In June 2023, PacifiCorp filed deferral applications with its state commissions in all six states to track the costs associated with third-party liability from litigation due to the 2020 Wildfires. The deferred accounting applications enable PacifiCorp to preserve its ability to seek recovery in the future in the event the outcome could potentially impact its financial stability. The applications state that PacifiCorp is not seeking recovery of these costs from customers at this time and does not expect to determine if it will seek recovery until the appeals process has concluded.

MidAmerican Energy

Iowa Gas

In June 2023, MidAmerican Energy filed a request with the IUB for an increase in its Iowa retail natural gas rates, which would increase revenue by $39 million annually. If approved, the requested rates would increase retail customer's bills by an average of 6.1%. Interim rates of $31 million annually, or an average increase to customer's bills of 4.8%, were effective in June 2023.

South Dakota

In May 2022, MidAmerican Energy filed a request with the South Dakota Public Utilities Commission ("SDPUC") for a $7 million, or 6.4%, annual increase in South Dakota retail natural gas rates. In March 2023, MidAmerican Energy filed a settlement agreement between all parties allowing a total increase of $6 million, or 5.5%, annual increase in South Dakota retail natural gas rates, upon completion of the capital investment phase-in adjustment clause. On March 31, 2023, the SDPUC issued an order approving the settlement agreement with final rates effective April 1, 2023.

Wind PRIME

In January 2022, MidAmerican Energy filed an application with the IUB for advance ratemaking principles for Wind PRIME. If approved, MidAmerican Energy expects to proceed with Wind PRIME, which consists of up to 2,042 MWs of new wind generation and up to 50 MWs of solar generation. If all Wind PRIME generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind generation and nearly 200 MWs of solar generation. Wind PRIME is projected to allow MidAmerican Energy to generate renewable energy greater than or equal to all of its Iowa retail customers' annual energy needs. MidAmerican Energy expects to be eligible for 100% PTCs under current tax law for the Wind PRIME projects. In December 2022, MidAmerican Energy, the Iowa Office of Consumer Advocate and the Iowa Business Energy Coalition filed a non-unanimous settlement with the IUB that ~~includes~~included a rate of return of 11.0%. The settlement would benefit customers by providing an immediate rate decrease through lower retail fuel costs and future rate increase mitigation through accelerated depreciation of generation assets. ~~The IUB conducted a hearing on the application and proposed settlement during the week of February 20, 2023.~~ On April 27, 2023, the IUB issued its final order regarding the ~~application. The IUB~~application and found that MidAmerican Energy met the statutory requisites for a grant of advance ratemaking principles and granted the application, but rejected the settlement and proposed its own principles for the project. MidAmerican Energy ~~is reviewing~~reviewed the order and ~~assessing options for rejection or motion to reconsider. MidAmerican Energy must either accept or reject the order, or file~~filed a motion for reconsideration ~~within 20 days~~or rehearing on May 17, 2023. On June 15, 2023, the IUB granted the motion for reconsideration and ~~no later than May 17,~~rehearing. On July 14, 2023 the IUB issued a new procedural schedule with rehearing set to begin on October 10, 2023. MidAmerican Energy expects the IUB to issue an order on the request for reconsideration and rehearing by the end of 2023.

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Iowa Transmission Legislation

In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law provides MidAmerican Energy, as an incumbent electric transmission owner, the legal right to construct, own and maintain transmission lines in MidAmerican Energy's service territory that have been approved by the MISO (or another federally registered planning authority) and are eligible to receive regional cost allocation. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for the construction of eligible electric transmission lines that it intends to construct, own and maintain. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner must provide the IUB an estimate of the cost to construct the eligible electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the eligible electric transmission line. In October 2020, national transmission interests filed a lawsuit that challenged the law on state constitutional grounds. The suit argues that the law was enacted in violation of the "single-subject" provision of Iowa's state constitution because it was "log-rolled" into a late session appropriations bill and violates the equal protection provision of the Iowa constitution. The State of Iowa defended the law, and MidAmerican Energy and ITC Midwest both intervened and defended the law as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of standing, and the national transmission interests appealed. In June 2022, the Iowa Court of Appeals upheld the district court's decision, after which the national transmission interests asked the Iowa Supreme Court to reconsider. In November 2022, the Iowa Supreme Court granted the motion to reconsider. On March 24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower courts, held the national transmission interests had standing, and remanded the case to the district court to consider the state constitutional claims on their merits. The opinion also imposed a temporary injunction that stayed enforcement of the law pending a decision on the merits. On April 7, 2023, the State of Iowa, acting individually, and MidAmerican Energy and ITC Midwest, acting jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19, 2023, the national transmission interests filed a reply that (1) expressed its opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to hold that the injunction specifically applied to and precluded advancement of MidAmerican Energy's Long Range Transmission Projects ("LRTP") Tranche 1 projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on the constitutional claims on the merits without further briefing or argument. On April 26, 2023, the Iowa Supreme Court issued an order that denied the petitions for rehearing without comment and made minor, non-substantive changes to the decision, with no changes to the injunction. ~~No earlier than~~On May ~~18,~~30, 2023, the Iowa Supreme Court ~~will remand~~remanded the case to the district court for further proceedings on the ~~merits.~~merits, where the national transmission interests have filed a motion for summary judgment. The State of Iowa, MidAmerican Energy and ITC Midwest are collaborating on a resistance to the motion and the State of Iowa is preparing a cross motion for summary judgment. A hearing on the motions for summary judgment is scheduled for September 29, 2023, with defendants' resisting documents due on August 4, 2023, plaintiffs' documents due on September 8, 2023, and reply documents due on September 18, 2023. To this point, MISO has taken no action to reverse or disrupt its approval of MidAmerican Energy's LRTP Tranche 1 projects. This matter only potentially affects the manner in which MidAmerican Energy would secure the right to construct transmission lines that are eligible for regional cost allocation and are otherwise subject to competitive bidding under the MISO tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing rights to construct any other transmission lines, including lines required to serve new or expanded retail load, connect new generators or meet reliability criteria.

NV Energy (Nevada Power and Sierra Pacific)

Merger Application

In March 2022, the Nevada Utilities filed a joint application with the PUCN for authorization to merge Sierra Pacific with and into Nevada Power, with Nevada Power being the surviving entity. If approved by the PUCN as filed, Nevada Power will have two distinct electric service territories in northern and southern Nevada each with their own rates and one natural gas service territory in the Reno and Sparks area. In October 2022, all parties to the proceedings relating to the joint application entered into a Stipulation to delay the procedural schedule. The Nevada Utilities made a supplemental filing on December 30, 2022. In March 2023, the proceedings relating to the joint application were postponed to May 2023. In April 2023, the Nevada Utilities filed a notice with the PUCN requesting to withdraw the joint application to merge into a single corporate entity and vacate the current procedural schedule, and executed a termination of the related merger agreement. In May 2023, the PUCN issued an order vacating the procedural schedules and hearing.

