Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2018, and new regulatory matters occurring in 2019.

PacifiCorp

Retirement Plan Settlement Charge

During 2018, the PacifiCorp Retirement Plan incurred a settlement charge of $22 million as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018. In December 2018, PacifiCorp submitted filings with the UPSC, the OPUC, the WPSC and the WUTC seeking approval to ~~recover~~defer the settlement charge. Also in December 2018, an advice letter was filed with the CPUC requesting a memo account to ~~record~~track the costs associated with pension and postretirement settlements and curtailments. In April 2019, WUTC approved PacifiCorp's requested deferral. In May 2019, the UPSC denied PacifiCorp's request. In June 2019 and July 2019, PacifiCorp filed testimony with the WPSC and OPUC, respectively.

2017 Tax Reform

2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the United States federal corporate income tax rate from 35% to 21%. In 2018, PacifiCorp agreed to refund or defer the impact of the tax law change with each of its state regulatory commissions. The status of the remaining 2017 Tax Reform proceedings are noted in the applicable state section below.

Utah

In March 2018, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover $3 million, or 0.1%, in deferred net power costs from customers for the period January 1, 2017 through December 31, 2017, reflecting the difference between base and actual net power costs in the 2017 deferral period. The rate change was approved by the UPSC effective May 1, 2018 on an interim basis. A hearing was held in February 2019, and final approval was issued March 2019.

In March 2019, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover $24 million, or 1.1%, in deferred net power costs from customers for the period January 1, 2018 through December 31, 2018, reflecting the difference between base and actual net power costs in the 2018 deferral period. The rate change was approved by the UPSC effective May 1, 2019 on an interim ~~basis, and~~basis. Following a decision from the Utah Supreme Court in June 2019 that found the UPSC did not have authority to approve interim rates in conjunction with the EBA, the UPSC directed PacifiCorp to terminate the interim rate change pending final approval in the proceeding. The hearing on final approval is scheduled for February 2020.

In May 2019, Utah House Bill 411 went into effect. The legislation, among other things, authorizes the UPSC to approve a renewable energy program for communities seeking 100% renewable electricity. Participating cities must adopt a resolution with a goal to be on 100% renewable electricity by 2030 before December 31, 2019. Customers within a participating community may opt out of the program and maintain existing rates. Rates approved for the program may not result in any shift of costs or benefits to nonparticipating customers. Several communities in Utah, including Salt Lake City, have either recently set renewable goals or are actively considering them.

Oregon

In December 2018, PacifiCorp proposed to reduce customer rates to reflect the lower annual current income tax expense in Oregon resulting from 2017 Tax Reform. PacifiCorp reached an all-party settlement on the amortization of the current income tax expense benefits and the deferral of the decision regarding the ratemaking treatment of excess deferred income tax balances until no later than PacifiCorp's next general rate proceeding. The settlement, which results in a rate reduction of $48 million, or 3.7%, effective February 1, 2019, was approved by the OPUC in January 2019.

In December 2018, PacifiCorp filed anthe 2019 Renewable Adjustment Clause ("RAC") application requesting recovery of $37 million, or a 2.8% increase in rates, associated with repowering of approximately 900 MWs of company-owned and installed wind ~~facilities.~~facilities expected to be completed in 2019. In March 2019, the application was updated to request recovery of $32 million, or a 2.5% increase in rates. ~~A decision is expected from~~In August 2019, PacifiCorp filed an all-party settlement for the ~~OPUC~~2019 RAC. The settlement provides for an $11 million or 0.8% rate increase effective October 1, 2019, and a rate increase of $13 million or 1.0% effective December 1, 2019 for a total rate increase of $24 million or 1.8%. In addition parties agreed to use the excess deferred income tax balances not addressed in ~~September~~the 2017 Tax Reform proceeding to offset the majority of wind plant balances that will be retired as a result of repowering in 2019.

In April 2019, PacifiCorp submitted its annual TAM filing in Oregon requesting an annual decrease of $15 million, or an average price decrease of 1.2%, based on forecasted net power costs and loads for calendar year 2020. The filing includes the customer benefits of repowering, ~~resulting in~~including an increase in production tax ~~credits~~credits.

In May 2019, PacifiCorp filed an application for deferral of incremental costs associated with implementing wildfire mitigation measures in Oregon. Operations and ~~reduced power costs.~~maintenance costs associated with the implementation measures are estimated to be $5 million in 2019.

Wyoming

In April 2018, PacifiCorp filed a partial settlement related to the impact of 2017 Tax Reform with the WPSC that ~~provides~~provided a rate reduction of $23 million, or 3.3%, effective July 1, 2018 through June 30, 2019, with the remaining tax savings to be deferred with offsets to other costs. In June 2018, PacifiCorp filed reports with the WPSC with the calculation of the full impact of the tax law change on revenue requirement of $28 million annually, comprised of $20 million in current tax savings and $8 million for the amortization of excess deferred income ~~tax.~~tax balances. In March 2019, the WPSC issued a written order approving the continued annual rate reduction of $23 million until base rates are reset in the next general rate ~~proceeding. An additional~~proceeding and a $4 million ~~is currently being~~ offset ~~against~~to PacifiCorp's 2018 ECAM rates. The order reflected the $20 million of current tax savings and was updated to reflect a projection of $7 million for amortization of excess deferred income ~~tax.~~tax balances. In April 2019, PacifiCorp filed a new application updating the amount of benefits being returned to customers. PacifiCorp continued the interim rate reduction that includes the previously approved $23 million and an additional $4 million reduction to offset the 2019 ECAM, effective June 15, 2019.

In April 2019, PacifiCorp submitted a compliance filing to the WPSC regarding bonus tax depreciation resulting in a $2 million rate reduction for the period June 15, 2019 through June 14, 2020.

In February 2019, PacifiCorp filed a certificate of public convenience and necessity application with the WPSC requesting to repower the existing Foote Creek I wind facility, which was approved without conditions in April 2019. In connection with the repowering of Foote Creek, PacifiCorp acquired the joint owner's 21% interest in the facility in June 2019.

In April 2019, PacifiCorp filed its annual ECAM and RRA application with the WPSC. The filing requests approval to recover from customers $7 million, or approximately 1.0%, in deferred net power costs for the period January 1, 2018 through December 31, 2018. The rate change ~~will go~~went into effect on an interim basis June 15, 2019. PacifiCorp has proposed to offset this increase with other rate credits ~~proposed to go~~that went into effect on June 15, 2019.

In July 2019, ~~including~~Wyoming Senate Enrolled Act No. 74 went into effect. The legislation, among other things, requires electric utilities to make a good faith effort to sell a coal-fired generation facility in Wyoming before it can receive recovery in rates for capital costs associated with new generation facilities built, in whole or in part, to replace the ~~use~~retiring coal facility. The electric utility is obligated to purchase the electricity from the facility through a power purchase agreement at a price that is no greater than the utility’s avoided cost, as determined by the WPSC. Costs associated with an approved power purchase agreement are expected to be recoverable in rates from Wyoming customers. PacifiCorp is working with the WPSC and other stakeholders to determine the implementation process. The overall impacts of ~~deferred 2017 Tax Reform benefits.~~this legislation cannot be determined at this time.

Washington

In June 2019, PacifiCorp submitted its 2018 PCAM filing with WUTC seeking approval to credit $7 million to the PCAM balancing account. No rate changes were requested.

Idaho

In May 2018, the IPUC approved a rate reduction of $6 million, or 2.2%, effective June 1, 2018 through May 31, 2019, to pass back a portion of the current tax benefits associated with 2017 Tax Reform. In March 2019 an all-party settlement resolving the treatment of the remaining tax savings was filed with the IPUC. ~~Effective~~In May 2019, the IPUC approved the all-party settlement resulting in the rate reduction for current tax savings being adjusted to $8 million per year, effective June 1, 2019 ~~the rate reduction will be adjusted~~and $3 million related to ~~$7 million. Remaining~~amortization of excess deferred income taxes from the 2017 Tax Reform ~~benefits will be used~~being applied as an offset to ~~offset future rate increases.~~the 2019 ECAM.

In March 2019, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $15 million, or 0.4%, for deferred costs in 2018. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, recovery of Deer Creek Mine investment and changes in production tax credits and renewable energy credits. ~~Rates are proposed to go into effect~~In May 2019, the IPUC approved recovery of the $15 million, effective June 1, ~~2019.~~

2019 to be offset by the $3 million related to amortization of excess deferred income taxes stemming from the all-party settlement related to the 2017 Tax Reform.

California

In April 2018, PacifiCorp filed a general rate case with the CPUC for an overall rate increase of $1 million, or 0.9%, effective January 1, 2019. A CPUC decision is pending.

On September 21, 2018, California's governor signed legislation to strengthen California's ability to prevent and recover from catastrophic wildfires, including ~~Senate Bill 901 ("~~SB ~~901").~~901. SB 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp filed its wildfire mitigation plan with the CPUC on February 6, 2019. The wildfire mitigation plan incorporates the requirements outlined in SB 901, including situational awareness, system hardening, vegetation management and procedures for proactive de-energization in certain high risk areas during times of extreme danger. ~~A workshop was held February 13,~~

SB 901 also authorized utilities, including PacifiCorp, to establish two memorandum accounts to track costs related to California Wildfire Mitigation. In March 2019, ~~at which time~~ PacifiCorp ~~briefly described~~received approval to establish a FRMMA effective January 1, 2019 to track a range of fire risk mitigation activities incremental to what is already included in PacifiCorp's rates. The CPUC also granted PacifiCorp the ability to track costs related to complying with the implementation of Proactive Safety Power Shut-off, or de-energization events in the FRMMA.

