MidAmerican Energy

Under Iowa law, there are two options for temporary collection of higher rates following the filing of a request for a base rate increase. Collection can begin, subject to refund, either (1) within 10 days of filing, without IUB review, or (2) 90 days after filing, with approval by the IUB, depending upon the ratemaking principles and precedents utilized. In either case, if the IUB has not issued a final order within ten months after the filing date, the temporary rates become final and any difference between the requested rate increase and the temporary rates may then be collected subject to refund until receipt of a final order. Under Illinois law, new base rates may become effective 45 days after the filing of a request with the ICC, or earlier with ICC approval. The ICC has authority to suspend the proposed new rates, subject to hearing, for a period not to exceed approximately eleven months after filing. South Dakota law authorizes the SDPUC to suspend new base rates for up to six months during the pendency of rate proceedings; however, a utility may implement all or a portion of the proposed new rates six months after the filing of a request for a rate increase subject to refund pending a final order in the proceeding.

Iowa law also permits rate-regulated utilities to seek ratemaking principles with the IUB prior to the construction of certain types of new generating facilities. Pursuant to this law, MidAmerican Energy has applied for and obtained IUB ratemaking principles orders for a 484-MW (MidAmerican Energy's share) coal-fueled generating facility, a 495-MW combined cycle natural gas-fueled generating facility and ~~4,048~~6,048 MW (nominal ratings) of wind-powered generating facilities, including ~~599~~1,666 MW (nominal ratings) under construction, as of December 31, ~~2015.~~2017. These ratemaking principles established cost caps for the projects and authorized a fixed rate of return on equity for the respective generating facilities over the regulatory life of the facilities in any future Iowa rate proceeding. As of December 31, ~~2015,~~2017, the generating facilities ~~in-service~~in service totaled ~~$4.9~~$5.9 billion, or 42%, of MidAmerican Energy's regulated property, plant and equipment, net and were subject to these ratemaking principles at a weighted average return on equity of ~~11.9%~~11.7% with a weighted average remaining life of 2431 years.

Under its current Iowa, Illinois and South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in electric energy costs for its retail electric ~~generation~~sales through fuel, or energy, cost adjustment mechanisms. The Iowa mechanism also includes production tax credits associated with wind-powered generation placed in-service prior to ~~2013.~~2013, except for production tax credits earned by repowered facilities, which totaled 414 MW as of December 31, 2017. Eligibility for production tax credits associated with MidAmerican Energy's earliest projects began expiring in 2014. Additionally, MidAmerican Energy has transmission adjustment clauses to recover certain transmission charges related to retail customers in ~~Iowa and Illinois.~~all jurisdictions. The adjustment mechanisms reduce the regulatory lag for the recovery of energy and transmission costs related to retail electric customers in these jurisdictions.

Of the wind-powered generating facilities placed in-service as of December 31, ~~2015, 1,212~~2017, 2,097 MW (nominal ratings) have not been included in the determination of MidAmerican ~~Energy’s~~Energy's Iowa retail electric base rates. In accordance with the related ratemaking principles, until such time as these generation assets are reflected in base rates and ceasing thereafter, MidAmerican Energy ~~is to reduce~~reduced its revenue from Iowa energy adjustment clause recoveries by $5 million in 2015 and $9 million in 2016 and is to reduce its recoveries by $12 million for each calendar year thereafter.

MidAmerican Energy has mechanisms in Iowa where rate base may be reduced, including revenue sharing and retail customer benefits attributable to most of the wind-powered generating facilities placed in-service in 2016 ("Wind X"). The revenue sharing mechanism originates from multiple ratemaking principles proceedings and reduces rate base for Iowa electric returns on equity exceeding an established benchmark. The Wind X customer benefit mechanism reduces rate base for the value of higher cost retail energy displaced by Wind X production.

MidAmerican Energy's cost of gas is collected for each jurisdiction in its gas rates through a uniform PGA, which is updated monthly to reflect changes in actual costs. Subject to prudence reviews, the PGA accomplishes a pass-through of MidAmerican Energy's cost of gas to its customers and, accordingly, has no direct effect on net income. MidAmerican Energy's DSM program costs are collected through separately established rates that are adjusted annually based on actual and expected costs, as approved by the respective state regulatory commission. As such, recovery of DSM program costs has no direct impact on net income.

NV Energy (Nevada Power and Sierra Pacific)

Rate Filings

Nevada statutes require the Nevada Utilities to file electric general rate cases at least once every three years with the PUCN. Sierra Pacific may also file natural gas general rate cases with the PUCN. The Nevada Utilities are also subject to a two-part fuel and purchased power adjustment mechanism. The Nevada Utilities make quarterly filings to reset BTER, based on the last 12 months of fuel and purchased power costs. The difference between actual fuel and purchased power costs and the revenue collected in the BTER is deferred into a balancing account. During required annual DEAA proceedings, the prudence of fuel and purchased power costs is reviewed, and if any costs are disallowed on such grounds, the disallowances will be incorporated into the next subsequent quarterly BTER rate change. Additionally, Nevada regulations allow an electric or natural gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. The Nevada Utilities received approval from the PUCN and file quarterly adjustments to the DEAA rate to clear amounts deferred into the balancing account. AtDuring required annual DEAA proceedings, the ~~same time~~prudence of fuel and purchased power costs is reviewed, and if any costs are disallowed on such grounds, the disallowances will be incorporated into the next quarterly BTER rate change. Also, on an annual basis, the Nevada Utilities ~~make the annual DEAA filing, they also~~ (a) seek a determination that energy efficiency program expenditures were reasonable, (b) request that the PUCN reset base and amortization energy efficiency program rates, and (c) request that the ~~Commission~~PUCN reset base and amortization energy efficiency implementation ~~(formerly lost revenue)~~ rates. When the Nevada ~~Utilities’~~Utilities' regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, they are obligated to refund energy efficiency implementation revenue previously collected for that year.

Energy Choice Initiative - Deregulation

In November 2016, a majority of Nevada voters supported a ballot measure to amend Article 1 of the Nevada Constitution. If approved again in 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 have been engaged in the legislative process before the Governor's committee and related proceedings before the PUCN and the legislature. The Nevada Utilities 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 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.

Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Natural Gas Act ("NGA"), the Energy Policy Act of 2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding companies; accounting and records retention; securities issuances; construction and operation of hydroelectric facilities; and other matters. The FERC also has the enforcement authority to assess civil penalties of up to $1$1.2 million per day per violation of rules, regulations and orders issued under the Federal Power Act. The Utilities have implemented programs and procedures that facilitate and monitor compliance with the FERC's regulations described below. MidAmerican Energy is also subject to regulation by the NRC pursuant to the Atomic Energy Act of 1954, as amended ("Atomic Energy Act"), with respect to its ownership interest in the Quad Cities Station.

Wholesale Electricity and Capacity

The FERC regulates the Utilities' rates charged to wholesale customers for electricity and transmission capacity and related services. ~~Most~~Much of the Utilities' wholesale electricity sales and purchases occur under market-based pricing allowed by the FERC and are therefore subject to market volatility. As a result of a 2016 order from the FERC following BHE's acquisition of NV Energy, the Utilities are precluded from selling at market-based rates in the PacifiCorp-East, PacifiCorp-West, Idaho Power Company and NorthWestern Energy balancing authority areas. The Utilities had previously relinquished their market-based rate authority in the NV Energy balancing authority area. Wholesale electricity sales in those specific balancing authority areas are permitted at cost-based rates. On October 30, 2017, the FERC granted the application of PacifiCorp, Nevada Power and Sierra Pacific for authority to bid into the California EIM at market-based rates.

The Utilities' authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the Utilities are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. ~~PacifiCorp's~~PacifiCorp, the Nevada Utilities and certain affiliates, representing the BHE Northwest Companies, file together for market power study purposes. The BHE Northwest Companies' most recent triennial filing was made in June ~~2013~~2016 and, ~~is currently pending before~~as to its non-mitigated balancing authority areas, was approved in November 2017. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC. On December 9, 2014, the FERC issued an order requesting that the BHE subsidiaries having authority to sell power and energy at market-based rates, including the Utilities, show cause why their market-based rate authority remains just and reasonable following BHE's acquisition of NV Energy. This proceeding, which is focused on the western interconnection, remains ongoing. MidAmerican Energy'sFERC-defined Northeast Region. The most recent triennial ~~filings were submitted~~filing for the Northeast Region was made in June ~~2014~~2017 and an order accepting it was issued in January 2018. MidAmerican Energy and certain affiliates file together for ~~the FERC-defined Northeast Region and December 2014 for~~market power study purposes of the FERC-defined Central Region. The ~~June 2014 triennial filing was accepted by the FERC in January 2015, and the December 2014 triennial filing was accepted by the FERC in November 2015. The Nevada Utilities'~~ most recent triennial filing for the Central Region was made in ~~July 2013~~December 2017 and ~~approved by~~is currently pending with the ~~FERC in April 2014. In July 2016, the Nevada Utilities plan to make their triennial filing.~~FERC. Under the FERC's market-based rules, the Utilities must also file with the FERC a notice of change in status when there is a change in the conditions that the FERC relied upon in granting market-based rate authority.

Transmission

PacifiCorp's and the Nevada Utilities' wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp's and the Nevada Utilities' OATT, respectively. These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp's and the Nevada Utilities' transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC's Standards of Conduct. PacifiCorp and the Nevada Utilities have made several required compliance filings in accordance with these rules.

In December 2011, PacifiCorp adopted a cost-based formula rate under its OATT for its transmission services. Cost-based formula rates are intended to be an effective means of recovering PacifiCorp's investments and associated costs of its transmission system without the need to file rate cases with the FERC, although the formula rate results are subject to discovery and challenges by the FERC and intervenors. A significant portion of these services are provided to PacifiCorp's energy supply management function.

MidAmerican Energy participates in the MISO as a transmission-owning member. Accordingly, the MISO is the transmission provider under its FERC-approved OATT. While the MISO is responsible for directing the operation of MidAmerican Energy's transmission system, MidAmerican Energy retains ownership of its transmission assets and, therefore, is subject to the FERC's reliability standards discussed below. MidAmerican Energy's transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC Standards of Conduct.

MidAmerican Energy has approval from the MISO to construct and own four Multi-Value Projects ("MVPs") located in Iowa and Illinois that will ~~add~~have added approximately ~~245~~250 miles of 345 kV transmission line to MidAmerican Energy's transmission ~~system.~~system since 2012, of which 224 miles have been placed in-service as of December 31, 2017. The MISO OATT allows for broad cost allocation for MidAmerican Energy's MVPs, including similar MVPs of other MISO participants. Accordingly, a significant portion of the revenue requirement associated with MidAmerican Energy's MVP investments will be shared with other MISO participants based on the MISO's cost allocation methodology, and a portion of the revenue requirement of the other participants' MVPs will be allocated to MidAmerican Energy. Additionally, MidAmerican Energy has approval from the FERC to include 100% of construction work in progress in the determination of rates for its MVPs and to use a forward-looking rate structure for all of its transmission investments and costs. The transmission assets and financial results of MidAmerican Energy's MVPs are excluded from the determination of its retail electric rates.

The FERC has established an extensive number of mandatory reliability standards developed by the NERC and the WECC, including planning and operations, critical infrastructure protection and regional standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the ~~FERC,~~FERC; the ~~NERC~~NERC; and the WECC for PacifiCorp, Nevada Power, and Sierra ~~Pacific~~Pacific; and the Midwest Reliability Organization for MidAmerican Energy.

Hydroelectric

The FERC licenses and regulates the operation of hydroelectric systems, including license compliance and dam safety programs. Most of PacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Under the Federal Power Act, 1617 dams associated with PacifiCorp's hydroelectric generating facilities licensed with the FERC are classified as "high hazard potential," meaning it is probable in the event of dam failure that loss of human life in the downstream population could occur. The FERC provides guidelines utilized by PacifiCorp in development of public safety programs consisting of a dam safety program and emergency action plans.

PacifiCorp's Klamath River hydroelectric system is the only significant hydroelectric system for which PacifiCorp ~~is currently engaged in the~~has a pending relicensing process with the FERC. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 13 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for an update regarding hydroelectric relicensing for PacifiCorp's Klamath River hydroelectric system.

Nuclear Regulatory Commission

General

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station. Exelon Generation, the operator and 75% owner of Quad Cities Station, is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.

The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. Current licenses for Quad Cities Station provide for operation until December 14, 2032. The NRC review and regulatory process covers, among other things, operations, maintenance and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.

Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.

The NRC also regulates the decommissioning of ~~nuclear powered~~nuclear-powered generating facilities, including the planning and funding for the eventual decommissioning of the facilities. In accordance with these regulations, MidAmerican Energy submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay its share of the costs of decommissioning Quad Cities Station. MidAmerican Energy has established a trust for the investment of funds collected for nuclear decommissioning of Quad Cities Station. ~~The decommissioning costs are included in base rates in MidAmerican Energy's Iowa tariffs.~~

Under the Nuclear Waste Policy Act of 1982 ("NWPA"), the U.S. Department of Energy ("DOE") is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Exelon Generation, as required by the NWPA, signed a contract with the DOE under which the DOE was to receive spent nuclear fuel and high-level radioactive waste for disposal beginning not later than January 1998. The DOE did not begin receiving spent nuclear fuel on the scheduled date and remains unable to receive such fuel and waste. The costs to be incurred by the DOE for disposal activities were previously being financed by fees charged to owners and generators of the waste. In accordance with a 2013 ruling by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit"), the DOE, in May 2014, provided notice that, effective May 16, 2014, the spent nuclear fuel disposal fee would be zero. In 2004, Exelon Generation, reached a settlement with the DOE concerning the DOE's failure to begin accepting spent nuclear fuel in 1998. As a result, Quad Cities Station has been billing the DOE, and the DOE is obligated to reimburse the station for all station costs incurred due to the DOE's delay. Exelon Generation has completed construction of an interim spent fuel storage installation ("ISFSI") at Quad Cities Station to store spent nuclear fuel in dry casks in order to free space in the storage pool. The first pad at the ISFSI is expected to facilitate storage of casks to support operations at Quad Cities Station until at least 2020. The first storage in a dry cask commenced in November 2005. By 2020, Exelon Generation plans to add a second pad to the ISFSI to accommodate storage of spent nuclear fuel through the end of operations at Quad Cities Station.

Nuclear Insurance

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation, insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988 ("Price-Anderson"), which was amended and extended by the Energy Policy Act. The general types of coverage maintained are: nuclear liability, property damage or loss and nuclear worker liability, as discussed below.

Exelon Generation purchases private market nuclear liability insurance for Quad Cities Station in the maximum available amount of ~~$375~~$450 million, which includes coverage for MidAmerican Energy's ownership. In accordance with Price-Anderson, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Quad Cities Station is approximately $64 million per incident, payable in installments not to exceed $10 million annually.

The insurance for nuclear property ~~insurance~~damage losses covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Exelon Generation purchases primary and excess property insurance protection for the combined interests in Quad Cities Station, with coverage limits ~~totaling~~for nuclear damage losses up to $1.5 billion and non-nuclear property damage losses up to $2.1 billion. MidAmerican Energy also directly purchases extra expense coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments to be called upon based on the industry mutual board of directors' discretion for adverse loss experience. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $9 million.

The master nuclear worker liability coverage, which is purchased by Exelon Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of ~~$375~~$450 million for the nuclear industry as a whole, which is in effect to cover tort claims of workers in nuclear-related industries.

United States Mine Safety

PacifiCorp's mining operations are regulated by the Federal Mine Safety and Health Administration, which administers federal mine safety and health laws and regulations, and state regulatory agencies. The Federal Mine Safety and Health Administration has the statutory authority to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay penalties or fines for violations of federal mine safety standards. Federal law requires PacifiCorp to have a written emergency response plan specific to each underground mine it operates, which is reviewed by the Federal Mine Safety and Health Administration every six months, and to have at least two mine rescue teams located within one hour of each mine. Information regarding PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.

Interstate Natural Gas Pipeline Subsidiaries

The Pipeline Companies are regulated by the FERC, pursuant to the NGA and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, ~~rates; charges;~~(a) rates, charges, terms and conditions of ~~service;~~service and (b) the construction and operation of interstate pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities. The Pipeline Companies hold certificates of public convenience and necessity issued by the FERC, which authorize them to construct, operate and maintain their pipeline and related facilities and services.

FERC regulations and the Pipeline Companies' tariffs allow each of the Pipeline Companies to charge approved rates for the services set forth in their respective tariff. Generally, these rates are a function of the cost of providing services to their customers, including prudently incurred operations and maintenance expenses, taxes, ~~interest,~~ depreciation and amortization and a reasonable return on their investments. Both Northern Natural Gas' and Kern River's tariff rates have been developed under a rate design methodology whereby substantially all of their fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid by firm transportation and storage customers regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, costs. Kern River's reservation rates have historically been approved using a "levelized" cost-of-service methodology so that the rate remains constant over the levelization period. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense and return on equity amounts decrease. Both Northern Natural Gas' and Kern River's rates are subject to change in future general rate proceedings.

Natural gas transportation companies may not grant any undue preference to any customer. FERC regulations also restrict each pipeline's marketing affiliates' access to certain non-public information regarding their affiliated interstate natural gas transmission pipelines.

Interstate natural gas pipelines are also subject to regulations administered by the Office of Pipeline Safety within the Pipeline and Hazardous Materials Safety Administration, an agency within the United States Department of Transportation ("DOT"). Federal pipeline safety regulations are issued pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("NGPSA"), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas facilities, and requires an entity that owns or operates pipeline facilities to comply with such plans. Major amendments to the NGPSA include the Pipeline Safety Improvement Act of 2002 ("2002 Act"), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 ("2006 Act") ~~and~~, the Pipeline Safety, Regulatory Certainty, ~~and~~ Job Creation Act of 2011 ("2011 Act") and the Protecting Our Infrastructure Of Pipelines And Enhancing Safety Act Of 2016 ("2016 Act").