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Transportation Electrification Plan ("TEP")

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

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

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

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

The permission for the appeal was granted by the CMA and the appeal is expected to conclude in the ~~fourth~~third quarter of 2023 in accordance with the timetable required of the CMA. The outcome of this appeal may increase the revenue available to the Company if the CMA amends the price control determination.

BHE Pipeline Group

BHE GT&S

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

Northern Natural Gas

In July 2022, Northern Natural Gas filed a general rate case that proposed an overall annual cost-of-service of $1.3 billion. This is an increase of $323 million above the cost of service filed in its 2019 rate case of $1.0 billion. Depreciation on increased rate base and an increase in depreciation and negative salvage rates account for $115 million of the $323 million increase in the filed cost of service. Northern Natural Gas has requested increases in various rates, including transportation and storage reservation rates. In January 2023, the FERC approved Northern Natural Gas filing to implement its interim rates effective January 1, 2023, subject to refund and the outcome of hearing procedures. ~~Procedural hearings are scheduled~~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 ~~begin~~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 ~~14,~~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

2024-2025 General Tariff Application

In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with ~~total~~ total transmission tariffs of C$902.3 million and C$908.6 million for 2024 and 2025, respectively, which extends AltaLink's previous five-year commitment to maintain its tariff at or below C$904 million from 2019 to 2023 for another year. The application also requests the approval to reinstate C$98.9 million cost of removal to rate base which was not previously approved, based on additional information filed.

In July 2023, AltaLink requested the AUC to suspend the schedule for its 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 the AUC later this year to recover all costs incurred as a result of the recent wildfire events.

Generic Cost of Capital Proceeding

In January 2022, the AUC initiated the generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with respect to the first stage of the GCOC proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial ~~markets due to the COVID-19 pandemic.~~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 ~~third~~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, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2022, and new environmental matters occurring in 2023.

Air Quality Regulations

The Clean Air Act, as well as state laws and regulations impacting air emissions, provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. These laws and regulations continue to be promulgated and implemented and will impact the operation of BHE's generating facilities and require them to reduce emissions at those facilities to comply with the requirements. In addition, the potential adoption of state or federal clean energy standards, which include low-carbon, non-carbon and renewable electricity generating resources, may also impact electricity generators and natural gas providers.

41Greenhouse 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 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 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 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 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 Section 111 establishes a cooperative approach between the 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 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 ~~will accept~~accepted comments on the proposal ~~for 60 days following its publication in the Federal Register.~~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. In addition, the EPA must 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 proposed to disapprove the Utah and Wyoming interstate ozone SIPs. On January 30, 2023, the EPA entered into a stipulated extension to the 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 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 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. to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 Eastern and Midwestern states. In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. In March 2023, the EPA released the final Good Neighbor Rule. The electric generation sector remains the key industry regulated by the rule and will ~~have access~~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 ~~non-SCR~~SNCR on the Hunter and Huntington Units by 2026 as part of the preferred portfolio. The level of NOx allowances for the Utah units remains similar to 2021 levels, with significant reductions for the coal units beginning in 2026. The daily limit, which takes effect in 2030, will further restrict operation of coal-fueled units without ~~adequate controls.~~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 season if operated beyond 2025. Nevada's regional haze SIP has an enforceable retirement date for North Valmy Units 1 and 2 of December 31, 2028, and NV Energy's IRP identified a December 31, 2025, retirement date for the units. The EPA's updated modeling suggests that Arizona, Iowa and Kansas may be significantly contributing to nonattainment in downwind states. The EPA intends to undertake additional assessment of its modeling for these states and will determine if it is necessary to address obligations for these states in future actions. The EPA also deferred final action for Wyoming, pending further review of updated air quality and contribution modeling and analysis. Additional notice and comment rulemaking, such as a supplemental rule, would be required to rescind Iowa's approved SIP and incorporate additional states into the program. The states of Nevada, Utah and Wyoming challenged the EPA's ~~denial~~denials and deferral, respectively, of their interstate ozone transport SIPs in the Ninth, Tenth and D.C. Circuit ~~Court~~Courts of Appeals. PacifiCorp also filed petitions with the court opposing the EPA's action in ~~both states.~~Utah and Wyoming. At the time of filing, at least ~~six~~11 other states have challenged the EPA's action to disapprove SIPs in different regional federal ~~Courts~~courts of ~~Appeal.~~appeal. Stays have been granted by four circuit courts for SIP disapprovals in eight states. Relevant to Registrants, the states of Nevada, Texas and Utah were granted stays. The final good neighbor rule was published June 5, 2023 and takes effect August 4, 2023. The EPA issued an interim final rule stating that the federal rule will not take effect in states in which the SIP disapprovals have been deferred or stayed. In addition to litigation over SIP disapprovals, there are numerous appeals of the final good neighbor rule pending in four different circuit courts, and at least four motions to stay the final rule have been filed in three different circuit courts. Additional appeals may be filed prior to the rule's August 4, 2023, effective date. Until additional rulemaking is completed and litigation is exhausted, the potential impacts to the relevant Registrants cannot be determined.

~~The~~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.~~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.

In June 2019, the state of Utah incorporated a BART alternative into its SIP for regional haze planning period one. The BART alternative makes the shutdown of PacifiCorp's Carbon generating facility enforceable under the SIP and removes the requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA approved the SIP revision with the BART alternative in October 2020. The EPA's actions also withdrew a prior FIP that required installation of SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and 2. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. The EPA defended the SIP, and PacifiCorp and the state of Utah intervened in the ~~litigation.~~litigation in support of the EPA. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. A final decision from the court is expected by fall 2023. ~~The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for the regional haze second planning period on June 6, 2022. The SIP sets mass-based NO~~x ~~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. The state submitted the SIP to the EPA in August 2022 and the EPA determined the submission was complete August 22, 2022. The EPA is required to make a determination on the Utah SIP by August 2023.