In May 2019, the CPUC issued a decision approving PacifiCorp's 2019 Wildfire Mitigation Plan. In June 2019, following approval of its ~~wildfire mitigation plan as filed. Intervenors~~2019 Wildfire Mitigation Plan, PacifiCorp filed ~~comments~~to establish a second Wildfire Mitigation Plan Implementation Memorandum Account ("WMPIMA") effective May 31, 2019, to track costs related to the implementation of its approved 2019 Plan. Cost recovery is still contingent on the ~~wildfire mitigation plans on March 13, 2019 and~~CPUC's review of activities tracked in the ~~respondents filed reply comments on March 22, 2019. A proposed decision was released April 29, 2019 by~~memorandum accounts.

SB 901 also required the CPUC to develop a financial stress test methodology to determine the maximum amount an electrical corporation's shareholders can pay for 2017 catastrophic wildfire damages without harming ratepayers or impacting the utility's ability to provide adequate and safe service. The CPUC's final decision in June 2019 regarding this test does not have an impact on PacifiCorp as its assets did not cause catastrophic wildfires in California in 2017.

In July 2019, California Governor Gavin Newsom signed AB 1054 into law. AB 1054 is comprehensive legislation addressing wildfire risk in the state of California. The new law authorizes a wildfire fund which ~~will~~would operate as an insurance fund to support the creditworthiness of electrical utilities, if certain utilities participate by making the required contributions, among other things. PacifiCorp does not intend to participate in the wildfire fund.

AB 1054 also amends CPUC requirements for recovery of wildfire-related costs regardless of participation in the insurance fund. The CPUC must allow cost recovery of the costs and expenses of a "covered wildfire" which is defined as a fire ignited on or after July 12, 2019, if they are determined to be ~~considered for final action no sooner than May 30, 2019,~~just and ~~is subject to comments by parties of record~~reasonable, meaning the electrical corporation's conduct related to the ~~proceeding.~~ignition was consistent with actions that a reasonable utility would have undertaken in good faith under similar circumstances, at the relevant point in time, and based on the information available to the electrical corporation at the relevant point in time.

NV Energy (Nevada Power and Sierra Pacific)

Regulatory Rate Review

In June 2019, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $5 million but requested an annual revenue reduction of $5 million. An order is expected by the end of 2019 and, if approved, would be effective January 1, 2020.

In July 2019, as a part of the DEAA filing, the PUCN approved an order confirming the methodology of calculating the earnings sharing and directing Nevada Power, in its next regulatory rate review, to address the return of the earnings sharing to customers. The approved order is expected to be filed in August 2019.

2017 Tax Reform

In February 2018, the Nevada Utilities made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the rate reduction proposed by the Nevada Utilities. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing the Nevada Utilities to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, the Nevada Utilities filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, the Nevada Utilities filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review.

Optional Pricing Program

In November 2018, the Nevada Utilities made filings with the PUCN to implement the Optional Pricing Program ("OPP"). The Nevada Utilities have designed the OPP to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option that is based on renewable resources. The OPP provides for an energy rate that would replace the base tariff energy rate and deferred energy accounting adjustment. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings but plan to refile a modified tariff in August 2019 that incorporates the considerations raised by intervenors.

Chapter 704B Applications

Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one MW or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs. In June 2019, the Nevada Legislature passed Senate Bill 547 ("SB 547") which modifies the 704B process. The modifications outlined in SB 547, among others, require a utility to establish limits in their integrated resource plan on the amount of load that can take service under Chapter 704B, customers taking service under Chapter 704B continue to pay for public program costs and requires the alternative energy providers to be licensed by the PUCN. In addition, SB 547 requires customers to file a 704B application with the PUCN in January allowing for alignment with the capacity amount established in the integrated resource plan.

Since 2016, five fully bundled retail customers have transitioned to distribution only service and are acquiring energy from an energy supplier other than the Nevada Utilities. The total estimated peak demand of these customers was approximately 400 MWs, as of the date their applications were filed with the PUCN, which represents approximately 5% of the annual hourly peak demand on the Nevada ~~Utilities’~~Utilities' electric system in 2018. The PUCN has imposed cumulative impact fees of $155 million on these customers which includes impact fee credits of $20 million established by the PUCN subsequent to the initial application approvals.

~~As of April 2019, the~~The Nevada Utilities have ~~an estimated 122~~approximately 120 fully bundled retail customers that are eligible to file Chapter 704B applications. The PUCN has approved the applications of ~~three~~five additional fully bundled retail customers whose total estimated peak demand is approximately 5595 MWs, as of the date their applications were filed with the PUCN. The PUCN has imposed impact fees of ~~$18~~$30 million on these customers. Subsequent to approval, ~~one customer~~two customers with ana total estimated peak demand of 5approximately 50 MWs and imposed impact fees of $2$17 million ~~has~~have withdrawn their ~~application.~~applications leaving only three fully bundled customer applications open and approved. The PUCN has also approved the applications of ~~three~~four pending customers not yet receiving service. These ~~five~~seven customers have not yet become distribution only service customers.

As of ~~April~~June 2019, in addition to the approved 704B applications, the Nevada Utilities have also received communications from ~~eleven~~eight additional fully bundled or pending customers, three of which provided a letter of intent to file an application with the PUCN and ~~eight~~five of which filed an application with the PUCN to purchase energy from another energy supplier and become distribution only service customers. ~~One applicant has~~Four applicants have subsequently withdrawn their ~~application.~~applications leaving only one 704B application in process. The three letters of intent are no longer eligible to pursue 704B applications under the previous process due to the passing of SB 547.

The Nevada Utilities are addressing further Chapter 704B activity by evaluating options that include aligning with customer initiatives, implementing alternative pricing plans ~~such as~~including the OPP, educating current customers on the value of the Nevada Utilities' fully bundled service and evaluating legislative or administrative changes to the Chapter 704B process ~~and participating in current and future Chapter 704B proceedings.~~as a result of SB 547.

Northern Powergrid Distribution Companies

GEMA, through the Ofgem, published its RIIO-2 sector methodology consultation in December 2018, continuing the process of developing the next set of price control arrangements that will be implemented for transmission and gas distribution networks in Great Britain. Ofgem explicitly states that this consultation does not set out proposals for Northern Powergrid's next price control, which will begin in April 2023. However, it also states that some of the proposals may be capable of application to that price control. Regarding allowed return on capital, Ofgem ~~has~~ stated in the December 2018 consultation that it ~~currently considers that~~considered a cost of equity of 4.0% (plus inflation calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs) would be appropriate for energy networks, which is approximately 2.5 percentage points lower than the current comparable cost of equity. This cost of equity assumption is based on a proposed debt capitalization assumption for the next price control of 60%, which is five percentage points lower than the 65% debt capitalization assumption for the current price control.

In May 2019, Ofgem published its sector methodology decision for the RIIO-2 price controls that will apply to transmission and gas distribution starting in April 2021. The ~~next significant milestone~~decision confirmed a continued intention to move to lower returns, although Ofgem increased its initial view on the cost of equity of 4.0% to 4.3%. The transmission and gas distribution price control reviews are now moving into a detailed implementation phase, with draft and final determinations due in the ~~process will be Ofgem's decision on the methodology, due in May 2019, followed by an initial consultation~~summer and fall of 2020. Early discussions are now taking place for the next electricity distribution price control review, which is due to set price controls from April 2023 following determinations in ~~late 2019.~~2022.

BHE Pipeline Group

Northern Natural Gas

In July 2018, the FERC issued a final rule adopting procedures for determining whether natural gas pipelines were collecting unjust and unreasonable rates in light of the reduction in the federal corporate tax rate from 2017 Tax Reform. Pursuant to the final rule, in October 2018, Northern Natural Gas filed an informational filing on FERC Form No. 501-G and a Statement Demonstrating Why No Rate Adjustment is Necessary. OnIn January ~~16,~~ 2019, FERC initiated a Section 5 investigation to determine whether the rates currently charged by Northern Natural Gas are just and reasonable. As required by the FERC Section 5 order, Northern Natural Gas filed a full cost and revenue study on April 1, 2019. On July 1, 2019, Northern Natural Gas ~~expects to file~~filed a ~~general~~ Section 4 rate ~~case, as soon as July 1, 2019, which would supersede a Section 5 rate action to address Northern Natural Gas' significant investment.~~case. Northern Natural Gas ~~believes~~has requested increases in various rates, including transportation reservation rates ranging from approximately 35% in the Field Area to 90% in the Market Area to be implemented, subject to refund, effective January 1, 2020. The Section 5 investigation remains pending as a ~~rate increase will result~~separate case from the Section 4 rate case, ~~and higher rates would~~although the cases may be ~~implemented subject to refund~~consolidated in ~~early 2020.~~the future.

BHE Transmission

AltaLink

General Tariff Application

In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat for customers for the next five years. The three-year application achieves flat tariffs by keeping operating and maintenance expenses flat, with the exception of salaries and wages and software licensing fees, transitioning to a new salvage recovery approach and continuing the use of the flow-through income tax method. In addition, similar to the refund approved by the AUC for the 2017-2018 GTA of C$31 million, AltaLink proposes to provide a further tariff reduction over the three years by refunding previously collected accumulated depreciation surplus of an additional C$31 million.

In November 2018, the AUC approved the 2019 interim refundable transmission tariff at C$74 million per month effective January 2019.

AltaLink provided responses to information requests in November 2018 and additional responses in December 2018 and April 2019. In April 2019, AltaLink filed an update to its 2019-2021 GTA application primarily to reflect its 2018 actual results and the impact of the AUC decision on AltaLink's 2014-2015 deferral account reconciliation application. The application update also included AltaLink's fire mitigation plan and a request for additional capital expenditures and operating expenses to enhance its current practices, operations and maintenance program to reduce the risk of fires being ignited by its transmission ~~system operation caused fire ignition.~~system. The ~~updated~~ application requests the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021 respectively, which are lower than the approved 2018 revenue requirement of C$904 million. The forecast revenue requirement is based on an 8.5% return on equity and 37% deemed equity approved by the AUC for 2019 and 2020 and assumes the same for 2021 as placeholders.

