional		Income				Other											Additional		Income				Other
		Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total			Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total
		Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity			Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity
Balance, June 30, 2021		$	3,750	$	—	$	6,377	$	(658)	$	37,303	$	(1,360)	$	3,953	$	49,365
Balance, March 31, 2022																		Balance, March 31, 2022	$	1,650	$	—	$	6,374	$	(744)	$	40,608	$	(1,358)	$	3,894	$	50,424
Net income	Net income	—		—		—		—		1,922		—		103		2,025		Net income	—		—		—		—		2,897		—		120		3,017
Other comprehensive loss	Other comprehensive loss	—		—		—		—		—		(163)		—		(163)		Other comprehensive loss	—		—		—		—		—		(430)		—		(430)
Preferred stock redemptions	Preferred stock redemptions	(1,450)		—		—		—		—		—		—		(1,450)		Preferred stock redemptions	(800)		—		—		—		—		—		—		(800)
Preferred stock dividend	Preferred stock dividend	—		—		—		—		(26)		—		—		(26)		Preferred stock dividend	—		—		—		—		(13)		—		—		(13)
Common stock purchases																		Common stock purchases	—		—		(77)		—		(793)		—		—		(870)
Distributions																		Distributions	—		—		—		—		—		—		(129)		(129)
Contributions																		Contributions	—		—		—		—		—		—		2		2

Other equity transactions																		Other equity transactions	—		—		1		—		(11)		—		—		(10)
Balance, June 30, 2022																		Balance, June 30, 2022	$	850	$	—	$	6,298	$	(744)	$	42,688	$	(1,788)	$	3,887	$	51,191

Balance, December 31, 2021																		Balance, December 31, 2021	$	1,650	$	—	$	6,374	$	(744)	$	40,754	$	(1,340)	$	3,895	$	50,589
Net income																		Net income	—		—		—		—		2,768		—		229		2,997
Other comprehensive loss																		Other comprehensive loss	—		—		—		—		—		(448)		—		(448)
Preferred stock redemptions																		Preferred stock redemptions	(800)		—		—		—		—		—		—		(800)
Preferred stock dividend																		Preferred stock dividend	—		—		—		—		(29)		—		—		(29)
Common stock purchases																		Common stock purchases	—		—		(77)		—		(793)		—		—		(870)
Distributions	Distributions	—		—		—		—		—		—		(130)		(130)		Distributions	—		—		—		—		—		—		(245)		(245)
Contributions																		Contributions	—		—		—		—		—		—		2		2

Purchase of noncontrolling interest		—		—		(3)		—		—		—		—		(3)
Other equity transactions	Other equity transactions	—		—		—		—		—		—		(2)		(2)		Other equity transactions	—		—		1		—		(12)		—		6		(5)
Balance, September 30, 2021		$	2,300	$	—	$	6,374	$	(658)	$	39,199	$	(1,523)	$	3,924	$	49,616
Balance, June 30, 2022																		Balance, June 30, 2022	$	850	$	—	$	6,298	$	(744)	$	42,688	$	(1,788)	$	3,887	$	51,191

Balance, December 31, 2020		$	3,750	$	—	$	6,377	$	(658)	$	35,093	$	(1,552)	$	3,967	$	46,977
Balance, March 31, 2023																		Balance, March 31, 2023	$	850	$	—	$	6,298	$	—	$	42,814	$	(2,109)	$	3,798	$	51,651
Net income	Net income	—		—		—		—		4,207		—		311		4,518		Net income	—		—		—		—		1,075		—		130		1,205
Other comprehensive income	Other comprehensive income	—		—		—		—		—		29		4		33		Other comprehensive income	—		—		—		—		—		264		—		264
Preferred stock redemptions		(1,450)		—		—		—		—		—		—		(1,450)
Preferred stock dividend		—		—		—		—		(101)		—		—		(101)

Distributions		—		—		—		—		—		—		(364)		(364)
Contributions		—		—		—		—		—		—		9		9
Purchase of noncontrolling interest		—		—		(3)		—		—		—		—		(3)
Other equity transactions		—		—		—		—		—		—		(3)		(3)
Balance, September 30, 2021		$	2,300	$	—	$	6,374	$	(658)	$	39,199	$	(1,523)	$	3,924	$	49,616

Balance, June 30, 2022		$	850	$	—	$	6,298	$	(744)	$	42,688	$	(1,788)	$	3,887	$	51,191
Net (loss) income		—		—		—		—		(842)		—		147		(695)
Other comprehensive loss		—		—		—		—		—		(595)		—		(595)
Long-term income tax receivable adjustments		—		—		—		744		(744)		—		—		—

Preferred stock dividend	Preferred stock dividend	—		—		—		—		(8)		—		—		(8)		Preferred stock dividend	—		—		—		—		(9)		—		—		(9)