The 2002 Act established additional safety and pipeline integrity regulations for all natural gas pipelines in high-consequence areas. The 2002 Act imposed major new requirements in the areas of operator qualifications, risk analysis and integrity management. The 2002 Act mandated more frequent periodic inspection or testing of natural gas pipelines in high-consequence areas, which are locations where the potential consequences of a natural gas pipeline accident may be significant or may do considerable harm to persons or property. Pursuant to the 2002 Act, the DOT promulgated new regulations that require natural gas pipeline operators to develop comprehensive integrity management programs, to identify applicable threats to natural gas pipeline segments that could impact high-consequence areas, to assess these segments and to provide ongoing mitigation and monitoring. The regulations ~~required that all baseline high-consequence area segments be assessed by December 17, 2012 and~~ require recurring inspections of high consequence area segments every seven years ~~thereafter. Based on~~after the ~~Pipeline Companies' extensive compliance efforts, they have~~initial baseline assessment which was completed ~~all required high-consequence area pipeline baseline integrity assessments.~~by Kern River ~~also completed the required in-line inspections~~ in early 2011 ~~on that portion of its pipeline system required by the conditions associated with a special permit which allowed for an increase to the maximum allowable operating pressure.~~and Northern Natural Gas in 2012.

The 2006 Act required pipeline operators to institute human factors management plans for personnel employed in pipeline control centers. DOT regulations published pursuant to the 2006 Act required development and implementation of written control room management procedures.

The 2011 Act was a response to natural gas pipeline incidents, most notably the San Bruno natural gas pipeline explosion that occurred in September 2010 in California. The 2011 Act increased the maximum allowable civil penalties for violations, directs operator assistance for Federal authorities conducting investigations and authorized the DOT to hire additional inspection and enforcement personnel. The 2011 Act also directed the DOT to study several topics, including the definition of high-consequence areas, the use of automatic shutoff valves in high-consequence areas, expansion of integrity management requirements beyond high-consequence areas and cast iron pipe replacement. The studies are complete, and ~~the~~a number of notices of proposed rulemaking have been issued. The BHE Pipeline Group ~~anticipate notices~~anticipates final rules on a number of ~~proposed rules at some point~~areas sometime in ~~2016 on each of the areas studied.~~2018. The BHE Pipeline Group cannot currently assess the potential cost of compliance with new rules and regulations under the 2011 Act.

The 2016 Actrequired the Pipeline and Hazardous Materials Safety Administration to set federal minimum safety standards for underground natural gas storage facilities and authorized emergency order (interim final rule) authority. The Pipeline and Hazardous Materials Safety Administration issued an interim final rule requiring underground natural gas storage field operators to implement the requirements of the American Petroleum Institute ("API") Recommended Practice 1171, "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs." Northern Natural Gas has three underground natural gas storage fields which fall under this regulation and has implemented programs to be in full compliance with this regulation. Kern River does not have underground natural gas storage facilities.

The DOT and related state agencies routinely audit and inspect the pipeline facilities for compliance with their regulations. The Pipeline Companies conduct internal audits of their facilities every four ~~years;~~years with more frequent reviews of those deemed higher risk. The Pipeline Companies also conduct preliminary audits in advance of agency audits. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis. The Pipeline Companies believe their pipeline systems comply in all material respects with the NGPSA and with DOT regulations issued pursuant to the NGPSA.

Northern Powergrid Distribution Companies

The Northern Powergrid Distribution Companies, as holders of electricity distribution licenses, are subject to regulation by GEMA. GEMA regulates distribution network operators ("DNOs") within the terms of the Electricity Act 1989 and the terms of DNO licenses, which are revocable with 25 years notice. Under the Electricity Act 1989, GEMA has a duty to ensure that DNOs can finance their regulated activities and DNOs have a duty to maintain an investment grade credit rating. GEMA discharges certain of its duties through its staff within Ofgem. Each of fourteen licensed DNOs distributes electricity from the national grid transmission system to end users within its respective distribution services area.

DNOs are subject to price controls, enforced by Ofgem, that limit the revenue that may be recovered and retained from their electricity distribution activities. The regulatory regime that has been applied to electricity distributors in Great Britain encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DNOs to reflect a number of factors, including, but not limited to, the rate of inflation (as measured by the United Kingdom's Retail Prices Index) and the quality of service delivered by the licensee's distribution system. The current price control, Electricity Distribution 1 ("ED1"), has been set for a period of eight years, starting April 1, 2015, although the formula has been, and may be, reviewed by the regulator following public consultation. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Ofgem's judgment of the future allowed revenue of licensees is likely to take into account, among other things:

the actual operating and capital costs of each of the licensees;

the operating and capital costs that each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the more efficient licensees;

the actual value of certain costs which are judged to be beyond the control of the licensees;

the taxes that each licensee is expected to pay;

the regulatory value ascribed to the expenditures that have been incurred in the past and the efficient expenditures that are to be incurred in the forthcoming regulatory period;

the rate of return to be allowed on expenditures that make up the regulatory asset value;

the financial ratios of each of the licensees and the license requirement for each licensee to maintain investment grade status;

an allowance in respect of the repair of the pension deficits in the defined benefit pension schemes sponsored by each of the licensees; and

any under- or over-recoveries of revenues, relative to allowed revenues, in the previous price control period.

A number of incentive schemes also operate within the current price control period to encourage DNOs to provide an appropriate quality of service to end users. This includes specified payments to be made for failures to meet prescribed standards of service. The aggregate of these guaranteed standards payments is uncapped, but may be excused in certain prescribed circumstances that are generally beyond the control of the ~~DNO.~~DNOs.

A new price control can be implemented by GEMA without the consent of the ~~DNO,~~DNOs, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's ~~Competition and Markets Authority ("CMA"),~~CMA, as can certain other parties. Any appeals must be notified within 20 working days of the license modification by GEMA. If the CMA determines that the appellant has relevant standing, then the statute requires that the CMA complete its process within six months, or in some exceptional circumstances seven months. The Northern Powergrid Distribution Companies appealed Ofgem's proposals for the resetting of the formula that commenced April 1, 2015, as did one other party, and the CMA subsequently revised GEMA's decision.

The current electricity distribution price control became effective April 1, 2015 and is due to terminate on March 31, 2023, and will be immediately replaced with a new price control (in line with GEMA's current timetable). This price control is the first to be set for electricity distribution in Great Britain since Ofgem completed its review of network regulation (known as the RPI-X @ 20 project). The key changes to the price control calculations, compared to those used in previous price controls are that:

the period over which new regulatory assets are depreciated is being gradually lengthened, from 20 years to 45 years, with the change being phased over eight years;

allowed revenues will be adjusted during the price control period, rather than at the next price control review, to partially reflect cost variances relative to cost allowances;

the allowed cost of debt will be updated within the price control period by reference to a long-run trailing average based on external benchmarks of utility debt costs;

allowed revenues will be adjusted in relation to some new service standard incentives, principally relating to speed and service standards for new connections to the network; and

there is scope for a mid-period review and adjustment to revenues in the latter half of the period for any changes in the outputs required of licensees for certain specified reasons.

Under the price control, as revised by the CMA, and excluding the effects of incentive schemes and any deferred revenues from the prior price control, the base allowed revenue of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc decreased by approximately ~~0.1%~~1.0% and ~~0.2%~~0.5%, respectively, infrom 2015-16 to 2016-17, and then remains constant in all subsequent years within the price control period (RIIO-ED1), through 2022-23, before the addition of ~~inflation (as measured by the United Kingdom's Retail Prices Index). Base allowed revenue in 2015-16 remains unchanged from the price control final settlement.~~inflation. Nominal base allowed revenues will increase in line with inflation.

Ofgem also monitors DNO compliance with license conditions and enforces the remedies resulting from any breach of condition. License conditions include the prices and terms of service, financial strength of the DNO, the provision of information to Ofgem and the public, as well as maintaining transparency, non-discrimination and avoidance of cross-subsidy in the provision of such services. Ofgem also monitors and enforces certain duties of a DNO set out in the Electricity Act 1989, including the duty to develop and maintain an efficient, coordinated and economical system of electricity distribution. Under changes to the Electricity Act 1989 introduced by the Utilities Act 2000, GEMA is able to impose financial penalties on DNOs that contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or that are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee's revenue.

ALP Transmission

ALP is regulated by the AUC, pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Alberta Utilities Commission Act (Alberta) and the Hydro and Electric Energy Act (Alberta). The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including ALP, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems. The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of ALP's activities, including its tariffs, rates, construction, operations and financing.

The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:

regulating and adjudicating issues related to the operation of electric utilities within Alberta;

processing and approving general tariff applications relating to revenue requirements and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of ALP's transmission system;

approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;

reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;

adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and

collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.

ALP's tariffs are regulated by the AUC under the provisions of the Electric Utilities Act in respect of rates and terms and conditions of service. The Electric Utilities Act and related regulations require the AUC to consider that it is in the public interest to provide consumers the benefit of unconstrained transmission access to competitive generation and the wholesale electricity market. In regulating transmission tariffs, the AUC must facilitate sufficient investment to ensure the timely upgrade, enhancement or expansion of transmission facilities, and foster a stable investment climate and a continued stream of capital investment for the transmission system.

Under the Electric Utilities Act, ALP prepares and files applications with the AUC for approval of tariffs to be paid by the AESO for the use of its transmission facilities, and the terms and conditions governing the use of those facilities. The AUC reviews and approves such tariff applications based on a cost-of-service regulatory model under a forward test year basis. Under this model, the AUC provides ALP with a reasonable opportunity to (i) earn a fair return on equity; and (ii) recover its forecast costs, including operating expenses, depreciation, borrowing costs and taxes associated with its regulated transmission business. The AUC must approve tariffs that are just, reasonable and not unduly preferential, arbitrary or unjustly discriminatory. ALP's transmission tariffs are not dependent on the price or volume of electricity transported through its transmission system.

The AESO is an independent system operator in Alberta, Canada that oversees the AIES and wholesale electricity market. The AESO is responsible for directing the safe, reliable and economic operation of the AIES, including long-term transmission system planning. ALP and the other transmission facility owners receive substantially all of their transmission tariff revenues from the AESO. The AESO, in turn, charges wholesale tariffs, approved by the AUC, in a manner that promotes fair and open access to the AIES and facilitates a competitive market for the purchase and sale of electricity. The AESO monitors compliance with approved reliability standards, which are enforced by the Market Surveillance Administrator, which may impose penalties on transmission facility owners for non-compliance with the approved reliability standards.

The AESO determines the need and plans for the expansion and enhancement of a congestion free transmission system in Alberta in accordance with applicable law and reliability standards. The AESO's responsibilities include long-term transmission planning and management, including assessing and planning for the current and future transmission system capacity needs of the AESO market participants. When the AESO determines an expansion or enhancement of the transmission system is needed, with limited exceptions, it submits an application to the AUC for approval of the proposed expansion or enhancement. The AESO then determines which transmission provider should submit an application to the AUC for a permit and license to construct and operate the designated transmission facilities. Generally the transmission provider operating in the geographic area where the transmission facilities expansion or enhancement is to be located is selected by the AESO to build, own and operate the transmission facilities. In addition, Alberta law provides that certain transmission projects may be subject to a competitive process open to qualified bidders.

Independent Power Projects

The Yuma, Cordova, Saranac, Power Resources, Topaz, Agua Caliente, Solar Star, Bishop Hill II, Jumbo Road, Marshall, ~~and~~Grande Prairie, Pinyon Pines, Alamo 6 and Pearl independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act, while the Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978. Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities. ~~In addition, the~~

The Yuma, Cordova, Saranac, ~~Yuma,~~ Imperial Valley, Topaz, Agua Caliente, Solar Star, Bishop Hill II, Marshall, Grande Prairie and Pinyon Pines independent power projects have obtained authority from the FERC to sell their power using market-based rates. ~~Jumbo Road's~~This authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the respective independent power projects are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. The Pinyon Pines, Solar Star, Topaz and Yuma independent power projects and power marketer CalEnergy, LLC file together for market power study purposes of the FERC-defined Southwest Region. The most recent triennial filing for the Southwest Region was made in June 2016 and an order accepting it was issued December 2016. The Cordova and Saranac independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2017 and an order accepting it was issued in January 2018. The Bishop Hill II independent power project and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2017 and is currently pending with the FERC.

The entire output of Jumbo Road, Alamo 6, Pearl and Power Resources is ~~dedicated to its offtaker~~ within the Electric Reliability Council of Texas ("ERCOT") and ~~does~~market-based authority is not ~~require market-based authority~~required for such sales solely within ERCOT as the ERCOT market is not a FERC-jurisdictional market. Similarly, Wailuku sells its output solely to the Hawaii Electric Company within the Hawaii electric grid which is not a FERC-jurisdictional market and Wailuku therefore does not require market-based rate authority.

EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility's "avoided cost" and to sell back-up power to the QFs on a non-discriminatory basis, unless they have successfully petitioned the FERC for an exemption from this purchase requirement. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utilities' avoided cost.

The Philippine Congress has passed the Electric Power Industry Reform Act of 2001 ("EPIRA"), which is aimed at restructuring the Philippine power industry, privatizing the National Power Corporation and introducing a competitive electricity market, among other initiatives. The implementation of EPIRA may impact future operations in the Philippines and the Philippine power industry as a whole, the effect of which is not yet known as changes resulting from EPIRA are ongoing.

Residential Real Estate Brokerage Company

HomeServices is regulated by the United States Bureau of Consumer Financial Protection under the Truth In Lending Act ("TILA") and the Real Estate Settlement Procedures Act ("RESPA"); the United States Federal Trade Commission with respect to certain franchising activities; and by state agencies where it operates. TILA primarily governs the real estate lending process by mandating lenders to fully inform borrowers about loan costs. RESPA primarily governs the real estate settlement process by mandating all parties fully inform borrowers about all closing costs, lender servicing and escrow account practices and business relationships between closing service providers and other parties to the transaction.

REGULATORY MATTERS

In addition to the discussion contained herein regarding regulatory matters, refer to "General Regulation" in Item 1 of this Form 10-K for further discussion regarding the general regulatory framework.

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 sought approvals to construct or procure four new Wyoming wind resources with a total capacity of 860 MWs identified as benchmark resources and certain transmission facilities. A request for proposals was issued in September 2017 seeking up to 1,270 MWs to compete against PacifiCorp's benchmark resources in the final resource selection process for the project. PacifiCorp has identified four winning wind resource bids from this solicitation totaling 1,311 MWs, consisting of 1,111 MWs owned and 200 MW as a power-purchase agreement. The combined new wind and transmission projects will cost approximately $2 billion. Hearings are expected to be set by the WPSC, UPSC, and IPUC to occur in the second quarter of 2018. The second application sought approval of PacifiCorp's resource decision to upgrade or "repower" existing wind resources, as prudent and in the public interest. PacifiCorp estimates the wind repowering project will cost approximately $1 billion. Applications filed in Utah, Idaho, and Wyoming seek approval for the proposed rate-making treatment associated with the projects. The hearings on repowering in Utah and Wyoming have been extended to provide time for supplemental analyses for updated costs and the Tax Cuts and Jobs Act enacted on December 22, 2017 ("2017 Tax Reform") and are scheduled to occur in April and May 2018. On December 28, 2017, the IPUC approved an all-party stipulation for approval of the application to repower existing wind facilities and allow recovery of costs in rates through an adjustment to the annual ECAM filing.

The 2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. PacifiCorp has agreed to defer the impact of the tax law change with each of its state rate regulatory bodies. PacifiCorp will be proposing to reduce customer rates for a portion of the lower annual income tax expense resulting from the decrease in federal tax rates, and deferring the remainder to offset other costs as approved by the regulatory bodies. PacifiCorp cannot predict the timing or ultimate outcome of regulatory actions on its proposals.

Utah Mine Disposition

In December 2014, PacifiCorp filed applications with the UPSC, the OPUC, the WPSC and the IPUC seeking certain approvals, prudence determinations and accounting orders to close its Deer Creek mining operations, sell certain Utah mining assets, enter into a replacement coal supply agreement, amend an existing coal supply agreement, withdraw from the United Mine Workers of America ("UMWA") 1974 Pension Plan and settle PacifiCorp's other postretirement benefit obligation for UMWA participants (collectively, the "Utah Mine Disposition").

The applications filed with the UPSC, the WPSC and the IPUC, requested that the commissions approve: (a) closure of the Deer Creek mine; (b) asset sales to a third party for certain Utah mining assets, including the Cottonwood Preparatory Plant; (c) the execution of a long-term coal supply agreement for the Huntington generating facility and amendment to the existing long-term coal supply agreement for the Hunter generating facility; and (d) the withdrawal from the UMWA 1974 Pension Plan that was triggered upon closure of the Deer Creek mine. In the UPSC and WPSC applications, PacifiCorp's request for approval to sell certain Utah mining assets included the sale of the Fossil Rock coal reserves that are currently reflected in rates in Utah and Wyoming. In addition to the requested approvals, PacifiCorp's applications filed with the UPSC, the WPSC and the IPUC requested that the noted components of the transaction and the settlement of PacifiCorp's other postretirement benefit obligation related to the UMWA participants be found prudent and in the public interest. These applications also requested accounting orders to defer the costs associated with the Utah Mine Disposition for current or future recovery. As certain amounts are currently reflected in rates, such as the recovery through depreciation of the Deer Creek mining assets and assets to be sold, these amounts serve to reduce the regulatory assets established as a result of the Utah Mine Disposition. The application requested continued recovery of contributions to the UMWA 1974 Pension Plan with ultimate ratemaking treatment of the UMWA 1974 Pension Plan withdrawal to be determined in a future proceeding once the final withdrawal obligation is determined.