In ~~November 2018,~~July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions from the April 2019 GTA of C$23 million of operating expenses and C$58 million of transmission capital maintenance and information technology capital expenditures over three years, as well as lower forecast interest rates and lower depreciation for the steel poles asset class. These reductions resulted in a C$38 million, or 1.4%, net decrease to the three-year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019 before taking into account an additional C$20 million of forecast line clearance capital. The application excluded certain matters consisting of the new salvage study and salvage recovery approach, additional capital for operations and maintenance and capital programs to reduce risk of fires being ignited by its transmission system, and to comply with line clearance code compliance requirements, and certain retirements for towers and fixtures. Excluded matters will be examined by the AUC in an oral hearing scheduled for September 2019. The negotiated settlement application requests the approval of revised revenue requirements of C$873 million, C$870 million and C$870 million for 2019, 2020 and 2021, respectively, which are lower than the approved ~~the 2019 interim refundable transmission tariff at~~2018 revenue requirement of C$~~74.0 million per month effective January 2019.~~904 million.

2021 Generic Cost of Capital Proceeding

In December 2018, the AUC initiated a Generic Cost of Capital ("GCOC") proceeding to consider returning to a formula-based approach to determining the return on equity for a given year, starting with 2021. On April 4, 2019, after receiving comments from interested parties, the AUC expanded the scope of the proceeding to include a traditional non-formulaic GCOC inquiry as well as the consideration of returning to a formula-based approach. The AUC also issued a process timeline for the proceeding to commence in January 2020, with a hearing scheduled in April 2020.

Deferral Account Reconciliation Application

In April 2017, AltaLink filed its application with the AUC with respect to AltaLink's 2014 projects and deferral accounts and specific 2015 projects. The application included approximately C$2.0 billion in net capital additions. In June 2017, the AUC ruled that the scope of the deferral account proceeding would not be extended to consider the utilization of assets for which final cost approval is sought. However, the AUC will initiate a separate proceeding to address the issue of transmission asset utilization and how the corporate and property law principles applied in the Utility Asset Disposition ("UAD") decision may relate.

In December 2017, AltaLink amended its application to include the remaining capital projects completed in 2015. The amended 2014 and 2015 deferral account reconciliation application includes 110 completed projects with total gross capital additions, excluding AFUDC, of C$3.8 billion. An oral hearing was held in September 2018 after the completion of an extensive information request process earlier in the year.

In December 2018 and January 2019 the AUC issued decisions approving C$3,833 million out of the C$4,017 million capital project additions, including AFUDC, included in the application. Project costs of C$155 million were deferred to a future hearing. The AUC disallowed capital additions of approximately C$30 million including applicable AFUDC, pending receipt of additional requested supporting documentation for certain specific items. In February 2019, AltaLink filed its 2014-2015 deferral accounts reconciliation application compliance filing to reflect the findings, conclusions and directions arising from this decision. In its compliance filing, AltaLink requested approval of interest in the amount of C$10 million on total outstanding amount of C$110 million to be recovered through a one-time payment from the AESO, upon AUC approval. In addition, the AUC ruled that it will put in placeholder amounts for the approved costs of the assets in the 2014-2015 DACDA proceeding until the AUC-initiated proceeding to consider the issue of transmission asset utilization.

In March 2019, AltaLink responded to information requests from the AUC. A decision from the AUC is expected in the ~~second~~third quarter of 2019.

In July 2019, AltaLink filed its 2016-2018 DACDA application with the AUC after a ruling on confidentiality. The application includes 116 projects with total actual gross capital additions, excluding AFUDC, of C$947 million.

First Nations Asset Transfer Application

In November 2018, the AUC approved, with conditions, AltaLink's application filed in April 2017 to sell and transfer approximately C$91 million of transmission assets located on reserve lands to new limited partnerships with First Nations. The transfers are part of the agreement which allowed AltaLink to route the Southwest Project on reserve land.

In December 2018, AltaLink filed an application with the Alberta Court of Appeal for permission to appeal the conditions imposed by the AUC decision. In January 2019, AltaLink also filed an application for review and variance with the AUC. In May 2019, the AUC issued a decision dismissing the application for review and variance on the basis that AltaLink had not met the requirements for a review of the findings in the original decision. The appeal on this matter is set for October 2019.

In March 2019, AltaLink filed correspondence informing the AUC that the Blood Tribe intends to proceed with the transfer of assets related to KainaiLink, L.P.

In June 2019, AltaLink closed the transaction with the Piikani Nation by transferring transmission assets of C$53 million and long-term debt of C$33 million to PiikaniLink, L.P. The Piikani Nation purchased a 51% interest in PiikaniLink, L.P. for C$10 million.

BHE Renewables' Counterparty Risk

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California ("PG&E Bankruptcy Filing"). The Company owns 100% of Topaz and owns a 49% interest in Agua Caliente. Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale power purchase agreement ("PPA") that is in effect until October 2039. As of ~~March 31,~~June 30, 2019, the Company's consolidated balance sheet includes $1.1 billion of property, plant and equipment, net and $0.9 billion of non-recourse project debt related to Topaz. Agua Caliente is a 290-MW solar photovoltaic electric power generating facility located in Arizona. Agua Caliente sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until June 2039. As of ~~March 31,~~June 30, 2019, the Company's equity investment in Agua Caliente totals ~~$47~~$56 million and the project has $0.8 billion of non-recourse project debt owed to the United States Department of Energy. The PG&E Bankruptcy Filing is an event of default under the Topaz PPA ("PPA Default"). PG&E paid in full the invoices for December deliveries and all amounts invoiced to date for post-petition energy deliveries for both Topaz and Agua Caliente in 2019. PG&E has not paid for the power delivered from January 1 through January 28, 2019. The Company continues to perform on its obligations and deliver renewable energy to the PG&E Utility, and PG&E has publicly stated it will pay suppliers in full under normal terms for post-petition goods and services received. The Company maintains that, in light of the current facts and circumstances, the PPA Default could not reasonably be expected to result in a material adverse effect under the Topaz indenture and, therefore, no default has occurred under the Topaz indenture. In July 2019, California Governor Gavin Newsom signed AB 1054 into law. AB 1054 is comprehensive legislation addressing wildfire risk in the state of California that, among other items, authorizes a wildfire fund which would operate as an insurance fund to support the creditworthiness of electrical utilities, if certain utilities, including PG&E, participate by making the required contributions, among other things. In July 2019, PG&E notified the CPUC of its intent to participate in the insurance fund and such participation requires, among other items, PG&E to exit bankruptcy by June 30, 2020. The Company believes it is more likely than not that no impairment exists and current debt obligations will be met, as post-petition contractual revenue payments are expected to be paid by PG&E Utility to the Topaz and Agua Caliente projects. The Company will continue to monitor the situation, including continued receipt of future PG&E payments and the future risk of the PPAs being rejected or modified through the bankruptcy process.

Quad Cities Generating Station Operating Status

Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018, as a result of Illinois not passing adequate legislation and Quad Cities Station not clearing the 2019-2020 PJM Interconnection, L.L.C. capacity auction. MidAmerican Energy expressed to Exelon Generation its desire for the continued operation of the facility through the end of its operating license in 2032 and worked with Exelon Generation on solutions to that end. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission credits will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. For the nuclear assets already in rate base, MidAmerican Energy's customers will not be charged for the subsidy, and MidAmerican Energy will not receive additional revenue from the subsidy.

On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of Illinois ("Northern District of Illinois") against the Illinois Power Agency alleging that the state's zero emission credit program violates certain provisions of the United States Constitution. Both lawsuits were dismissed at the Northern District of Illinois, and the United States Court of Appeals for the Seventh Circuit affirmed the dismissals. On April 15, 2019, plaintiffs' petition seeking United States Supreme Court review of the case was denied.

On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Offer Price Rule ("MOPR") provisions to apply to existing resources receiving zero emission credit compensation. If successful, an expanded MOPR could result in an increased risk of Quad Cities Station not clearing in future capacity auctions and Exelon Generation no longer receiving capacity revenues for the facility. As majority owner and operator of Quad Cities Station, Exelon Generation has filed protests at the FERC in response to each filing. The FERC has not yet issued a decision on the requests.

On April 10, 2019, PJM Interconnection, L.L.C. ("PJM") notified the FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked the FERC to clarify that it would not require the PJM to re-run the auction in the event the FERC alters those market rules in its decision on the MOPR complaint. It is too early to predict the final outcome of each of these proceedings or their potential impact on the continued operation of Quad Cities Station.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2018, and new environmental matters occurring in 2019.

Climate Change

In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce greenhouse gas emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global greenhouse gas emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. Under the terms of the Paris Agreement, ratifying countries are bound for a three-year period and must provide one-year's notice of their intent to withdraw. On June 1, 2017, President Trump announced the United States would withdraw from the Paris Agreement. Under the terms of the agreement, the withdrawal would be effective in November 2020. The cornerstone of the United States' commitment was the Clean Power Plan which was finalized by the EPA in 2015 but has since been proposed for repeal by the EPA.

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fueled with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. The EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. The EPA accepted comment on the proposal through March 18, 2019. Until such time as the EPA undertakes further action on the proposed reconsideration or the court takes action, any new fossil-fueled generating facilities constructed by the relevant Registrants will be required to meet the GHG new source performance standards.