The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. The EPA's final action 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 by 2019. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming and several environmental groups also filed an appeal of the EPA's final action. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The parties worked to mediate claims under the Wyoming regional haze requirements until the abatement on litigation was lifted in September 2022. Opening briefs were submitted in October 2022. In the litigation, PacifiCorp objects to the EPA's FIP requiring SCR on the Wyodak Unit. That requirement in the agency's plan remains stayed by the court. PacifiCorp has also intervened on behalf of the EPA against claims that Naughton Units 1 and 2 should have been subject to a SCR requirement. Oral argument ~~will be~~was held May 16, 2023. PacifiCorp ~~has claimed~~argued that the Naughton claims are moot but that a court ruling on the Wyodak claims is necessary ~~to determine whether~~because the EPA's federal plan complies with the Clean Air Act. A final decision from the court is expected by late fall 2023. Separately, on February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree, PacifiCorp must convert Jim Bridger Units 1 and 2 to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. The EPA and PacifiCorp executed an administrative order on consent June 9, 2022, covering compliance for Jim Bridger Units 1 and 2 under the regional haze rule. The federal order contains the same emission and operating limits as the Wyoming consent decree and adds federal approval of the compliance pathway outlined in the state consent decree, including revision of the SIP to include conversion of Jim Bridger Units 1 and 2 to natural gas. On December 30, 2022, the Wyoming Air Quality Division submitted the state-approved revised regional haze SIP requiring natural gas conversion of Jim Bridger Units 1 and 2 to the EPA for approval. The plan revision replaces a previous requirement for SCR at the units. The Wyoming Air Quality Division also issued an air permit for the natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. PacifiCorp submitted a notice of compliance to the EPA on March 9, 2023, to certify completion of the Jim Bridger administrative compliance order through completion of the requirements to comply with Wyoming's consent decree and revised SIP submission. PacifiCorp remains subject to the compliance terms of the Wyoming consent decree as it works to convert Jim Bridger Units 1 and 2 to natural gas. The EPA is in on-going discussions with Wyoming to finalize a determination on the SIP revisions, with a decision anticipated by fall 2023. Wyoming submitted a SIP for the second round of regional haze planning to the EPA in August 2022 and the EPA determined the submission was complete that same month. Wyoming determined that no additional controls are necessary on any Wyoming resources to make reasonable progress under the regional haze rules. The EPA is required to make a determination on the Wyoming SIP by August 2023.

The state of Colorado first planning period regional haze SIP requires SCR equipment at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are in-service. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021, with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in its 2023 IRP.

4452

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 ~~summer~~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 ~~will accept~~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, 2022. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2022.

4555

PacifiCorp and its subsidiaries

Consolidated Financial Section

4656

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 ~~March 31,~~June 30, 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~~six-month periods ended ~~March 31,~~June 30, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 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 24, 2023, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of 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

~~May 5,~~August 4, 2023

4757

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


		As of					As of
		March 31,		December 31,			June 30,		December 31,
		2023		2022			2023		2022
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	19	$	641	Cash and cash equivalents	$	586	$	641
Trade receivables, net	Trade receivables, net	780		825		Trade receivables, net	736		825
Other receivables, net	Other receivables, net	112		72		Other receivables, net	63		72
Inventories	Inventories	491		474		Inventories	533		474
Derivative contracts	Derivative contracts	114		184		Derivative contracts	51		184

Regulatory assets	Regulatory assets	302		275		Regulatory assets	374		275

Other current assets	Other current assets	215		213		Other current assets	112		213
Total current assets	Total current assets	2,033		2,684		Total current assets	2,455		2,684

Property, plant and equipment, net	Property, plant and equipment, net	24,695		24,430		Property, plant and equipment, net	25,488		24,430
Regulatory assets	Regulatory assets	1,684		1,605		Regulatory assets	1,745		1,605
Other assets	Other assets	707		686		Other assets	864		686

Total assets	Total assets	$	29,119	$	29,405	Total assets	$	30,552	$	29,405

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

4858

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


		As of					As of
		March 31,		December 31,			June 30,		December 31,
		2023		2022			2023		2022
LIABILITIES AND SHAREHOLDERS' EQUITY	LIABILITIES AND SHAREHOLDERS' EQUITY					LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	900	$	1,049	Accounts payable	$	1,036	$	1,049
Accrued interest	Accrued interest	143		128		Accrued interest	145		128
Accrued property, income and other taxes	Accrued property, income and other taxes	92		67		Accrued property, income and other taxes	161		67

Accrued employee expenses	Accrued employee expenses	97		86		Accrued employee expenses	101		86

Current portion of long-term debt	Current portion of long-term debt	440		449		Current portion of long-term debt	565		449
Regulatory liabilities	Regulatory liabilities	97		96		Regulatory liabilities	99		96
Other current liabilities	Other current liabilities	389		271		Other current liabilities	335		271
Total current liabilities	Total current liabilities	2,158		2,146		Total current liabilities	2,442		2,146

Long-term debt	Long-term debt	9,218		9,217		Long-term debt	9,984		9,217
Regulatory liabilities	Regulatory liabilities	2,690		2,843		Regulatory liabilities	2,587		2,843
Deferred income taxes	Deferred income taxes	3,097		3,152		Deferred income taxes	3,136		3,152
Other long-term liabilities	Other long-term liabilities	1,635		1,306		Other long-term liabilities	1,976		1,306
Total liabilities	Total liabilities	18,798		18,664		Total liabilities	20,125		18,664

Commitments and contingencies (Note 9)	Commitments and contingencies (Note 9)					Commitments and contingencies (Note 9)

Shareholders' equity:	Shareholders' equity:					Shareholders' equity:
Preferred stock	Preferred stock	2		2		Preferred stock	2		2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—		—		Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—		—
Additional paid-in capital	Additional paid-in capital	4,479		4,479		Additional paid-in capital	4,479		4,479
Retained earnings	Retained earnings	5,849		6,269		Retained earnings	5,955		6,269
Accumulated other comprehensive loss, net	Accumulated other comprehensive loss, net	(9)		(9)		Accumulated other comprehensive loss, net	(9)		(9)
Total shareholders' equity	Total shareholders' equity	10,321		10,741		Total shareholders' equity	10,427		10,741

Total liabilities and shareholders' equity	Total liabilities and shareholders' equity	$	29,119	$	29,405	Total liabilities and shareholders' equity	$	30,552	$	29,405


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	~~178~~194
Item 4.	Controls and Procedures	~~178~~194


Item 1.	Legal Proceedings	~~179~~195
Item 1A.	Risk Factors	~~182~~199
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~182~~199
Item 3.	Defaults Upon Senior Securities	~~183~~199
Item 4.	Mine Safety Disclosures	~~183~~199
Item 5.	Other Information	~~183~~200
Item 6.	Exhibits	~~183~~200
Signatures		~~187~~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

