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, 2016, and new regulatory matters occurring in 2017.

PacifiCorp

In June 2017, PacifiCorp filed two applications each with the UPSC, IPUC and the WPSC for the Energy Vision 2020 project. The first application seeks approvals to construct or procure four new Wyoming wind resources with a total capacity of 860 megawatts and certain transmission facilities. PacifiCorp estimates that the combined wind and transmission projects will cost approximately $2 billion. The UPSC has set a procedural schedule with hearings to occur in March 2018, and schedules in Idaho and Wyoming will be set after the expiration of public notice periods in August 2017. The second application seeks approval of PacifiCorp's resource decision to upgrade or “repower” existing wind resources, as prudent and in the public interest. PacifiCorp estimates that the wind repowering project will cost approximately $1.13 billion. The UPSC has set a procedural schedule with hearings to occur in November 2017 with requested approval in December 2017. Schedules in Idaho and Wyoming will also be set after the expiration of public notice periods in August 2017. Both applications seek approval for the proposed ratemaking treatment associated with the projects.

Utah

In March 2017, PacifiCorp filed its annual Energy Balancing Account ("EBA") with the UPSC seeking approval to refund to customers $7 million in deferred net power costs for the period January 1, 2016 through December 31, 2016, reflecting the difference between base and actual net power costs in the 2016 deferral period. In April 2017, PacifiCorp revised its recommendation and requested approval to refund an additional $7 million to customers resulting in an interim rate reduction of $14 million. The rate change isbecame effective on an interim basis May 1, 2017.

In March 2017, PacifiCorp filed its annual REC balancing account application with the UPSC seeking to refund to customers $1 million for the period January 1, 2016 through December 31, 2016 for the difference in base and actual renewable energy credits. The rate change ~~will be~~became effective on an interim basis June 1, 2017.

As a result of the Utah Sustainable Transportation and Energy Plan legislation that was signed into law in March 2016, PacifiCorp filed an application in September 2016 seeking approval of ~~phase 1 of~~ a proposed five-year pilot program with an annual budget of $10 million authorized under the ~~legislation. The UPSC issued an order approving phase one of the five-year pilot program in December 2016. Phases two and three of PacifiCorp's application for approval of~~legislation to address clean-coal technology programs, authorized by the legislation are ongoing at the UPSC. A hearing was held April 18, 2017 in Phase two of the application which includes projects under the Clean Coal Technology Program and an incentive for commercial line ~~extensions. Phase three addresses the~~extension programs, an electric vehicle incentive program ~~including a~~and associated residential time of use rate ~~pilot.~~

pilot, and other programs authorized in legislation. The UPSC issued orders approving PacifiCorp's application in phases in December 2016, May 2017, and June 2017.

In November 2016, PacifiCorp filed cost of service analyses, as ordered by the UPSC, to quantify the cost shifting due to net metering. The UPSC ordered the analyses to comply with a 2014 law requiring the examination of whether the costs of net metering exceed the benefits to PacifiCorp and other customers. The filing includes a proposal for a new rate schedule for residential customer generators with a three-part rate based on the cost of serving this class of customer, which will mitigate future cost shifting. PacifiCorp proposed that the new rate schedule only apply to new net metering customers that submit applications after December 9, 2016. On December 9, 2016, PacifiCorp requested that the effective date for the start of a transitional tariff be suspended while it works with stakeholders on a collaborative process to resolve net metering rate design issues. The filing also requests an increase in the application fees for net metering. In February 2017, the UPSC ruled on motions to dismiss and requests for a show cause order for a ~~general~~regulatory rate ~~case~~review filed by various parties to the docket and denied the motions. The UPSC has set a procedural schedule with hearings to occur in August 2017.

Oregon

In March 2017, PacifiCorp submitted its filing for the annual Transitional Adjustment Mechanism ("TAM") filing in Oregon requesting an annual increase of $18 million, or an average price increase of 1.5%, based on forecasted net power costs and loads for calendar year 2018. Consistent with Oregon Senate Bill 1547, the filing includes an update of the impact of expiring production tax credits, which accounts for $6 million of the total rate adjustment. The filing was updated in July to reflect changes in contracts and market conditions. The updated filing is requesting an annual increase of $8 million, or an average price increase of 0.6%. The filing will be updated for changes in contracts and market conditions again in ~~July and~~ November 2017, before final rates become effective in January 2018.

Wyoming

In April 2017, PacifiCorp filed its annual Energy Cost Adjustment Mechanism ("ECAM") and REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") applications with the WPSC. The ECAM filing requests approval to refund to customers $5 million in deferred net power costs for the period January 1, 2016 through December 31, 2016, and the RRA application requests approval to refund to customers $1 million. ~~If approved by~~In June 2017, the WPSC approved the ECAM and RRA rates ~~will be effective June 15, 2017~~ on an interim basis until a final order is issued by the WPSC.

Washington

In August 2017, PacifiCorp submitted a compliance filing to implement the second-year rate increase approved as part of the two-year rate plan in the 2015 regulatory rate review. The compliance filing will include rates based on the $8 million, or 2.3%, increase ordered by the WUTC in September 2016. If approved by the WUTC, the rates would be effective September 2017.

Idaho

In January 2017, a $1 million, or 0.4%, decrease in base rates became effective as a result of a filing made with the IPUC to update net power costs in base rates in compliance with a prior rate plan stipulation.

In March 2017, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $8 million for deferred costs in 2016. 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 longwall mine investment, and changes in production tax credits and renewable energy credits. IfThe IPUC approved ~~by the IPUC,~~ the ECAM application with rates ~~would be~~ effective June 1, 2017.

California

In April 2017, PacifiCorp filed an application with the CPUC for an overall rate increase of 1.3% to recover $3 million of costs recorded in the catastrophic events memorandum account over a two-year period effective April 1, ~~2018,~~2018. The catastrophic events memorandum account includes costs for implementing drought-related fire hazard mitigation measures and storm damage and recovery efforts associated with the December 2016 and January 2017 winter storms.

In August 2017, PacifiCorp filed for a rate decrease of $1 million, or 1.1%, through its annual Energy Cost Adjustment Clause. If approved by the CPUC, the rates would be effective January 2018.

NV Energy (Nevada Power and Sierra Pacific)

Regulatory Rate Reviews

In June 2017, Nevada Power filed an electric regulatory rate review with the PUCN. The filing requested no incremental annual revenue relief. An order is expected by the end of 2017 and, if approved, would be effective January 1, 2018.