Clean Power Plan

In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The compliance period would have begun in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030 and was expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. On February 9, 2016, the United States Supreme Court ordered that the EPA's emission guidelines for existing sources be stayed pending the disposition of the challenges to the rule in the D.C. Circuit and any action on a writ of certiorari before the United States Supreme Court. Oral argument was heard before the D.C. Circuit on September 27, 2016. The court has not yet issued its decision. On June 19, 2019, the EPA finalized the Affordable Clean Energy rule and fully repealed the Clean Power Plan. Under the Affordable Clean Energy rule, the EPA determined that the best system of emissions reduction for existing coal-fueled power plants is heat rate improvements based on a set of candidate technologies and measures that could improve heat rates. The EPA did not establish state emission limits or budgets. Instead, states will be required to develop unit-specific standards of performance that reflect the emission limitation achievable through application of the best system of emission reduction technologies. Measures taken to meet the standards of performance must be achieved at the source itself and standards of performance will be measured in terms of pounds of carbon dioxide per MWh. State compliance plans are due by September 2022, three years after the effective date of the rule. Litigation challenging the rule has already been filed in the D.C. Circuit and until all litigation is exhausted and state plans are developed, the full impacts on the Registrants cannot be determined. However, PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advanced customer energy efficiency programs.

Renewable Portfolio Standards

Each state's RPS described below could significantly impact the relevant Registrant's consolidated financial results. Resources that meet the qualifying electricity requirements under each RPS vary from state to state. Each state's RPS requires some form of compliance reporting and the relevant Registrant can be subject to penalties in the event of noncompliance. Each Registrant believes it is in material compliance with all applicable RPS laws and regulations.

Since 1997, NV Energy has been required to comply with a RPS. Current law requires the Nevada Utilities to meet 18% of their energy requirements with renewable resources for 2014, 20% for 2015 through 2019, 22% for 2020 and 2024, and 25% for 2025 and thereafter. The RPS also requires 5% of the portfolio requirement come from solar resources through 2015 and increasing to 6% in 2016. Nevada law also permits energy efficiency measures to be used to satisfy a portion of the RPS through 2025, subject to certain limitations. In November 2018, Nevada voters approved a measure to increase the state's RPS to 50% by 2030; the measure must be voted on and approved a second time, in November 2020, in order to take effect. In the interim, the Nevada Legislature passed Senate Bill ("SB") 358 in June 2019 which raises Nevada's renewable portfolio standards to 50% by 2030.

Washington's Energy Independence Act establishes a renewable energy target for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020 and each year thereafter. In April 2013, Washington State Senate Bill No. 5400 ("SB 5400") was signed into law. SB 5400 expands the geographic area in which eligible renewable resources may be located to beyond the Pacific Northwest, allowing renewable resources located in all states served by PacifiCorp to qualify. SB 5400 also provides PacifiCorp with additional flexibility and options to meet Washington's renewable mandates. In May 2019, the state of Washington enacted Senate Bill 5116, the Clean Energy Transformation Act. The legislation, among other things, establishes three targets for reducing and eventually eliminating fossil-fueled generation from Washington retail electricity rates between 2025 and 2045. The coal phase-out standard requires all electric utilities to eliminate from rates, coal-fired resources by December 31, 2025. PacifiCorp has begun discussions with regulators and other Washington investor-owned utilities regarding compliance obligations and implementation.

Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Registrants' operations are described below.

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 to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.

MidAmerican Energy retired certain coal-fueled generating units as the least-cost alternative to comply with the MATS. Walter Scott, Jr. Energy Center Units 1 and 2 were retired in 2015, and George Neal Energy Center Units 1 and 2 were retired in April 2016. A fifth unit, Riverside Generating Station, was limited to natural gas combustion in March 2015.

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 United States 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. Oral argument in the case was held before the United States Supreme Court in March 2015, and a decision was issued by the United States Supreme Court in June 2015, which reversed and remanded the MATS rule to the D.C. Circuit for further action. The United States Supreme Court held 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. The United States Supreme Court's decision did not vacate or stay implementation of the MATS rule. In December 2015, the D.C. Circuit issued an order remanding the rule to the EPA, without vacating the rule. As a result, the relevant Registrants continue to have a legal obligation under the MATS rule and the respective permits issued by the states in which each respective Registrant operates to comply with the MATS rule, including operating all emissions controls or otherwise complying with the MATS requirements.

On December 27, 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. EPA proposes to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112; however, EPA proposes to retain the emission standards and other requirements of the MATS rule, because EPA is not proposing to remove coal- and oil-fueled power plants from the list of sources regulated under Section 112. The public comment period on the proposal closed April 17, 2019. Until EPA takes final action on the rule, the relevant Registrants cannot fully determine the impacts of the proposed changes to the MATS rule.

Regional Haze

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

The state of Utah issued a regional haze SIP requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to nitrogen oxides controls and require the installation of selective catalytic reduction ("SCR") controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the ~~CAMX~~Comprehensive Air Quality Model with Extensions ("CAMX") air quality dispersion model. On ~~January 14,~~June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze state implementation plan revision, which incorporates a best available retrofit technology alternative into Utah's regional haze state implementation plan. The best available retrofit technology alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the state implementation plan and removes the requirement to install selective catalytic reduction technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah ~~submitted a SIP~~Division of Air Quality anticipates submitting the state implementation plan revision to the EPA ~~which includes the updated modeling information and additional analysis.~~for approval in July 2019.

The state of Wyoming issued two regional haze SIPs requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the sulfur dioxide SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the nitrogen oxides and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the nitrogen oxides and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-nitrogen oxides 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-nitrogen oxides 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 ("Wyodak Facility"), requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on the Wyodak Facility in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for the Wyodak Facility, pending further action by the Tenth Circuit in the appeal. A stay remains in place and the case has not yet been set for oral argument. In June 2014, the Wyoming Department of Environmental Quality issued a revised BART permit allowing Naughton Unit 3 to operate on coal through 2017 and providing for natural gas conversion of the unit in 2018; in October 2016, an application was filed with the Wyoming Department of Environmental Quality requesting a revision of the dates for the end of coal firing and the start of gas firing for Naughton Unit 3 to align with the requirements of the Wyoming SIP. The Wyoming Department of Environmental Quality approved a change to the requirements for Naughton Unit 3, extending the requirement to cease coal firing to no later than January 30, 2019, and complete the gas conversion by June 30, 2019. On March 17, 2017, Wyoming Department of Environmental Quality issued an extension to operate the unit as a coal-fueled unit through January 30, 2019. The Wyoming Department of Environmental Quality submitted a proposed revision to the Wyoming SIP, including a change to the Naughton Unit 3 compliance date, to the EPA for approval on November 28, 2017. On November 7, 2018, the EPA published its proposed approval of the Wyoming SIP relative to the Naughton 3 gas conversion. The comment period closed December 7, 2018 and the EPA has not taken final action. PacifiCorp removed the unit from coal-fueled service on January 30, 2019, and is evaluating the economic benefits of converting it to a natural gas-fueled generation resource. On February 5, 2019, PacifiCorp submitted a reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of selective catalytic reduction, to be replaced with a permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. The proposal ~~will~~is expected to be open for public comment ~~May 31, 2019 through June 30,~~in August 2019, and the state of Wyoming ~~will~~plans to hold a public ~~hearings~~hearing on ~~July 1,~~August 20, 2019 to consider the proposal and public input.

The state of Arizona issued a regional haze SIP requiring, among other things, the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions requiring SCR controls on Cholla Unit 4. PacifiCorp filed an appeal in the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it relates to their interests. The Ninth Circuit issued an order in February 2015, holding the matter in abeyance while the parties pursued an alternate compliance approach for Cholla Unit 4. The Arizona Department of Environmental Quality's revision of the draft permit and revision to the Arizona regional haze SIP were approved by the EPA through final action published in the Federal Register on March 27, 2017, with an effective date of April 26, 2017. The final action allows Cholla Unit 4 to utilize coal until April 30, 2025 and convert to gas or otherwise cease burning coal by June 30, 2025.

The state of Colorado regional haze SIP requires SCR controls at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are either already in service or currently being constructed. 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. The terms of the agreement were incorporated into an amended Colorado regional haze SIP in 2017 and were submitted to the EPA for its review and approval. The EPA's approval of the amended Colorado regional haze SIP was published in the Federal Register on July 5, 2018, with an effective date of August 6, 2018.

Until the EPA takes final action in each state and decisions have been made in the pending appeals, PacifiCorp cannot fully determine the impacts of the Regional Haze Rule on its respective generating facilities.

The Navajo Generating Station, in which Nevada Power is a joint owner with an 11.3% ownership share, is also a source that is subject to the regional haze BART requirements. In January 2013, the EPA announced a proposed FIP addressing BART and an alternative for the Navajo Generating Station that includes a flexible timeline for reducing nitrogen oxides emissions. The EPA issued a final FIP on August 8, 2014 adopting, with limited changes, the Navajo Generating Station proposal as a "better than BART" determination. Nevada Power filed the ERCR Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019, which was approved by the PUCN. In February 2017, the non-federal owners of the Navajo Generating Station announced the facility will shut down on or before December 23, 2019, unless new owners can be found. All current owners have since approved a lease extension with the Navajo Nation to allow operations to continue through 2019. On March 21, 2019, the Navajo Nation Council voted to end efforts to transition ownership and extend facility operations. The plant will cease operations by the end of 2019. Ownership transfer negotiations and closure preparations are ongoing and, until concluded, the relevant Registrant cannot determine whether additional action may be required.

Water Quality Standards

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The final rule was released in May 2014, and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the United States must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when organisms are drawn into the facility). PacifiCorp and MidAmerican Energy are assessing the options for compliance at their generating facilities impacted by the final rule and will complete impingement and entrainment studies. PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than 125 million gallons per day of water from waters of the United States for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter and Huntington generating facilities currently utilize closed cycle cooling towers but are designed to withdraw more than two million gallons of water per day. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. The costs of compliance with the cooling water intake structure rule cannot be fully determined until the prescribed studies are conducted and the respective state environmental agencies review the studies to determine whether additional mitigation technologies should be applied. In the event that PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant to the consolidated financial statements. Nevada Power and Sierra Pacific do not utilize once-through cooling water intake or discharge structures at any of their generating facilities. All of the Nevada Power and Sierra Pacific generating stations are designed to have either minimal or zero discharge; therefore, they are not impacted by the §316(b) final rule.