In April 2015, PacifiCorp filed all-party settlement stipulations with the UPSC and the WPSC finding that the decision to enter into the Utah Mine Disposition transaction was prudent and in the public interest and recommended the appropriate treatment for accounting and ratemaking purposes. The UPSC approved the stipulation in April 2015 and the WPSC approved the stipulation in May 2015. The IPUC also issued an order in May 2015, approving the Utah Mine Disposition and ruling that the decision to enter into the transaction was prudent and in the public interest. The IPUC's order established the accounting treatment necessary to implement the transaction while deferring any incremental ratemaking treatment to the next general rate case.

PacifiCorp's application filed with the OPUC requested that the OPUC determine that closure of the Deer Creek mine was in the public interest, that its decision to enter into the Utah Mine Disposition was prudent and sought approval to sell certain Utah mine assets. PacifiCorp also requested that the costs associated with the Utah Mine Disposition, including the unrecovered investments and closure costs, be transferred to or deferred as a regulatory asset and recovered through a one-year tariff rider beginning June 1, 2015 with an offset for amounts currently in rates. The application requested the same treatment of the UMWA 1974 Pension Plan withdrawal sought in the applications filed with the UPSC, the WPSC and the IPUC. In May 2015, the OPUC issued its final order concluding that the transaction produces net benefits for customers and was in the public interest. In accordance with the OPUC order, PacifiCorp implemented two tariffs that reflect an overall annual rate increase of $3 million effective June 2015.

~~In December 2014, PacifiCorp also~~ filed an advice letter with the CPUC to request approval to sell certain Utah mining assets and to establish memorandum accounts to track the costs associated with the Utah Mine Disposition for future recovery. In July 2015, the CPUC Energy Division issued a letter requiring PacifiCorp to file a formal application for approval of the sale of certain Utah mining assets. Accordingly, in September 2015, PacifiCorp filed an application with the CPUC. On February 6, 2017, a joint motion was filed with the CPUC seeking approval of a settlement agreement reached by PacifiCorp and all other parties. The agreement states, among other things, that the decision to sell certain Utah mining assets is in the public interest. Parties also reserve their rights to additional testimony, briefs and hearings to the extent the CPUC determines that additional California Environmental Quality Act proceedings are necessary. A CPUC decision on the joint motion and settlement agreement is expected in 2018.

For additional information related to the accounting impacts associated with the Utah Mine Disposition, refer to ~~Note 6 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and~~ Notes 5 and 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.

Utah

In March ~~2015,~~2017, PacifiCorp filed its annual EBA with the UPSC ~~requesting recovery of $31~~seeking approval to refund to customers $7 million in deferred net power costs for the period January 1, ~~2014~~2016 through December 31, ~~2014.~~2016, reflecting the difference between base and actual net power costs in the 2016 deferral period. In ~~September 2015, a settlement agreement was filed with the UPSC~~April 2017, PacifiCorp revised its recommendation and requested approval to refund an additional $7 million to customers resulting in ~~which the parties agreed to recovery~~an interim rate reduction of ~~$30~~$14 million. The rate change became effective on an interim basis May 1, 2017. In ~~October 2015,~~January 2018, the UPSC approved a stipulation that provides an additional $3 million reduction, which will be incorporated into the ~~settlement agreement with the new rates effective November 2015.~~2018 EBA filing to be made in March 2018.

In March ~~2015,~~2017, PacifiCorp filed its annual REC balancing account application with the UPSC ~~requesting recovery of $6~~seeking to refund to customers $1 million ~~over a two-year period. In May 2015,~~for the ~~UPSC approved~~period January 1, 2016 through December 31, 2016 for the ~~new rates~~difference in base and actual RECs. The rate change became effective ~~June 2015~~ on an interim basis ~~until~~June 1, 2017.

As a ~~final order is~~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 a proposed five-year pilot program with an annual budget of $10 million authorized under the legislation to address clean-coal technology programs, commercial line extension programs, an electric vehicle incentive program and associated residential time of use rate pilot and other programs authorized in legislation. The UPSC issued orders approving PacifiCorp's application in phases in December 2016, May 2017, June 2017 and October 2017.

In November 2016, PacifiCorp filed cost of service analyses, as ordered by the ~~UPSC.~~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 ~~September 2015,~~February 2017, the UPSC ~~issued~~ruled on motions to dismiss and requests for a ~~final~~show cause order for a regulatory rate review filed by various parties to the docket and denied the motions. On August 28, 2017, PacifiCorp filed a settlement stipulation in the net metering proceeding. The stipulation provides for the closure of the net metering program to new entrants on November 15, 2017, with a transition to a new program that provides a separate compensation rate for exported power. All net metering customers, including those with a submitted application, as of November 15, 2017, will be grandfathered into the current program until January 1, 2036. A new proceeding will be initiated to establish a methodology for the determination of the export credit for new customers. During this period, a transition program for new customers will commence November 15, 2017, for a limited number of customers. Beginning December 1, 2017, PacifiCorp began accepting applications for the new transition program for private generation customers. Residential and non-residential private generation customers in the transition program will be compensated for exported energy at 90% and 92.5% of the current average energy rates, respectively. The rates for the exported energy will be fixed through January 1, 2033 for these transition program customers. The new residential and non-residential transition program customers' compensation will be only available for the first 170 MW and 70 MW, respectively. The stipulation also includes an agreement to support a two-year extension on the state tax credit for residential solar installations. A hearing on the stipulation was held on September 18, 2017, and an order approving ~~the interim rates as final.~~it was issued September 29, 2017.

Oregon

In ~~April 2015,~~March 2017, PacifiCorp ~~made~~submitted its ~~initial~~ filing for the annual TAM ~~with the OPUC for~~filing in Oregon requesting an annual increase of ~~$12~~$18 million, or an average price increase of 1%1.5%, based on forecasted net power costs and loads for calendar year ~~2016.~~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. In October ~~2015,~~2017, the OPUC issued ~~a preliminary~~an order approving PacifiCorp's ~~request.~~request with some minor adjustments to the NPC modeling. PacifiCorp ~~filed~~submitted the final update ~~reducing the requested increase to $9 million effective January 2016. A final order from the OPUC approving the revised increase was issued~~ in ~~December 2015.~~

~~Wyoming~~

~~In March 2015, PacifiCorp filed~~November 2017 which reflected a ~~general~~ rate ~~case with the WPSC requesting an annual~~ increase of ~~$32~~$2 million, or an average price increase of 5%0.2%, effective January 2016. The filing included a proposal to implement a modified ECAM to replace the current ECAM, which sunsets for new deferrals December 2015. In June 2015, PacifiCorp filed a net power cost update that reduced the requested increase to $30 million. In September 2015, PacifiCorp filed rebuttal testimony reducing the requested increase to $27 million, or an average price increase of 4%. Hearings were held in October and early November of 2015. In December 2015, the WPSC approved an overall increase of $16 million effective January 2016, and approved the continuation of the current ECAM with certain modifications that allow for the inclusion of chemical costs and start-up fuel costs. In addition, the WPSC ordered a $1 million credit to customers for benefits related to bonus tax depreciation through a separate tariff rider effective January 2016.2018.

Wyoming

In ~~March 2015,~~April 2017, PacifiCorp filed its annual ECAM, REC and RRA applications with the WPSC. The ECAM filing requests approval to ~~recover $8~~refund to customers $5 million in deferred net power costs for the period January 1, ~~2014~~2016 through December 31, ~~2014,~~2016, and the RRA application requests approval to refund to customers $1 ~~million to customers.~~million. In ~~May 2015,~~June 2017, the WPSC approved the ECAM, REC and RRA rates ~~effective May 2015~~ on an interim basis. In ~~September 2015,~~November 2017, a stipulation was filed resolving all issues in the proceeding. The stipulation results in an additional refund to customers of $1 million in 2017. The WPSC approved athe stipulation ~~in which~~at the ~~parties agreed to allow the interim rates that were effective in May 2015 to become final.~~hearing on November 28, 2017.

Washington

In ~~May 2014,~~August 2017, PacifiCorp ~~filed~~submitted a ~~general~~compliance filing to implement the second-year rate ~~case with~~increase approved as part of the two-year rate plan in the 2015 regulatory rate review. The compliance filing included rates based on the $8 million, or 2.3%, increase ordered by the WUTC requesting an annual increase of $27 million, or an average price increase of 8%. In November 2014, PacifiCorp filed rebuttal testimony that increased the request to $32 million, or an average price increase of 10%, primarily as a result of updated net power costs. In March 2015,in September 2016. The compliance filing was approved by the WUTC ~~issued~~on September 14, 2017, with rates effective September 15, 2017. On December 1, 2017, PacifiCorp submitted a ~~final order~~tariff filing to implement the first price change for the decoupling mechanism approved in ~~the proceeding approving an overall annual increase of $10 million, or an average price increase of 3%, effective March 2015. In April~~PacifiCorp's 2015 ~~PacifiCorp filed a petition for judicial review of certain findings~~regulatory rate review. WUTC staff disputed PacifiCorp's interpretation of the WUTC's ~~March 2015 order.~~

order for the decoupling mechanism and PacifiCorp's subsequent calculations requesting additional funds be booked for return to customers. In ~~the March 2015 general rate case order described above,~~February 2018, the WUTC ~~initiated a second phase of~~granted the ~~proceeding to implement a PCAM under which a portion of the difference between base net power costs set during a general rate case~~staff's motions and ~~actual net power costs would be deferred~~rejected PacifiCorp's tariff revision and ~~reflected in future rates. In May 2015, the WUTC approved an all-party stipulation in which the parties agreed to the implementation of a PCAM. The PCAM applies a $4 million dead band~~required that PacifiCorp re-file price changes for positive or negative net power cost variances. For net power cost variances between $4 million and $10 million, the PCAM reflects asymmetrical sharing bands in which amounts to be recovered from customers will be allocated 50% to customers and 50% to PacifiCorp, and amounts to be credited to customers will be allocated 75% to customers and 25% to PacifiCorp. Positive or negative net power cost variances in excess of $10 million will be allocated 90% to customers and 10% to PacifiCorp. PacifiCorp will make its ~~first annual PCAM filing in June 2016 to cover net power costs for the period April 1, 2015 through December 31, 2015. The PCAM will convert to a calendar year basis beginning in 2016.~~

~~In November 2015, PacifiCorp submitted a filing with the WUTC for approval of an expedited rate filing, a two-year rate plan and a proposal for a~~ decoupling mechanism. As part of the filing, PacifiCorp is seeking approval of a rate increase of $10 million, or an average price increase of 3%, effective mid-2016, and a second rate increase of $10 million, or an average price increase of 3%, effective mid-2017. The filing also includes a proposal to accelerate depreciation of certain coal-fueled generating facilities in the west control area that serve Washington. As part of the proposed rate plan, if approved, PacifiCorp commits to not file a general rate case for rates effective earlier than April 1, 2018. The WUTC decision is pending with a target effective date of the first step rate increase of July 1, 2016.

Idaho

In ~~February 2015,~~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 ~~$17 million, consisting primarily of $10~~$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 ~~$6 million for the difference between REC revenues included~~changes in ~~base rates~~production tax credits and ~~actual REC revenues. In March 2015, the~~renewable energy credits. The IPUC approved ~~recovery of $16 million~~the ECAM application with rates effective ~~April 2015.~~June 1, 2017.

California

In ~~May 2015,~~April 2017, PacifiCorp filed an application with the ~~IPUC requesting approval~~CPUC for an overall rate increase of 1.3% to modify the ECAM, update base net power costs and increase rates by $10 million, effective January 2016. The requested increase included $7 million for the difference between REC revenues included in base rates and actual REC revenues, andrecover $3 million asof costs recorded in the catastrophic events memorandum account over a ~~result of updating base net power costs. In October 2015, PacifiCorp filed a settlement agreement~~two-year period effective April 1, 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 ~~IPUC in which the parties agreed to the requested increase in rates, effective January 2016. The IPUC approved the settlement agreement in~~ December ~~2015. The settlement agreement modifies the ECAM to include production tax credits~~2016 and ~~exclude sulfur dioxide revenues. In addition, the settlement agreement allows another update to base net power costs in rates to be effective~~ January 2017 ~~and also specifies that January~~winter storms. The CPUC issued an order in February 2018 ~~would be the earliest effective date that PacifiCorp could seek an increase to base rates through a general rate case.~~

In February 2016, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $17 million, consisting primarily of $7 million for deferred net power costs, $6 million for the difference between REC revenues included in base rates and actual REC revenues and $4 million for a Lake Side 2 resource adder. If approved by the IPUC, the new rates will be effective April 2016.

~~California~~approving this request.

In August ~~2014,~~2017, PacifiCorp filed for a rate ~~increase~~decrease of $5$1 million, or 4%1.1%, through its annual ECAC. The CPUC ~~approved~~issued an order approving PacifiCorp's request in December 2017, the ~~new rates~~rate decrease was effective ~~March 2015.~~January 2018.

In June 2015, PacifiCorp filed for a rate increase of $1 million, or 1%, through its PTAM for major capital additions to include the costs of the Sigurd-Red Butte transmission line in rates. The CPUC approved the new rates effective July 2015.

~~In August 2015, PacifiCorp filed for a rate decrease of $2 million, or 2%, through its annual ECAC. In December 2015, the CPUC approved the new rates effective January 2016.~~

In October 2015, PacifiCorp filed for a rate increase of $1 million, or 1%, through its PTAM for attrition factor. The CPUC approved PacifiCorp's filing in October 2015 with new rates effective January 2016.

MidAmerican Energy

In July 2014, the IUB issued an order approving ~~new retail electric base rates for~~increases in MidAmerican Energy's Iowa ~~customers. The order allowed MidAmerican Energy to increase its~~retail electric base rates over approximately three years with equal annualized increases in revenues of $45 million, ~~or 3.6% over 2012,~~ effective August 2013 and again on January 1, 2015 and 2016, for a total annualized increase of $135 million when fully implemented. In addition to an increase in base rates, the order approved, (1) the implementation of two new adjustment clauses related to the recovery of retail energy production costs and certain electric transmission charges (2) seasonal pricing that increased the difference between higher base rates in effect for June through September and base rates applicable to the remaining months of the year; and (3)among other items, a revenue sharing mechanism that shares with MidAmerican Energy's customers 80% of revenues related to equity returns above 11% and 100% of revenues related to equity returns above 14%, with the customer portion of any sharing reducing rate base. MidAmerican Energy recorded a regulatory liability for revenue sharing totaling $26 million in 2017 and $30 million in 2016, which reduced rate base in the respective following January. In August 2016, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's construction of up to 2,000 MW (nominal ratings) of additional wind-powered generating facilities. The ~~changes in seasonal pricing, adjustment clauses and new~~ratemaking principles modified the revenue sharing mechanism, ~~were~~ effective in 2018, such that sharing will be triggered each year by MidAmerican Energy's actual equity returns above a threshold calculated annually in accordance with ~~final~~the order. The threshold is the weighted average of equity returns for rate base ~~rates. Additionally,~~as authorized via ratemaking principles proceedings and for remaining rate base, interest rates on 30-year single A-rated utility bond yields plus 400 basis points, with a minimum return of 9.5%. Pursuant to the change in revenue sharing, MidAmerican Energy will share with customers 100% of the revenue in excess of this trigger. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases.

The 2017 Tax Reform enacted significant changes to the ~~OCA have agreed not~~Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to ~~seek~~21%. MidAmerican Energy has made filings or ~~support an increase~~has been in discussions with each of its state rate regulatory bodies proposing either a reduction in retail rates or rate base for all or a portion of the net benefits of the 2017 Tax Reform for 2018 and beyond. MidAmerican Energy has proposed in Iowa, its largest jurisdiction, to reduce customer revenue via a rider mechanism for 50% of the lower annual income tax expense resulting from the decrease in federal tax rates, updated annually. Results for the ~~final base rates~~Iowa electric jurisdiction will be subject to ~~become effective prior~~Iowa revenue sharing provisions. If MidAmerican Energy's filings in each of its rate jurisdictions are approved as proposed, it is estimated that 2018 revenue will be reduced by approximately $72 million, subject to ~~January 1, 2018, unless~~change depending upon actual results of operations. MidAmerican Energy ~~projects~~cannot predict the timing or ultimate outcome of regulatory actions on its ~~return on equity for 2015, 2016 or 2017 to be below 10%.~~proposals.

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 ~~PUCN's final~~filing supported an annual revenue increase of $29 million, or 2%, but requested no incremental annual revenue relief. In December 2017, the PUCN issued an order ~~approving~~which reduced Nevada Power's revenue requirement by $26 million and requires Nevada Power to share 50% of revenues related to equity returns above 9.7%. As a result of the ~~merger between BHE~~order, Nevada Power recorded expense of $28 million primarily due to the reduction of a regulatory asset to return to customers revenue collected for costs not incurred. In January 2018, Nevada Power filed a petition for clarification of certain findings and ~~NV Energy stipulated that~~directives in the order. The new rates were effective in February 2018.