Distributions	Distributions	—		—		—		—		—		—		(149)		(149)		Distributions	—		—		—		—		—		—		(144)		(144)
Contributions	Contributions	—		—		—		—		—		—		2		2		Contributions	—		—		—		—		—		—		1		1

Other equity transactions	Other equity transactions	—		—		—		—		(1)		—		—		(1)		Other equity transactions	—		—		—		—		—		—		(8)		(8)
Balance, September 30, 2022		$	850	$	—	$	6,298	$	—	$	41,093	$	(2,383)	$	3,887	$	49,745
Balance, June 30, 2023																		Balance, June 30, 2023	$	850	$	—	$	6,298	$	—	$	43,880	$	(1,845)	$	3,777	$	52,960

Balance, December 31, 2021		$	1,650	$	—	$	6,374	$	(744)	$	40,754	$	(1,340)	$	3,895	$	50,589
Balance, December 31, 2022																		Balance, December 31, 2022	$	850	$	—	$	6,298	$	—	$	41,833	$	(2,149)	$	3,807	$	50,639
Net income	Net income	—		—		—		—		1,926		—		376		2,302		Net income	—		—		—		—		2,064		—		244		2,308
Other comprehensive loss		—		—		—		—		—		(1,043)		—		(1,043)
Long-term income tax receivable adjustments		—		—		—		744		(744)		—		—		—
Preferred stock redemptions		(800)		—		—		—		—		—		—		(800)
Other comprehensive income																		Other comprehensive income	—		—		—		—		—		304		—		304

Preferred stock dividend	Preferred stock dividend	—		—		—		—		(37)		—		—		(37)		Preferred stock dividend	—		—		—		—		(17)		—		—		(17)
Common stock purchases		—		—		(77)		—		(793)		—		—		(870)

Distributions	Distributions	—		—		—		—		—		—		(394)		(394)		Distributions	—		—		—		—		—		—		(269)		(269)
Contributions	Contributions	—		—		—		—		—		—		4		4		Contributions	—		—		—		—		—		—		3		3

Other equity transactions	Other equity transactions	—		—		1		—		(13)		—		6		(6)		Other equity transactions	—		—		—		—		—		—		(8)		(8)
Balance, September 30, 2022		$	850	$	—	$	6,298	$	—	$	41,093	$	(2,383)	$	3,887	$	49,745
Balance, June 30, 2023																		Balance, June 30, 2023	$	850	$	—	$	6,298	$	—	$	43,880	$	(1,845)	$	3,777	$	52,960


			As of						As of
		Depreciable	September 30,		December 31,			Depreciable	June 30,		December 31,
		Life	2022		2021			Life	2023		2022
Regulated assets:	Regulated assets:						Regulated assets:
Utility generation, transmission and distribution systems	Utility generation, transmission and distribution systems	5-80 years	$	90,756	$	90,223	Utility generation, transmission and distribution systems	5-80 years	$	94,351	$	92,759
Interstate natural gas pipeline assets	Interstate natural gas pipeline assets	3-80 years	17,882		17,423		Interstate natural gas pipeline assets	3-80 years	18,605		18,328
			108,638		107,646				112,956		111,087
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(34,011)		(32,680)		Accumulated depreciation and amortization		(36,088)		(34,599)
Regulated assets, net	Regulated assets, net		74,627		74,966		Regulated assets, net		76,868		76,488

Nonregulated assets:	Nonregulated assets:						Nonregulated assets:
Independent power plants	Independent power plants	2-50 years	8,052		7,665		Independent power plants	2-50 years	8,476		8,545
Cove Point LNG facility	Cove Point LNG facility	40 years	3,397		3,364		Cove Point LNG facility	40 years	3,417		3,412
Other assets	Other assets	2-30 years	2,903		2,666		Other assets	2-30 years	2,787		2,693
			14,352		13,695				14,680		14,650
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(3,274)		(3,041)		Accumulated depreciation and amortization		(3,617)		(3,452)
Nonregulated assets, net	Nonregulated assets, net		11,078		10,654		Nonregulated assets, net		11,063		11,198

Net operating assets			85,705		85,620
									87,931		87,686
Construction work-in-progress	Construction work-in-progress		5,198		4,196		Construction work-in-progress		7,610		5,357
Property, plant and equipment, net	Property, plant and equipment, net		$	90,903	$	89,816	Property, plant and equipment, net		$	95,541	$	93,043


		Input Levels for Fair Value Measurements											Input Levels for Fair Value Measurements
		Level 1		Level 2		Level 3		Other(1)		Total			Level 1		Level 2		Level 3		Other(1)		Total
As of September 30, 2022:
As of June 30, 2023:												As of June 30, 2023:
Assets:	Assets:											Assets:
Commodity derivatives	Commodity derivatives	$	14	$	617	$	58	$	(124)	$	565	Commodity derivatives	$	3	$	195	$	13	$	(58)	$	153