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. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions has changed the effluent discharged from coal- and natural gas-fueled generating facilities. Under the originally-promulgated guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal with the new limits to be met as soon as possible, beginning November 1, 2018 and fully implemented by December 31, 2023. On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with the EPA. The EPA granted the request for reconsideration on April 12, 2017, imposed an immediate administrative stay of compliance dates in the rule that had not passed judicial review and requested the court stay the pending litigation over the rule until September 12, 2017. On June 6, 2017, the EPA proposed to extend many of the compliance deadlines that would otherwise occur in 2018 and on September 18, 2017, the EPA issued a final rule extending certain compliance dates for flue gas desulfurization wastewater and bottom ash transport water limits until November 1, 2020. In a separate action, on April 12, 2019, the Fifth Circuit Court of Appeal vacated two aspects of the final effluent limitation guidelines, concerning discharge limits for (1) legacy wastewater from ash transport or treatment systems and (2) combustion residual leachate from landfills or settling ponds. The Firth Circuit found that EPA's own data did not support the agency's conclusion that impoundments were the best technology available for these two waste streams. EPA must now complete a new effluent limitation guideline for these discharge limits. While most of the issues raised by effluent limitation guidelines are already being addressed through the coal combustion residuals rule and are not expected to impose significant additional requirements on the facilities, the impact of the rule cannot be fully determined until the reconsideration and remand actions are complete and any judicial review is conducted.

In April 2014, the EPA and the United States Army Corps of Engineers issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but is currently under appeal in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. The EPA plans to undertake a two-step process, with the first step to repeal the 2015 rule and the second step to carry out a notice-and-comment rulemaking in which a substantive re-evaluation of the definition of the "waters of the United States" will be undertaken. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule and on November 16, 2017, the agencies proposed to extend the implementation day of the "waters of the United States" rule to 2020; neither of the proposals has been finalized. On January 22, 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extension of the compliance deadline. On December 11, 2018, the EPA and the Corps of Engineers proposed a revised definition of "waters of the United States" that is intended further clarify jurisdictional questions, eliminate case-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in Rapanos v. United States. The public comment period closed April 15, 2019. Until the rule is fully litigated and finalized, the Registrants cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs or increased requirements for compensatory mitigation.

Coal Combustion Byproduct Disposal

In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts under the RCRA. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and was effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of coal combustion residuals. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. The final rule requires regulated entities to post annual groundwater monitoring and corrective action reports. The first of these reports was posted to the respective Registrant's coal combustion rule compliance data and information websites in March 2018. Based on the results in those reports, additional action may be required under the rule.

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 Station 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 ten 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. Refer to Note 13 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of ~~this~~the Form 10-K and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of ~~this~~the Form 10-K for ~~discussion of~~ the impacts on asset retirement obligations as a result of the final rule.

Additional substantive revisions to the rule are expected to be finalized by the EPA by December 2019 but have not yet been released for public comment. If adopted, certain elements of the proposal have the potential to reduce costs of compliance. The D.C. Circuit issued a decision on August 21, 2018, vacating several elements of the rule, including closure provisions for unlined surface impoundments, and finding that the Resource Conservation and Recovery Act provides the EPA authority to regulate inactive surface impoundments at inactive facilities. The court's order was effective October 15, 2018, and as a result, the EPA will need to undertake additional rulemaking to implement the court's order. Until such time as additional rulemaking is final, the impacts on the Registrants cannot be determined.

Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit in 2015, resulting in settlement of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive surface impoundments to regulation. Oral argument was held by the D.C. Circuit on November 20, 2017 over certain portions of the 2015 rule that had not been settled or otherwise remanded. On August 21, 2018, the D.C. Circuit issued its opinion in Utility Solid Waste Activities Group v. EPA, finding it was arbitrary and capricious for EPA to allow unlined ash ponds to continue operating until some unknown point in the future when groundwater contamination could be detected. The D.C. Circuit vacated the closure section of the CCR rule and remanded the issue of unlined ponds to EPA for reconsideration with specific instructions to consider harm to the environment, not just to human health. The D.C. Circuit also held EPA's decision to not regulate legacy ponds was arbitrary and capricious. While the D.C. Circuit's decision was pending, the EPA, on March 15, 2018, issued a proposal to address provisions of the final coal combustion rule that were remanded back to the agency on June 14, 2016, by the D.C. Circuit. The proposal included provisions that establish alternative performance standards for owners and operators of coal combustion residuals units located in states that have approved permit programs or are otherwise subject to oversight through a permit program administered by the EPA. The EPA published the first phase of the coal combustion rule amendments on July 30, 2018, with an effective date of August 28, 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, 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 EPA's request to remand the rule, without vacatur, leaving the October 31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. Until the rule is fully litigated and finalized, the Registrants cannot determine whether additional action may be required.

Separately, on August 10, 2017, the EPA issued proposed permitting guidance on how states' coal combustion residuals permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. Utilizing that guidance, the state of Oklahoma submitted an application to the EPA for approval of its state program and, on June 28, 2018, the EPA's approval of the application was published in the Federal Register. Environmental groups, including Waterkeeper Alliance and the Sierra Club, filed suit in the United States District Court for the District of Columbia on September 26, 2018, alleging that the EPA unlawfully approved Oklahoma's permit program. This suit also incorporates claims first identified in a July 26, 2018 notice of intent to sue that alleged the EPA failed to perform nondiscretionary duties related to the development and publication of minimum guidelines for public participation in the approval of state permit programs for coal combustion residuals. To date, none of the states in which the Registrants operate has submitted an application for approval of state permitting authority. The state of Utah adopted the federal final rule in September 2016, which required two landfills to submit permit applications by March 2017. It is anticipated that the state of Utah will submit an application for approval of its coal combustion residuals permit program prior to the end of 2019.

Notwithstanding the status of the final coal combustion residuals 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 coal combustion residuals 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, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2018. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2018.

PacifiCorp and its subsidiaries

Consolidated Financial Section

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of ~~March 31,~~June 30, 2019, the related consolidated statements of operations and changes in shareholders' equity for the three-month and six-month periods ended June 30, 2019 and 2018, and of cash flows for the ~~three-month~~six-month periods ended ~~March 31,~~June 30, 2019 and 2018, 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, 2018, 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 22, 2019, 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, 2018, 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 3,~~August 2, 2019

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	March 31,		December 31,		June 30,		December 31,
	2019		2018		2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	669	$	77	$	536	$	77
Trade receivables, net	591		640		606		640
Other receivables, net	114		92		76		92
Inventories	406		417		440		417
Other current assets	152		133		139		133
Total current assets	1,932		1,359		1,797		1,359

Property, plant and equipment, net	19,698		19,570		20,156		19,570
Regulatory assets	1,090		1,076		1,083		1,076
Other assets	329		308		330		308

Total assets	$	23,049	$	22,313	$	23,366	$	22,313

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2018. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2018.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2018. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2018. Refer to Note 8 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of ~~March 31,~~June 30, 2019.


Item 4.	Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended ~~March 31,~~June 30, 2019 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PART II


Item 1.	Legal Proceedings

Not applicable.


Item 1A.	Risk Factors

There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2018.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.


Item 3.	Defaults Upon Senior Securities

Not applicable.


Item 4.	Mine Safety Disclosures

Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.


Item 5.	Other Information

Not applicable.


Item 6.	Exhibits

The following is a list of exhibits filed as part of this Quarterly Report.


Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY


4.1	Trust Deed, dated as of May 24, 2019, among Northern Electric Finance plc, as issuer, Northern Powergrid (Northeast) Limited, as Guarantor, and HSBC Corporate Trustee Company (UK) Limited, as Trustee, relating to the £150,000,000 in aggregate principal amount of 2.75% Guaranteed Bonds due 2049.


4.2	Amendment No. 1 to the Fiscal Agency Agreement, dated as of July 17, 2018, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to an additional $200,000,000 in principal amount of the 4.30% Senior Bonds due 2049.


10.1	$3,500,000,000 Amended and Restated Credit Agreement, dated as of May 31, 2019, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Union Bank, N.A, as Administrative Agent and the LC Issuing Banks.


15.1	Awareness Letter of Independent Registered Public Accounting Firm.


31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

PACIFICORP


15.2	Awareness Letter of Independent Registered Public Accounting Firm.


31.3	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


31.4	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.3	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


32.4	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP


~~4.1~~4.3	Thirtieth Supplemental Indenture, dated as of March 1, 2019, to PacifiCorp's Mortgage and Deed of Trust dated as of January 9, 1989 (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated March 1, 2019).


10.2	$600,000,000 Amended and Restated Credit Agreement, dated as of May 31, 2019, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent, and the LC Issuing Banks.


10.3	$600,000,000 Amended and Restated Credit Agreement, dated as of May 31, 2019, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent, and the LC Issuing Banks.


95	Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

MIDAMERICAN ENERGY


15.3	Awareness Letter of Independent Registered Public Accounting Firm.


31.5	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


31.6	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.5	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


32.6	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY


10.4	$900,000,000 Amended and Restated Credit Agreement, dated as of May 31, 2019, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Mizuho Bank, Ltd., as Administrative Agent and the LC Issuing Banks.

MIDAMERICAN FUNDING


31.7	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


31.8	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.7	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


32.8	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

NEVADA POWER


15.4	Awareness Letter of Independent Registered Public Accounting Firm.


31.9	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


31.10	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.9	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


32.10	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER


~~Exhibit No.~~10.5	~~Description~~ $400,000,000 Third Amended and Restated Credit Agreement, dated as of May 31, 2019, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.

SIERRA PACIFIC


31.11	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


31.12	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.11	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


32.12	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC


10.6	$250,000,000 Third Amended and Restated Credit Agreement, dated as of May 31, 2019, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks.