2020 Wildfires						Wildfires in Oregon and 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


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 Income ~~(Loss)~~						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						4757
Consolidated Balance Sheets						4858
Consolidated Statements of Operations						5060
Consolidated Statements of Changes in Shareholders' Equity						5161
Consolidated Statements of Cash Flows						5262
Notes to Consolidated Financial Statements						5363
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm						7184
Balance Sheets						7285
Statements of Operations						7487
Statements of Changes in Shareholder's Equity						7588
Statements of Cash Flows						7689
Notes to Financial Statements						7790
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						8598
Consolidated Balance Sheets						8699
Consolidated Statements of Operations						88101
Consolidated Statements of Changes in Member's Equity						89102
Consolidated Statements of Cash Flows						90103
Notes to Consolidated Financial Statements						91104
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~104~~118
Consolidated Balance Sheets						~~105~~119
Consolidated Statements of Operations						~~106~~120
Consolidated Statements of Changes in Shareholder's Equity						~~107~~121
Consolidated Statements of Cash Flows						~~108~~122
Notes to Consolidated Financial Statements						~~109~~123
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~124~~138
Consolidated Balance Sheets						~~125~~139
Consolidated Statements of Operations						~~126~~140
Consolidated Statements of Changes in Shareholder's Equity						~~127~~141
Consolidated Statements of Cash Flows						~~128~~142
Notes to Consolidated Financial Statements						~~129~~143
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~145~~159
Consolidated Balance Sheets						~~146~~160
Consolidated Statements of Operations						~~148~~162
Consolidated Statements of Comprehensive Income						~~149~~163
Consolidated Statements of Changes in Equity						~~150~~164
Consolidated Statements of Cash Flows						~~151~~165
Notes to Consolidated Financial Statements						~~152~~166
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm						~~163~~178
Consolidated Balance Sheets						~~164~~179
Consolidated Statements of Operations						~~166~~181
Consolidated Statements of Comprehensive Income						~~167~~182
Consolidated Statements of Changes in Shareholder's Equity						~~168~~183
Consolidated Statements of Cash Flows						~~169~~184
Notes to Consolidated Financial Statements						~~170~~185


Berkshire Hathaway Energy Company and its subsidiaries						2831
PacifiCorp and its subsidiaries						6374
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company						95108
Nevada Power Company and its subsidiaries						~~117~~130
Sierra Pacific Power Company and its subsidiaries						~~137~~151
Eastern Energy Gas Holdings, LLC and its subsidiaries						~~159~~173
Eastern Gas Transmission and Storage, Inc. and its subsidiaries						~~175~~190


		Three-Month Periods			Three-Month Periods						Six-Month Periods
		Ended March 31,			Ended June 30,						Ended June 30,
			2023			2022			2023		2022		2023		2022
Operating revenue:	Operating revenue:							Operating revenue:
Energy	Energy		$	5,471		$	4,823	Energy	$	4,933	$	4,940	$	10,404	$	9,763
Real estate	Real estate		875			1,207		Real estate	1,296		1,672		2,171		2,879
Total operating revenue	Total operating revenue		6,346			6,030		Total operating revenue	6,229		6,612		12,575		12,642

Operating expenses:	Operating expenses:							Operating expenses:
Energy:	Energy:							Energy:
Cost of sales	Cost of sales		1,955			1,460		Cost of sales	1,566		1,525		3,521		2,985
Operations and maintenance	Operations and maintenance		1,542			943		Operations and maintenance	1,200		1,081		2,742		2,024
Depreciation and amortization	Depreciation and amortization		1,050			1,007		Depreciation and amortization	970		1,045		2,020		2,052
Property and other taxes	Property and other taxes		212			205		Property and other taxes	197		199		409		404
Real estate	Real estate		920			1,179		Real estate	1,250		1,555		2,170		2,734
Total operating expenses	Total operating expenses		5,679			4,794		Total operating expenses	5,183		5,405		10,862		10,199

Operating income	Operating income		667			1,236		Operating income	1,046		1,207		1,713		2,443

Other income (expense):	Other income (expense):							Other income (expense):
Interest expense	Interest expense		(586)			(532)		Interest expense	(599)		(550)		(1,185)		(1,082)
Capitalized interest	Capitalized interest		24			17		Capitalized interest	33		18		57		35
Allowance for equity funds	Allowance for equity funds		49			38		Allowance for equity funds	61		42		110		80
Interest and dividend income	Interest and dividend income		86			23		Interest and dividend income	127		30		213		53
Gains (losses) on marketable securities, net			699			(1,257)
Gains on marketable securities, net								Gains on marketable securities, net	303		2,528		1,002		1,271
Other, net	Other, net		40			5		Other, net	78		(26)		118		(21)
Total other income (expense)	Total other income (expense)		312			(1,706)		Total other income (expense)	3		2,042		315		336

Income (loss) before income tax expense (benefit) and equity income (loss)	Income (loss) before income tax expense (benefit) and equity income (loss)		979			(470)		Income (loss) before income tax expense (benefit) and equity income (loss)	1,049		3,249		2,028		2,779
Income tax expense (benefit)	Income tax expense (benefit)		(162)			(507)		Income tax expense (benefit)	(255)		149		(417)		(358)
Equity income (loss)	Equity income (loss)		(38)			(57)		Equity income (loss)	(99)		(83)		(137)		(140)
Net income (loss)			1,103			(20)
Net income								Net income	1,205		3,017		2,308		2,997
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests		114			109		Net income attributable to noncontrolling interests	130		120		244		229
Net income (loss) attributable to BHE shareholders			989			(129)
Net income attributable to BHE shareholders								Net income attributable to BHE shareholders	1,075		2,897		2,064		2,768
Preferred dividends	Preferred dividends		8			16		Preferred dividends	9		13		17		29
Earnings (loss) on common shares			$	981		$	(145)
Earnings on common shares								Earnings on common shares	$	1,066	$	2,884	$	2,047	$	2,739