In June 2016, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing requested no incremental annual revenue relief. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving most, but not all, issues in the proceeding and reduced Sierra Pacific's electric revenue requirement by $3 million spread evenly to all rate classes. In December 2016, the PUCN approved the settlement agreement and established an additional six MW of net metering capacity under the grandfathered rates, which are those net metering rates that were in effect prior to January 2016; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. The new rates were effective January 1, 2017. In January 2017, Sierra Pacific filed a petition for reconsideration relating to the creation of the additional six MWs of net metering at the grandfathered rates. Sierra Pacific believes the effects of the PUCN decision result in additional cost shifting to non-net metering customers and reduces the stipulated rate reduction for other customer classes. In June 2017, the PUCN denied the petition for reconsideration.

In June 2016, Sierra Pacific filed a gas regulatory rate review with the PUCN. The filing requested a slight decrease in its incremental annual revenue requirement. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving all issues in the proceeding and reduced Sierra Pacific's gas revenue requirement by $2 million. In December 2016, the PUCN approved the settlement agreement. The new rates were effective January 1, 2017.

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 applicants' 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 May 2015, MGM Resorts International ("MGM") and Wynn Las Vegas, LLC ("Wynn"), filed ~~an application~~applications with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service ~~customer~~customers of Nevada Power. In December 2015, the PUCN granted the ~~application~~applications subject to conditions, including paying an impact fee, on-going charges and receiving approval for specific alternative energy providers and terms. In December 2015, ~~Wynn~~the applicants filed ~~a petition~~petitions for reconsideration. In January 2016, the PUCN granted reconsideration and updated some of the terms, including removing a limitation related to energy purchased indirectly from NV Energy. In September 2016, MGM and Wynn paid impact fees ~~totaling~~of $82 million and $15 ~~million.~~million, respectively. In October 2016, MGM and Wynn became a distribution only service ~~customer~~customers and started procuring energy from another energy supplier. In April 2017, Wynn filed a motion with the PUCN seeking relief from the January 2016 order and requested the PUCN adopt an alternative impact fee and revise on-going charges associated with retirement of assets and high cost renewable contracts. In May 2017, a stipulation reached between MGM, Regulatory Operations Staff and the Bureau of Consumer Protection was filed requiring Nevada Power to credit $16 million as an offset against MGM's remaining impact fee obligation and, in June 2017, the PUCN approved the stipulation as filed.

In September 2016, Switch, Ltd. ("Switch"), a customer of the Nevada Utilities, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power and Sierra Pacific. In December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions, including paying an impact fee to Nevada Power. In ~~March~~May 2017, Switch ~~provided notice that it intends to pay the~~paid impact ~~fee~~fees of $27 million and, ~~proceed with purchasing~~in June 2017, Switch became a distribution only service customer and started procuring energy from ~~alternative providers.~~ another energy supplier.

In November 2016, Caesars Enterprise Service ("Caesars"), a customer of the Nevada Utilities, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power and Sierra Pacific. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.

In May 2017, Peppermill Resort Spa Casino ("Peppermill"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific.

Net Metering

Nevada enacted Senate Bill 374 ("SB 374") on June 5, 2015. The legislation required the Nevada Utilities to prepare cost-of-service studies and propose new rules and rates for customers who install distributed, renewable generating resources. In July 2015, the Nevada Utilities made filings in compliance with SB 374 and the PUCN issued final orders December 23, 2015.

The final orders issued by the PUCN establish separate rate classes for customers who install distributed, renewable generating facilities. The establishment of separate rate classes recognizes the unique characteristics, costs and services received by these partial requirements customers. The PUCN also established new, cost-based rates or prices for these new customer classes, including increases in the basic service charge and related reductions in energy charges. Finally, the PUCN established a separate value for compensating customers who produce and deliver excess energy to the Nevada Utilities. The valuation will consider eleven factors, including alternatives available to the Nevada Utilities. The PUCN established a gradual, five-step process for transition over four years to the new, cost-based rates.

In January 2016, the PUCN denied requests to stay the order issued December 23, 2015. The PUCN also voted to reopen the evidentiary proceeding to address the application of new net metering rules for customers who applied for net metering service before the issuance of the final order. In February 2016, the PUCN affirmed most of the provisions of the December 23, 2015 order and adopted a twelve-year transition plan for changing rates for net metering customers to cost-based rates for utility services and value-based pricing for excess energy. Subsequently, two solar industry interest groups filed petitions for judicial review of the PUCN order issued in February 2016. The petitions request that the court either modify the PUCN order or direct the PUCN to modify its decision in a manner that would maintain rates and rules of service applicable to net metering as existed prior to the December 23, 2015 order of the PUCN. Two of the three petitions filed by the solar industry interest groups have been dismissed. In September 2016, the state district court issued an order in the third petition. The court concluded that the PUCN failed to provide existing net metering customers adequate legal notice of the proceeding. The court affirmed the PUCN's decision to establish new net energy metering rates and apply those to new net metering customers. The Nevada state district court decision was appealed to the Nevada Supreme Court.

In July 2016, the Nevada Utilities filed applications with the PUCN to revert back to the original net metering rates for a period of twenty years for customers who installed or had an active application for distributed, renewable generating facilities as of December 31, 2015. In September 2016, the PUCN issued an order accepting the stipulation and approved the applications as modified by the stipulation. In December 2016, as a part of Sierra Pacific's regulatory rate review, the PUCN issued an order establishing an additional six MWs of net metering under the grandfathered rates in the Sierra Pacific service territory; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. As mentioned above, Sierra Pacific ~~has~~ filed a petition for reconsideration relating to the additional six MWs of net ~~metering.~~metering, which was denied in June 2017.

In March 2017, the Nevada Utilities filed a joint application with several solar companies to extend the period for eligible customers to opt into the grandfathered net metering rates. The PUCN voted to approve the application and give qualifying customers until July 2017 to make this election.

Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The legislation, among other things, established net metering crediting rates for private solar customers with installed net metering systems less than 25 kilowatts. Under AB 405, private solar customers will be compensated at 95% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the first 80 MWs of cumulative installed capacity of all net metering systems in Nevada, 88% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the next 80 MWs of cumulative installed capacity in Nevada, 81% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the next 80 MWs of cumulative installed capacity in Nevada, and 75% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for any additional installed rooftop solar capacity. In July 2017, the Nevada Utilities filed with the PUCN proposed amendments to their tariffs necessary to comply with the provisions of AB 405. The filing in July 2017 also included a proposed optional time of use rate tariff for both Nevada Power and Sierra Pacific.