ALL REGISTRANTS

101

The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended ~~March 31,~~June 30, 2019, is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	BERKSHIRE HATHAWAY ENERGY COMPANY

Date: ~~May 3,~~August 2, 2019	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Executive Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	PACIFICORP

Date: ~~May 3,~~August 2, 2019	/s/ Nikki L. Kobliha
	Nikki L. Kobliha
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)

	MIDAMERICAN FUNDING, LLC
	MIDAMERICAN ENERGY COMPANY

Date: ~~May 3,~~August 2, 2019	/s/ Thomas B. Specketer
	Thomas B. Specketer
	Vice President and Controller
	of MidAmerican Funding, LLC and
	Vice President and Chief Financial Officer
	of MidAmerican Energy Company
	(principal financial and accounting officer)

	NEVADA POWER COMPANY

Date: ~~May 3,~~August 2, 2019	/s/ Michael E. Cole
	Michael E. Cole
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	SIERRA PACIFIC POWER COMPANY

Date: ~~May 3,~~August 2, 2019	/s/ Michael E. Cole
	Michael E. Cole
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)

~~154~~170



Commission File Number	Exact name of registrant as specified in its charter; State or other jurisdiction of incorporation or organization	IRS Employer Identification No.
001-14881	BERKSHIRE HATHAWAY ENERGY COMPANY	94-2213782
	(An Iowa Corporation)
	666 Grand Avenue, Suite 500
	Des Moines, Iowa 50309-2580
	515-242-4300

001-05152	PACIFICORP	93-0246090
	(An Oregon Corporation)
	825 N.E. Multnomah Street
	Portland, Oregon 97232
	888-221-7070

333-90553	MIDAMERICAN FUNDING, LLC	47-0819200
	(An Iowa Limited Liability Company)
	666 Grand Avenue, Suite 500
	Des Moines, Iowa 50309-2580
	515-242-4300

333-15387	MIDAMERICAN ENERGY COMPANY	42-1425214
	(An Iowa Corporation)
	666 Grand Avenue, Suite 500
	Des Moines, Iowa 50309-2580
	515-242-4300

000-52378	NEVADA POWER COMPANY	88-0420104
	(A Nevada Corporation)
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	702-402-5000

000-00508	SIERRA PACIFIC POWER COMPANY	88-0044418
	(A Nevada Corporation)
	6100 Neil Road
	Reno, Nevada 89511
	775-834-4011

	N/A
	(Former name or former address, if changed from last report)



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
Nevada Utilities		Nevada Power Company and Sierra Pacific Power Company
Registrants		Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, MidAmerican Energy, Nevada Power and Sierra Pacific
Northern Powergrid		Northern Powergrid Holdings Company
BHE Pipeline Group		Consists of Northern Natural Gas Company and Kern River Gas Transmission Company
Northern Natural Gas		Northern Natural Gas Company
Kern River		Kern River Gas Transmission Company
BHE Transmission		Consists of BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada		BHE Canada Holdings Corporation
AltaLink		AltaLink, L.P.
BHE U.S. Transmission		BHE U.S. Transmission, LLC
BHE Renewables		Consists of BHE Renewables, LLC and CalEnergy Philippines
HomeServices		HomeServices of America, Inc. and its subsidiaries
Utilities		PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company
Domestic Regulated Businesses		PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Northern Natural Gas Company and Kern River Gas Transmission Company
Topaz		Topaz Solar Farms LLC
Agua Caliente		Agua Caliente Solar, LLC

Certain Industry Terms
2017 Tax Reform		The Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018
AB 1054		California Assembly Bill 1054
AESO		Alberta Electric System Operator
AFUDC		Allowance for Funds Used During Construction
AUC		Alberta Utilities Commission
CPUC		California Public Utilities Commission
DEAA		Deferred Energy Accounting Adjustment
Dth		Decatherm
EBA		Energy Balancing Account
ECAM		Energy Cost Adjustment Mechanism
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission



FRMMA		Fire Risk Mitigation Memorandum Account
GAAP		Accounting principles generally accepted in the United States of America
GEMA		Gas and Electricity Markets Authority



GHG		Greenhouse Gases
GWh		Gigawatt Hour
GTA		General Tariff Application
IPUC		Idaho Public Utilities Commission
IRP		Integrated Resource Plan
IUB		Iowa Utilities Board
kV		Kilovolt
MW		Megawatt
MWh		Megawatt Hour
Ofgem		Office of Gas and Electric Markets
OPUC		Oregon Public Utility Commission
PUCN		Public Utilities Commission of Nevada
REC		Renewable Energy Credit
RPS		Renewable Portfolio Standards
RRA		Renewable Energy Credit and Sulfur DioxideRevenue Adjustment Mechanism
SB 901		California Senate Bill 901
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
TAM		Transition Adjustment Mechanism
UPSC		Utah Public Service Commission
WPSC		Wyoming 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		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		5160
Consolidated Balance Sheets		5261
Consolidated Statements of Operations		5463
Consolidated Statements of Changes in Shareholders' Equity		5564
Consolidated Statements of Cash Flows		5665
Notes to Consolidated Financial Statements		5766
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		7487
Balance Sheets		7588
Statements of Operations		7790
Statements of Changes in Shareholder's Equity		7891
Statements of Cash Flows		7992
Notes to Financial Statements		8093
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		89102
Consolidated Balance Sheets		90103
Consolidated Statements of Operations		92105
Consolidated Statements of Changes in Member's Equity		93106
Consolidated Statements of Cash Flows		94107
Notes to Consolidated Financial Statements		95108
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~109~~123
Consolidated Balance Sheets		~~110~~124
Consolidated Statements of Operations		~~111~~125
Consolidated Statements of Changes in Shareholder's Equity		~~112~~126
Consolidated Statements of Cash Flows		~~113~~127
Notes to Consolidated Financial Statements		~~114~~128
Sierra Pacific Power Company
Report of Independent Registered Public Accounting Firm		~~130~~144
Balance Sheets		~~131~~145
Statements of Operations		~~132~~146
Statements of Changes in Shareholder's Equity		~~133~~147
Statements of Cash Flows		~~134~~148
Notes to Financial Statements		~~135~~149



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



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



Registrant	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company	Emerging growth company
BERKSHIRE HATHAWAY ENERGY COMPANY			X
PACIFICORP			X
MIDAMERICAN FUNDING, LLC			X
MIDAMERICAN ENERGY COMPANY			X
NEVADA POWER COMPANY			X
SIERRA PACIFIC POWER COMPANY			X



Item 1.	Legal Proceedings	~~151~~167
Item 1A.	Risk Factors	~~151~~167
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~151~~167
Item 3.	Defaults Upon Senior Securities	~~151~~167
Item 4.	Mine Safety Disclosures	~~151~~167
Item 5.	Other Information	~~151~~167
Item 6.	Exhibits	~~151~~167
Signatures		~~154~~170


Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations



Berkshire Hathaway Energy Company and its subsidiaries		2830
PacifiCorp and its subsidiaries		6778
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		99112
Nevada Power Company and its subsidiaries		~~123~~137
Sierra Pacific Power Company		~~144~~159


	Three-Month Periods						Three-Month Periods						Six-Month Periods
	Ended March 31,						Ended June 30,						Ended June 30,
	2019			2018			2019			2018			2019			2018
Operating revenue:
Energy	$	3,825		$	3,679		$	3,567		$	3,720		$	7,392		$	7,399
Real estate	785			761			1,327			1,273			2,112			2,034
Total operating revenue	4,610			4,440			4,894			4,993			9,504			9,433

Operating expenses:
Energy:
Cost of sales	1,214			1,168			1,027			1,126			2,241			2,294
Operations and maintenance	802			785			822			849			1,624			1,633
Depreciation and amortization	720			704			728			739			1,448			1,443
Property and other taxes	149			143			148			142			297			286
Real estate	806			769			1,210			1,165			2,016			1,934
Total operating expenses	3,691			3,569			3,935			4,021			7,626			7,590

Operating income	919			871			959			972			1,878			1,843

Other income (expense):
Interest expense	(477		)	(466		)	(476		)	(461		)	(953		)	(927		)
Capitalized interest	16			12			17			15			33			27
Allowance for equity funds	32			21			38			24			70			45
Interest and dividend income	30			26			36			32			66			58
Losses on marketable securities, net	(68		)	(209		)
Gains (losses) on marketable securities, net							6			(387		)	(62		)	(596		)
Other, net	35			30			30			1			65			31
Total other income (expense)	(432		)	(586		)	(349		)	(776		)	(781		)	(1,362		)

Income before income tax benefit and equity (loss) income	487			285
Income before income tax benefit and equity income (loss)							610			196			1,097			481
Income tax benefit	(148		)	(221		)	(76		)	(168		)	(224		)	(389		)
Equity (loss) income	(10		)	12
Equity income (loss)							2			14			(8		)	26
Net income	625			518			688			378			1,313			896
Net income attributable to noncontrolling interests	3			5			4			6			7			11
Net income attributable to BHE shareholders	$	622		$	513		$	684		$	372		$	1,306		$	885


	BHE Shareholders' Equity																					BHE Shareholders' Equity
							Long-term						Accumulated															Long-term						Accumulated
				Additional			Income						Other												Additional			Income						Other
	Common			Paid-in			Tax			Retained			Comprehensive			Noncontrolling			Total			Common			Paid-in			Tax			Retained			Comprehensive			Noncontrolling			Total
	Shares	Stock		Capital			Receivable			Earnings			Loss, Net			Interests			Equity			Shares	Stock		Capital			Receivable			Earnings			Loss, Net			Interests			Equity
Balance, March 31, 2018																						77	$	—	$	6,363		$	—		$	23,719		$	(1,415	)	$	127		$	28,794
Net income																						—	—		—			—			372			—			4			376
Other comprehensive income																						—	—		—			—			—			(250		)	—			(250		)
Reclassification of long-term income tax receivable																						—	—		—			(609		)	—			—			—			(609		)
Long-term income tax receivable adjustments																						—	—		—			115			(115		)	—			—			—
Distributions																						—	—		—			—			—			—			(3		)	(3		)
Other equity transactions																						—	—		(5		)	—			—			—			1			(4		)
Balance, June 30, 2018																						77	$	—	$	6,358		$	(494	)	$	23,976		$	(1,665	)	$	129		$	28,304