		BHE Shareholders' Equity																	BHE Shareholders' Equity
								Long-term				Accumulated													Long-term				Accumulated
						Additional		Income				Other											Additional		Income				Other
		Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total			Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total
		Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity			Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity
Balance, March 31, 2022																		Balance, March 31, 2022	$	1,650	$	—	$	6,374	$	(744)	$	40,608	$	(1,358)	$	3,894	$	50,424
Net income																		Net income	—		—		—		—		2,897		—		120		3,017
Other comprehensive loss																		Other comprehensive loss	—		—		—		—		—		(430)		—		(430)
Preferred stock redemptions																		Preferred stock redemptions	(800)		—		—		—		—		—		—		(800)
Preferred stock dividend																		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	Balance, December 31, 2021	$	1,650	$	—	$	6,374	$	(744)	$	40,754	$	(1,340)	$	3,895	$	50,589
Net (loss) income		—		—		—		—		(129)		—		109		(20)
Net income																		Net income	—		—		—		—		2,768		—		229		2,997
Other comprehensive loss	Other comprehensive loss	—		—		—		—		—		(18)		—		(18)		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	—		—		—		—		—		—		(245)		(245)
Contributions																		Contributions	—		—		—		—		—		—		2		2

Other equity transactions																		Other equity transactions	—		—		1		—		(12)		—		6		(5)
Balance, June 30, 2022																		Balance, June 30, 2022	$	850	$	—	$	6,298	$	(744)	$	42,688	$	(1,788)	$	3,887	$	51,191

Balance, March 31, 2023																		Balance, March 31, 2023	$	850	$	—	$	6,298	$	—	$	42,814	$	(2,109)	$	3,798	$	51,651
Net income																		Net income	—		—		—		—		1,075		—		130		1,205
Other comprehensive income																		Other comprehensive income	—		—		—		—		—		264		—		264

Preferred stock dividend	Preferred stock dividend	—		—		—		—		(16)		—		—		(16)		Preferred stock dividend	—		—		—		—		(9)		—		—		(9)

Distributions	Distributions	—		—		—		—		—		—		(116)		(116)		Distributions	—		—		—		—		—		—		(144)		(144)

Contributions																		Contributions	—		—		—		—		—		—		1		1

Other equity transactions	Other equity transactions	—		—		—		—		(1)		—		6		5		Other equity transactions	—		—		—		—		—		—		(8)		(8)
Balance, March 31, 2022		$	1,650	$	—	$	6,374	$	(744)	$	40,608	$	(1,358)	$	3,894	$	50,424

Balance, June 30, 2023																		Balance, June 30, 2023	$	850	$	—	$	6,298	$	—	$	43,880	$	(1,845)	$	3,777	$	52,960

Balance, December 31, 2022	Balance, December 31, 2022	$	850	$	—	$	6,298	$	—	$	41,833	$	(2,149)	$	3,807	$	50,639	Balance, December 31, 2022	$	850	$	—	$	6,298	$	—	$	41,833	$	(2,149)	$	3,807	$	50,639
Net income	Net income	—		—		—		—		989		—		114		1,103		Net income	—		—		—		—		2,064		—		244		2,308
Other comprehensive income	Other comprehensive income	—		—		—		—		—		40		—		40		Other comprehensive income	—		—		—		—		—		304		—		304

Preferred stock dividend	Preferred stock dividend	—		—		—		—		(8)		—		—		(8)		Preferred stock dividend	—		—		—		—		(17)		—		—		(17)

Distributions	Distributions	—		—		—		—		—		—		(125)		(125)		Distributions	—		—		—		—		—		—		(269)		(269)
Contributions	Contributions	—		—		—		—		—		—		2		2		Contributions	—		—		—		—		—		—		3		3

Balance, March 31, 2023		$	850	$	—	$	6,298	$	—	$	42,814	$	(2,109)	$	3,798	$	51,651
Other equity transactions																		Other equity transactions	—		—		—		—		—		—		(8)		(8)
Balance, June 30, 2023																		Balance, June 30, 2023	$	850	$	—	$	6,298	$	—	$	43,880	$	(1,845)	$	3,777	$	52,960


			As of						As of
		Depreciable	March 31,		December 31,			Depreciable	June 30,		December 31,
		Life	2023		2022			Life	2023		2022
Regulated assets:	Regulated assets:						Regulated assets:
Utility generation, transmission and distribution systems	Utility generation, transmission and distribution systems	5-80 years	$	93,123	$	92,759	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	18,492		18,328		Interstate natural gas pipeline assets	3-80 years	18,605		18,328
			111,615		111,087				112,956		111,087
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(35,395)		(34,599)		Accumulated depreciation and amortization		(36,088)		(34,599)
Regulated assets, net	Regulated assets, net		76,220		76,488		Regulated assets, net		76,868		76,488

Nonregulated assets:	Nonregulated assets:						Nonregulated assets:
Independent power plants	Independent power plants	2-50 years	8,514		8,545		Independent power plants	2-50 years	8,476		8,545
Cove Point LNG facility	Cove Point LNG facility	40 years	3,416		3,412		Cove Point LNG facility	40 years	3,417		3,412
Other assets	Other assets	2-30 years	2,680		2,693		Other assets	2-30 years	2,787		2,693
			14,610		14,650				14,680		14,650
Accumulated depreciation and amortization	Accumulated depreciation and amortization		(3,493)		(3,452)		Accumulated depreciation and amortization		(3,617)		(3,452)
Nonregulated assets, net	Nonregulated assets, net		11,117		11,198		Nonregulated assets, net		11,063		11,198

			87,337		87,686				87,931		87,686
Construction work-in-progress	Construction work-in-progress		6,246		5,357		Construction work-in-progress		7,610		5,357
Property, plant and equipment, net	Property, plant and equipment, net		$	93,583	$	93,043	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 March 31, 2023:
As of June 30, 2023:												As of June 30, 2023:
Assets:	Assets:											Assets:
Commodity derivatives	Commodity derivatives	$	3	$	280	$	16	$	(65)	$	234	Commodity derivatives	$	3	$	195	$	13	$	(58)	$	153

Interest rate derivatives	Interest rate derivatives	42		43		16		—		101		Interest rate derivatives	53		57		12		—		122
Mortgage loans held for sale	Mortgage loans held for sale	—		650		—		—		650		Mortgage loans held for sale	—		834		—		—		834
Money market mutual funds	Money market mutual funds	671		—		—		—		671		Money market mutual funds	1,539		—		—		—		1,539
Debt securities:	Debt securities:											Debt securities:
U.S. government obligations	U.S. government obligations	3,079		—		—		—		3,079		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	—		70		—		—		70		Corporate obligations	—		72		—		—		72
Municipal obligations	Municipal obligations	—		4		—		—		4		Municipal obligations	—		3		—		—		3