Interest rate derivatives	Interest rate derivatives	54		100		12		—		166		Interest rate derivatives	53		57		12		—		122
Mortgage loans held for sale	Mortgage loans held for sale	—		661		—		—		661		Mortgage loans held for sale	—		834		—		—		834
Money market mutual funds	Money market mutual funds	1,394		—		—		—		1,394		Money market mutual funds	1,539		—		—		—		1,539
Debt securities:	Debt securities:											Debt securities:
U.S. government obligations	U.S. government obligations	830		—		—		—		830		U.S. government obligations	3,902		—		—		—		3,902
International government obligations	International government obligations	—		1		—		—		1		International government obligations	—		1		—		—		1
Corporate obligations	Corporate obligations	—		69		—		—		69		Corporate obligations	—		72		—		—		72
Municipal obligations	Municipal obligations	—		3		—		—		3		Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	Agency, asset and mortgage-backed obligations	—		1		—		—		1		Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:	Equity securities:											Equity securities:
U.S. companies	U.S. companies	333		—		—		—		333		U.S. companies	405		—		—		—		405
International companies	International companies	5,137		—		—		—		5,137		International companies	3,138		—		—		—		3,138
Investment funds	Investment funds	248		—		—		—		248		Investment funds	287		—		—		—		287
		$	8,010	$	1,452	$	70	$	(124)	$	9,408		$	9,327	$	1,163	$	25	$	(58)	$	10,457
Liabilities:	Liabilities:											Liabilities:
Commodity derivatives	Commodity derivatives	$	(2)	$	(199)	$	(113)	$	102	$	(212)	Commodity derivatives	$	(6)	$	(98)	$	(187)	$	62	$	(229)
Foreign currency exchange rate derivatives	Foreign currency exchange rate derivatives	—		(35)		—		—		(35)		Foreign currency exchange rate derivatives	—		(11)		—		—		(11)
Interest rate derivatives	Interest rate derivatives	—		—		(13)		—		(13)		Interest rate derivatives	—		(1)		(1)		—		(2)
		$	(2)	$	(234)	$	(126)	$	102	$	(260)		$	(6)	$	(110)	$	(188)	$	62	$	(242)


2021:
2022:										2022:
Beginning balance	Beginning balance	$	105	$	41	$	116	$	62	Beginning balance	$	(239)	$	13	$	(151)	$	19
Changes included in earnings(1)	Changes included in earnings(1)	(18)		(13)		(34)		(34)		Changes included in earnings(1)	(26)		8		(82)		2
Changes in fair value recognized in OCI	Changes in fair value recognized in OCI	(6)		—		(13)		—		Changes in fair value recognized in OCI	5		—		10		—
Changes in fair value recognized in net regulatory assets	Changes in fair value recognized in net regulatory assets	12		—		21		—		Changes in fair value recognized in net regulatory assets	1		—		(59)		—
Purchases	Purchases	1		—		2		—		Purchases	1		—		1		—

Settlements	Settlements	(62)		—		(60)		—		Settlements	11		—		34		—

Transfers out of Level 3 into Level 2										Transfers out of Level 3 into Level 2	69		—		69		—
Ending balance	Ending balance	$	32	$	28	$	32	$	28	Ending balance	$	(178)	$	21	$	(178)	$	21


	As of September 30, 2022				As of December 31, 2021
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	50,217	$	44,433	$	49,762	$	57,189


	As of June 30, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	51,622	$	46,124	$	51,635	$	46,906


		For the Three-Month Period Ended September 30, 2022																			For the Three-Month Period Ended June 30, 2023
		PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total			PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:	Customer Revenue:																			Customer Revenue:
Regulated:	Regulated:																			Regulated:
Retail electric	Retail electric	$	1,465	$	799	$	1,250	$	—	$	—	$	—	$	—	$	(1)	$	3,513	Retail electric	$	1,232	$	569	$	1,043	$	—	$	—	$	—	$	—	$	—	$	2,844
Retail gas	Retail gas	—		97		20		—		—		—		—		1		118		Retail gas	—		90		43		—		—		—		—		—		133
Wholesale	Wholesale	69		208		33		—		—		—		—		—		310		Wholesale	26		52		9		—		—		—		—		2		89
Transmission and distribution	Transmission and distribution	54		16		24		260		—		168		—		—		522		Transmission and distribution	34		13		19		244		—		166		—		—		476
Interstate pipeline	Interstate pipeline	—		—		—		—		594		—		—		(26)		568		Interstate pipeline	—		—		—		—		542		—		—		(27)		515
Other	Other	24		—		—		—		1		—		—		(1)		24		Other	24		—		—		—		(1)		—		—		—		23
Total Regulated	Total Regulated	1,612		1,120		1,327		260		595		168		—		(27)		5,055		Total Regulated	1,316		724		1,114		244		541		166		—		(25)		4,080
Nonregulated	Nonregulated	—		1		—		71		326		16		264		177		855		Nonregulated	—		1		—		33		270		30		376		1		711
Total Customer Revenue	Total Customer Revenue	1,612		1,121		1,327		331		921		184		264		150		5,910		Total Customer Revenue	1,316		725		1,114		277		811		196		376		(24)		4,791
Other revenue	Other revenue	23		27		7		28		43		(7)		38		26		185		Other revenue	11		34		5		29		7		(4)		61		(1)		142
Total	Total	$	1,635	$	1,148	$	1,334	$	359	$	964	$	177	$	302	$	176	$	6,095	Total	$	1,327	$	759	$	1,119	$	306	$	818	$	192	$	437	$	(25)	$	4,933