Energy Choice Initiative

In November 2016, a majority of Nevada voters supported a ballot measure to amend Article 1 of the Nevada Constitution. If approved again in the general election of 2018, the proposed constitutional amendment would require the Nevada Legislature to create, on or before July 2023, an open and competitive retail electric market that includes provisions to reduce costs to customers, protect against service disconnections and unfair practices, and prohibit the granting of monopolies and exclusive franchises for the generation of electricity. The outcome of any customer choice initiative could have broad implications to the Nevada Utilities. The Governor issued an executive order establishing the Governor’s Committee on Energy Choice in which the Nevada Utilities have representation. The Nevada Utilities are engaged in the initiative process and with the Governor's Committee on Energy Choice but cannot assess or predict the outcome of the potential constitutional amendment or the financial impact, if any, at this time. The uncertainty created by the ballot initiative complicates both the short-term allocation of resources and long-term resource planning for the Nevada Utilities, including the ability to forecast load growth and the timing of resource additions. This uncertainty in planning is evidenced by a recent decision the PUCN issued denying Nevada Power’s proposed purchase of the South Point Energy Center, citing the unknown outcomes of the energy choice initiative as one of the factors considered in their decision.

ALP

General Tariff Applications

In November 2014, ALP filed a GTA requesting the AUC approve revenue requirements of C$811 million for 2015 and C$1.0 billion for 2016, primarily due to continued investment in capital projects as directed by the AESO. ALP amended the GTA in June 2015 and in October 2015. In May 2016, the AUC issued its decision pertaining to the 2015-2016 GTA. ALP filed its 2015-2016 GTA compliance filing in July 2016 to comply with the AUC's decision and to provide customers with tariff relief through: (i) the discontinuance of construction work-in-progress ("CWIP") in rate base and the return to AFUDC accounting effective January 1, 2015, and (ii) the refund of previously collected CWIP in rate base as part of ALP's transmission tariffs during 2011-2014 less related returns. In October 2016, ALP amended its 2015-2016 GTA compliance filing made in July 2016 to reflect the impacts of the generic cost of capital decision issued in October 2016.

In December 2016, the AUC issued its decision with respect to ALP’s 2015-2016 GTA compliance filing made in July 2016, as amended. The AUC found that ALP has either complied with or the AUC has otherwise relieved ALP from its compliance with all its directions in its decision except for Directive 47, which dealt with the determination of the refund for previously collected CWIP-in-rate base and all related amounts. In January 2017, ALP filed its second compliance filing as directed by the AUC and requested a technical conference to explain the technical aspects of the filing.

In March 2017, the technical conference was held, and all key aspects of ALP’s approach and methodologies used in its second compliance filing to comply with AUC directives were reviewed and discussed. In April 2017, ALP filed with the AUC an amendment to its second compliance filing asking to remove C$7 million of recapitalized AFUDC associated with canceled projects that were not capitalized to rate base, and to increase the amount of income tax refund related to previously collected CWIP-in-rate base by C$4 million. As a result of this amendment, ALP’s forecast transmission tariffs were reduced from C$679 million to C$675 million for 2016, and remained unchanged at C$599 million for 2015, compared to the January 2017 second compliance filing, as amended.

During the second quarter 2017, ALP responded to information requests from the AUC with respect to its second compliance filing amendment filed in April 2017. Further direction or a final decision from the AUC is expected in the third quarter 2017. Once the AUC approves ALP’s second compliance filing, as amended, final transmission tariff rates for the 2015 and 2016 test years will be set, subject to further adjustment through the deferral account reconciliation process.

ALP updated and refiled its 2017-2018 GTA in August 2016 to reflect the findings and conclusions of the AUC in its 2015-2016 GTA decision issued in May 2016. In October 2016, ALP amended its 2017-2018 GTA to reflect the impacts of the generic cost of capital decision issued in October 2016 and other updates and revisions. The amendment requests the AUC to approve ALP's revenue requirement of C$891 million for 2017 and C$919 million for 2018. In November 2016, the AUC approved the 2017 interim refundable transmission tariff at C$70 million per month effective January 2017. In December 2016, the AUC approved ALP's request to enter into a negotiated settlement process. In January 2017, the parties successfully reached a negotiated settlement on all aspects of ALP’s 2017-2018 GTA and in February 2017, ALP filed with the AUC the 2017-2018 negotiated settlement application for approval. The application consists of negotiated reductions of C$16 million of operating expenses and C$40 million of transmission maintenance and information technology capital expenditures over the two years, as well as an increase to miscellaneous revenue of C$3 million. These reductions resulted in a C$24 million, or 1.3%, net decrease to the two-year total revenue requirement applied for in ALP’s 2017-2018 GTA amendment filed in October 2016. In addition, ALP proposed to provide significant tariff relief through the refund of previously collected accumulated depreciation surplus of C$130 million (C$125 million net of other related impacts). The negotiated settlement agreement also provides for additional potential reductions over the two years through a 50/50 cost savings sharing mechanism.

During the second quarter 2017, ALP responded to information requests from the AUC with respect to its 2017-2018 negotiated settlement agreement application filed in February 2017. Further direction or a final decision from the AUC is expected in 2017.

2018 Generic Cost of Capital Proceeding

In July 2017, the AUC denied the utilities’ request that the interim determinations of 8.5% return on equity and deemed capital structures for 2018 be made final, by stating that it is not prepared to finalize 2018 values in the absence of an evidentiary process and its intention to issue the generic cost of capital decision for 2018, 2019 and 2020 by the end of 2018 to reduce regulatory lag. The AUC also confirmed the process timelines with an oral hearing scheduled for March 2018.

Deferral Account Reconciliation Application

In April 2017, ALP filed its application with the AUC with respect to ALP’s 2014 projects and deferral accounts and specific 2015 projects. The application includes 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.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact 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 the EPA and various 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. Refer to "Liquidity and Capital Resources" of each respective Registrant in Part I, Item 2 of this Form 10-Q for discussion of each Registrant's forecast environmental-related capital expenditures. 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, 2016, and new environmental matters occurring in 2017.

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.