Agency, asset and mortgage-backed obligations												Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:	Equity securities:											Equity securities:
U.S. companies	U.S. companies	385		—		—		—		385		U.S. companies	405		—		—		—		405
International companies	International companies	3,329		—		—		—		3,329		International companies	3,138		—		—		—		3,138
Investment funds	Investment funds	278		—		—		—		278		Investment funds	287		—		—		—		287
		$	7,787	$	1,048	$	32	$	(65)	$	8,802		$	9,327	$	1,163	$	25	$	(58)	$	10,457
Liabilities:	Liabilities:											Liabilities:
Commodity derivatives	Commodity derivatives	$	(8)	$	(92)	$	(166)	$	52	$	(214)	Commodity derivatives	$	(6)	$	(98)	$	(187)	$	62	$	(229)
Foreign currency exchange rate derivatives	Foreign currency exchange rate derivatives	—		(20)		—		—		(20)		Foreign currency exchange rate derivatives	—		(11)		—		—		(11)
Interest rate derivatives	Interest rate derivatives	—		(5)		(1)		1		(5)		Interest rate derivatives	—		(1)		(1)		—		(2)
		$	(8)	$	(117)	$	(167)	$	53	$	(239)		$	(6)	$	(110)	$	(188)	$	62	$	(242)


2022:	2022:					2022:
Beginning balance	Beginning balance	$	(151)	$	19	Beginning balance	$	(239)	$	13	$	(151)	$	19
Changes included in earnings(1)	Changes included in earnings(1)	(56)		(6)		Changes included in earnings(1)	(26)		8		(82)		2
Changes in fair value recognized in OCI	Changes in fair value recognized in OCI	5		—		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	(60)		—		Changes in fair value recognized in net regulatory assets	1		—		(59)		—

Purchases						Purchases	1		—		1		—

Settlements	Settlements	23		—		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	$	(239)	$	13	Ending balance	$	(178)	$	21	$	(178)	$	21


	As of March 31, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	51,150	$	47,805	$	51,635	$	46,906


	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 March 31, 2023																			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	$	1,349	$	491	$	848	$	—	$	—	$	—	$	—	$	—	$	2,688	Retail electric	$	1,232	$	569	$	1,043	$	—	$	—	$	—	$	—	$	—	$	2,844
Retail gas	Retail gas	—		296		96		—		—		—		—		—		392		Retail gas	—		90		43		—		—		—		—		—		133
Wholesale	Wholesale	61		100		31		—		—		—		—		(1)		191		Wholesale	26		52		9		—		—		—		—		2		89
Transmission and distribution	Transmission and distribution	38		14		18		281		—		165		—		—		516		Transmission and distribution	34		13		19		244		—		166		—		—		476
Interstate pipeline	Interstate pipeline	—		—		—		—		878		—		—		(56)		822		Interstate pipeline	—		—		—		—		542		—		—		(27)		515
Other	Other	32		—		—		—		2		—		—		—		34		Other	24		—		—		—		(1)		—		—		—		23
Total Regulated	Total Regulated	1,480		901		993		281		880		165		—		(57)		4,643		Total Regulated	1,316		724		1,114		244		541		166		—		(25)		4,080
Nonregulated	Nonregulated	—		3		1		45		266		40		305		—		660		Nonregulated	—		1		—		33		270		30		376		1		711
Total Customer Revenue	Total Customer Revenue	1,480		904		994		326		1,146		205		305		(57)		5,303		Total Customer Revenue	1,316		725		1,114		277		811		196		376		(24)		4,791
Other revenue	Other revenue	4		16		5		28		27		—		88		—		168		Other revenue	11		34		5		29		7		(4)		61		(1)		142
Total	Total	$	1,484	$	920	$	999	$	354	$	1,173	$	205	$	393	$	(57)	$	5,471	Total	$	1,327	$	759	$	1,119	$	306	$	818	$	192	$	437	$	(25)	$	4,933


	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
Customer Revenue:
Regulated:
Retail electric	$	2,581	$	1,060	$	1,891	$	—	$	—	$	—	$	—	$	—	$	5,532
Retail gas	—		386		139		—		—		—		—		—		525
Wholesale	87		152		40		—		—		—		—		1		280
Transmission and distribution	72		27		37		525		—		331		—		—		992
Interstate pipeline	—		—		—		—		1,420		—		—		(83)		1,337
Other	56		—		—		—		1		—		—		—		57
Total Regulated	2,796		1,625		2,107		525		1,421		331		—		(82)		8,723
Nonregulated	—		4		1		78		536		70		681		1		1,371
Total Customer Revenue	2,796		1,629		2,108		603		1,957		401		681		(81)		10,094
Other revenue	15		50		10		57		34		(4)		149		(1)		310
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	$	2,786	$	20,146	$	22,932	BHE Pipeline Group	$	3,007	$	20,764	$	23,771
BHE Transmission	BHE Transmission	490		—		490		BHE Transmission	328		—		328
Total	Total	$	3,276	$	20,146	$	23,422	Total	$	3,335	$	20,764	$	24,099


		Unrecognized		Foreign		Unrealized				AOCI			Unrecognized		Foreign		Unrealized				AOCI
		Amounts on		Currency		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, 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)	15		(110)		77		—		(18)		Other comprehensive income (loss)	40		(591)		103		—		(448)
Balance, March 31, 2022		$	(303)	$	(1,196)	$	136	$	5	$	(1,358)
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)	Balance, December 31, 2022	$	(390)	$	(1,896)	$	135	$	2	$	(2,149)
Other comprehensive (loss) income	Other comprehensive (loss) income	(4)		99		(55)		—		40		Other comprehensive (loss) income	(11)		331		(16)		—		304
Balance, March 31, 2023		$	(394)	$	(1,797)	$	80	$	2	$	(2,109)
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	$	279	$	280	PacifiCorp	$	279	$	279	$	558	$	559
MidAmerican Funding	MidAmerican Funding	234		250		MidAmerican Funding	226		277		460		527
NV Energy	NV Energy	152		140		NV Energy	153		139		305		279
Northern Powergrid	Northern Powergrid	85		80		Northern Powergrid	85		100		170		180
BHE Pipeline Group	BHE Pipeline Group	172		131		BHE Pipeline Group	95		125		267		256
BHE Transmission	BHE Transmission	61		58		BHE Transmission	65		60		126		118
BHE Renewables	BHE Renewables	66		66		BHE Renewables	67		65		133		131
HomeServices	HomeServices	13		15		HomeServices	12		14		25		29
BHE and Other(1)	BHE and Other(1)	1		2		BHE and Other(1)	—		—		1		2
Total depreciation and amortization	Total depreciation and amortization	$	1,063	$	1,022	Total depreciation and amortization	$	982	$	1,059	$	2,045	$	2,081