		For the Nine-Month Period Ended September 30, 2022																			For the Six-Month Period Ended June 30, 2023
		PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total			PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:	Customer Revenue:																			Customer Revenue:
Regulated:	Regulated:																			Regulated:
Retail electric	Retail electric	$	3,817	$	1,865	$	2,680	$	—	$	—	$	—	$	—	$	(2)	$	8,360	Retail electric	$	2,581	$	1,060	$	1,891	$	—	$	—	$	—	$	—	$	—	$	5,532
Retail gas	Retail gas	—		570		99		—		—		—		—		1		670		Retail gas	—		386		139		—		—		—		—		—		525
Wholesale	Wholesale	179		488		68		—		—		—		—		(2)		733		Wholesale	87		152		40		—		—		—		—		1		280
Transmission and distribution	Transmission and distribution	131		44		59		803		—		516		—		—		1,553		Transmission and distribution	72		27		37		525		—		331		—		—		992
Interstate pipeline	Interstate pipeline	—		—		—		—		1,863		—		—		(94)		1,769		Interstate pipeline	—		—		—		—		1,420		—		—		(83)		1,337
Other	Other	72		—		1		—		2		—		—		(1)		74		Other	56		—		—		—		1		—		—		—		57
Total Regulated	Total Regulated	4,199		2,967		2,907		803		1,865		516		—		(98)		13,159		Total Regulated	2,796		1,625		2,107		525		1,421		331		—		(82)		8,723
Nonregulated	Nonregulated	—		3		1		128		889		38		695		461		2,215		Nonregulated	—		4		1		78		536		70		681		1		1,371
Total Customer Revenue	Total Customer Revenue	4,199		2,970		2,908		931		2,754		554		695		363		15,374		Total Customer Revenue	2,796		1,629		2,108		603		1,957		401		681		(81)		10,094
Other revenue	Other revenue	47		80		18		88		101		(11)		68		93		484		Other revenue	15		50		10		57		34		(4)		149		(1)		310
Total	Total	$	4,246	$	3,050	$	2,926	$	1,019	$	2,855	$	543	$	763	$	456	$	15,858	Total	$	2,811	$	1,679	$	2,118	$	660	$	1,991	$	397	$	830	$	(82)	$	10,404


		Performance obligations expected to be satisfied:							Performance obligations expected to be satisfied:
		Less than 12 months		More than 12 months		Total			Less than 12 months		More than 12 months		Total
BHE Pipeline Group	BHE Pipeline Group	$	2,931	$	21,414	$	24,345	BHE Pipeline Group	$	3,007	$	20,764	$	23,771
BHE Transmission	BHE Transmission	688		172		860		BHE Transmission	328		—		328
Total	Total	$	3,619	$	21,586	$	25,205	Total	$	3,335	$	20,764	$	24,099


		Unrecognized		Foreign		Unrealized				AOCI			Unrecognized		Foreign		Unrealized				AOCI
		Amounts on		Currency		(Losses) Gains				Attributable			Amounts on		Currency		Gains				Attributable
		Retirement		Translation		on Cash		Noncontrolling		To BHE			Retirement		Translation		on Cash		Noncontrolling		To BHE
		Benefits		Adjustment		Flow Hedges		Interests		Shareholders, Net			Benefits		Adjustment		Flow Hedges		Interests		Shareholders, Net

Balance, December 31, 2020		$	(492)	$	(1,062)	$	(8)	$	10	$	(1,552)
Other comprehensive income (loss)		44		(59)		48		(4)		29
Balance, September 30, 2021		$	(448)	$	(1,121)	$	40	$	6	$	(1,523)

Balance, December 31, 2021	Balance, December 31, 2021	$	(318)	$	(1,086)	$	59	$	5	$	(1,340)	Balance, December 31, 2021	$	(318)	$	(1,086)	$	59	$	5	$	(1,340)
Other comprehensive income (loss)	Other comprehensive income (loss)	65		(1,256)		148		—		(1,043)		Other comprehensive income (loss)	40		(591)		103		—		(448)
Balance, September 30, 2022		$	(253)	$	(2,342)	$	207	$	5	$	(2,383)
Balance, June 30, 2022												Balance, June 30, 2022	$	(278)	$	(1,677)	$	162	$	5	$	(1,788)