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. Certain groups appealed the EPA's approval of the sulfur dioxide portion and oral argument was heard before the United States Court of Appeals for the Tenth Circuit ("Tenth Circuit") in March 2014. In October 2014, the Tenth Circuit upheld the EPA's approval of the sulfur dioxide portion of the SIP. The state of Utah and PacifiCorp filed petitions for administrative and judicial review of the EPA's final rule on the BART determinations for the nitrogen oxides and particulate matter portions of Utah's regional haze SIP in March 2013. In May 2014, the Tenth Circuit dismissed the petition on jurisdictional grounds. In addition, and separate from the EPA's approval process and related litigation, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. The alternative BART analysis and revised regional haze SIP were submitted in June 2015 to the EPA for review and proposed action after a public comment period. The revised regional haze SIP included a state-enforceable requirement to cease operation of the Carbon Facility by August 15, 2015. PacifiCorp retired the Carbon Facility in December 2015. 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 have filed requests with the EPA to reconsider and stay that decision, and have also filed motions for stay and petitions for review with the Tenth Circuit asking the court to overturn the EPA’s actions. In June 2017, the state of Utah and PacifiCorp issued requests to the EPA to reconsider its decision in issuing the FIP. By letter dated July 14, 2017, from Administrator Scott Pruitt, the EPA indicated that based on existing and new evidence potentially relevant to the EPA’s evaluation of Utah’s 2015 SIP, the agency would reconsider its final rule and prepare a notice of proposed rulemaking and take public comment on its proposed action. On July 18, 2017, the EPA filed with the Tenth Circuit a motion to hold the pending appeals in abeyance pending agency reconsideration of the final rule. The Tenth Circuit initially requested that all parties file a response setting forth their opposition or nonopposition to the EPA’s motion to hold the cases in abeyance by July 28, 2017. However, on July 18, 2017, PacifiCorp asked the Tenth Circuit to take judicial notice of the EPA’s request to hold the appeals in abeyance and reaffirmed its request to stay the FIP. The Tenth Circuit ordered all parties to respond to both the EPA's motion for abeyance and the motions by PacifiCorp and others to take judicial notice of EPA's reconsideration by August 4, 2017. The EPA, on July 25, 2017, also filed an unopposed motion to extend the current deadline for the filing of its brief on the merits of the case from August 1, 2017, to August 29, 2017, to allow the court to rule on the pending motions.

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 relating to PacifiCorp and Arizona Public Service Company as they work with state and federal agencies on an alternate compliance approach for Cholla Unit 4. In January 2015, permit applications and studies were submitted to amend the Cholla Title V permit, and subsequently the Arizona SIP to convert Cholla Unit 4 to a natural gas-fueled unit in ~~2025. The~~2025; after notice and comment, the Arizona Department of Environmental Quality prepared a draft permit and a revision to the Arizona regional haze SIP, held two public hearings in July 2015 and, after considering the comments received during the public comment period that closed on July 14, 2015, submitted the ~~final proposals~~amended Arizona SIP to the EPA, ~~for review, public comment and final action. The EPA issued its proposed action to approve amendments to the Arizona regional haze SIP,~~ which ~~were published in the Federal Register in July 2016. The EPA's final action to approve~~approved the amendments to the Arizona regional haze SIP ~~was issued January 13, 2017, and published in the Federal Register March 27, 2017,~~ with an effective date of April 26, 2017.

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. Nevada Power, along with the other owners of the facility, have been reviewing the EPA's proposal to determine its impact on the viability of the facility's future operations. The land lease for the Navajo Generating Station is subject to renewal in 2019. ~~Renewal~~In the spring 2017, the owners of the lease will require completion of an Environmental Impact Statement as well as a renewal of the fuel supply agreement. In September 2013, the EPA issued a supplemental proposal that included another BART alternative called the Technical Work Group Alternative, which is based on a proposal submitted to the EPA by a group of Navajo Generating Station stakeholders. The EPA accepted comments on the various alternatives through January 6, 2014 and, in August 2014, the EPA announced it had approved the final plan for the Navajo Generating Station ~~including~~voted to shut down and demolish the ~~reduction of emissions of nitrogen oxides~~plant on or before December 23, 2019; however, the owners agreed to continue operating the plant through 2019 with demolition to follow if the tribe approved a new lease by ~~approximately 80% through~~July 1, 2017. Subsequently, the ~~retirement of one unit, or~~Navajo Council approved the ~~curtailment of generation equivalent to one unit, in 2019~~requested lease extension June 26, 2017, and ~~installation of SCR controls at~~on July 1, 2017, the ~~other two units by 2030. In October 2014, several groups filed an appeal~~Navajo Nation signed the replacement lease with the utility owners of the ~~EPA's decision in~~Navajo Generating Station. Two remaining owners, the ~~Ninth Circuit; oral arguments were heard by the Ninth Circuit on November 18, 2016. The Hopi Tribe was initially part~~U.S. Bureau of the larger group appeal but their challenge was subsequently severed from that appeal and is proceeding separately. On March 20, 2017, the Ninth Circuit denied the petitions for review in the larger group appealReclamation and the ~~petition filed~~City of Los Angeles, must approve the lease by December 1, 2017, to enable continued operations through 2019. The Navajo Nation, along with the ~~Hopi Tribe, upholding~~U.S. Bureau of Reclamation and Peabody Energy have further indicated a desire to keep the ~~EPA’s ability~~plant and coal mine operating through at least 2030, which would require a new ownership structure for the facility. The utility owners have specified that a new ownership proposal must be put forward by October 1, 2017, in order to ~~issue a FIP on tribal land.~~complete the transition prior to December 23, 2019. Nevada Power filed the ~~ERCR~~Emissions Reduction and Capacity Replacement Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019, which was approved by the PUCN.

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. The Clean Power Plan, which was finalized by the EPA in 2015 and is currently under review, was the primary basis for the United States' commitment under the Paris Agreement.

On June 1, 2017, President Trump announced the United States would begin the four-year process of withdrawing from the Paris Agreement.

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-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards have been appealed to the D.C. Circuit and oral argument was scheduled to be heard April 17, ~~2017. In~~2017; however, the court cancelled the oral arguments March 30, 2017, ~~President Trump signed an Executive Order~~and, on Promoting Energy Independence and Economic Growth which includes a requirement to review and revise or rescind the new source performance standards. In response to the Executive Order, the Department of Justice requestedApril 28, 2017, ordered that the ~~court postpone the oral argument scheduled for April 17, 2017, and filed a motion to hold the case~~cases be held in abeyance for 3060 days, ~~after~~with supplemental briefs required to be filed May 15, 2017, regarding whether the ~~conclusion~~cases should be remanded to the EPA rather than held in abeyance. Until such time as the court renders a final determination regarding the validity of the ~~required regulatory review and any new rulemaking. On March 30, 2017,~~standards or the ~~court canceled~~EPA rescinds the ~~oral arguments pending disposition of the motion to hold the case in abeyance. Despite the pendency of the appeal and activities associated with implementing the Executive Order,~~standards, 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 EPA also changed the compliance period to begin in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh and 1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. The EPA also released in August 2015, a draft federal plan as an option or backstop for states to utilize in the event they do not submit approvable state plans. The public comment period on the draft federal plan and proposed model trading rules closed January 21, 2016. States were required to submit their initial implementation plans by September 2016 but could request an extension to September 2018. However, 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 U.S. Supreme Court. Oral argument was heard before the full D.C. Circuit (with the exception of Chief Judge Merrick Garland) on September 27, 2016, and the court has not yet issued its decision. AsIn accordance with an executive order issued March 28, 2017, the ~~new source performance standards,~~EPA signed a Federal Register notice March 28, 2017, announcing the ~~existing source standards are subject to~~EPA’s review of the rule and ~~revision or rescission under the Executive Order, and the Department of Justice~~EPA filed a motion ~~seeking~~ to ~~have~~hold the case ~~held~~ in abeyance pending completion of the EPA’s review and ~~associated action.~~any resulting rulemaking. On April 28, 2017, the D.C. Circuit issued an order holding the case in abeyance for 60 days and ordered the parties to file supplemental briefs addressing whether the case should be remanded to the EPA rather than held in abeyance. On June 8, 2017, the EPA sent its review of the Clean Power Plan to the Office of Management and Budget for interagency review. The full impacts of the final rule or the federal plan on the Registrants cannot be determined until the outcome of the pending litigation and subsequent appeals, the outcome of any issues should the case be remanded for further action by the EPA and the review of the rule and any subsequent action taken by the EPA in response to the Executive Order. 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 advancement of customer energy efficiency programs.