The 2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. In February 2018, the Nevada Utilities would not seek recovery of any lost revenue for calendar year 2014 in an amount that exceeded 50% of the lost revenue the Nevada Utilities could otherwise request. In February 2014, the Nevada Utilities each filed an applicationmade filings with the PUCN ~~to reset the EEIR and EEPR. In June 2014, the PUCN accepted~~proposing a ~~stipulation to adjust the EEIR, as of July 1, 2014, to collect 50% of the estimated lost revenue that the Nevada Utilities would otherwise be allowed to recover~~tax rate reduction rider for the ~~2014 calendar year.~~lower annual income tax expense anticipated to result from the 2017 Tax Reform for 2018 and beyond. The ~~EEIR was effective from July through December 2014, reset on January 1, 2015~~filings support an annual rate reduction of $59 million and ~~was in effect through September 2015.~~

In February 2015, the Nevada Utilities each filed an application to reset the EEIR and EEPR. In August 2015, the PUCN accepted a stipulation for the Nevada Utilities to calculate the base EEIR using a revised methodology for calculating lost revenue and$25 million for Nevada Power and Sierra Pacific, respectively. The Nevada Utilities cannot predict the timing or ultimate outcome of regulatory actions on its proposals.

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 ~~make~~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 ~~$5 million and $1 million reduction, respectively,~~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 ~~EEPR~~creation of the additional six MW of net metering at the grandfathered rates. Sierra Pacific believes the effects of the PUCN decision results 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 ~~to more accurately reflect~~by $2 million. In December 2016, the ~~actual level of spending~~PUCN approved the settlement agreement. The new rates were effective January 1, 2017.

EEPR and ~~to minimize any over collection from its customers. The reset of the~~ EEIR ~~and~~

EEPR was ~~effective October 1, 2015~~established to allow the Nevada Utilities to recover the costs of implementing energy efficiency programs and ~~remains~~EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in ~~effect through September 30, 2016.~~the utility's annual DEAA application based on energy efficiency program budgets prepared by the Nevada Utilities and approved by the PUCN in integrated resource plan proceedings. To the extent the Nevada Utilities' earned rate of return exceeds the rate of return used to set base general rates, the Nevada Utilities' are required to refund to customers EEIR revenue ~~collected.~~previously collected for that year. In March 2017, the Nevada Utilities each filed an application to reset the EEIR and EEPR and refund the EEIR revenue received in 2016, including carrying charges. In September 2017, the PUCN issued an order accepting a stipulation requiring Nevada Power to refund the 2016 revenue and reset the rates as filed effective October 1, 2017. The current EEIR liability for Nevada Power and Sierra Pacific is ~~$18~~$10 million and $3$1 million, respectively, which is included in current regulatory liabilities on ~~each respective~~the Consolidated Balance ~~Sheet~~Sheets as of December 31, ~~2015.~~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 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 ~~November 2014, one Nevada Power retail electric customer~~May 2015, MGM Resorts International ("MGM") and Wynn Las Vegas, LLC ("Wynn"), filed ~~an application~~applications with the PUCN to purchase energy from ~~a provider~~alternative providers of a new electric resource and become a distribution only service ~~customer. The application was denied in June 2015 and the customer subsequently filed a petition for reconsideration. In July 2015, the PUCN approved a settlement between the customer and~~customers of Nevada

Power. In October 2015, the PUCN approved a separate green energy agreement between Nevada Power and the customer and tariff changes embedded in the settlement agreement. The customer withdrew its petition for reconsideration in November 2015. In May 2015, three additional customers filed applications to purchase energy from a provider of a new electric resource and become a distribution only service customer. In December 2015, the PUCN granted the applications ~~of the three customers~~ subject to conditions, including paying an impact fee, on-going charges and receiving approval for specific alternative energy providers and terms.

In December 2015, the ~~customers~~applicants filed petitions for reconsideration. In January 2016, the PUCN granted ~~reconsiderations~~reconsideration and updated some of the terms, including removing a limitation related to energy purchased indirectly from NV Energy. ~~One~~In September 2016, MGM and Wynn paid impact fees of $82 million and $15 million, respectively. In October 2016, MGM and Wynn became distribution only service 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. This request is still pending. In May 2017, a stipulation reached between MGM, Regulatory Operations Staff and the Bureau of Consumer Protection was filed requiring Nevada Power to reduce the original $82 million impact fee by $16 million and apply the credit against MGM's remaining on-going charge obligation. In June 2017, the PUCN approved the stipulation as filed.

In September 2016, Switch, Ltd. ("Switch"), a customer of the ~~applicants subsequently~~Nevada Utilities, filed ~~a petition for judicial review and a complaint for declaratory relief in state district court. In addition, there are no material applications pursuant to Chapter 704B pending before~~an application with the PUCN into purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada ~~Power's~~Power and Sierra ~~Pacific's respective~~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 May 2017, Switch paid impact fees of $27 million and, in June 2017, Switch became a distribution only service ~~territories.~~customer and started procuring energy from 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 monthly for three and six years at Sierra Pacific and Nevada Power, respectively, and proceed with purchasing energy from alternative providers. In July 2017, Caesars made the required compliance filings and, in September 2017, the PUCN issued an order allowing Caesars to acquire electric energy and ancillary services from another energy supplier and become a distribution only service customer of the Nevada Utilities. In December 2017, Caesars provided notice that it intends to transition eligible meters in the Nevada Power service territory to unbundled electric service in February 2018 at the earliest. In January 2018, Caesars became a distribution only service customer and started procuring energy from another energy supplier for its eligible meters in the Sierra Pacific service territory.

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. In August 2017, the PUCN approved a stipulation allowing Peppermill to purchase energy from alternative providers subject to conditions, including paying an impact fee. In September 2017, Peppermill provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.

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,~~private, 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~~established separate rate classes for customers who install ~~distributed,~~private, 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,~~Additionally, the PUCN established a separate value for compensating customers who produce and deliver excess energy to the Nevada Utilities. The valuation ~~will consider~~considered 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.

~~Emissions Reduction~~ 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 ~~Capacity Replacement Plan~~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, which was settled and dismissed in August 2017.

In July 2015, Nevada Power filed an amendment to its Emissions Reduction and Capacity Replacement Plan ("ERCR Plan") with the PUCN. In September 2015, the PUCN approved the filed amendment requesting two renewable power purchase agreements with 100‑MW solar photovoltaic generating facilities related to the replacement of coal plants. Each of these agreements were entered into by issuing requests for proposals for the procurement of energy through the competitive solicitation process that was set forth in Nevada Power's ERCR Plan in compliance with Senate Bill No. 123 ("SB 123"). In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123. As a result, Nevada Power will not proceed with issuance of a third 100-MW request for proposal for renewable energy until such time as the PUCN determines Nevada Power has satisfactorily demonstrated a need for such electric generating capacity.

~~Joint Dispatch Agreement Application~~

~~The Nevada Utilities were parties to an Interim Joint Dispatch Agreement ("Interim JDA") which outlined the joint dispatch of their combined power supply resources utilizing ON Line. In March 2015,~~2016, the Nevada Utilities filed ~~an application~~applications with the PUCN ~~seeking approval~~to revert back to the original net metering rates for a period of ~~a Joint Dispatch Agreement with a new term (the "JDA").~~twenty years for customers who installed or had an active application for private, renewable generating facilities as of December 31, 2015. In ~~July 2015,~~September 2016, the PUCN issued an order accepting the stipulation and approved the ~~JDA with minor modifications, and established~~applications as modified by the stipulation. In December ~~31, 2019~~2016, as a part of Sierra Pacific's regulatory rate review, the ~~termination date~~PUCN issued an order establishing an additional six MWs of net metering under the grandfathered rates in the Sierra Pacific service territory. As mentioned above, Sierra Pacific filed a petition for reconsideration relating to the ~~agreement. The JDA became effective September 29, 2015, by approval from the FERC, replacing the Interim JDA. The JDA covers real-time, hourly and daily transactions, including sales~~additional six MWs of ~~the combined resources into the California ISO through the EIM.~~net metering, which was denied in June 2017.

Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The ~~primary difference between the Interim JDA and the JDA is the extension~~legislation, among other things, established net metering crediting rates for private generation customers with installed net metering systems less than 25 kilowatts. Under AB 405, private generation customers will be compensated at 95% of the ~~agreement to December 31, 2019, at which time~~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 ~~their regulators will review~~75% of the ~~JDA to determine if it should be renewed or amended. The JDA also recognizes that, upon NV Energy’s entry into~~rate the ~~EIM, dispatch and non-native sales include transactions~~customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for any additional private generation capacity. In July 2017, the Nevada Utilities filed with the ~~California ISO. As~~PUCN proposed amendments to their tariffs necessary to comply with the ~~prior versions~~provisions of ~~the JDA, the agreement establishes Nevada Power as the EIM scheduling coordinator~~AB 405. The filing in July 2017 also included a proposed optional time of use rate tariff for both ~~Sierra Pacific and~~ Nevada Power and ~~recognizes that the joint dispatch costs and benefits associated with the EIM transactions will be governed by the accounting protocols and allocations~~Sierra Pacific, which has not yet been set ~~forth in the JDA.~~

~~Advanced Metering Infrastructure~~

for procedural review. In ~~October 2014,~~September 2017, the PUCN issued an order directing the Nevada Utilities to ~~provide information relating~~place all new private generation customers who have submitted applications after June 15, 2017 into a new rate class with rates equal to ~~failures~~the rate class they would be in ~~certain remote disconnect/reconnect electric meters~~if they were not private generation customers. Private generation customers with installed net metering systems less than 25-kilowatts prior to June 15, 2017 may elect to migrate to the new rate class created under AB 405 or stay in their otherwise-applicable rate class. The new AB 405 rates became effective December 1, 2017.

Emissions Reduction and Capacity Replacement Plan

Consistent with the Emissions Reduction and Capacity Replacement Plan ("ERCR Plan"), Nevada Power acquired a 272-MW natural gas co-generating facility in 2014, acquired a 210-MW natural gas peaking facility in 2014, constructed a 15-MW solar photovoltaic facility in 2015 and contracted two renewable power purchase agreements with 100-MW solar photovoltaic generating facilities in 2015. In February 2016, Nevada Power solicited proposals to acquire 35 MW of nameplate renewable energy capacity to be owned by Nevada Power. Nevada Power did not enter into any agreements to acquire the 35 MW of nameplate renewable energy capacity; however, it has the option to acquire the 35 MW in the future under the ERCR Plan, subject to PUCN approval. In addition, Nevada Power was granted approval to purchase the remaining 130 MW of the Silverhawk natural gas-fueled combined cycle generating facility. In June 2016, Nevada Power executed a long-term power purchase agreement for 100 MW of nameplate renewable energy capacity in Nevada. In December 2016, the order was approved. In addition, the order approved the early retirement of Reid Gardner Unit 4 in the first quarter of 2017. These transactions are related to Nevada Power's compliance with Senate Bill No. 123, resulting in the retirement of 812 MW of coal-fueled generation by 2019.

IRP

In July 2016, Sierra Pacific filed its statutorily required IRP. In August 2016, Nevada Power filed an amendment to its related IRP. As a part of the filings, the Nevada Utilities ~~have installed after media reports were published that electric meter failures may have resulted~~sought PUCN authorization to acquire the South Point Energy Center, a 504-MW combined-cycle generating facility located in ~~fire events.~~Arizona. In December 2016, the PUCN denied the acquisition of this facility. In January 2017, Nevada Power filed a petition for reconsideration relating to the acquisition of South Point Energy Center. In February 2017, the PUCN affirmed the denial of the acquisition of South Point Energy Center. The Nevada Utilities ~~completed an internal review~~amended their respective IRPs in ~~response to this~~November 2017, requesting approval of three long-term renewable purchase power contracts. Nevada law was modified in 2017 under Senate Bill 146 and other federal, state and local inquiries relating to these events. The information compiled and submitted indicates that no fire has resulted from the remote disconnect/reconnect electric meters. Additionally, in October 2014, the Nevada State Fire Marshal issued a report concluding that the incidents of electric arcing fires continue to decrease in Nevada and at this time there is no statewide fire problem related to the replacement of electric meters. In December 2014, the Nevada Utilities filed the requested information with the PUCN. In March 2015, the PUCN staff made additional requests and in May 2015, the Nevada Utilities provided the follow up items. In September 2015, the Nevada Utilities provided the PUCN electric meter testing results from a third party laboratory. All tests of the integrity and functionality of the meters subject to the distress testing passed. Analysis and internal investigation is continuing, butfor future filings requires Nevada Power and Sierra Pacific ~~do not believe this will have a material adverse impact on each respective Consolidated Financial Statements.~~to file jointly.

~~ALP~~Kern River

In December 2016, Kern River filed a Stipulation and Agreement of Settlement with the FERC to establish an alternative set of rates for customers that extend service contracts associated with Kern River's original system and 2002 expansion, 2003 expansion and 2010 expansion projects. The stipulation provided a lower rate option to customers, improved the likelihood of re-contracting expiring capacity and extended recovery of Kern River's rate base. Under the stipulation, customers have the option to stay with previously established rates or choose the alternative lower rates. The reduction in rates was accomplished by extending the rate term to 25 years instead of the current term of 10 or 15 years, resulting in rates that are 9% to 26% lower than the previously established rates. Kern River received FERC approval of the stipulation in January 2017. The stipulation allowed regulatory depreciation on plant allocated to volumes of shippers that elected extended Period Two rates and plant allocated to capacity that has been turned back to be adjusted to 25 years, retroactive to the start of each Period Two term.

ALP

General Tariff Applications

In November 2014, ALP filed a general tariff application ("GTA") ~~asking~~requesting the AUC to 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.

~~In June 2015,~~ ALP amended the GTA in June 2015 and October 2015. In May 2016, the AUC issued its decision pertaining to ~~propose additional transmission~~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 approximately C$415 million tariff relief ~~measures for customers~~in 2015 and ~~modifications to its capital structure. The amended GTA includes timing benefits to customers by discontinuing~~2016 through: (i) the ~~use~~discontinuance of construction work-in-progress ~~in-rate~~("CWIP") in rate base and the return to AFUDC accounting effective January 1, 2015, and ~~refunding related amounts received~~(ii) the refund of previously collected CWIP in rate base as part of ~~the 2011 to 2014~~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 ~~(ii)~~all related amounts. In January 2017, ALP filed its second compliance filing as directed by the ~~collection~~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 ~~advance~~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.

In August 2017, the AUC issued a decision with respect to ALP's second compliance filing amendment filed in April 2017. The AUC denied ALP's proposal to remove C$7 million of recapitalized AFUDC associated with canceled projects on the basis that the amount would more appropriately be recovered through ALP's deferral account reconciliation process. The AUC also directed the recalculation of the amount of related income taxes using typical direct assigned project schedules filed in the general tariff applications, and to adjust its funded future income ~~taxes, effective January 1,~~tax liability only for the change in timing differences.

In September 2017, ALP filed its third compliance filing with the AUC which proposed a one-time payment to the AESO of C$7 million to settle the 2015-2016 final transmission tariffs of C$485 million for 2016 and ~~refunding amounts previously received~~C$723 million for 2015. In December 2017, the AUC approved ALP's third compliance filing as ~~part~~filed.

ALP filed its 2017-2018 GTA in February 2016. The AUC held this application in abeyance pending the release of the ~~transmission tariffs.~~

2015-2016 GTA Decision. ALP subsequently 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 ~~2015, an update~~2016, ALP amended its 2017-2018 GTA to ~~this amended application was filed.~~reflect the impacts of the generic cost of capital decision issued in October 2016 and other updates and revisions. The ~~October 2015 update requested~~amendment requests the AUC to approve ~~an increase to 39% in~~ ALP's ~~common equity ratio resulting in~~ revenue ~~requirements~~requirement of C$~~672~~891 million for ~~2015~~2017 and C$~~703~~919 million for ~~2016. In addition, the October 2015 update forecasted capital expenditures~~2018. The 2017-2018 GTA reflected an additional C$185 million of tariff relief related to be C$961 million for 2015 and C$538 million for 2016. ALP based its direct assign capital forecast, which comprises more than 80% of its total capital expenditures, on the long-range capital plan released by the AESOitems approved in January 2014, using its risk-adjusted capital forecasting model accepted by the AUC in its decision on ALP's previous general tariff application. ALP's actual capital program may vary from ALP's regulatory filings, depending on the timing of regulatory approvals, directions from the AESO, and other factors beyond ALP's control.

~~The oral hearing for~~ the 2015-2016 GTA ~~which was amended and updated, took place~~decision. In December ~~2015 and the AUC is expected to issue its final decision in the second quarter of 2016. In addition,~~2016, the AUC approved ALP's request to ~~continue its 2015 interim transmission tariff decision to invoice the AESO C$61 million per month commencing January 1, 2016, until~~enter into a ~~final decision is issued for the 2015-2016 GTA.~~negotiated settlement process.

In January 2017, ALP successfully reached a negotiated settlement with all parties regarding all aspects of ALP's 2017-2018 GTA and in February ~~2016,~~2017, ALP filed ~~a GTA asking~~with the AUC ~~to approve its transmission tariff~~the 2017-2018 negotiated settlement application for approval. The application consists of negotiated reductions of C$~~853~~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. In August 2017, the AUC issued a decision approving ALP's negotiated settlement agreement for the 2017-2018 GTA, as filed. Also, the AUC approved a C$31 million refund of accumulated depreciation surplus as opposed to the C$130 million refund proposed by ALP and three customer groups.

In November 2017, ALP filed and received AUC approval regarding its compliance filing, which includes revenue requirements of C$864 million and C$888 million for 2017 and ~~C$990 million for 2018.~~2018, respectively.

~~2016~~2018 Generic Cost of Capital Proceeding

In ~~April 2015,~~July 2017, the AUC ~~opened a new GCOC proceeding to set~~denied the utilities' request that the interim determinations of 8.5% return on equity and deemed capital ~~structure~~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 ~~returns~~cost of capital decision for ~~2016~~2018, 2019 and ~~2017.~~2020 by the end of 2018 to reduce regulatory lag. The AUC ~~has issued a schedule for this proceeding~~also confirmed the process timelines with aan oral hearing scheduled for ~~the second quarter~~March 2018.