Balance, December 31, 2022												Balance, December 31, 2022	$	(390)	$	(1,896)	$	135	$	2	$	(2,149)
Other comprehensive (loss) income												Other comprehensive (loss) income	(11)		331		(16)		—		304
Balance, June 30, 2023												Balance, June 30, 2023	$	(401)	$	(1,565)	$	119	$	2	$	(1,845)


Depreciation and amortization:	Depreciation and amortization:									Depreciation and amortization:
PacifiCorp	PacifiCorp	$	277	$	272	$	836	$	811	PacifiCorp	$	279	$	279	$	558	$	559
MidAmerican Funding	MidAmerican Funding	338		218		865		634		MidAmerican Funding	226		277		460		527
NV Energy	NV Energy	144		138		423		411		NV Energy	153		139		305		279
Northern Powergrid	Northern Powergrid	92		73		272		217		Northern Powergrid	85		100		170		180
BHE Pipeline Group	BHE Pipeline Group	124		124		380		363		BHE Pipeline Group	95		125		267		256
BHE Transmission	BHE Transmission	58		59		176		177		BHE Transmission	65		60		126		118
BHE Renewables	BHE Renewables	67		61		198		182		BHE Renewables	67		65		133		131
HomeServices	HomeServices	14		14		43		37		HomeServices	12		14		25		29
BHE and Other(1)	BHE and Other(1)	2		1		4		2		BHE and Other(1)	—		—		1		2
Total depreciation and amortization	Total depreciation and amortization	$	1,116	$	960	$	3,197	$	2,834	Total depreciation and amortization	$	982	$	1,059	$	2,045	$	2,081





Interest expense:
PacifiCorp	$	105	$	110	$	318	$	322
MidAmerican Funding	84		81		249		237
NV Energy	55		51		158		154
Northern Powergrid	31		33		97		98
BHE Pipeline Group	37		33		110		111
BHE Transmission	39		39		115		117
BHE Renewables	45		39		131		119
HomeServices	2		1		5		3
BHE and Other(1)	157		144		454		432
Total interest expense	$	555	$	531	$	1,637	$	1,593


(Loss) earnings on common shares:
PacifiCorp	$	409	$	333	$	622	$	728
MidAmerican Funding	300		373		745		728
NV Energy	270		282		392		416
Northern Powergrid	100		83		282		162
BHE Pipeline Group	234		144		755		627
BHE Transmission	59		65		183		184
BHE Renewables	173		163		526		360
HomeServices	29		102		134		321
BHE and Other(1)	(2,424)		351		(1,750)		580
Total (loss) earnings on common shares	$	(850)	$	1,896	$	1,889	$	4,106


Earnings on common shares:
PacifiCorp	$	107	$	83	$	(13)	$	213
MidAmerican Funding	233		204		482		445
NV Energy	90		93		124		122
Northern Powergrid	96		71		107		182
BHE Pipeline Group	187		199		556		521
BHE Transmission	58		62		122		124
BHE Renewables	206		264		285		409
HomeServices	34		84		—		105
BHE and Other(1)	55		1,824		384		618
Total earnings on common shares	$	1,066	$	2,884	$	2,047	$	2,739


(Loss) income before income tax benefit and equity loss by country:
Income (loss) before income tax expense (benefit) and equity income (loss) by country:										Income (loss) before income tax expense (benefit) and equity income (loss) by country:
U.S.	U.S.	$	(2,068)	$	1,511	$	395	$	3,699	U.S.	$	914	$	3,117	$	1,733	$	2,463
United Kingdom	United Kingdom	118		107		344		343		United Kingdom	93		87		206		226
Canada	Canada	43		49		135		134		Canada	44		46		87		92
Australia										Australia	(3)		1		2		1
Other	Other	12		8		10		13		Other	1		(2)		—		(3)
Total (loss) income before income tax benefit and equity loss by country		$	(1,895)	$	1,675	$	884	$	4,189
Total income (loss) before income tax expense (benefit) and equity income (loss) by country										Total income (loss) before income tax expense (benefit) and equity income (loss) by country	$	1,049	$	3,249	$	2,028	$	2,779