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. 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 guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal; the new limits ~~must be~~were to have been met as soon as possible, beginning November 1, 2018 and ~~must be~~ 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 that 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. The public comment period on EPA’s proposed extension of the deadlines closed July 5, 2017. While most of the issues raised by this rule 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 action is complete and any judicial review is concluded.

In April 2014, the EPA and the United States Army Corps of Engineers issued a joint proposal to address ~~"Waters~~"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 U.S. Supreme Court granted a petition to address jurisdictional challenges to the rule. On June 27, 2017, the EPA initiated the repeal of the “waters of the United States” 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. The proposed repeal of the rule has not yet been published in the Federal Register. Depending on the outcome of the appeal(s), and intended rulemaking, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits would have been required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. On February 28, 2017, President Trump signed an Executive Order directing the EPA to review and rescind or revise the rule. Until the rule is reviewed and rescinded or 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.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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, 2016. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2016.

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

Portland, Oregon

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of ~~March 31,~~June 30, 2017, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2017 and 2016, and of changes in shareholders' equity and cash flows for the ~~three-month~~six-month periods ended ~~March 31,~~June 30, 2017 and 2016. These interim financial statements are the responsibility of PacifiCorp's management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 Public Company Accounting Oversight Board (United States), 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.

Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them 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), the consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Portland, Oregon

~~May 5,~~August 4, 2017

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	March 31,		December 31,		June 30,		December 31,
	2017		2016		2017		2016
ASSETS

Current assets:
Cash and cash equivalents	$	15	$	17	$	167	$	17
Accounts receivable, net	633		728		681		728
Income taxes receivable	—		17		—		17
Inventories:
Materials and supplies	229		228		231		228
Fuel	212		215		224		215
Regulatory assets	35		53		28		53
Other current assets	78		96		75		96
Total current assets	1,202		1,354		1,406		1,354

Property, plant and equipment, net	19,130		19,162		19,141		19,162
Regulatory assets	1,535		1,490		1,535		1,490
Other assets	370		388		378		388

Total assets	$	22,237	$	22,394	$	22,460	$	22,394

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of						As of
	March 31,			December 31,			June 30,			December 31,
	2017			2016			2017			2016
LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	371		$	408		$	397		$	408
Income taxes payable	80			—			160			—
Accrued employee expenses	76			67			85			67
Accrued interest	106			115			115			115
Accrued property and other taxes	92			63			100			63
Short-term debt	8			270			—			270
Current portion of long-term debt and capital lease obligations	93			58			92			58
Regulatory liabilities	39			54			61			54
Other current liabilities	173			164			169			164
Total current liabilities	1,038			1,199			1,179			1,199

Regulatory liabilities	1,017			978			1,020			978
Long-term debt and capital lease obligations	6,934			7,021			6,935			7,021
Deferred income taxes	4,870			4,880			4,868			4,880
Other long-term liabilities	909			926			914			926
Total liabilities	14,768			15,004			14,916			15,004

Commitments and contingencies (Note 7)

Shareholders' equity:
Preferred stock	2			2			2			2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—			—			—			—
Additional paid-in capital	4,479			4,479			4,479			4,479
Retained earnings	3,000			2,921			3,075			2,921
Accumulated other comprehensive loss, net	(12		)	(12		)	(12		)	(12		)
Total shareholders' equity	7,469			7,390			7,544			7,390

Total liabilities and shareholders' equity	$	22,237		$	22,394		$	22,460		$	22,394



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)



Registrant	Yes	No
BERKSHIRE HATHAWAY ENERGY COMPANY	X
PACIFICORP	X
MIDAMERICAN FUNDING, LLC		X
MIDAMERICAN ENERGY COMPANY	X
NEVADA POWER COMPANY	X
SIERRA PACIFIC POWER COMPANY	X



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.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	~~138~~152
Item 4.	Controls and Procedures	~~138~~152



Item 1.	Legal Proceedings	~~139~~153
Item 1A.	Risk Factors	~~139~~153
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~139~~153
Item 3.	Defaults Upon Senior Securities	~~139~~153
Item 4.	Mine Safety Disclosures	~~139~~153
Item 5.	Other Information	~~139~~153
Item 6.	Exhibits	~~139~~153
Signatures		~~140~~154
Exhibit Index		~~141~~155



Berkshire Hathaway Energy Company and Related Entities
BHE		Berkshire Hathaway Energy Company
Berkshire Hathaway Energy or the Company		Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp		PacifiCorp and its subsidiaries
MidAmerican Funding		MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy		MidAmerican Energy Company
NV Energy		NV Energy, Inc. and its subsidiaries
Nevada Power		Nevada Power Company and its subsidiaries
Sierra Pacific		Sierra Pacific Power Company and its subsidiaries
Nevada Utilities		Nevada Power Company and Sierra Pacific Power Company
Registrants		Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, ~~LLC,~~ MidAmerican Energy, Nevada Power and Sierra Pacific
Subsidiary Registrants		PacifiCorp, MidAmerican Funding, ~~LLC,~~ MidAmerican Energy, Nevada Power and Sierra Pacific
Northern Powergrid		Northern Powergrid Holdings Company
Northern Natural Gas		Northern Natural Gas Company
Kern River		Kern River Gas Transmission Company
AltaLink		BHE Canada Holdings Corporation
ALP		AltaLink, L.P.
BHE U.S. Transmission		BHE U.S. Transmission, LLC
HomeServices		HomeServices of America, Inc. and its subsidiaries
BHE Pipeline Group or Pipeline Companies		Consists of Northern Natural Gas and Kern River
BHE Transmission		Consists of AltaLink and BHE U.S. Transmission
BHE Renewables		Consists of BHE Renewables, LLC and CalEnergy Philippines
Utilities		PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company
Berkshire Hathaway		Berkshire Hathaway Inc.
Pinyon Pines Projects		168-megawatt and 132-megawatt wind-powered generating facilities in California