Interest expense:
PacifiCorp	$	124	$	106
MidAmerican Funding	84		82
NV Energy	63		51
Northern Powergrid	30		32
BHE Pipeline Group	39		37
BHE Transmission	37		38
BHE Renewables	45		42
HomeServices	4		1
BHE and Other(1)	160		143
Total interest expense	$	586	$	532


Earnings (loss) on common shares:
PacifiCorp	$	(120)	$	130
MidAmerican Funding	249		241
NV Energy	34		29
Northern Powergrid	11		111
BHE Pipeline Group	369		322
BHE Transmission	64		62
BHE Renewables	79		145
HomeServices	(34)		21
BHE and Other(1)	329		(1,206)
Total earnings (loss) on common shares	$	981	$	(145)


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


		First Quarter								Second Quarter					First Six Months
		2023		2022		Change					2023		2022		Change				2023		2022		Change
Operating revenue:	Operating revenue:											Operating revenue:
PacifiCorp	PacifiCorp	$	1,484	$	1,297	$	187	14	%			PacifiCorp	$	1,327	$	1,314	$	13	1	%	$	2,811	$	2,611	$	200	8	%
MidAmerican Funding	MidAmerican Funding	920		1,005		(85)		(8)				MidAmerican Funding	759		897		(138)		(15)		1,679		1,902		(223)		(12)
NV Energy	NV Energy	999		693		306		44				NV Energy	1,119		899		220		24		2,118		1,592		526		33
Northern Powergrid	Northern Powergrid	354		315		39		12				Northern Powergrid	307		345		(38)		(11)		661		660		1		—
BHE Pipeline Group	BHE Pipeline Group	1,173		1,035		138		13				BHE Pipeline Group	818		856		(38)		(4)		1,991		1,891		100		5
BHE Transmission	BHE Transmission	205		183		22		12				BHE Transmission	192		183		9		5		397		366		31		8
BHE Renewables	BHE Renewables	393		336		57		17				BHE Renewables	437		478		(41)		(9)		830		814		16		2
HomeServices	HomeServices	875		1,207		(332)		(28)				HomeServices	1,296		1,672		(376)		(22)		2,171		2,879		(708)		(25)
BHE and Other	BHE and Other	(57)		(41)		(16)		39				BHE and Other	(26)		(32)		6		19		(83)		(73)		(10)		(14)
Total operating revenue	Total operating revenue	$	6,346	$	6,030	$	316	5	%			Total operating revenue	$	6,229	$	6,612	$	(383)	(6)	%	$	12,575	$	12,642	$	(67)	(1)	%

Earnings (loss) on common shares:
Earnings on common shares:												Earnings on common shares:
PacifiCorp	PacifiCorp	$	(120)	$	130	$	(250)	*				PacifiCorp	$	107	$	83	$	24	29	%	$	(13)	$	213	$	(226)	*
MidAmerican Funding	MidAmerican Funding	249		241		8		3				MidAmerican Funding	233		204		29		14		482		445		37		8
NV Energy	NV Energy	34		29		5		17				NV Energy	90		93		(3)		(3)		124		122		2		2
Northern Powergrid	Northern Powergrid	11		111		(100)		(90)				Northern Powergrid	96		71		25		35		107		182		(75)		(41)
BHE Pipeline Group	BHE Pipeline Group	369		322		47		15				BHE Pipeline Group	187		199		(12)		(6)		556		521		35		7
BHE Transmission	BHE Transmission	64		62		2		3				BHE Transmission	58		62		(4)		(6)		122		124		(2)		(2)
BHE Renewables(1)	BHE Renewables(1)	79		145		(66)		(46)				BHE Renewables(1)	206		264		(58)		(22)		285		409		(124)		(30)
HomeServices	HomeServices	(34)		21		(55)		*				HomeServices	34		84		(50)		(60)		—		105		(105)		(100)
BHE and Other	BHE and Other	329		(1,206)		1,535		*				BHE and Other	55		1,824		(1,769)		(97)		384		618		(234)		(38)
Total earnings (loss) on common shares		$	981	$	(145)	$	1,126	*
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	$	173	$	19	$	58	$	21	$	18	$	64	$	216	$	394	$	963	Cash and cash equivalents	$	112	$	586	$	454	$	81	$	26	$	74	$	271	$	625	$	2,229

Credit facilities(1)	Credit facilities(1)	3,500		2,000		1,509		650		295		795		2,725		—		11,474		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	(755)		—		—		(83)		(49)		(127)		(805)		—		(1,819)		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	—		(249)		(363)		—		—		(1)		—		—		(613)		Tax-exempt bond support and letters of credit	—		(249)		(306)		—		—		(1)		—		—		(556)
Net credit facilities	Net credit facilities	2,745		1,751		1,146		567		246		667		1,920		—		9,042		Net credit facilities	2,255		1,751		1,203		1,000		237		700		1,447		—		8,593

Total net liquidity	Total net liquidity	$	2,918	$	1,770	$	1,204	$	588	$	264	$	731	$	2,136	$	394	$	10,005	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		2024, 2025		2023, 2025		2025		2025		2023, 2026, 2027		2023, 2024, 2026						Maturity dates	2026		2026		2024, 2026		2026		2025		2024, 2026, 2027		2023, 2024, 2026


		Three-Month Periods				Annual			Six-Month Periods				Annual
		Ended March 31,				Forecast			Ended June 30,				Forecast
		2022		2023		2023			2022		2023		2023
Capital expenditures by business:	Capital expenditures by business:							Capital expenditures by business:
PacifiCorp	PacifiCorp	$	374	$	643	$	3,662	PacifiCorp	$	894	$	1,529	$	3,594
MidAmerican Funding	MidAmerican Funding	459		382		2,324		MidAmerican Funding	862		763		2,147
NV Energy	NV Energy	272		437		1,751		NV Energy	541		889		1,794
Northern Powergrid	Northern Powergrid	169		124		597		Northern Powergrid	450		249		556
BHE Pipeline Group	BHE Pipeline Group	205		169		1,431		BHE Pipeline Group	457		406		1,364
BHE Transmission	BHE Transmission	47		43		191		BHE Transmission	95		86		200
BHE Renewables	BHE Renewables	19		29		269		BHE Renewables	61		59		302
HomeServices	HomeServices	12		11		46		HomeServices	20		19		39
BHE and Other(1)	BHE and Other(1)	(4)		10		12		BHE and Other(1)	2		25		26
Total	Total	$	1,553	$	1,848	$	10,283	Total	$	3,382	$	4,025	$	10,022