In October 2017, ALP's evidence was submitted recommending a range of ~~2016. ALP filed evidence in January 2016. ALP’s external rate of return expert evidence proposes~~ 9% to ~~10.5%~~10.75% return on equity, on a recommended equity ~~component~~ratio of 40%, compared to the placeholder return on equity of 8.3% on a 36% equity component. The fair return and equity thickness recommended reflect the concerns noted by rating agencies and other members of the financial community regarding the increased business risks of utilities in Alberta. ALP’s credit metrics expert has recommended that the AUC authorize return on equity and equity thickness determinations that allow for a funds from operations to debt credit ratio above the 13% that Standard & Poor’s has cautioned might be a floor for regulated utilities facing growing uncertainty while operating in Alberta.. ALP also filed evidence ~~which outlined capital market participant’s heightened view of~~outlining increased uncertainties in the Alberta utility regulatory ~~environment~~environment. In January 2018, the Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the ~~widening credit spreads.~~City of Calgary filed intervenor evidence. The return on equity recommended by the intervenors ranges from 6.3% to 7.75%. The equity ratio recommended by the intervenors for ALP ranges from 35% to 37%.

Deferral Account Reconciliation Application

In ~~December 2014,~~April 2017, ALP filed its ~~2012-2013 Deferral Accounts Reconciliation Application seeking~~application with the ~~AUC's approval~~AUC with respect to ~~collect~~ALP's 2014 projects and deferral accounts and specific 2015 projects. The application includes approximately C$~~30 million from~~2.0 billion in net capital additions. In June 2017, the ~~AESO for previously uncollected~~AUC ruled that the scope of the deferral account ~~balances. In addition, ALP~~proceeding would not be extended to consider the utilization of assets for which final cost approval is seeking approval of nearly C$1.7 billion of direct assign capital additions, included as part of the direct assigned capital deferral account filing. The oral hearing took place in November 2015 and reconvened in January 2016 because there was not sufficient time to complete the hearing. A decision fromsought. However, the AUC ~~is expected~~will initiate a separate proceeding to address the issue of transmission asset utilization and how the corporate and property law principles applied in ~~mid-2016.~~

~~Appeals of Recent~~ ~~AUC~~ ~~Decisions~~the Utility Asset Disposition decision may relate.

In ~~March 2015,~~December 2017, ALP amended its application to include the ~~AUC issued its decision regarding cost of~~remaining capital matters applicable to all electricity and natural gas utilities under its jurisdiction, including ALP. In its decision, which was retroactively applied to January 1, 2013, the AUC decreased the generic rate of return on common equity applicable to all utilities to 8.30% from the previously approved placeholder rate of 8.75% and decreased ALP's common equity ratio from 37% to 36% for the years 2013,projects completed in 2015. The amended 2014 and 2015. The approved common equity ratio and generic rate of return on common equity will remain in effect on an interim basis for 2016 and beyond, until changed by the AUC. ALP and other utilities had applied to the Alberta Court of Appeal for Leave to appeal this decision, which is set to be heard in May 2016.

In November 2013, the AUC issued its Utility Asset Disposition ("UAD") decision in which it concluded, among other things, that in the case of the extraordinary retirement of an asset before it is fully depreciated, under or over recovery of capital investment on an extraordinary retirement should be borne by the utility and its shareholders. ALP and other utilities appealed the AUC's UAD decision to the Alberta Court of Appeal, which was dismissed in September 2015. In November 2015 ~~ALP, Epcor and Enmax, filed a joint leave application to the Supreme Court of Canada for appeal of the Alberta Court of Appeal's UAD decision.~~

In its November 2013 decision pertaining to ALP's 2013-2014 GTA, the AUC directed ALP to re-forecast the capital project expenditures for 2013 and 2014 Engineering, Procurement and Construction Management ("EPCM") services to reflect a two times labor multiplier and other approved mark-ups. While the AUC has not disallowed the new EPCM rates that ALP negotiated, there is a risk that, in a future direct assigned capital deferral account ~~decision, the AUC may disallow a portion~~reconciliation application includes 110 completed projects with total gross capital additions, excluding AFUDC, of the costs ALP has incurred for EPCM services in connection with capital projects executed under these relationship agreements. ALP has appealed this decision, which is scheduled to be heard in February 2016. ALP has requested approval of the capital project expenditures, including the new competitively bid EPCM rates, in its 2012-2013 direct assigned capital deferral account filing. ALP filed additional evidence supporting the new EPCM rates in 2015.C$3.8 billion.

BHE U.S. Transmission

A significant portion of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base regulatory rate ~~proceeding.~~review. In ~~July 2015,~~December 2017, the most recent interim rate change filing was approved which set total annual revenue requirements at ~~$304~~$332 million and a rate base of ~~$2.2~~$2.5 billion. In ~~November 2015,~~January 2017, the PUCT ~~ordered ETT~~approved ETT's request to ~~file a~~suspend the base regulatory rate ~~case by~~review filing scheduled for February 2017 and set ETT's annual revenue requirement to $327 million, effective March 2017. Results of a base regulatory rate review would be prospective except for any deemed disallowance by the PUCT of the transmission investment since the initial base regulatory rate ~~case~~review in 2007. ~~A refund of interim transmission rates would reduce future net income and cash flows. Management is unable to determine a range of potential losses that are reasonably possible of occurring.~~

~~Northern Powergrid Distribution Companies~~

In March 2015, Northern Powergrid sought permission from the Competition and Markets Authority ("CMA") to appeal against the license modifications that give effect to the RIIO-ED1 price control. The appeal related to three specific areas:

~~Ofgem's decision to demand further cost savings in relation to smart grid technology over and above the ones captured by its original benchmarking exercise;~~

~~Ofgem's assessment of the variation in wage rates across the country; and~~

~~Ofgem's projections for labor cost increases.~~

Permission to appeal was granted by the CMA on March 30, 2015. British Gas Trading Limited (an electricity supplier) was granted permission to appeal the price control, with a view to reduce the revenue available to all slow-tracked Distribution Network Operators.

In September 2015, the CMA announced that it had upheld Northern Powergrid's appeal on cost savings in relation to smart grid technology concluding that Ofgem's decision was not based on robust evidence. The CMA has therefore increased Northern Powergrid's cost allowance for the period to March 2023 by £32 million (2012/13 prices). The CMA decided that Ofgem's decision on the assessment of the variation in wage rates across the country and their projections for labor cost increases fell within the margin of discretion that is available to Ofgem.

In September 2015, the CMA also announced that it had upheld one part of one ground of the British Gas appeal. As a result the CMA has reduced the value of an incentive scheme for all slow-tracked Distribution Network Operators which reduces Northern Powergrid revenues by £14 million (2012/13 prices) over the period to March 2023.

ENVIRONMENTAL LAWS AND REGULATIONS

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air and water quality, RPS, 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 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. Refer to "Liquidity and Capital Resources" of each respective Registrant in Item 7 of this Form 10-K for discussion of each Registrant's forecast environmental-related capital expenditures.

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.

National Ambient Air Quality Standards

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

In ~~November 2014,~~October 2015, the EPA ~~released a new proposal to strengthen~~revised the national ambient air quality standard for ground level ozone, ~~from~~strengthening the ~~current level of~~standard from 75 parts per billion to ~~a level between 65 and~~ 70 parts per billion. ~~In October 2015,~~It is anticipated that the EPA ~~set the standard at 70 parts per billion. The EPA anticipates making~~will make attainment/nonattainment designations for the revised standards by late ~~2017, which will likely be based on 2014-2016 air quality data.~~2017. Nonattainment areas will have until 2020 to late 2037 to meet the standard. Given the level at which the standard was set in conjunction with retirements and the installation of controls, the new standard is not expected to have a significant impact on the relevant Registrant. The EPA designated the entire state of Iowa as attainment/unclassifiable on November 16, 2017.

Until the 2015 standard is fully implemented, the EPA continues to implement the 2008 ozone standards. The Upper Green River Basin Area in Wyoming, including all of Sublette and portions of Lincoln and Sweetwater Counties, were proposed to be designated as nonattainment for the 2008 ozone standard. When the final designations were released in April 2012, portions of Lincoln and Sweetwater Counties and Sublette County were determined to be in marginal nonattainment. While PacifiCorp's Jim Bridger plant is located in Sweetwater County, it is not in the portion of the designated nonattainment area and has not been impacted by the 2012 designation. In December ~~2012, the~~2017, EPA ~~approved Nevada's request~~Region 9 notified Nevada of its intent to ~~redesignate~~designate a portion of Clark County as nonattainment under the 2015 standard and will modify the state's recommendation for this area. The EPA also intends to bedesignate all other areas in ~~attainment for~~ the 1997 eight-hour ozone standard while also approving Clark County's plan to maintain compliance with the standard through 2022. However, Clark County remains unclassifiable for the 2008 ozone standard. If the EPA revises the ozone standard to be more stringent, it is possible that Clark County will again bestate not previously designated as attainment/unclassifiable. This redesignation to nonattainment ~~for ozone, creating the potential to~~could potentially impact Nevada Power's Clark, Sun Peak, Las Vegas, Lenzie, Silverhawk, Harry Allen, Higgins, and Goodsprings generating facilities. However, until such time as the 2015 standard is implemented orfor Clark County in a final action, any potential impacts cannot be determined. In order for the EPA to consider more current air quality data in the final designation, Nevada must submit certified quality-assured air quality monitoring data for the time period 2015-2017 to the EPA by February 28, 2018. After considering any additional information received, the EPA plans to promulgate final ozone designations in spring of 2018.

On December 20, 2017, the EPA responded to the state of Arizona's recommendation that a section of Yuma County, in which the Yuma independent power project is ~~classified~~located, be designated as nonattainment with respect to the 2015 National Ambient Air Quality Standards for ozone, indicating its acceptance of the ~~2008 or 2015 standards,~~state's designations for areas in attainment, and requesting additional data to finalize designations of nonattainment areas by February 28, 2018. The Yuma independent power project could be impacted by the requirements of the final rule. Until such time as the designations are final, any potential impacts cannot be determined.

In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 100 parts per billion. In February 2012, the EPA published final designations indicating that based on air quality monitoring data, all areas of the country are designated as "unclassifiable/attainment" for the 2010 nitrogen dioxide national ambient air quality standard.

In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where sulfur dioxide emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour sulfur dioxide standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of sulfur dioxide area designations will continue with the deployment of additional sulfur dioxide monitoring networks across the country.

The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour sulfur dioxide standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 sulfur dioxide standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of sulfur dioxide in 2012 or emitted more than 2,600 tons of sulfur dioxide and had an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of sulfur dioxide and having an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa ~~has assembled technical support documents demonstrating that all facilities affected by the first phase of designations have attained the standard, but has not yet~~ submitted ~~the information~~documentation to the ~~EPA. The~~ EPA ~~intends to promulgate~~in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 sulfur dioxide ~~area designations no later than July 2, 2016.~~standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment.

On January 9, 2018, the EPA published the results for the Air Quality Designations for the 2010 Sulfur Dioxide Primary National Ambient Air Quality Standard-Round 3 in the Federal Register. The Utah county of Emery, where PacifiCorp's Hunter and Huntington generation stations are located, was classified as attainment/unclassifiable. The Wyoming counties of Campbell and Lincoln, where PacifiCorp's Wyodak and Naughton generation stations are located, were classified as attainment/unclassifiable. The eastern portion of Sweetwater County, where PacifiCorp's Jim Bridger generation station is located, was classified as attainment/unclassifiable. Converse County, where PacifiCorp's Dave Johnston generation station is located, will not be designated until December 31, 2020.

In December 2012, the EPA finalized more stringent fine particulate matter national ambient air quality standards, reducing the annual standard from 15 micrograms per cubic meter to 12 micrograms per cubic meter and retaining the 24-hour standard at 35 micrograms per cubic meter. The EPA did not set a separate secondary visibility standard, choosing to rely on the existing secondary 24-hour standard to protect against visibility impairment. In December 2014, the EPA issued final area designations for the 2012 fine particulate matter standard. Based on these designations, the areas in which the relevant Registrant operates generating facilities have been classified as "unclassifiable/attainment." Unless additional monitoring suggests otherwise, the relevant Registrant does not anticipate that any impacts of the revised standard will be significant.

In December 2014, the Utah SIP for fine particulate matter was adopted by the Utah Air Quality Board. PacifiCorp's Lake Side and Gadsby generating facilities operate within nonattainment areas for fine particulate matter; however, the SIP did not impose significant new requirements on PacifiCorp's impacted generating facilities, nor did the EPA's comments on the Utah SIP identify requirements for PacifiCorp's existing generating facilities that would have a material impact on its consolidated financial results.

As new, more stringent national ambient air quality standards are adopted, the number of counties designated as nonattainment areas is likely to increase. Businesses operating in newly designated nonattainment counties could face increased regulation and costs to monitor or reduce emissions. For instance, existing major emissions sources may have to install reasonably available control technologies to achieve certain reductions in emissions and undertake additional monitoring, recordkeeping and reporting. The construction or modification of facilities that are sources of emissions could also become more difficult in nonattainment areas. Until new requirements are promulgated and additional monitoring and modeling is conducted, the impacts on the Registrants cannot be determined.

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 ~~is retiring~~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 ~~are to be~~were retired byin April ~~15,~~ 2016. A fifth unit, Riverside Generating Station, was limited to natural gas combustion in March 2015.

PacifiCorp retired its two coal-fueled generating units at the Carbon Facility in 2015 to comply with the MATS requirements and other environmental regulations as well as in conformance with Utah's Regional Haze SIP. Refer to the Regional Haze section below for additional requirements regarding the Carbon Facility.

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.

Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of nitrogen oxides and sulfur dioxide, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the Cross-State Air Pollution Rule ("CSAPR") was promulgated to address interstate transport of sulfur dioxide and nitrogen oxides emissions in 27 eastern and Midwestern states.

The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce nitrogen oxides emissions in 2017. The ~~public comment period closed on~~final rule was published in the ~~proposal February 1,~~Federal Register in October 2016. The rule requires additional reductions in nitrogen oxides emissions beginning in May 2017. On December 23, 2016, a lawsuit was filed against the EPA in the D.C. Circuit over the final CSAPR "update" rule, which is still pending.

MidAmerican Energy has installed emissions controls at ~~some of~~ its coal-fueled generating facilities to comply with the CSAPR and may purchase emissions allowances to meet a portion of its compliance obligations. The cost of these allowances is subject to market conditions at the time of purchase and historically has not been material. MidAmerican Energy believes that the controls installed to date are consistent with the reductions to be achieved from implementation of the ~~rule; however,~~rule and does not anticipate that any impacts of the ~~rule's full impact cannot~~CSAPR update will be ~~predicted until the EPA takes final action on the Phase II rules.~~significant.

MidAmerican Energy operates natural gas-fueled generating facilities in Iowa and BHE Renewables operates natural gas-fueled generating facilities in Texas, Illinois and New York, which are subject to the CSAPR. However, the provisions are not anticipated to have a material impact on Berkshire Hathaway Energy or MidAmerican Energy. None of PacifiCorp's, Nevada Power's or Sierra Pacific's generating facilities are subject to the CSAPR. However, in a Notice of Data Availability published in the January 6, 2017, Federal Register, the EPA provided preliminary estimates of which upwind states may have linkages to downwind states experiencing ozone levels at or exceeding the 2015 ozone national ambient air quality standard of 70 parts per billion, and, using similar methodology to that in the CSAPR, indicated that Utah and Wyoming could have an obligation under the "good neighbor" provisions of the Clean Air Act to reduce nitrogen oxides emissions.

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. ~~In January 2016, a public hearing was held on the EPA's alternative proposals and the public comment period closes March 14, 2016. The~~ EPA's final action on the Utah regional haze SIP ~~is expected~~was effective August 4, 2016. The EPA approved in ~~mid-2016. Until~~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 ~~makes~~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 ~~final determination, it~~decision issuing the FIP. 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 ~~unknown whether additional controls will be required on~~in effect while the ~~four BART-eligible units in Utah.~~EPA conducts its reconsideration process.

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 ~~federal implementation plan ("FIP").~~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 its final action,~~2018; in October 2016, an application was filed with the ~~EPA indicated it supported the conversion~~Wyoming Department of Environmental Quality requesting a revision of the ~~unit to natural~~dates for the end of coal firing and the start of gas ~~as its fuel source and would expedite action relative to consideration of the natural gas conversion once the state of Wyoming submitted the requisite SIP amendment; nonetheless,~~firing for Naughton Unit 3 ~~natural~~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 ~~should it ultimately be pursued, remains subject~~by June 30, 2019. On March 17, 2017, Wyoming Department of Environmental Quality issued an extension to ~~final~~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 ~~by the EPA.~~November 28, 2017.

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~~while the parties pursued 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 Arizona Department of Environmental ~~Quality prepared a~~Quality's revision of the 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 to~~were approved by the EPA ~~for review, public comment and final action. The EPA's~~through final action published in the Federal Register on ~~the Arizona regional haze SIP is expected~~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 ~~late 2016.~~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 ~~underway.~~either already in service or currently being constructed. In addition, in February 2015, the state of Colorado ~~submitted~~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 ~~amended SIP is pending consideration~~terms of the agreement were approved by the ~~EPA.~~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.