Balance, December 31, 2017	77	$	—	$	6,368		$	—		$	22,206		$	(398	)	$	132		$	28,308		77	$	—	$	6,368		$	—		$	22,206		$	(398	)	$	132		$	28,308
Adoption of ASU 2016-01	—	—		—			—			1,085			(1,085		)	—			—			—	—		—			—			1,085			(1,085		)	—			—
Net income	—	—		—			—			513			—			4			517			—	—		—			—			885			—			8			893
Other comprehensive income	—	—		—			—			—			68			—			68			—	—		—			—			—			(182		)	—			(182		)
Reclassification of long-term income tax receivable																						—	—		—			(609		)	—			—			—			(609		)
Long-term income tax receivable adjustments																						—	—		—			115			(115		)	—			—			—
Common stock purchases	—	—		(5		)	—			(85		)	—			—			(90		)	—	—		(5		)	—			(85		)	—			—			(90		)
Distributions	—	—		—			—			—			—			(9		)	(9		)	—	—		—			—			—			—			(12		)	(12		)
Balance, March 31, 2018	77	$	—	$	6,363		$	—		$	23,719		$	(1,415	)	$	127		$	28,794
Other equity transactions																						—	—		(5		)	—			—			—			1			(4		)
Balance, June 30, 2018																						77	$	—	$	6,358		$	(494	)	$	23,976		$	(1,665	)	$	129		$	28,304

Balance, March 31, 2019																						77	$	—	$	6,355		$	(457	)	$	25,968		$	(1,830	)	$	126		$	30,162
Net income																						—	—		—			—			684			—			4			688
Other comprehensive income																						—	—		—			—			—			(58		)	—			(58		)
Distributions																						—	—		—			—			—			—			(3		)	(3		)
Other equity transactions																						—	—		—			—			(1		)	—			(1		)	(2		)
Balance, June 30, 2019																						77	$	—	$	6,355		$	(457	)	$	26,651		$	(1,888	)	$	126		$	30,787

Balance, December 31, 2018	77	$	—	$	6,371		$	(457	)	$	25,624		$	(1,945	)	$	130		$	29,723		77	$	—	$	6,371		$	(457	)	$	25,624		$	(1,945	)	$	130		$	29,723
Net income	—	—		—			—			622			—			3			625			—	—		—			—			1,306			—			7			1,313
Other comprehensive income	—	—		—			—			—			115			—			115			—	—		—			—			—			57			—			57
Common stock purchases	—	—		(16		)	—			(277		)	—			—			(293		)	—	—		(16		)	—			(277		)	—			—			(293		)
Distributions	—	—		—			—			—			—			(7		)	(7		)	—	—		—			—			—			—			(10		)	(10		)
Other equity transactions	—	—		—			—			(1		)	—			—			(1		)	—	—		—			—			(2		)	—			(1		)	(3		)
Balance, March 31, 2019	77	$	—	$	6,355		$	(457	)	$	25,968		$	(1,830	)	$	126		$	30,162
Balance, June 30, 2019																						77	$	—	$	6,355		$	(457	)	$	26,651		$	(1,888	)	$	126		$	30,787


		As of							As of
	Depreciable	March 31,			December 31,			Depreciable	June 30,			December 31,
	Life	2019			2018			Life	2019			2018
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	77,659		$	76,707		5-80 years	$	78,087		$	76,707
Interstate natural gas pipeline assets	3-80 years	7,547			7,524			3-80 years	7,571			7,524
		85,206			84,231				85,658			84,231
Accumulated depreciation and amortization		(26,253		)	(25,894		)		(26,637		)	(25,894		)
Regulated assets, net		58,953			58,337				59,021			58,337

Nonregulated assets:
Independent power plants	5-30 years	6,844			6,826			5-30 years	6,962			6,826
Other assets	3-30 years	1,474			1,424			3-30 years	1,625			1,424
		8,318			8,250				8,587			8,250
Accumulated depreciation and amortization		(1,711		)	(1,610		)		(2,000		)	(1,610		)
Nonregulated assets, net		6,607			6,640				6,587			6,640

Net operating assets		65,560			64,977				65,608			64,977
Construction work-in-progress		3,388			3,110				4,331			3,110
Property, plant and equipment, net		$	68,948		$	68,087			$	69,939		$	68,087


(3)	Investments and Restricted Cash and Cash Equivalents and Investments


	As of						As of
	March 31,			December 31,			June 30,			December 31,
	2019			2018			2019			2018
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,434		$	1,809		$	1,666		$	1,809
Accrued interest	522			469			533			469
Accrued property, income and other taxes	475			599			419			599
Accrued employee expenses	316			275			345			275
Short-term debt	2,214			2,516			2,594			2,516
Current portion of long-term debt	1,078			2,081			1,906			2,081
Other current liabilities	1,358			1,021			1,444			1,021
Total current liabilities	7,397			8,770			8,907			8,770

BHE senior debt	8,228			8,577			8,229			8,577
BHE junior subordinated debentures	100			100			100			100
Subsidiary debt	28,510			25,492			27,861			25,492
Regulatory liabilities	7,347			7,346			7,382			7,346
Deferred income taxes	9,080			9,047			9,093			9,047
Other long-term liabilities	3,721			3,134			3,783			3,134
Total liabilities	64,383			62,466			65,355			62,466

Commitments and contingencies (Note 10)

Equity:
BHE shareholders' equity:
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding	—			—			—			—
Additional paid-in capital	6,355			6,371			6,355			6,371
Long-term income tax receivable	(457		)	(457		)	(457		)	(457		)
Retained earnings	25,968			25,624			26,651			25,624
Accumulated other comprehensive loss, net	(1,830		)	(1,945		)	(1,888		)	(1,945		)
Total BHE shareholders' equity	30,036			29,593			30,661			29,593
Noncontrolling interests	126			130			126			130
Total equity	30,162			29,723			30,787			29,723

Total liabilities and equity	$	94,545		$	92,189		$	96,142		$	92,189


	As of		As of
	March 31,		June 30,
	2019		2019
Right-of-use assets:
Operating leases	$	544	$	553
Finance leases	509		509
Total right-of-use assets	$	1,053	$	1,062

Lease liabilities:
Operating leases	$	586	$	597
Finance leases	522		523
Total lease liabilities	$	1,108	$	1,120


	Three-Month Period			Three-Month Period		Six-Month Period
	Ended March 31,			Ended June 30,		Ending June 30,
	2019			2019		2019

Variable	$	144		$	153	$	296
Operating	41			41		82
Finance:
Amortization	4			4		8
Interest	11			10		21
Short-term	1			1		3
Total lease costs	$	201		$	209	$	410

Weighted-average remaining lease term (years):
Operating leases	7.5					8.0
Finance leases	29.5					29.1

Weighted-average discount rate:
Operating leases	5.3		%			5.2		%
Finance leases	8.7		%			8.7		%


	March 31, 2019									December 31, 2018⁽¹⁾						June 30, 2019									December 31, 2018⁽¹⁾
	Operating			Finance			Total			Operating		Capital		Total		Operating			Finance			Total			Operating		Capital		Total
2019	$	115		$	53		$	168		$	147	$	69	$	216	$	77		$	39		$	116		$	147	$	69	$	216
2020	138			68			206			128		68		196		139			69			208			128		68		196
2021	116			74			190			110		73		183		117			75			192			110		73		183
2022	92			67			159			87		67		154		93			68			161			87		67		154
2023	66			56			122			61		56		117		66			57			123			61		56		117
Thereafter	198			775			973			159		772		931		236			776			1,012			159		772		931
Total undiscounted lease payments	725			1,093			1,818			$	692	$	1,105	$	1,797	728			1,084			1,812			$	692	$	1,105	$	1,797
Less - amounts representing interest	(139		)	(571		)	(710		)							(131		)	(561		)	(692		)
Lease liabilities	$	586		$	522		$	1,108								$	597		$	523		$	1,120


	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, 2019
As of June 30, 2019
Assets:
Commodity derivatives	$	—		$	82		$	100		$	(40	)	$	142		$	—		$	38		$	106		$	(25	)	$	119
Interest rate derivatives	—			10			19			—			29			—			6			25			—			31
Mortgage loans held for sale	—			506			—			—			506			—			1,065			—			—			1,065
Money market mutual funds⁽²⁾	1,169			—			—			—			1,169			951			—			—			—			951
Debt securities:
United States government obligations	190			—			—			—			190			193			—			—			—			193
International government obligations	—			4			—			—			4			—			4			—			—			4
Corporate obligations	—			47			—			—			47			—			49			—			—			49
Municipal obligations	—			2			—			—			2			—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			1			—			—			1			—			1			—			—			1
Equity securities:
United States companies	292			—			—			—			292			311			—			—			—			311
International companies	1,363			—			—			—			1,363			1,358			—			—			—			1,358
Investment funds	182			—			—			—			182			182			—			—			—			182
	$	3,196		$	652		$	119		$	(40	)	$	3,927		$	2,995		$	1,165		$	131		$	(25	)	$	4,266
Liabilities:
Commodity derivatives	$	—		$	(162	)	$	(14	)	$	96		$	(80	)	$	(2	)	$	(187	)	$	(20	)	$	117		$	(92	)
Interest rate derivatives	(1		)	(17		)	(1		)	—			(19		)	(2		)	(24		)	(2		)	—			(28		)
	$	(1	)	$	(179	)	$	(15	)	$	96		$	(99	)	$	(4	)	$	(211	)	$	(22	)	$	117		$	(120	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of ~~$56~~$92 million and $59 million as of ~~March 31,~~June 30, 2019 and December 31, 2018, respectively.