Capital expenditures by type:	Capital expenditures by type:							Capital expenditures by type:
Wind generation	Wind generation	$	153	$	105	$	2,172	Wind generation	$	304	$	615	$	1,791
Electric distribution	Electric distribution	388		477		2,071		Electric distribution	805		1,045		2,221
Electric transmission	Electric transmission	261		291		2,063		Electric transmission	628		749		2,013
Natural gas transmission and storage	Natural gas transmission and storage	103		65		1,097		Natural gas transmission and storage	335		304		1,021
Solar generation	Solar generation	51		40		236		Solar generation	261		251		444
Electric battery and pumped hydro storage	Electric battery and pumped hydro storage	1		40		236		Electric battery and pumped hydro storage	3		45		257
Other	Other	596		830		2,408		Other	1,046		1,016		2,275
Total	Total	$	1,553	$	1,848	$	10,283	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 March 31, 2023
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	$	133	$	15	$	15	$	3	$	166	Commodity assets	$	57	$	—	$	6	$	5	$	68
Commodity liabilities	Commodity liabilities	(7)		(7)		(39)		(4)		(57)		Commodity liabilities	(6)		—		(36)		(17)		(59)
Total	Total	126		8		(24)		(1)		109		Total	51		—		(30)		(12)		9

Total derivatives	Total derivatives	126		8		(24)		(1)		109		Total derivatives	51		—		(30)		(12)		9
Cash collateral payable		(12)		—		—		—		(12)
Cash collateral receivable (payable)												Cash collateral receivable (payable)	—		—		—		—		—
Total derivatives - net basis	Total derivatives - net basis	$	114	$	8	$	(24)	$	(1)	$	97	Total derivatives - net basis	$	51	$	—	$	(30)	$	(12)	$	9

As of December 31, 2022	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	$	279	$	27	$	9	$	3	$	318	Commodity assets	$	279	$	27	$	9	$	3	$	318
Commodity liabilities	Commodity liabilities	(22)		(7)		(14)		(5)		(48)		Commodity liabilities	(22)		(7)		(14)		(5)		(48)
Total	Total	257		20		(5)		(2)		270		Total	257		20		(5)		(2)		270

Total derivatives	Total derivatives	257		20		(5)		(2)		270		Total derivatives	257		20		(5)		(2)		270
Cash collateral payable(2)	Cash collateral payable(2)	(73)		(5)		—		—		(78)		Cash collateral payable(2)	(73)		(5)		—		—		(78)
Total derivatives - net basis	Total derivatives - net basis	$	184	$	15	$	(5)	$	(2)	$	192	Total derivatives - net basis	$	184	$	15	$	(5)	$	(2)	$	192


		Unit of	March 31,	December 31,		Unit of	June 30,	December 31,
		Measure	2023	2022		Measure	2023	2022

Electricity purchases, net	Electricity purchases, net	Megawatt hours	3	2	Electricity purchases, net	Megawatt hours	2	2
Natural gas purchases	Natural gas purchases	Decatherms	158	127	Natural gas purchases	Decatherms	145	127


Cash and cash equivalents	$	19586

Credit facilities	2,000
Less:

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

Total net liquidity	$	~~1,770~~2,337
Credit facilities:
Maturity dates	~~2024, 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, March 31, 2022										Balance, March 31, 2022	$	—	$	561	$	8,643	$	9,204
Net income										Net income	—		—		207		207

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

Balance, December 31, 2021	Balance, December 31, 2021	$	—	$	561	$	8,399	$	8,960	Balance, December 31, 2021	$	—	$	561	$	8,399	$	8,960
Net income	Net income	—		—		244		244		Net income	—		—		451		451

Balance, March 31, 2022		$	—	$	561	$	8,643	$	9,204
Balance, June 30, 2022										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	Balance, December 31, 2022	$	—	$	561	$	9,084	$	9,645
Net income	Net income	—		—		242		242		Net income	—		—		478		478
Common stock dividend	Common stock dividend	—		—		(100)		(100)		Common stock dividend	—		—		(100)		(100)
Other equity transactions	Other equity transactions	—		—		1		1		Other equity transactions	—		—		1		1
Balance, March 31, 2023		$	—	$	561	$	9,227	$	9,788
Balance, June 30, 2023										Balance, June 30, 2023	$	—	$	561	$	9,463	$	10,024


	As of March 31, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,722	$	7,127	$	7,729	$	6,964


		As of					As of
		March 31, 2023		December 31, 2022			June 30, 2023		December 31, 2022
Assets:	Assets:					Assets:
Regulated electric	Regulated electric	$	22,091	$	22,092	Regulated electric	$	22,425	$	22,092
Regulated natural gas	Regulated natural gas	1,716		1,885		Regulated natural gas	1,717		1,885
Other	Other	—		1		Other	1		1
Total assets	Total assets	$	23,807	$	23,978	Total assets	$	24,143	$	23,978


		Paid-in Capital		Retained Earnings		Total Member's Equity			Paid-in Capital		Retained Earnings		Total Member's Equity

Balance, March 31, 2022								Balance, March 31, 2022	$	1,679	$	8,363	$	10,042
Net income								Net income	—		204		204

Balance, June 30, 2022								Balance, June 30, 2022	$	1,679	$	8,567	$	10,246

Balance, December 31, 2021	Balance, December 31, 2021	$	1,679	$	8,122	$	9,801	Balance, December 31, 2021	$	1,679	$	8,122	$	9,801
Net income	Net income	—		241		241		Net income	—		445		445

Balance, March 31, 2022		$	1,679	$	8,363	$	10,042
Balance, June 30, 2022								Balance, June 30, 2022	$	1,679	$	8,567	$	10,246

Balance, March 31, 2023								Balance, March 31, 2023	$	1,679	$	9,149	$	10,828
Net income								Net income	—		233		233

Balance, June 30, 2023								Balance, June 30, 2023	$	1,679	$	9,382	$	11,061

Balance, December 31, 2022	Balance, December 31, 2022	$	1,679	$	9,000	$	10,679	Balance, December 31, 2022	$	1,679	$	9,000	$	10,679
Net income	Net income	—		249		249		Net income	—		482		482
Distribution to member	Distribution to member	—		(100)		(100)		Distribution to member	—		(100)		(100)

Balance, March 31, 2023		$	1,679	$	9,149	$	10,828
Balance, June 30, 2023								Balance, June 30, 2023	$	1,679	$	9,382	$	11,061