Certain Industry Terms
AESO		Alberta Electric System Operator
AFUDC		Allowance for Funds Used During Construction
AUC		Alberta Utilities Commission
CPUC		California Public Utilities Commission
Dth		Decatherms
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GHG		Greenhouse Gases
GWh		Gigawatt Hours
GTA		General Tariff Application
IPUC		Idaho Public Utilities Commission
IUB		Iowa Utilities Board
kV		Kilovolt



MW		Megawatts
MWh		Megawatt Hours
OPUC		Oregon Public Utility Commission
PUCN		Public Utilities Commission of Nevada
REC		Renewable Energy Credit
RPS		Renewable Portfolio Standards
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
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		4756
Consolidated Balance Sheets		4857
Consolidated Statements of Operations		5059
Consolidated Statements of Changes in Shareholders' Equity		5160
Consolidated Statements of Cash Flows		5261
Notes to Consolidated Financial Statements		5362
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		6879
Balance Sheets		6980
Statements of Operations		7182
Statements of Changes in Equity		7283
Statements of Cash Flows		7384
Notes to Financial Statements		7485
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		8394
Consolidated Balance Sheets		8495
Consolidated Statements of Operations		8697
Consolidated Statements of Changes in Equity		8798
Consolidated Statements of Cash Flows		8899
Notes to Consolidated Financial Statements		89100
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~101~~113
Consolidated Balance Sheets		~~102~~114
Consolidated Statements of Operations		~~103~~115
Consolidated Statements of Changes in Shareholder's Equity		~~104~~116
Consolidated Statements of Cash Flows		~~105~~117
Notes to Consolidated Financial Statements		~~106~~118
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~120~~133
Consolidated Balance Sheets		~~121~~134
Consolidated Statements of Operations		~~122~~135
Consolidated Statements of Changes in Shareholder's Equity		~~123~~136
Consolidated Statements of Cash Flows		~~124~~137
Notes to Consolidated Financial Statements		~~125~~138



Berkshire Hathaway Energy Company and its subsidiaries		2831
PacifiCorp and its subsidiaries		6170
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		92103
Nevada Power Company and its subsidiaries		~~114~~126
Sierra Pacific Power Company and its subsidiaries		~~133~~146


	Three-Month Periods						Three-Month Periods						Six-Month Periods
	Ended March 31,						Ended June 30,						Ended June 30,
	2017			2016			2017			2016			2017			2016
Operating revenue:
Energy	$	3,581		$	3,550		$	3,598		$	3,280		$	7,179		$	6,830
Real estate	585			491			956			841			1,541			1,332
Total operating revenue	4,166			4,041			4,554			4,121			8,720			8,162

Operating costs and expenses:
Energy:
Cost of sales	1,119			1,095			1,049			970			2,168			2,065
Operating expense	883			882			950			909			1,833			1,791
Depreciation and amortization	610			619			660			640			1,270			1,259
Real estate	583			492			846			748			1,429			1,240
Total operating costs and expenses	3,195			3,088			3,505			3,267			6,700			6,355

Operating income	971			953			1,049			854			2,020			1,807

Other income (expense):
Interest expense	(458		)	(473		)	(457		)	(468		)	(915		)	(941		)
Capitalized interest	10			11			10			103			20			114
Allowance for equity funds	17			15			18			115			35			130
Interest and dividend income	26			27			27			27			53			54
Other, net	25			10			(3		)	1			22			11
Total other income (expense)	(380		)	(410		)	(405		)	(222		)	(785		)	(632		)

Income before income tax expense and equity income	591			543			644			632			1,235			1,175
Income tax expense	52			74			83			121			135			195
Equity income	24			26			26			34			50			60
Net income	563			495			587			545			1,150			1,040
Net income attributable to noncontrolling interests	7			5			13			9			20			14
Net income attributable to BHE shareholders	$	556		$	490		$	574		$	536		$	1,130		$	1,026


	BHE Shareholders' Equity																		BHE Shareholders' Equity
										Accumulated																		Accumulated
				Additional						Other												Additional						Other
	Common			Paid-in			Retained			Comprehensive			Noncontrolling			Total			Common			Paid-in			Retained			Comprehensive			Noncontrolling			Total
	Shares	Stock		Capital			Earnings			Loss, Net			Interests			Equity			Shares	Stock		Capital			Earnings			Loss, Net			Interests			Equity

Balance, December 31, 2015	77	$	—	$	6,403		$	16,906		$	(908	)	$	134		$	22,535		77	$	—	$	6,403		$	16,906		$	(908	)	$	134		$	22,535
Net income	—	—		—			490			—			4			494			—	—		—			1,026			—			8			1,034
Other comprehensive income	—	—		—			—			99			—			99
Other comprehensive loss																			—	—		—			—			(71		)	—			(71		)
Distributions	—	—		—			—			—			(4		)	(4		)	—	—		—			—			—			(9		)	(9		)
Balance, March 31, 2016	77	$	—	$	6,403		$	17,396		$	(809	)	$	134		$	23,124
Other equity transactions																			—	—		1						—			9			10
Balance, June 30, 2016																			77	$	—	$	6,404		$	17,932		$	(979	)	$	142		$	23,499

Balance, December 31, 2016	77	$	—	$	6,390		$	19,448		$	(1,511	)	$	136		$	24,463		77	$	—	$	6,390		$	19,448		$	(1,511	)	$	136		$	24,463
Net income	—	—		—			556			—			4			560			—	—		—			1,130			—			9			1,139
Other comprehensive income	—	—		—			—			126			—			126			—	—		—			—			422			—			422
Distributions	—	—		—			—			—			(7		)	(7		)	—	—		—			—			—			(12		)	(12		)
Common stock purchases	—	—		(1		)	(18		)	—			—			(19		)	—	—		(1		)	(18		)	—			—			(19		)
Common stock exchange																			—	—		(6		)	(94		)	—			—			(100		)
Other equity transactions	—	—		(8		)	—			—			(3		)	(11		)	—	—		(21		)	1			—			(3		)	(23		)
Balance, March 31, 2017	77	$	—	$	6,381		$	19,986		$	(1,385	)	$	130		$	25,112
Balance, June 30, 2017																			77	$	—	$	6,362		$	20,467		$	(1,089	)	$	130		$	25,870