(2)	Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.


2018:
Beginning balance	$	94		$	9		$	81		$	16		$	94		$	9
Changes included in earnings	—			30			4			56			4			86
Changes in fair value recognized in OCI	(1		)	—			1			—			—			—
Changes in fair value recognized in net regulatory assets	(9		)	—			(5		)	—			(14		)	—
Purchases	1			—			—			—			1			—
Settlements	(4		)	(23		)	2			(55		)	(2		)	(78		)
Ending balance	$	81		$	16		$	83		$	17		$	83		$	17



	As of March 31, 2019				As of December 31, 2018
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	37,916	$	42,154	$	36,250	$	38,874


	For the Three-Month Period Ended March 31, 2019																				For the Three-Month Period Ended June 30, 2019
	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:
Regulated:
Retail electric	$	1,186	$	443	$	527	$	—	$	—		$	—	$	—	$	—		$	2,156	$	1,107	$	467	$	658	$	—	$	—	$	—	$	—	$	—		$	2,232
Retail gas	—		260		37		—		—			—		—		—			297		—		95		21		—		—		—		—		—			116
Wholesale	28		110		18		—		—			—		—		—			156		11		66		10		—		—		—		—		(1		)	86
Transmission and distribution	25		16		24		230		—			167		—		—			462		25		15		24		209		—		168		—		—			441
Interstate pipeline	—		—		—		—		372			—		—		(37		)	335		—		—		—		—		212		—		—		(24		)	188
Other	—		—		1		—		—			—		—		—			1		—		—		—		—		—		—		—		—			—
Total Regulated	1,239		829		607		230		372			167		—		(37		)	3,407		1,143		643		713		209		212		168		—		(25		)	3,063
Nonregulated	—		6		—		8		—			1		126		139			280		—		10		—		10		—		7		197		142			366
Total Customer Revenue	1,239		835		607		238		372			168		126		102			3,687		1,143		653		713		219		212		175		197		117			3,429
Other revenue⁽²⁾	20		7		7		25		(1		)	—		41		39			138		24		7		8		24		—		—		52		23			138
Total	$	1,259	$	842	$	614	$	263	$	371		$	168	$	167	$	141		$	3,825	$	1,167	$	660	$	721	$	243	$	212	$	175	$	249	$	140		$	3,567



	For the Six-Month Period Ended June 30, 2019
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group			BHE Transmission		BHE Renewables		BHE and Other⁽¹⁾			Total
Customer Revenue:
Regulated:
Retail electric	$	2,293	$	910	$	1,185	$	—	$	—		$	—	$	—	$	—		$	4,388
Retail gas	—		355		58		—		—			—		—		—			413
Wholesale	39		176		28		—		—			—		—		(1		)	242
Transmission and distribution	50		31		48		439		—			335		—		—			903
Interstate pipeline	—		—		—		—		584			—		—		(61		)	523
Other	—		—		1		—		—			—		—		—			1
Total Regulated	2,382		1,472		1,320		439		584			335		—		(62		)	6,470
Nonregulated	—		16		—		18		—			8		323		281			646
Total Customer Revenue	2,382		1,488		1,320		457		584			343		323		219			7,116
Other revenue⁽²⁾	44		14		15		49		(1		)	—		93		62			276
Total	$	2,426	$	1,502	$	1,335	$	506	$	583		$	343	$	416	$	281		$	7,392


(1)	The BHE and Other reportable segment represents amounts related principally to other entities, corporate functions and intersegment eliminations.


(2)	Includes net payments to counterparties for the financial settlement of certain derivative contracts at BHE Pipeline Group.



	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	918	$	5,796	$	6,714


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

Balance, December 31, 2017	$	(383	)	$	(1,129	)	$	1,085		$	29		$	(398	)	$	(383	)	$	(1,129	)	$	1,085		$	29		$	(398	)
Adoption of ASU 2016-01	—			—			(1,085		)	—			(1,085		)	—			—			(1,085		)	—			(1,085		)
Other comprehensive (loss) income	(3		)	73			—			(2		)	68			51			(234		)	—			1			(182		)
Balance, March 31, 2018	$	(386	)	$	(1,056	)	$	—		$	27		$	(1,415	)
Balance, June 30, 2018																$	(332	)	$	(1,363	)	$	—		$	30		$	(1,665	)

Balance, December 31, 2018	$	(358	)	$	(1,623	)	$	—		$	36		$	(1,945	)	$	(358	)	$	(1,623	)	$	—		$	36		$	(1,945	)
Other comprehensive (loss) income	(32		)	155			—			(8		)	115			(14		)	106			—			(35		)	57
Balance, March 31, 2019	$	(390	)	$	(1,468	)	$	—		$	28		$	(1,830	)
Balance, June 30, 2019																$	(372	)	$	(1,517	)	$	—		$	1		$	(1,888	)



Depreciation and amortization:
PacifiCorp	$	209		$	197		$	414		$	399
MidAmerican Funding	179			208			356			366
NV Energy	120			114			240			227
Northern Powergrid	63			64			126			127
BHE Pipeline Group	29			30			57			72
BHE Transmission	60			61			118			123
BHE Renewables	69			66			139			130
HomeServices	11			11			24			23
BHE and Other⁽¹⁾	(1		)	(1		)	(2		)	(1		)
Total depreciation and amortization	$	739		$	750		$	1,472		$	1,466


Operating income:
Interest expense:
PacifiCorp	$	284		$	247		$	102	$	96	$	198	$	192
MidAmerican Funding	116			79			74		61		149		124
NV Energy	84			89			56		59		118		117
Northern Powergrid	129			147			35		36		69		73
BHE Pipeline Group	243			226			12		10		24		20
BHE Transmission	76			81			39		42		78		85
BHE Renewables	18			28			44		49		88		101
HomeServices	(21		)	(8		)	7		6		14		10
BHE and Other⁽¹⁾	(10		)	(18		)	107		102		215		205
Total operating income	919			871
Interest expense	(477		)	(466		)
Capitalized interest	16			12
Allowance for equity funds	32			21
Interest and dividend income	30			26
Losses on marketable securities, net	(68		)	(209		)
Other, net	35			30
Total income before income tax expense and equity income	$	487		$	285
Total interest expense							$	476	$	461	$	953	$	927



Operating revenue by country:
United States	$	4,476	$	4,570	$	8,653	$	8,548
United Kingdom	242		245		505		522
Canada	175		177		343		357
Philippines and other	1		1		3		6
Total operating revenue by country	$	4,894	$	4,993	$	9,504	$	9,433



Income before income tax expense and equity income by country:
United States	$	336	$	118
United Kingdom	103		112
Canada	40		41
Philippines and other	8		14
Total income before income tax expense and equity income by country	$	487	$	285


(1)	The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.



	First Quarter
	2019			2018			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	180		$	148		$	32		22	%
MidAmerican Funding	190			103			87			84
NV Energy	29			33			(4		)	(12	)
Northern Powergrid	80			84			(4		)	(5	)
BHE Pipeline Group	181			167			14			8
BHE Transmission	56			56			—			—
BHE Renewables	48			54			(6		)	(11	)
HomeServices	(22		)	(10		)	(12		)	*
BHE and Other	(120		)	(122		)	2			2
Total net income attributable to BHE shareholders	$	622		$	513		$	109		21



	Second Quarter											First Six Months
	2019			2018			Change					2019			2018			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	168		$	185		$	(17	)	(9	)%	$	348		$	333		$	15		5	%
MidAmerican Funding	153			103			50			49		343			206			137			67
NV Energy	81			77			4			5		110			110			—			—
Northern Powergrid	64			41			23			56		144			125			19			15
BHE Pipeline Group	48			40			8			20		229			207			22			11
BHE Transmission	51			53			(2		)	(4	)	107			109			(2		)	(2	)
BHE Renewables	120			111			9			8		168			165			3			2
HomeServices	90			77			13			17		68			67			1			1
BHE and Other	(91		)	(315		)	224			71		(211		)	(437		)	226			52
Total net income attributable to BHE shareholders	$	684		$	372		$	312		84		$	1,306		$	885		$	421		48


							MidAmerican			NV			Northern			BHE															MidAmerican			NV		Northern		BHE
	BHE			PacifiCorp			Funding			Energy			Powergrid			Canada			Other			Total			BHE			PacifiCorp			Funding			Energy		Powergrid		Canada			Other			Total

Cash and cash equivalents	$	65		$	669		$	433		$	131		$	31		$	53		$	279		$	1,661		$	11		$	536		$	186		$	135	$	95	$	65		$	237		$	1,265

Credit facilities⁽²⁾⁽¹⁾	3,500			1,200			909			650			221			655			1,635			8,770			3,500			1,200			909			650		190		668			1,810			8,927
Less:
Short-term debt	(912		)	—			—			—			(103		)	(239		)	(960		)	(2,214		)	(837		)	—			—			—		—		(357		)	(1,400		)	(2,594		)
Tax-exempt bond support and letters of credit	—			(256		)	(370		)	(80		)	—			(5		)	—			(711		)	—			(256		)	(370		)	—		—		(5		)	—			(631		)
Net credit facilities	2,588			944			539			570			118			411			675			5,845			2,663			944			539			650		190		306			410			5,702

Total net liquidity	$	2,653		$	1,613		$	972		$	701		$	149		$	464		$	954		$	7,506		$	2,674		$	1,480		$	725		$	785	$	285	$	371		$	647		$	6,967
Credit facilities:
Maturity dates⁽¹⁾	2021			2021			2019, 2021			2021			2020			2023			2019, 2020, 2022						2022			2022			2020, 2022			2022		2020		2023			2019, 2020, 2022


⁽¹⁾	Refer to Note 5 of the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for further discussion regarding the Company's recent financing transactions.