		Third Quarter								First Nine Months									Second Quarter								First Six Months
		2022		2021		Change				2022		2021		Change					2023		2022		Change				2023		2022		Change
Operating revenue:	Operating revenue:																	Operating revenue:
PacifiCorp	PacifiCorp	$	1,635	$	1,491	$	144	10	%	$	4,246	$	4,031	$	215	5	%	PacifiCorp	$	1,327	$	1,314	$	13	1	%	$	2,811	$	2,611	$	200	8	%
MidAmerican Funding	MidAmerican Funding	1,148		966		182		19		3,050		2,726		324		12		MidAmerican Funding	759		897		(138)		(15)		1,679		1,902		(223)		(12)
NV Energy	NV Energy	1,334		1,085		249		23		2,926		2,443		483		20		NV Energy	1,119		899		220		24		2,118		1,592		526		33
Northern Powergrid	Northern Powergrid	359		277		82		30		1,019		857		162		19		Northern Powergrid	307		345		(38)		(11)		661		660		1		—
BHE Pipeline Group	BHE Pipeline Group	964		785		179		23		2,855		2,584		271		10		BHE Pipeline Group	818		856		(38)		(4)		1,991		1,891		100		5
BHE Transmission	BHE Transmission	177		185		(8)		(4)		543		547		(4)		(1)		BHE Transmission	192		183		9		5		397		366		31		8
BHE Renewables	BHE Renewables	302		316		(14)		(4)		763		773		(10)		(1)		BHE Renewables	437		478		(41)		(9)		830		814		16		2
HomeServices	HomeServices	1,405		1,743		(338)		(19)		4,284		4,738		(454)		(10)		HomeServices	1,296		1,672		(376)		(22)		2,171		2,879		(708)		(25)
BHE and Other	BHE and Other	176		120		56		47		456		414		42		10		BHE and Other	(26)		(32)		6		19		(83)		(73)		(10)		(14)
Total operating revenue	Total operating revenue	$	7,500	$	6,968	$	532	8	%	$	20,142	$	19,113	$	1,029	5	%	Total operating revenue	$	6,229	$	6,612	$	(383)	(6)	%	$	12,575	$	12,642	$	(67)	(1)	%

(Loss) earnings on common shares:
Earnings on common shares:																		Earnings on common shares:
PacifiCorp	PacifiCorp	$	409	$	333	$	76	23	%	$	622	$	728	$	(106)	(15)	%	PacifiCorp	$	107	$	83	$	24	29	%	$	(13)	$	213	$	(226)	*
MidAmerican Funding	MidAmerican Funding	300		373		(73)		(20)		745		728		17		2		MidAmerican Funding	233		204		29		14		482		445		37		8
NV Energy	NV Energy	270		282		(12)		(4)		392		416		(24)		(6)		NV Energy	90		93		(3)		(3)		124		122		2		2
Northern Powergrid	Northern Powergrid	100		83		17		20		282		162		120		74		Northern Powergrid	96		71		25		35		107		182		(75)		(41)
BHE Pipeline Group	BHE Pipeline Group	234		144		90		63		755		627		128		20		BHE Pipeline Group	187		199		(12)		(6)		556		521		35		7
BHE Transmission	BHE Transmission	59		65		(6)		(9)		183		184		(1)		(1)		BHE Transmission	58		62		(4)		(6)		122		124		(2)		(2)
BHE Renewables(1)	BHE Renewables(1)	173		163		10		6		526		360		166		46		BHE Renewables(1)	206		264		(58)		(22)		285		409		(124)		(30)
HomeServices	HomeServices	29		102		(73)		(72)		134		321		(187)		(58)		HomeServices	34		84		(50)		(60)		—		105		(105)		(100)
BHE and Other	BHE and Other	(2,424)		351		(2,775)		*		(1,750)		580		(2,330)		*		BHE and Other	55		1,824		(1,769)		(97)		384		618		(234)		(38)
Total (loss) earnings on common shares		$	(850)	$	1,896	$	(2,746)	*		$	1,889	$	4,106	$	(2,217)	(54)	%
Total earnings on common shares																		Total earnings on common shares	$	1,066	$	2,884	$	(1,818)	(63)	%	$	2,047	$	2,739	$	(692)	(25)	%


																BHE Pipeline																			BHE Pipeline
						MidAmerican		NV		Northern		BHE				Group and									MidAmerican		NV		Northern		BHE				Group and
		BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		HomeServices		Other		Total			BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		HomeServices		Other		Total

Cash and cash equivalents	Cash and cash equivalents	$	106	$	219	$	582	$	123	$	164	$	60	$	291	$	232	$	1,777	Cash and cash equivalents	$	112	$	586	$	454	$	81	$	26	$	74	$	271	$	625	$	2,229

Credit facilities(1)	Credit facilities(1)	3,500		1,200		1,509		650		237		777		3,400		—		11,273		Credit facilities(1)	3,500		2,000		1,509		1,000		341		812		2,230		—		11,392
Less:	Less:																			Less:
Short-term debt	Short-term debt	(100)		—		—		(320)		(14)		(261)		(746)		—		(1,441)		Short-term debt	(1,245)		—		—		—		(104)		(111)		(783)		—		(2,243)
Tax-exempt bond support and letters of credit	Tax-exempt bond support and letters of credit	—		(218)		(370)		(17)		—		(1)		—		—		(606)		Tax-exempt bond support and letters of credit	—		(249)		(306)		—		—		(1)		—		—		(556)
Net credit facilities	Net credit facilities	3,400		982		1,139		313		223		515		2,654		—		9,226		Net credit facilities	2,255		1,751		1,203		1,000		237		700		1,447		—		8,593