		As of							As of
	Depreciable	March 31,			December 31,			Depreciable	June 30,			December 31,
	Life	2017			2016			Life	2017			2016
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	71,308		$	71,536		5-80 years	$	72,317		$	71,536
Interstate natural gas pipeline assets	3-80 years	6,944			6,942			3-80 years	6,969			6,942
		78,252			78,478				79,286			78,478
Accumulated depreciation and amortization		(23,515		)	(23,603		)		(24,029		)	(23,603		)
Regulated assets, net		54,737			54,875				55,257			54,875

Nonregulated assets:
Independent power plants	5-30 years	5,856			5,594			5-30 years	5,880			5,594
Other assets	3-30 years	1,081			1,002			3-30 years	1,164			1,002
		6,937			6,596				7,044			6,596
Accumulated depreciation and amortization		(1,136		)	(1,060		)		(1,222		)	(1,060		)
Nonregulated assets, net		5,801			5,536				5,822			5,536

Net operating assets		60,538			60,411				61,079			60,411
Construction work-in-progress		2,350			2,098				2,607			2,098
Property, plant and equipment, net		$	62,888		$	62,509			$	63,686		$	62,509


						Unit of	June 30,		December 31,
	Unit of	March 31,		December 31,		Measure	2017		2016
	Measure	2017		2016
Electricity purchases	Megawatt hours	10		5		Megawatt hours	11		5
Natural gas purchases	Decatherms	305		271		Decatherms	279		271
Fuel purchases	Gallons	8		11		Gallons	5		11
Interest rate swaps	US$	814		714		US$	694		714
Mortgage sale commitments, net	US$	(143	)	(309	)	US$	(348	)	(309	)


	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, 2017
As of June 30, 2017
Assets:
Commodity derivatives	$	1		$	26		$	95		$	(16	)	$	106		$	2		$	26		$	96		$	(19	)	$	105
Interest rate derivatives	—			9			12			—			21			—			8			10			—			18
Mortgage loans held for sale	—			218			—			—			218			—			408			—			—			408
Money market mutual funds⁽²⁾	828			—			—			—			828			773			—			—			—			773
Debt securities:
United States government obligations	163			—			—			—			163			161			—			—			—			161
International government obligations	—			4			—			—			4			—			4			—			—			4
Corporate obligations	—			35			—			—			35			—			36			—			—			36
Municipal obligations	—			2			—			—			2			—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			1			—			—			1			—			1			—			—			1
Equity securities:
United States companies	263			—			—			—			263			270			—			—			—			270
International companies	1,255			—			—			—			1,255			1,388			—			—			—			1,388
Investment funds	171			—			—			—			171			175			—			—			—			175
	$	2,681		$	295		$	107		$	(16	)	$	3,067		$	2,769		$	485		$	106		$	(19	)	$	3,341
Liabilities:
Commodity derivatives	$	(2	)	$	(220	)	$	(23	)	$	104		$	(141	)	$	(2	)	$	(211	)	$	(15	)	$	103		$	(125	)
Interest rate derivatives	(1		)	(11		)	(3		)	—			(15		)	—			(12		)	(2		)	—			(14		)
	$	(3	)	$	(231	)	$	(26	)	$	104		$	(156	)	$	(2	)	$	(223	)	$	(17	)	$	103		$	(139	)



As of December 31, 2016
Assets:
Commodity derivatives	$	5		$	49		$	87		$	(22	)	$	119
Interest rate derivatives	—			16			7			—			23
Mortgage loans held for sale	—			359			—			—			359
Money market mutual funds⁽²⁾	586			—			—			—			586
Debt securities:
United States government obligations	161			—			—			—			161
International government obligations	—			3			—			—			3
Corporate obligations	—			36			—			—			36
Municipal obligations	—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			2			—			—			2
Equity securities:
United States companies	250			—			—			—			250
International companies	1,190			—			—			—			1,190
Investment funds	147			—			—			—			147
	$	2,339		$	467		$	94		$	(22	)	$	2,878
Liabilities:
Commodity derivatives	$	(2	)	$	(199	)	$	(27	)	$	96		$	(132	)
Interest rate derivatives	(1		)	(11		)	(1		)	—			(13		)
	$	(3	)	$	(210	)	$	(28	)	$	96		$	(145	)


(1)	General


(3)	Business Acquisitions


(4)	Property, Plant and Equipment, Net


(5)	Investments and Restricted Cash and Investments


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $8884 million and $74 million as of ~~March 31,~~June 30, 2017 and December 31, 2016, 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.



	As of March 31, 2017				As of December 31, 2016
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	36,417	$	41,112	$	36,116	$	40,718


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

Balance, December 31, 2015	$	(438	)	$	(1,092	)	$	615	$	7		$	(908	)	$	(438	)	$	(1,092	)	$	615	$	7		$	(908	)
Other comprehensive income (loss)	22			67			33		(23		)	99			62			(205		)	71		1			(71		)
Balance, March 31, 2016	$	(416	)	$	(1,025	)	$	648	$	(16	)	$	(809	)
Balance, June 30, 2016															$	(376	)	$	(1,297	)	$	686	$	8		$	(979	)

Balance, December 31, 2016	$	(447	)	$	(1,675	)	$	585	$	26		$	(1,511	)	$	(447	)	$	(1,675	)	$	585	$	26		$	(1,511	)
Other comprehensive income (loss)	5			87			38		(4		)	126			1			308			119		(6		)	422
Balance, March 31, 2017	$	(442	)	$	(1,588	)	$	623	$	22		$	(1,385	)
Balance, June 30, 2017															$	(446	)	$	(1,367	)	$	704	$	20		$	(1,089	)


Interest expense:
PacifiCorp	$	95	$	95	$	95	$	96	$	190	$	191
MidAmerican Funding	59		54		59		55		118		109
NV Energy	58		67		58		63		116		130
Northern Powergrid	31		36		33		36		64		72
BHE Pipeline Group	12		13		10		13		22		26
BHE Transmission	41		36		39		38		80		74
BHE Renewables	50		49		52		48		102		97
HomeServices	1		1		1		—		2		1
BHE and Other⁽¹⁾	111		122		110		119		221		241
Total interest expense	$	458	$	473	$	457	$	468	$	915	$	941


Operating revenue by country:
United States	$	3,747	$	3,599	$	4,177	$	3,889		$	7,924	$	7,488
United Kingdom	245		279		219		249			464		528
Canada	166		160		158		(17		)	324		143
Philippines and other	8		3		—		—			8		3
Total operating revenue by country	$	4,166	$	4,041	$	4,554	$	4,121		$	8,720	$	8,162


(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.