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. ~~Nevada Power, along~~The EPA issued a final FIP on August 8, 2014 adopting, 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~~limited changes, the Navajo Generating Station ~~is subject to renewal in 2019. Renewal of the lease will require completion of an Environmental Impact Statement as well~~proposal 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 the reduction of emissions of nitrogen oxides by approximately 80% through the retirement of one unit, or the curtailment of generation equivalent to one unit, in 2019 and installation of SCR controls at the other two units by 2030. In October 2014, several groups filed an appeal of the EPA's decision in the Ninth Circuit. The Hopi Tribe was initially part of the larger group appeal but their challenge was subsequently severed from that appeal and is proceeding separately. Until such time as additional action is taken by the Ninth Circuit and the uncertainties regarding lease and agreement renewal terms for the Navajo Generating Station are addressed, Nevada Power cannot predict the outcome of this matter."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. As of the end of 2017, no viable offers for a new ownership structure were presented. In the event that a new owner is identified, compliance with the FIP, imposing a long-term facility-wide cap on total emissions of nitrogen oxides and alternative operating scenarios such as curtailment or other emission reductions equivalent to installation of selective catalytic reduction on two units in 2030, would be required.

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

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 iswas the Clean Power Plan which was finalized by the EPA in ~~2015.~~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-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards ~~have been~~were appealed to the D.C. Circuit ~~Court~~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 ~~Appeals. However, despite~~time. Until such time as the ~~pendency of~~EPA undertakes further action to reconsider the ~~appeal,~~new source performance standards 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 ~~EPA also changed the~~ compliance period ~~to begin~~would have begun 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~~2030 and ~~1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is~~was 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, onOn 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 ~~Court of Appeals~~ and any action on a writ of certiorari before the ~~United States~~U.S. Supreme Court. Oral argument was heard before the D.C. Circuit on September 27, 2016. The court has not yet issued its decision. On October 10, 2017, the EPA issued a proposal to repeal the Clean Power Plan and the EPA will take comments on the proposed repeal until April 26, 2018. In addition, the EPA published in the Federal Register an Advance Notice of Proposed Rulemaking on December 28, 2017, seeking public input on, without committing to, a potential replacement rule. The public comment period for the Advance Notice of Proposed Rulemaking is currently scheduled to conclude February 26, 2018. The full impacts of the ~~final rule or~~EPA's recent efforts to repeal the ~~federal plan~~Clean Power Plan are not expected to have a material impact on the ~~Registrants cannot be determined until the outcome of the pending litigation and subsequent appeals, the development and implementation of state plans, and finalization of the federal plan.~~Registrants. 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~~advanced customer energy efficiency programs.

InNotwithstanding the absence of comprehensive climate legislation or regulation, the Registrants have continued to invest in lower- and non-carbon generating resources and to operate in an environmentally responsible manner. In July 2015, BHE signed the American Business Act on Climate pledge, in which BHE pledged to build on the Company's combined investment of more than $15 billion in renewable energy generation under construction and in operation through 2014 by investing up to an additional $15 billion. Components of BHE's pledge, which continue to be implemented, include:

Pursue the construction of an additional 552 MW of new wind-powered generation in Iowa, increasing MidAmerican Energy's generating portfolio to more than 4,000 MW of wind, which was equivalent to an estimated 51 percent of its Iowa customers' annual retail usage in 2017. MidAmerican Energy surpassed its Climate Pledge commitments in 2016 and 2017 and is currently continuing with the construction of an additional 2,000 MW of wind-powered generation in Iowa, of which 334 MW was placed in-service in 2017. The 2,000-MW wind project is expected to be fully complete in late 2019, and by year-end 2020, MidAmerican Energy's annual renewable energy generation is expected to reach a level that is equivalent to ~~58 percent~~more than 90% of its Iowa customers' annual retail ~~energy load in 2017.~~usage. MidAmerican Energy owns the largest portfolio of wind-powered generating capacity in the United States among rate-regulated utilities.

Retire more than 75 percent of the Nevada Utilities' coal-fueled generating capacity in Nevada by 2019. In accordance with the ERCR plan filed in May 2014, Nevada Power retired Reid Gardner Units Nos. 1-3 in December 2014 and Reid Gardner Unit No. 4 in March 2017, which represented 300 MW and 257 MW, respectively, of coal-fueled generating capacity in Nevada. Additionally, as part of the ERCR plan filed in May 2014 and approved by the PUCN, Nevada Power anticipates eliminating its ownership participation in the Navajo Generating Station in 2019.

Add more than 1,000 MW of incremental solar and wind capacity through long-term power purchase agreements to PacifiCorp's owned 1,030 MW of wind-powered generating capacity. PacifiCorp owns the second largest portfolio of wind-powered generating capacity in the United States among rate-regulated utilities. ~~This incremental renewable generation, expected~~PacifiCorp's Climate Pledge commitments were met December 2016. As of December 31, 2017, PacifiCorp's non-carbon generating capacity, owned and contracted, totaled 4,573 MW, which is capable of generating energy equivalent to ~~be on-line~~24 percent of its retail sales in 2017. In 2017, PacifiCorp announced Energy Vision 2020, which will significantly expand the amount of wind power serving customers by 2020 through a $3 billion investment in repowering its existing wind fleet with larger blades and newer technology; adding at least 1,311 megawatts of new wind resources by the end of ~~2017, would bring PacifiCorp's non-carbon generating capacity~~2020; and building transmission in Wyoming to ~~more than 4,500 MW, which equates to approximately 22 percent of PacifiCorp's retail energy load in 2017.~~enable additional wind generation.

Invest in transmission infrastructure in the West and Midwest to support the integration of renewable energy onto the grid.

Support and advance the development of markets in the West to optimize the electric grid, lower costs, enhance reliability and more effectively integrate renewable sources.

New federal, regional, state and international accords, legislation, regulation, or judicial proceedings limiting GHG emissions could have a material adverse impact on the Registrants, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Registrants include:

Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;

Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;

Additional costs may be incurred to purchase and deploy new generating technologies;

Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;

Operating costs may be higher and generating unit outputs may be lower;

Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and

The relevant Registrant's natural gas pipeline operations, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.

The impact of events or conditions caused by climate change, whether from natural processes or human activities, are uncertain and could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Registrants' existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.

Regional and State Activities

Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant, and include:

In June 2013, Nevada ~~Senate Bill~~SB 123 ~~("SB 123")~~ was signed into law. Among other things, SB 123 and regulations thereunder require Nevada Power to file with the PUCN an emission reduction and capacity replacement plan by May 1, 2014. In May 2014, Nevada Power filed its emissions reduction capacity replacement plan. The plan provided for the retirement or elimination of 300 MW of coal generating capacity by December 31, 2014, another 250 MW of coal generating capacity by December 31, 2017, and another 250 MW of coal generating capacity by December 31, 2019, along with replacement of such capacity with a mixture of constructed, acquired or contracted renewable and non-technology specific generating units. The plan also sets forth the expected timeline and costs associated with decommissioning coal-fired generating units that will be retired or eliminated pursuant to the plan. The PUCN has the authority to approve or modify the emission reduction and capacity replacement plan filed by Nevada Power. Given the PUCN may recommend and/or approve variations to Nevada Power's resource plans relative to requirements under SB 123, the specific impacts of ~~SB��~~SB 123 on Nevada Power cannot be determined.

Under the authority of California's Global Warming Solutions Act, ~~signed into law in 2006,~~which includes a series of policies aimed at returning California greenhouse gas emissions to 1990 levels by 2020, the California Air Resources Board adopted a GHG cap-and-trade program with an effective date of January 1, 2012; compliance obligations were imposed on entities beginning in 2013. ~~The~~PacifiCorp is subject to the cap-and-trade program ~~purports to impose compliance obligations on entities, including PacifiCorp, that deliver~~as a retail service provider in California and an importer of wholesale energy to points that are outside of California, irrespective of retail service obligations. These obligations and other impacts to wholesale energy market structures may, if implemented as written, increase costs to PacifiCorp.into California. In addition, California law imposes a GHG emissions performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the GHG emissions levels of a state-of-the-art combined-cycle natural gas-fueled generating facility, as well as legislation that adopts2015, Governor Jerry Brown issued an ~~economy-wide cap on GHG emissions to 1990 levels by 2020. An~~ executive order ~~issued in 2015 aims~~ to reduce emissions to 40% below 1990 levels by 2030 and 80% by 2050. In September 2016, California Senate Bill 32 was signed into law establishing greenhouse gas emissions reduction targets of 40% below 1990 levels by 2030.

The states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electricity generating resources. Under the laws in California and Oregon, the emissions performance standards provide that emissions must not exceed 1,100 pounds of carbon dioxide per MWh. Effective April 2013, Washington's amended emissions performance standards provide that GHG emissions for base load electricity generating resources must not exceed 970 pounds of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.

Washington and Oregon enacted legislation in May 2007 and August 2007, respectively, establishing goals for the reduction of GHG emissions in their respective states. Washington's goals seek to (a) reduce emissions to 1990 levels by 2020; (b) reduce emissions to 25% below 1990 levels by 2035; and (c) reduce emissions to 50% below 1990 levels by 2050, or 70% below Washington's forecasted emissions in 2050. Oregon's goals seek to (a) cease the growth of Oregon GHG emissions by 2010; (b) reduce GHG levels to 10% below 1990 levels by 2020; and (c) reduce GHG levels to at least 75% below 1990 levels by 2050. Each state's legislation also calls for state government to develop policy recommendations in the future to assist in the monitoring and achievement of these goals.

In ~~January~~September 2016, the Washington State Department of Ecology ~~proposed~~issued a ~~new~~final rule regulating ~~greenhouse gas~~GHG emissions from sources in Washington. The ~~proposed~~ rule ~~would regulate~~regulates greenhouse gases including carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride beginning in 2017 with three-year compliance periods thereafter (i.e., 2017-2019, 2020-2022, etc.). Under the ~~proposed~~ rule, the Washington State Department of Ecology ~~will establish a greenhouse gas~~established GHG emissions reduction ~~pathway~~pathways for all covered entities. Covered entities may use emission reduction units, which may be traded with other covered entities, to meet their compliance requirements. PacifiCorp's resources that ~~would be~~are covered under the ~~proposed~~ rule ~~would~~ include the Chehalis generating facility, which is a natural gas combined-cycle plant located in Washington state. PacifiCorp received its baseline emission order on December 17, 2017, which specified the emission reduction requirements for the Chehalis generating facility every three years beginning in 2017. The reduction requirements average 1.7% per year. However, the Washington State Department of Ecology suspended the compliance obligations of the Clean Air Rule after a Thurston County Superior Court judge ruled the state lacks authority to mandate reductions from indirect emitters. Pending further interpretation of the court’s decision by the Washington State Department of Ecology, entities subject to the rule are required to continue reporting emissions.

The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to reduce GHG emissions in ten Northeastern and Mid-Atlantic states, required, beginning in 2009, the reduction of carbon dioxide emissions from the power sector of 10% by 2018. In May 2011, New Jersey withdrew from participation in the Regional Greenhouse Gas Initiative. Following a program review in 2012, the nine Regional Greenhouse Gas Initiative states implemented a new 2014 cap which was approximately 45% lower than the 2012-2013 cap. The cap is reduced each year ~~thereafter~~ by 2.5%. from 2015 to 2020. As called for in the 2012 program review, a program review was initiated for 2016 and continues through 2017 with the expectation that states will implement program changes in the fourth control period from 2018 to 2020. In December 2017, an updated model rule was released by the Regional Greenhouse Gas Initiative states which includes an additional 30% regional cap reduction between 2020 and 2030.

GHG Litigation

Each Registrant closely monitors ongoing environmental litigation applicable to its respective operations. Numerous lawsuits have been unsuccessfully pursued against the industry that attempt to link GHG emissions to public or private harm. The lower courts initially refrained from adjudicating the cases under the "political question" doctrine, because of their inherently political nature. These cases have typically been appealed to federal appellate courts and, in certain circumstances, to the United States Supreme Court. ~~An adverse ruling~~In the U.S. Supreme Court's 2011 decision in ~~similar~~the case of American Electric Power Co., Inc., et al. v. Connecticut et al., the court addressed the question of whether federal common law nuisance claims could be maintained against certain electric power companies' for their GHG emissions and require the setting of an emissions cap for the emitters. The court held that the Clean Air Act and the EPA actions it authorizes displace any federal common law right to seek abatement of carbon dioxide emissions from fossil-fuel-fired power plants. Recent efforts by the EPA to repeal the Clean Power Plan could increase the filing of common law nuisance lawsuits against emitters of GHG. Adverse rulings in GHG-related cases ~~would likely~~could result in increased ~~regulation~~or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities.

The GHG rules, changes to those rules, and the Registrants' compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.

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.

Utah's Energy Resource and Carbon Emission Reduction Initiative provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere within the WECC, and renewable energy credits can be used.

The Oregon Renewable Energy Act ("OREA") provides a comprehensive renewable energy policy and RPS for Oregon. Subject to certain exemptions and cost limitations established in the law, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, and 20% in 2020 through 2024. In March 2016, Oregon Senate Bill No. 1547-B, the Clean Electricity and Coal Transition Plan, was signed into law. Senate Bill No. 1547-B requires that coal-fueled resources are eliminated from Oregon's allocation of electricity by January 1, 2030, and increases the current RPS target from 25% in 2025 to 50% by 2040. Senate Bill No. 1547-B also implements new REC banking provisions, as well as the following interim RPS targets: 27% in 2025 through 2029, 35% in 2030 through 2034, 45% in 2035 through 2039, and 50% by 2040 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs.

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.

The California RPS required all California retail sellers to procure an average of 20% of retail load from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020. In October 2015, California Senate Bill No. 350 was signed into law, which increased the current RPS requirement to 40% by December 31, 2024, 45% by December 31, 2027 and 50% by December 31, 2030. In December 2011, the CPUC adopted a decision confirming that multi-jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits within the three product content categories of RPS-eligible resources established by the legislation that have been imposed on other California retail sellers.

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.~~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. ~~Permitting~~Under the originally-promulgated guidelines, permitting authorities ~~are~~were required to include the new limits in each impacted facility's discharge permit upon ~~renewal;~~renewal with the new limits ~~must~~to be met as soon as possible, beginning November 1, 2018 and ~~must be~~fully implemented by December 31, 2023. ~~Most~~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. 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.~~facilities, the impact of the rule cannot be fully determined until the reconsideration action is 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~~"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. 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 U.S. 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. Depending on the outcome of final action by the ~~appeal(s),~~EPA and additional legal action, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits will be required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. However, 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 ~~presenting two alternatives to regulation~~ under the RCRA. ~~The public comment period closed in November 2010.~~ 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 will be posted to the respective Registrant's coal combustion rule compliance data and information websites by March 2, 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 ~~owns~~owned or ~~operates~~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, ~~were closed,~~ four impoundments discontinued receipt of coal combustion byproducts ~~and are subject to final closure on or before April 2018,~~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 Form 10-K and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for discussion of the impacts on asset retirement obligations as a result of the final rule.

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. On September 13, 2017, EPA Administrator Pruitt issued a letter to parties petitioning for administrative reconsideration of certain aspects of the coal combustion byproducts rule concluding it was appropriate and in the public interest to reconsider the provisions of the final rule addressed in the petitions. On September 27, 2017, the D.C. Circuit issued an order to the EPA requiring the agency to identify provisions of the rule that the agency intended to reconsider. The EPA submitted its list of potential issues to be reconsidered on November 15, 2017 and oral argument was held by the D.C. Circuit November 20, 2017 over certain portions of the final rule. The court has not yet issued a decision on the issues presented in the oral arguments. 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 January 16, 2018, the EPA proposed to approve the application. 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 2018.

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.

Other

Other laws, regulations and agencies to which the relevant Registrants are subject include, but are not limited to:

The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs.

The Nuclear Waste Policy Act of 1982, under which the United States Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 13 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 1112 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's nuclear decommissioning obligations.

The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of PacifiCorp's mining activities.

The FERC evaluates hydroelectric systems to ensure environmental impacts are minimized, including the issuance of environmental impact statements for licensed projects both initially and upon relicensing. The FERC monitors the hydroelectric facilities for compliance with the license terms and conditions, which include environmental provisions. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 13 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for information regarding the relicensing of PacifiCorp's Klamath River hydroelectric system.

The Registrants expect they will be allowed to recover their respective prudently incurred costs to comply with the environmental laws and regulations discussed above. The Registrants' planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (d) state-specific energy policies, resource preferences and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates affordable. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Registrants at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Registrants have established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.

Item 1A. Risk Factors

Each Registrant is subject to numerous risks and uncertainties, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by the relevant Registrant, should be made before making an investment decision. Additional risks and uncertainties not presently known or which each Registrant currently deems immaterial may also impair its business operations. Unless stated otherwise, the risks described below generally relate to each Registrant.

Corporate and Financial Structure Risks

BHE is a holding company and depends on distributions from subsidiaries, including joint ventures, to meet its obligations.

BHE is a holding company with no material assets other than the ownership interests in its subsidiaries and joint ventures, collectively referred to as its subsidiaries. Accordingly, cash flows and the ability to meet BHE's obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to BHE in the form of dividends or other distributions. BHE's subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, or to make funds available, whether by dividends or other payments, for the payment of amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, and do not guarantee the payment of any of its obligations. Distributions from subsidiaries may also be limited by:

their respective earnings, capital requirements, and required debt and preferred stock payments;

the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and

regulatory restrictions that limit the ability of BHE's regulated utility subsidiaries to distribute profits.

BHE is substantially leveraged, the terms of its existing senior and junior subordinated debt do not restrict the incurrence of additional debt by BHE or its subsidiaries, and BHE's senior debt is structurally subordinated to the debt of its subsidiaries, and each of such factors could adversely affect BHE's consolidated financial results.