Total net liquidity	Total net liquidity	$	3,506	$	1,201	$	1,721	$	436	$	387	$	575	$	2,945	$	232	$	11,003	Total net liquidity	$	2,367	$	2,337	$	1,657	$	1,081	$	263	$	774	$	1,718	$	625	$	10,822
Credit facilities:	Credit facilities:																			Credit facilities:
Maturity dates	Maturity dates	2025		2025		2023, 2025		2025		2024, 2026		2023, 2026		2023, 2026						Maturity dates	2026		2026		2024, 2026		2026		2025		2024, 2026, 2027		2023, 2024, 2026


		Nine-Month Periods				Annual			Six-Month Periods				Annual
		Ended September 30,				Forecast			Ended June 30,				Forecast
		2021		2022		2022			2022		2023		2023
Capital expenditures by business:	Capital expenditures by business:							Capital expenditures by business:
PacifiCorp	PacifiCorp	$	1,157	$	1,481	$	2,255	PacifiCorp	$	894	$	1,529	$	3,594
MidAmerican Funding	MidAmerican Funding	1,266		1,404		2,039		MidAmerican Funding	862		763		2,147
NV Energy	NV Energy	519		801		1,289		NV Energy	541		889		1,794
Northern Powergrid	Northern Powergrid	564		614		791		Northern Powergrid	450		249		556
BHE Pipeline Group	BHE Pipeline Group	684		800		1,223		BHE Pipeline Group	457		406		1,364
BHE Transmission	BHE Transmission	234		143		223		BHE Transmission	95		86		200
BHE Renewables	BHE Renewables	129		99		161		BHE Renewables	61		59		302
HomeServices	HomeServices	29		31		53		HomeServices	20		19		39
BHE and Other(1)	BHE and Other(1)	12		12		18		BHE and Other(1)	2		25		26
Total	Total	$	4,594	$	5,385	$	8,052	Total	$	3,382	$	4,025	$	10,022


Capital expenditures by type:	Capital expenditures by type:							Capital expenditures by type:
Wind generation	Wind generation	$	872	$	583	$	846	Wind generation	$	304	$	615	$	1,791
Electric distribution	Electric distribution	1,217		1,316		1,814		Electric distribution	805		1,045		2,221
Electric transmission	Electric transmission	539		1,157		1,743		Electric transmission	628		749		2,013
Natural gas transmission and storage	Natural gas transmission and storage	647		640		959		Natural gas transmission and storage	335		304		1,021
Solar generation	Solar generation	104		333		408		Solar generation	261		251		444
Electric battery and pumped hydro storage								Electric battery and pumped hydro storage	3		45		257
Other	Other	1,215		1,356		2,282		Other	1,046		1,016		2,275
Total	Total	$	4,594	$	5,385	$	8,052	Total	$	3,382	$	4,025	$	10,022


		Derivative											Derivative
		Contracts -				Other		Other					Contracts -				Other		Other
		Current		Other		Current		Long-term					Current		Other		Current		Long-term
		Assets		Assets		Liabilities		Liabilities		Total			Assets		Assets		Liabilities		Liabilities		Total
As of September 30, 2022
As of June 30, 2023												As of June 30, 2023
Not designated as hedging contracts(1):	Not designated as hedging contracts(1):											Not designated as hedging contracts(1):
Commodity assets	Commodity assets	$	144	$	52	$	7	$	—	$	203	Commodity assets	$	57	$	—	$	6	$	5	$	68
Commodity liabilities	Commodity liabilities	(20)		(4)		(13)		—		(37)		Commodity liabilities	(6)		—		(36)		(17)		(59)
Total	Total	124		48		(6)		—		166		Total	51		—		(30)		(12)		9

Total derivatives	Total derivatives	124		48		(6)		—		166		Total derivatives	51		—		(30)		(12)		9
Cash collateral payable		(16)		(7)		—		—		(23)
Cash collateral receivable (payable)												Cash collateral receivable (payable)	—		—		—		—		—
Total derivatives - net basis	Total derivatives - net basis	$	108	$	41	$	(6)	$	—	$	143	Total derivatives - net basis	$	51	$	—	$	(30)	$	(12)	$	9

As of December 31, 2021
As of December 31, 2022												As of December 31, 2022
Not designated as hedging contracts(1):	Not designated as hedging contracts(1):											Not designated as hedging contracts(1):
Commodity assets	Commodity assets	$	81	$	21	$	2	$	—	$	104	Commodity assets	$	279	$	27	$	9	$	3	$	318
Commodity liabilities	Commodity liabilities	(5)		(1)		(38)		(7)		(51)		Commodity liabilities	(22)		(7)		(14)		(5)		(48)
Total	Total	76		20		(36)		(7)		53		Total	257		20		(5)		(2)		270