									BHE																				BHE
			MidAmerican		NV		Northern		Pipeline			BHE		BHE		Home-							MidAmerican		NV		Northern		Pipeline			BHE		BHE		Home-
	PacifiCorp		Funding		Energy		Powergrid		Group			Transmission		Renewables		Services		Total			PacifiCorp		Funding		Energy		Powergrid		Group			Transmission		Renewables		Services		Total

December 31, 2016	$	1,129	$	2,102	$	2,369	$	930	$	75		$	1,470	$	95	$	840	$	9,010		$	1,129	$	2,102	$	2,369	$	930	$	75		$	1,470	$	95	$	840	$	9,010
Acquisitions	—		—		—		—		—			—		—		100		100			—		—		—		—		—			—		—		106		106
Foreign currency translation	—		—		—		12		—			13		—		—		25			—		—		—		36		—			54		—		—		90
Other	—		—		—		—		(2		)	—		—		—		(2		)	—		—		—		—		(2		)	—		—		—		(2		)
March 31, 2017	$	1,129	$	2,102	$	2,369	$	942	$	73		$	1,483	$	95	$	940	$	9,133
June 30, 2017																					$	1,129	$	2,102	$	2,369	$	966	$	73		$	1,524	$	95	$	946	$	9,204


	First Quarter											Second Quarter											First Six Months
	2017			2016			Change					2017			2016			Change					2017			2016			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	179		$	165		$	14		8	%	$	176		$	177		$	(1	)	(1	)%	$	355		$	342		$	13		4	%
MidAmerican Funding	102			73			29			40		131			127			4			3		233			200			33			17
NV Energy	33			21			12			57		91			76			15			20		124			97			27			28
Northern Powergrid	82			98			(16		)	(16	)	53			70			(17		)	(24	)	135			168			(33		)	(20	)
BHE Pipeline Group	121			109			12			11		27			30			(3		)	(10	)	148			139			9			6
BHE Transmission	60			48			12			25		53			68			(15		)	(22	)	113			116			(3		)	(3	)
BHE Renewables	34			12			22			*		71			32			39			*		105			44			61			*
HomeServices	—			1			(1		)	(100	)	62			55			7			13		62			56			6			11
BHE and Other	(55		)	(37		)	(18		)	(49	)	(90		)	(99		)	9			9		(145		)	(136		)	(9		)	(7	)
Total net income attributable to BHE shareholders	$	556		$	490		$	66		13		$	574		$	536		$	38		7		$	1,130		$	1,026		$	104		10


Operating income:
PacifiCorp	$	345		$	324		$	21		6	%	$	338		$	339		$	(1	)	—	%	$	683		$	663		$	20		3	%
MidAmerican Funding	107			100			7			7		136			140			(4		)	(3	)	243			240			3			1
NV Energy	98			89			9			10		191			173			18			10		289			262			27			10
Northern Powergrid	133			158			(25		)	(16	)	94			125			(31		)	(25	)	227			283			(56		)	(20	)
BHE Pipeline Group	208			192			16			8		55			60			(5		)	(8	)	263			252			11			4
BHE Transmission	77			76			1			1		73			(122		)	195			*		150			(46		)	196			*
BHE Renewables	15			24			(9		)	(38	)	84			52			32			62		99			76			23			30
HomeServices	2			(1		)	3			*		110			93			17			18		112			92			20			22
BHE and Other	(14		)	(9		)	(5		)	(56	)	(32		)	(6		)	(26		)	*		(46		)	(15		)	(31		)	*
Total operating income	$	971		$	953		$	18		2		$	1,049		$	854		$	195		23		$	2,020		$	1,807		$	213		12


	Three-Month Periods				Annual		Six-Month Periods					Annual
	Ended March 31,				Forecast		Ended June 30,					Forecast
	2016		2017		2017		2016			2017		2017
Capital expenditures by business:
PacifiCorp	$	201	$	178	$	837	$	415		$	370	$	825
MidAmerican Funding	332		238		1,783		506			546		1,893
NV Energy	146		99		427		274			226		439
Northern Powergrid	155		151		629		307			288		591
BHE Pipeline Group	30		38		366		74			83		362
BHE Transmission	112		85		329		272			146		340
BHE Renewables	45		71		230		242			137		310
HomeServices	4		5		32		8			11		32
BHE and Other	2		—		23		5		��	6		22
Total	$	1,027	$	865	$	4,656	$	2,103		$	1,813	$	4,814


Capital expenditures by type:
Wind generation	$	105	$	49	$	1,063	$	370	$	234	$	1,343
Solar generation	5		51		148		9		52		127
Electric transmission	115		92		352		234		190		353
Environmental	16		—		130		31		35		132
Other growth	92		136		552		198		256		567
Operating	694		537		2,411		1,261		1,046		2,292
Total	$	1,027	$	865	$	4,656	$	2,103	$	1,813	$	4,814


(1)	PacifiCorp's commodity derivatives are generally included in rates and as of ~~March 31,~~June 30, 2017 and December 31, 2016, a regulatory asset of ~~$103~~$95 million and $73 million, respectively, was recorded related to the net derivative liability of ~~$107~~$99 million and $77 million, respectively.


(1)	Prior period GWh amounts have been reclassified for consistency with the current period presentation.


(2)	GWh amounts are net of energy used by the related generating facilities.


~~(2)~~(3)	All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.


~~(3)~~(4)	The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.



Cash and cash equivalents	$	15

Credit facilities	1,000
Less:
Short-term debt	(8		)
Tax-exempt bond support	(92		)
Net credit facilities	900

Total net liquidity	$	915

Credit facilities:
Maturity dates	2018, 2019


	Common Stock		Retained Earnings			Accumulated Other Comprehensive Loss, Net			Total Equity			Common Stock		Retained Earnings			Accumulated Other Comprehensive Loss, Net			Total Equity

Balance, December 31, 2015	$	561	$	4,174		$	(30	)	$	4,705		$	561	$	4,174		$	(30	)	$	4,705
Net income	—		76			—			76			—		207			—			207
Other comprehensive income	—		—			1			1			—		—			2			2
Dividend	—		(117		)	27			(90		)	—		(117		)	27			(90		)
Balance, March 31, 2016	$	561	$	4,133		$	(2	)	$	4,692
Other equity transactions												$	—	$	(1	)	$	—		$	(1	)
Balance, June 30, 2016												$	561	$	4,263		$	(1	)	$	4,823

Balance, December 31, 2016	$	561	$	4,599		$	—		$	5,160		$	561	$	4,599		$	—		$	5,160
Net income	—		105			—			105			—		239			—			239
Balance, March 31, 2017	$	561	$	4,704		$	—		$	5,265
Other equity transactions												—		(1		)	—			(1		)
Balance, June 30, 2017												$	561	$	4,837		$	—		$	5,398



	As of March 31, 2017				As of December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	4,894	$	5,353	$	4,301	$	4,735