Total derivatives	Total derivatives	76		20		(36)		(7)		53		Total derivatives	257		20		(5)		(2)		270
Cash collateral receivable		—		—		5		—		5
Cash collateral payable(2)												Cash collateral payable(2)	(73)		(5)		—		—		(78)
Total derivatives - net basis	Total derivatives - net basis	$	76	$	20	$	(31)	$	(7)	$	58	Total derivatives - net basis	$	184	$	15	$	(5)	$	(2)	$	192


	Unit of	September 30,	December 31,
	Measure	2022	2021

Electricity purchases, net	Megawatt hours	2	2
Natural gas purchases	Decatherms	108	106


Cash and cash equivalents	$	~~219~~586

Credit facilities	~~1,200~~2,000
Less:

Tax-exempt bond support and letters of credit	~~(218)~~(249)
Net credit facilities	~~982~~1,751

Total net liquidity	$	~~1,201~~2,337

Credit facilities:
Maturity dates	~~2025~~2026


		Common Stock		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity			Common Stock		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity

Balance, June 30, 2021		$	—	$	561	$	7,865	$	8,426
Net income		—		—		377		377
Other equity transactions		—		—		(1)		(1)
Balance, September 30, 2021		$	—	$	561	$	8,241	$	8,802

Balance, December 31, 2020		$	—	$	561	$	7,504	$	8,065
Balance, March 31, 2022										Balance, March 31, 2022	$	—	$	561	$	8,643	$	9,204
Net income	Net income	—		—		737		737		Net income	—		—		207		207

Balance, September 30, 2021		$	—	$	561	$	8,241	$	8,802
Balance, June 30, 2022										Balance, June 30, 2022	$	—	$	561	$	8,850	$	9,411

Balance, December 31, 2021										Balance, December 31, 2021	$	—	$	561	$	8,399	$	8,960
Net income										Net income	—		—		451		451

Balance, June 30, 2022	Balance, June 30, 2022	$	—	$	561	$	8,850	$	9,411	Balance, June 30, 2022	$	—	$	561	$	8,850	$	9,411

Balance, March 31, 2023										Balance, March 31, 2023	$	—	$	561	$	9,227	$	9,788
Net income										Net income	—		—		236		236

Balance, June 30, 2023										Balance, June 30, 2023	$	—	$	561	$	9,463	$	10,024

Balance, December 31, 2022										Balance, December 31, 2022	$	—	$	561	$	9,084	$	9,645
Net income	Net income	—		—		305		305		Net income	—		—		478		478
Common stock dividend	Common stock dividend	—		—		(50)		(50)		Common stock dividend	—		—		(100)		(100)
Other equity transactions	Other equity transactions	—		—		(1)		(1)		Other equity transactions	—		—		1		1
Balance, September 30, 2022		$	—	$	561	$	9,104	$	9,665

Balance, December 31, 2021		$	—	$	561	$	8,399	$	8,960
Net income		—		—		756		756
Common stock dividend		—		—		(50)		(50)
Other equity transactions		—		—		(1)		(1)
Balance, September 30, 2022		$	—	$	561	$	9,104	$	9,665
Balance, June 30, 2023										Balance, June 30, 2023	$	—	$	561	$	9,463	$	10,024


	As of September 30, 2022				As of December 31, 2021
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,727	$	6,804	$	7,721	$	9,037


		As of					As of
		September 30, 2022		December 31, 2021			June 30, 2023		December 31, 2022
Assets:	Assets:					Assets:
Regulated electric	Regulated electric	$	22,195	$	21,385	Regulated electric	$	22,425	$	22,092
Regulated natural gas	Regulated natural gas	1,841		1,871		Regulated natural gas	1,717		1,885
Other	Other	—		1		Other	1		1
Total assets	Total assets	$	24,036	$	23,257	Total assets	$	24,143	$	23,978


	Paid-in Capital		Retained Earnings		Total Member's Equity

Balance, June 30, 2021	$	1,679	$	7,594	$	9,273
Net income	—		373		373
Other equity transactions	—		1		1
Balance, September 30, 2021	$	1,679	$	7,968	$	9,647

Balance, December 31, 2020	$	1,679	$	7,240	$	8,919
Net income	—		728		728

Balance, September 30, 2021	$	1,679	$	7,968	$	9,647

Balance, June 30, 2022	$	1,679	$	8,567	$	10,246
Net income	—		300		300
Other equity transactions	—		1		1
Balance, September 30, 2022	$	1,679	$	8,868	$	10,547

Balance, December 31, 2021	$	1,679	$	8,122	$	9,801
Net income	—		745		745
Other equity transactions	—		1		1
Balance, September 30, 2022	$	1,679	$	8,868	$	10,547