A significant portion of BHE's capital structure is comprised of debt, and BHE expects to incur additional debt in the future to fund items such as, among others, acquisitions, capital investments and the development and construction of new or expanded facilities. As of December 31, ~~2015~~2017, BHE had the following outstanding obligations:

senior unsecured debt of ~~$7.8~~$6.5 billion;

junior subordinated debentures of ~~$2.9~~$100 million;

short-term borrowings of $3.3 billion;

~~borrowings under its commercial paper program of $253 million;~~

guarantees and letters of credit in respect of subsidiary and equity method investments aggregating $~~234~~332 million; and

commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling ~~$478~~$265 million.

BHE's consolidated subsidiaries also have significant amounts of outstanding debt, which totaled ~~$27.9~~$29.8 billion as of December 31, ~~2015~~2017. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) BHE's share of the outstanding debt of its own or its subsidiaries' equity method investments.

Given BHE's substantial leverage, it may not have sufficient cash to service its debt, which could limit its ability to finance future acquisitions, develop and construct additional projects, or operate successfully under difficult conditions, including those brought on by adverse national and global economies, unfavorable financial markets or growth conditions where its capital needs may exceed its ability to fund them. BHE's leverage could also impair its credit quality or the credit quality of its subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.

The terms of BHE's debt do not limit its ability or the ability of its subsidiaries to incur additional debt or issue preferred stock. Accordingly, BHE or its subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations, capital leases or other highly leveraged transactions that could significantly increase BHE's or its subsidiaries' total amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect BHE's consolidated financial results. Many of BHE's subsidiaries' debt agreements contain covenants, or may in the future contain covenants, that restrict or limit, among other things, such subsidiaries' ability to create liens, sell assets, make certain distributions, incur additional debt or miss contractual deadlines or requirements, and BHE's ability to comply with these covenants may be affected by events beyond its control. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of BHE's other debt, BHE may not have sufficient funds to repay all of the accelerated debt simultaneously, and the other risks described under "Corporate and Financial Structure Risks" may be magnified as well.

Because BHE is a holding company, the claims of its senior debt holders are structurally subordinated with respect to the assets and earnings of its subsidiaries. Therefore, the rights of its creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders, if any. In addition, pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties ~~and~~in the state of Nevada, AltaLink's transmission properties, the equity interest of MidAmerican Funding's subsidiary ~~the long-term customer contracts of Kern River~~ and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects, are directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of BHE's debt.

A downgrade in BHE's credit ratings or the credit ratings of its subsidiaries, including the Subsidiary Registrants, could negatively affect BHE's or its subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.

BHE's senior unsecured debt and its subsidiaries' long-term debt, including the Subsidiary Registrants, are rated by various rating agencies. BHE cannot give assurance that its senior unsecured debt rating or any of its subsidiaries' long-term debt ratings will not be reduced in the future. Although none of the Registrants' outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase any such Registrant's borrowing costs and commitment fees on its revolving credit agreements and other financing arrangements, perhaps significantly. In addition, such Registrant would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market, the principal source of short-term borrowings for each Registrant, could be significantly limited, resulting in higher interest costs.

Similarly, any downgrade or other event negatively affecting the credit ratings of BHE's subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause BHE to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing its and its subsidiaries' liquidity and borrowing capacity.

Most of the Registrants' large wholesale customers, suppliers and counterparties require such Registrant to have sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If the credit ratings of a Registrant were to decline, especially below investment grade, the relevant Registrant's financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other form of security for existing transactions and as a condition to entering into future transactions with such Registrant. Amounts may be material and may adversely affect such Registrant's liquidity and cash flows.

BHE's majority shareholder, Berkshire Hathaway, could exercise control over BHE in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors and BHE could exercise control over the Subsidiary Registrants in a manner that would benefit BHE to the detriment of ~~their~~the Subsidiary Registrants' creditors and PacifiCorp's preferred stockholders.

Berkshire Hathaway is majority owner of BHE and has control over all decisions requiring shareholder approval. In circumstances involving a conflict of interest between Berkshire Hathaway and BHE's creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors.

BHE indirectly owns all of the common stock of PacifiCorp, Nevada Power and Sierra Pacific and is the sole member of MidAmerican Funding and, accordingly, indirectly owns all of MidAmerican Energy's common stock. As a result, BHE has control over all decisions requiring shareholder approval, including the election of directors. In circumstances involving a conflict of interest between BHE and the creditors of the Subsidiary Registrants, ~~and PacifiCorp's preferred stockholders,~~ BHE could exercise its control in a manner that would benefit BHE to the detriment of ~~their creditors and PacifiCorp's preferred stockholders.~~the Subsidiary Registrants' creditors.

Business Risks

Much of BHE's growth has been achieved through acquisitions, and any such ~~acquisitions~~acquisition may not be successful.

Much of BHE's growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. BHE will continue to investigate and pursue opportunities for future acquisitions that it believes, but cannot assure you, may increase value and expand or complement existing businesses. BHE may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful.

Any acquisition entails numerous risks, including, among others:

the failure to complete the transaction for various reasons, such as the inability to obtain the required regulatory approvals, materially adverse developments in the potential acquiree's business or financial condition or successful intervening offers by third parties;

the failure of the combined business to realize the expected benefits;

the risk that federal, state or foreign regulators or courts could require regulatory commitments or other actions in respect of acquired assets, potentially including programs, contributions, investments, divestitures and market mitigation measures;

the risk of unexpected or unidentified issues not discovered in the diligence process; and

the need for substantial additional capital and financial investments.

An acquisition could cause an interruption of, or a loss of momentum in, the activities of one or more of BHE's subsidiaries. In addition, the final orders of regulatory authorities approving acquisitions may be subject to appeal by third parties. The diversion of BHE management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect BHE's combined businesses and financial results and could impair its ability to realize the anticipated benefits of the acquisition.

BHE cannot assure you that future acquisitions, if any, or any integration efforts will be successful, or that BHE's ability to repay its obligations will not be adversely affected by any future acquisitions.

The Registrants are subject to operating uncertainties and events beyond each respective Registrant's control that impact the costs to operate, maintain, repair and replace utility and interstate natural gas pipeline systems, which could adversely affect each respective Registrant's consolidated financial results.

The operation of complex utility systems or interstate natural gas pipeline and storage systems that are spread over large geographic areas involves many operating uncertainties and events beyond each respective Registrant's control. These potential events include the breakdown or failure of the Registrants' thermal, nuclear, hydroelectric, solar, wind and other electricity generating facilities and related equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, which could lead to catastrophic events; unscheduled outages; strikes, lockouts or other labor-related actions; shortages of qualified labor; transmission and distribution system constraints; failure to obtain, renew or maintain rights-of-way, easements and leases on United States federal, Native American, First Nations or tribal lands; terrorist activities or military or other actions, including cyber attacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; third party excavation errors; unexpected degradation of pipeline systems; design, construction or manufacturing defects; and catastrophic events such as severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism ~~embargoes~~ and ~~mining accidents.~~embargoes. A catastrophic event might result in injury or loss of life, extensive property damage or environmental or natural resource damages. For example, in the event of an uncontrolled release of water at one of PacifiCorp's high hazard potential hydroelectric dams, it is probable that loss of human life, disruption of lifeline facilities and property damage could occur in the downstream population and civil or other penalties could be imposed by the FERC. Any of these events or other operational events could significantly reduce or eliminate the relevant Registrant's revenue or significantly increase its expenses, thereby reducing the availability of distributions to BHE. For example, if the relevant Registrant cannot operate its electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event, its revenue could decrease and its expenses could increase due to the need to obtain energy from more expensive sources. Further, the Registrants self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs. The scope, cost and availability of each Registrant's insurance coverage may change, including the portion that is self-insured. Any reduction of each Registrant's revenue or increase in its expenses resulting from the risks described above, could adversely affect the relevant Registrant's consolidated financial results.

Each Registrant is subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety, reliability and other laws and regulations that affect its operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations, including initiatives regarding deregulation and restructuring of the utility industry, are continually being proposed and enacted that impose new or revised requirements or standards on each Registrant.

Each Registrant is required to comply with numerous federal, state, local and foreign laws and regulations as described in "General Regulation" and "Environmental Laws and Regulations" in Item 1 of this Form 10-K that have broad application to each Registrant and limits the respective Registrant's ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring or disposing of operating assets; operating and maintaining generating facilities and transmission and distribution system assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; transacting between subsidiaries and affiliates; and paying dividends or similar distributions. These laws and regulations, which are followed in developing the Registrants' safety and compliance programs and procedures, ~~and~~ are implemented and enforced by federal, state and local regulatory agencies, such as ~~among others,~~ the Occupational Safety and Health Administration, the FERC, the EPA, the DOT, the NRC, the Federal Mine Safety and Health Administration and various state regulatory commissions in the United States, and foreign regulatory agencies, such as GEMA, which discharges certain of its powers through its staff within Ofgem, in Great Britain and the AUC in Alberta, Canada.

Compliance with applicable laws and regulations generally requires each Registrant to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs and damages arising out of contaminated ~~properties and refunds, fines, penalties and injunctive measures affecting operating assets for failure to comply with environmental regulations.~~properties. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, each Registrant could be required to shut down some facilities or materially alter its operations. Further, each Registrant may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for its operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay each Registrant from operating its facilities, developing or favorably locating new facilities or expanding existing facilities. If any Registrant fails to comply with any environmental or other regulatory requirements, such Registrant may be subject to penalties and fines or other sanctions, including changes to the way its electricity generating facilities are operated that may adversely impact generation or how the Pipeline Companies are permitted to operate their systems that may adversely impact throughput. The costs of complying with laws and regulations could adversely affect each Registrant's consolidated financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require such Registrant to increase its purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect such Registrant's consolidated financial results.

Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition and decreased revenues within each Registrant's service ~~territories;~~territories, such as the Nevada Energy Choice Initiative; new environmental requirements, including the implementation of or changes to the Clean Power Plan, RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to each Registrant's service territories as a result of condemnation or takeover by municipalities or other governmental entities, particularly where it lacks the exclusive right to serve its customers; the inability of each Registrant to recover its costs on a timely basis, if at all; new pipeline safety requirements; or a negative impact on each Registrant's current transportation and cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on each Registrant.

Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones are among the most challenging aspects of managing utility operations. The Registrants cannot accurately predict the type or scope of future laws and regulations that may be enacted, changes in existing ones or new interpretations by agency orders or court decisions nor can each Registrant determine their impact on it at this time; however, any one of these could adversely affect each Registrant's consolidated financial results through higher capital expenditures and operating costs and early closure of generating facilities or restrict or otherwise cause an adverse change in how each Registrant operates its business. To the extent that each Registrant is not allowed by its regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the costs of complying with such additional requirements could have a material adverse effect on the relevant Registrant's consolidated financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on the relevant Registrant's consolidated financial results. The Registrants have made their best estimate regarding the impact of the 2017 Tax Reform and the probability and timing of settlements of net regulatory liabilities established pursuant to the 2017 Tax Reform. However, the amount and timing of the settlements may change based on decisions and actions by each Registrant's regulators, which could have an effect on the relevant Registrant's consolidated financial results.

Recovery of costs and certain activities by each Registrant is subject to regulatory review and approval, and the inability to recover costs or undertake certain activities may adversely affect each Registrant's consolidated financial results.

State Regulatory Rate Review Proceedings

The Utilities establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but generally have the common objective of limiting rate increases while also requiring the Utilities to ensure system reliability. Decisions are subject to judicial appeal, potentially leading to further uncertainty associated with the approval proceedings.

States set retail rates based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any ~~state.~~state or other jurisdiction. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense, investment and capital structure that it deems are just and reasonable in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standard. Additionally, each state regulatory commission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital. While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that each Registrant will be able to realize the allowed rate of return.

Energy cost increases above the level assumed in establishing base rates may be subject to customer sharing. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on the Utilities, despite efforts to minimize this impact through the use of hedging contracts and sharing mechanisms or through future general regulatory rate ~~cases.~~reviews. Any of these consequences could adversely affect each Registrant's consolidated financial results.

FERC Jurisdiction

The FERC authorizes cost-based rates associated with transmission services provided by the Utilities' transmission facilities. Under the Federal Power Act, the Utilities, or MISO as it relates to MidAmerican Energy, may voluntarily file, or may be obligated to file, for changes, including general rate changes, to their system-wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity at wholesale, has jurisdiction over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect each Registrant's consolidated financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. As a transmission owning member of ~~the~~ MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. As participants in EIM, PacifiCorp, Nevada Power and Sierra Pacific are also subject to applicable California ISO rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.

The NERC has standards in place to ensure the reliability of the electric generation system and transmission ~~grid and generation system.~~grid. The Utilities are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.

The FERC has jurisdiction over, among other things, the construction, abandonment, modification and operation of natural gas pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including all rates, charges and terms and conditions of service. The FERC also has market transparency authority and has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.

Rates for the interstate natural gas transmission and storage operations at the Pipeline Companies, which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for charges, are authorized by the FERC. In accordance with the FERC's rate-making principles, the Pipeline Companies' current maximum tariff rates are designed to recover prudently incurred costs included in their pipeline system's regulatory cost of service that are associated with the construction, operation and maintenance of their pipeline system and to afford the Pipeline Companies an opportunity to earn a reasonable rate of return. Nevertheless, the rates the FERC authorizes the Pipeline Companies to charge their customers may not be sufficient to recover the costs incurred to provide services in any given period. Moreover, from time to time, the FERC may change, alter or refine its policies or methodologies for establishing pipeline rates and terms and conditions of service. In addition, the FERC has the authority under Section 5 of the Natural Gas Act of 1938 ("NGA") to investigate whether a pipeline may be earning more than its allowed rate of return and, when appropriate, to institute proceedings against such pipeline to prospectively reduce rates. Any such proceedings, if instituted, could result in significantly adverse rate decreases.

Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the maximum tariff rate for that service or the pipeline may agree to provide a discounted rate, which would be a rate between the maximum and minimum tariff rates. In a rate proceeding, rates in these contracts are generally not subject to adjustment. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the cost used in the determination of the negotiated or discounted rates, which could result either in losses or lower rates of return for providing such services. Under certain circumstances, FERC policy allows interstate natural gas pipelines to design new maximum tariff rates to recover such costs ~~under certain circumstances~~ in regulatory rate ~~cases.~~reviews. However, with respect to discounts granted to affiliates, the interstate natural gas pipeline must demonstrate that the discounted rate was necessary in order to meet competition.

GEMA Jurisdiction

The Northern Powergrid Distribution Companies, as Distribution Network Operators ("DNOs") and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year to year, but is a control on revenue that operates independently of ~~most~~a significant portion of the DNO's actual costs. A resetting of the formula does not require the consent of the DNO, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's Competition and Markets Authority. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of any price control, additional costs have a direct impact on the financial results of the Northern Powergrid Distribution Companies.

AUC Jurisdiction

The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including ALP, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems.

The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of ALP's activities, including its tariffs, rates, construction, operations and financing. The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:

regulating and adjudicating issues related to the operation of electric utilities within Alberta;

processing and approving general tariff applications relating to revenue requirements and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable and approval of the transmission tariff rates of regulated transmission providers by the AESO, which is the independent transmission system operator in Alberta ~~Canada~~ that controls the operation of AltaLink's transmission system;

approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;

reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;

adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and

collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.

In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.

The AESO determines the need and plans for the expansion and enhancement of a congestion free transmission system in Alberta in accordance with applicable law and reliability standards. The AESO's responsibilities include long-term transmission planning and management, including assessing and planning for the current and future transmission system capacity needs of AESO market participants. When AESO determines an expansion or enhancement of the transmission system is needed, with limited exceptions, it submits an application to the AUC for approval of the proposed expansion or enhancement. The AESO then determines which transmission provider should submit an application to the AUC for a permit and license to construct and operate the designated transmission facilities. Generally the transmission provider operating in the geographic area where the transmission facilities expansion or enhancement is to be located is selected by the AESO to build, own and operate the transmission facilities. In addition, Alberta law provides that transmission projects may be subject to a competitive process open to qualifying bidders. In either case, there can be no assurance that any jurisdictional market participant that BHE may own, including AltaLink, will be selected by the AESO to build, own and operate transmission facilities, even if BHE's market participant operates in the relevant geographic area, or that BHE's market participant will be successful in any such competitive process in which it may participate.

Physical or cyber attacks, both threatened and actual, could impact each Registrant's operations and could adversely affect its consolidated financial results.

Each Registrant relies on information technology in virtually all aspects of its business. A significant disruption or failure of its information technology systems by physical or cyber attack could result in service interruptions, safety failures, security violations, regulatory compliance failures, an inability to protect sensitive corporate and customer information and assets against intruders, and other operational difficulties. Attacks perpetrated against each Registrant's information systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.

Although the Registrants have taken steps intended to mitigate these risks, a significant disruption or cyber intrusion could lead to misappropriation of assets or data corruption. Cyber attacks could further adversely affect each Registrant's ability to operate facilities, information technology and business systems, or compromise sensitive customer and employee information. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on each Registrant. Additionally, if each Registrant is unable to acquire or implement new technology, it may suffer a competitive disadvantage, which could also have an adverse effect on its results of operations, financial condition or liquidity. Any of these items could adversely affect each Registrant's results of operations, financial condition or liquidity.

Each Registrant is actively pursuing, developing and constructing new or expanded facilities, the completion and expected costs of which are subject to significant risk, and each Registrant has significant funding needs related to its planned capital expenditures.

Each Registrant actively pursues, develops and constructs new or expanded facilities. Each Registrant expects to incur significant annual capital expenditures over the next several years. Such expenditures may include construction and other costs for new electricity generating facilities, electric transmission or distribution projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline systems, and continued maintenance and upgrades of existing assets.

Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, labor, siting and permitting and changes in environmental and operational compliance matters, load forecasts and other items over a multi-year construction period, as well as counterparty risk and the economic viability of the Registrants' suppliers, customers and contractors. Certain of the Registrants' construction projects are substantially dependent upon a single supplier or contractor and replacement of such supplier or contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in-service and, in extreme cases, the loss of the power purchase agreements or other long-term off-take contracts underlying such projects. Such costs may not be recoverable in the regulated rates or market or contract prices each Registrant is able to charge its customers. Delays in construction of renewable projects may result in delayed in-service dates which may result in the loss of anticipated revenue or income tax benefits. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or recover any such costs could adversely affect such Registrant's consolidated financial results.

Furthermore, each Registrant depends upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If BHE does not provide needed funding to its subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures.

A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its consolidated financial results.

a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas;

an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;

shifts in competitively priced natural gas supply sources away from the sources connected to the Pipeline Companies' systems, including ~~new~~ shale gas sources;

efforts by customers, legislators and regulators to reduce the consumption of electricity generated or distributed by each Registrant through various existing laws and regulations, as well as, deregulation, conservation, energy efficiency and ~~distributed~~private generation measures and programs;

laws mandating or encouraging renewable energy sources, which may decrease the demand for electricity and natural gas or change the market prices of these commodities;

higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels;

a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise;

a reduction in the state or federal subsidies or tax incentives that are provided to agricultural, industrial or other customers, or a significant sustained change in prices for commodities such as ethanol or corn for ethanol manufacturers; and

sustained mild weather that reduces heating or cooling needs.

Each Registrant's operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.

In most parts of the United States and other markets in which each Registrant operates, demand for electricity peaks during the summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In other areas, demand for electricity peaks during the winter when heating needs are higher. In addition, demand for natural gas and other fuels generally peaks during the winter. This is especially true in ~~Northern Natural Gas' traditional end-use and distribution market area and~~ MidAmerican Energy's and Sierra Pacific's retail natural gas businesses. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may negatively impact electricity generation at PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, PacifiCorp and MidAmerican Energy have added substantial wind-powered generating capacity, and BHE's unregulated subsidiaries are adding solar and wind-powered generating capacity, each of which is also a climate-dependent resource.

As a result, the overall financial results of each Registrant may fluctuate substantially on a seasonal and quarterly basis. Each Registrant has historically provided less service, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect each Registrant's consolidated financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase each Registrant's costs to provide services and could adversely affect its consolidated financial results. The extent of fluctuation in each Registrant's consolidated financial results may change depending on a number of factors related to its regulatory environment and contractual agreements, including its ability to recover energy costs, the existence of revenue sharing provisions as it relates to MidAmerican Energy, and terms of its wholesale sale contracts.

Each Registrant is subject to market risk associated with the wholesale energy markets, which could adversely affect its consolidated financial results.

In general, each Registrant's primary market risk is adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. The market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity, scheduled and unscheduled outages of generating facilities, prices and availability of fuel sources for generation, disruptions or constraints to transmission and distribution facilities, weather conditions, demand for electricity, economic growth and changes in technology. Volumetric changes are caused by fluctuations in generation or changes in customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations or customer behavior. For example, the Utilities purchase electricity and fuel in the open market as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market prices, the Utilities may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when the Utilities are a net seller of electricity in the wholesale market, the Utilities could earn less revenue. Although the Utilities have energy cost adjustment mechanisms, the risks associated with changes in market prices may not be fully mitigated due to customer sharing bands as it relates to PacifiCorp and other factors.

Potential terrorist activities and the impact of military or other actions, could adversely affect each Registrant's consolidated financial results.

The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the United States government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Political, economic, social or financial market instability or damage to or interference with the operating assets of the Registrants, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect its consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.

~~Physical or cyber attacks, both threatened and actual, could impact each Registrant's operations and could adversely affect its consolidated financial results.~~

Each Registrant relies on information technology in virtually all aspects of its business. A significant disruption or failure of its information technology systems by physical or cyber attack could result in service interruptions, safety failures, security violations, regulatory compliance failures, an inability to protect corporate information assets against intruders, and other operational difficulties. Attacks perpetrated against each Registrant's information systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.

Although the Registrants have taken steps intended to mitigate these risks, including business continuity planning, disaster recovery planning and business impact analysis, a significant disruption or cyber intrusion could lead to misappropriation of assets or data corruption and could adversely affect each Registrant's results of operations, financial condition or liquidity. Additionally, if each Registrant is unable to acquire or implement new technology, it may suffer a competitive disadvantage, which could also have an adverse effect on its results of operations, financial condition or liquidity. Cyber attacks could further adversely affect each Registrant's ability to operate facilities, information technology and business systems, or compromise confidential customer and employee information. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on each Registrant.

Certain Registrants are subject to the unique risks associated with nuclear generation.

The ownership and operation of nuclear power plants, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, compliance with and changes in regulation of nuclear power plants, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. Additionally, Exelon Generation, the 75% owner and operator of the facility, may respond to the occurrence of any of these or other risks in a manner that negatively impacts MidAmerican Energy, including closure of Quad Cities Station prior to the expiration of its operating license. The prolonged unavailability, or early closure, of Quad Cities Station due to operational or economic factors could have a materially adverse effect on the relevant Registrant's financial results, particularly when the cost to produce power at the plant is significantly less than market wholesale prices. The following are among the more significant of these risks:

Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear power plant could cause regulators to require a shut-down or reduced availability at Quad Cities Station.

In addition, issues relating to the disposal of nuclear waste material, including the availability, unavailability and expense of a permanent repository for spent nuclear fuel could adversely impact operations as well as the cost and ability to decommission nuclear power plants, including Quad Cities Station, in the future.

Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with applicable Atomic Energy Act regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

Nuclear Accident and Catastrophic Risks - Accidents and other unforeseen catastrophic events have occurred at nuclear facilities other than Quad Cities Station, both in the United States and elsewhere, such as at the Fukushima Daiichi nuclear power plant in Japan as a result of the earthquake and tsunami in March 2011. The consequences of an accident or catastrophic event can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident or catastrophic event could exceed the relevant Registrant's resources, including insurance coverage.

Certain of BHE's subsidiaries are subject to the risk that customers will not renew their contracts or that BHE's subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect its consolidated financial results.

Substantially all of the Pipeline Companies' revenues are generated under transportation and storage contracts that periodically must be renegotiated and extended or replaced, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue. If BHE's subsidiaries are unable to renew, remarket, or find replacements for their customer agreements on favorable terms, BHE's subsidiaries' sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, BHE cannot assure that the Pipeline Companies will be able to transport natural gas at efficient capacity levels. Substantially all of the Pipeline Companies' revenues are generated under transportation and storage contracts that periodically must be renegotiated and extended or replaced, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue. Similarly, without long-term power purchase agreements, BHE cannot assure that its unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements, or being required to discount rates significantly upon renewal or replacement, could adversely affect BHE's consolidated financial results. The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond BHE's subsidiaries' control.

Each Registrant is subject to counterparty risk, which could adversely affect its consolidated financial results.

Each Registrant is subject to counterparty credit risk related to contractual payment obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom each Registrant conducts business could impair the ability of these counterparties to meet their payment obligations. Each Registrant depends on these counterparties to remit payments on a timely basis. Each Registrant continues to monitor the creditworthiness of its wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if any Registrant's wholesale suppliers' or customers' financial condition deteriorates or they otherwise become unable to pay, it could have a significant adverse impact on each Registrant's liquidity and its consolidated financial results.

Each Registrant is subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and contractors. Each Registrant relies on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the Utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the Utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.

Each Registrant relies on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require the relevant Registrant to find other customers to take the energy at lower prices than the original customers committed to pay. If each Registrant's wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on its consolidated financial results.

The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses with RWE Npower PLC and British Gas Trading Limited accounting for approximately 21% and 15%, respectively, of distribution revenue in 2017. AltaLink's primary source of operating revenue is the AESO. Generally, a single customer purchases the energy from ~~Berkshire Hathaway Energy's~~BHE's independent power projects in the United States and the Philippines pursuant to long-term power purchase agreements. ~~Without~~Any material performance failure by the counterparties ~~under~~in these ~~agreements, Berkshire Hathaway Energy cannot assure that its unregulated power generators will be able to operate profitably.~~arrangements could have a significant adverse impact on BHE's consolidated financial results.

BHE owns investments and projects in foreign countries that are exposed to risks related to fluctuations in foreign currency exchange rates and increased economic, regulatory and political risks.

BHE's business operations and investments outside the United States increase its risk related to fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar. BHE's principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from its foreign operations changes with the fluctuations of the currency in which they transact. BHE indirectly owns a hydroelectric power plant in the Philippines and may acquire significant energy-related investments and projects outside of the United States. BHE may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in, or indexed to, United States dollars or a currency freely convertible into United States dollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect BHE's consolidated financial results.

~~BHE indirectly owns a hydroelectric power plant in the Philippines and may acquire significant energy-related investments and projects outside of the United States.~~ In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where BHE has operations or is pursuing investment opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. BHE may not choose to or be capable of either fully insuring against or effectively hedging these risks.

Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning and mine reclamation trust funds could unfavorably impact each Registrant's cash flows and liquidity.

Costs of providing each Registrant's defined benefit pension and other postretirement benefit plans and costs associated with the joint trustee plan to which PacifiCorp contributes depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, mortality assumptions, the interest rates used to measure required minimum funding levels, the funded status of the plans, changes in benefit design, tax deductibility and funding limits, changes in laws and government regulation and each Registrant's required or voluntary contributions made to the plans. Certain of the Registrant's pension and other postretirement benefit plans are in underfunded positions. Even if sustained growth in the investments over future periods increases the value of these plans' assets, each Registrant will likely be required to make cash contributions to fund these plans in the future. Additionally, each Registrant's plans ~~has~~have investments in domestic and foreign equity and debt securities and other investments that are subject to loss. Losses from investments could add to the volatility, size and timing of future contributions.

Furthermore, the funded status of the UMWA 1974 Pension Plan multiemployer plan to which PacifiCorp's subsidiary previously contributed is considered critical and declining. PacifiCorp's subsidiary involuntarily withdrew from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp has recorded its best estimate of the withdrawal obligation. If participating employers withdraw from a multiemployer plan, the unfunded obligations of the plan may be borne by the remaining participating employers, including any employers that withdrew during the three years prior to a mass withdrawal.

In addition, MidAmerican Energy is required to fund over time the projected costs of decommissioning Quad Cities Station, a nuclear power plant, and Bridger Coal Company, a joint venture of PacifiCorp's subsidiary, Pacific Minerals, Inc., is required to fund projected mine reclamation costs. Funds that MidAmerican Energy has invested in a nuclear decommissioning trust and PacifiCorp has invested in a mine reclamation trust are invested in debt and equity securities and poor performance of these investments will reduce the amount of funds available for their intended purpose, which could require MidAmerican Energy or PacifiCorp to make additional cash contributions. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on MidAmerican Energy's or PacifiCorp's liquidity by reducing their available cash.

Inflation and changes in commodity prices and fuel transportation costs may adversely affect each Registrant's consolidated financial results.

Inflation and increases in commodity prices and fuel transportation costs may affect each Registrant by increasing both operating and capital costs. As a result of existing rate agreements, contractual arrangements or competitive price pressures, each Registrant may not be able to pass the costs of inflation on to its customers. If each Registrant is unable to manage cost increases or pass them on to its customers, its consolidated financial results could be adversely affected.

Cyclical fluctuations in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.

The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:

rising interest rates or unemployment rates, including a sustained high unemployment rate in the United States;

periods of economic slowdown or recession in the markets served;

decreasing home affordability;

lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit, which may continue into future periods;

~~declining demand for residential real estate as an investment;~~inadequate home inventory levels;

nontraditional sources of new competition; and

changes in applicable tax law.

Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant. Significant dislocations and liquidity disruptions in the United States, Great Britain, Canada and global credit markets, such as those that occurred in 2008 and 2009, may materially impact liquidity in the bank and debt capital markets, making financing terms less attractive for borrowers that are able to find financing and, in other cases, may cause certain types of debt financing, or any financing, to be unavailable. Additionally, economic uncertainty in the United States or globally may adversely affect the United States' credit markets and could negatively impact each Registrant's ability to access funds on favorable terms or at all. If each Registrant is unable to access the bank and debt markets to meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of its capital expenditures, acquisition financing and its consolidated financial results.

Potential changes in accounting standards may impact each Registrant's consolidated financial results and disclosures in the future, which may change the way analysts measure each Registrant's business or financial performance.

The Financial Accounting Standards Board ("FASB") and the SEC continuously make changes to accounting standards and disclosure and other financial reporting requirements. New or revised accounting standards and requirements issued by the FASB or the SEC or new accounting orders issued by the FERC could significantly impact each Registrant's consolidated financial results and disclosures. For example, beginning in 2018 all changes in the fair values of equity securities (whether realized or unrealized) will be recognized as gains or losses in the relevant Registrant's consolidated financial statements. Accordingly, periodic changes in such Registrant's reported net income will likely be subject to significant variability.

Each Registrant is involved in a variety of legal proceedings, the outcomes of which are uncertain and could adversely affect its consolidated financial results.

Each Registrant is, and in the future may become, a party to a variety of legal proceedings. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of individual matters with certainty. It is possible that the final resolution of some of the matters in which each Registrant is involved could result in additional material payments substantially in excess of established reserves or in terms that could require each Registrant to change business practices and procedures or divest ownership of assets. Further, litigation could result in the imposition of financial penalties or injunctions and adverse regulatory consequences, any of which could limit each Registrant's ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct its business, including the siting or permitting of facilities. Any of these outcomes could have a material adverse effect on such Registrant's consolidated financial results.


Item 1B.	Unresolved Staff Comments

Not applicable.

Item 2. Properties

Each Registrant's energy properties consist of the physical assets necessary to support its applicable electricity and natural gas businesses. Properties of the relevant Registrant's electricity businesses include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of PacifiCorp's electric generating facilities. Properties of the relevant Registrant's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, compressor stations and meter stations. The transmission and distribution assets are primarily within each Registrant's service territories. In addition to these physical assets, the Registrants have rights-of-way, mineral rights and water rights that enable each Registrant to utilize its facilities. It is the opinion of each Registrant's management that the principal depreciable properties owned by it are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, ~~AltaLink's~~ALP's transmission properties and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of generation projects are pledged or encumbered to support or otherwise provide the security for ~~their~~the related subsidiary debt. For additional information regarding each Registrant's energy properties, refer to Item 1 of this Form 10-K and Notes 4, 5 and 21 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K, Notes 34 and 85 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Nevada Power in Item 8 of this Form 10-K and Notes 3 and 4 of the Notes to Consolidated Financial Statements of Sierra Pacific in Item 8 of this Form 10-K.

The following table summarizes Berkshire Hathaway Energy's electric generating facilities that are in operation as of December 31, ~~2015~~2017:

Facility Net

Net Owned

Facility Net

Net Owned

Energy

Capacity

Source

Entity

Location by Significance

(MW)

Entity

Location by Significance

(MW)

Natural gas

PacifiCorp, MidAmerican Energy, NV Energy and BHE Renewables

Nevada, Utah, Iowa, Illinois, Washington, Oregon, New York, Texas and Arizona

10,943

10,534

PacifiCorp, MidAmerican Energy, NV Energy and BHE Renewables

Nevada, Utah, Iowa, Illinois, Washington, Oregon, Texas, New York and Arizona

10,919

10,640

Coal

PacifiCorp, MidAmerican Energy and NV Energy

Iowa, Wyoming, Arizona, Utah, Montana, Colorado and Nevada

16,864

9,798

PacifiCorp, MidAmerican Energy and NV Energy

Wyoming, Iowa, Utah, Arizona, Nevada, Colorado and Montana

16,232

9,158

Wind

PacifiCorp, MidAmerican Energy and BHE Renewables

Iowa, Wyoming, Washington, California, Texas, Oregon and Illinois

5,133

5,124

PacifiCorp, MidAmerican Energy and BHE Renewables

Iowa, Wyoming, Nebraska, Washington, California, Texas, Oregon, Illinois and Kansas

6,533

6,524

Solar

BHE Renewables and NV Energy

California, Arizona and Nevada

1,441

1,293

BHE Renewables and NV Energy

California, Texas, Arizona, Minnesota and Nevada

1,675

1,527

Hydroelectric

PacifiCorp, MidAmerican Energy

and BHE Renewables

Washington, Oregon, The Philippines, Idaho, California, Utah, Hawaii, Montana, Wyoming and Illinois

1,297

1,275

PacifiCorp, MidAmerican Energy

and BHE Renewables

Washington, Oregon, The Philippines, Idaho, California, Utah, Hawaii, Montana, Illinois and Wyoming

1,299

1,277

Nuclear

MidAmerican Energy

Illinois

1,824

456

MidAmerican Energy

Illinois

1,820

455

Geothermal

PacifiCorp and BHE Renewables

California and Utah

370

PacifiCorp and BHE Renewables

California and Utah

370

Total

37,872

28,850

Total

38,848

29,951

Additionally, ~~Berkshire Hathaway Energy~~the Company has electric generating facilities that are under construction in Iowa, ~~Nebraska~~Illinois and ~~Kansas~~Minnesota as of December 31, ~~2015~~2017 having total Facility Net Capacity and Net Owned Capacity of ~~1,066~~1,902 MW.

The right to construct and operate each Registrant's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through ~~the exercise of the power of~~prescription, eminent domain or similar rights. PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, Northern Natural Gas and Kern River in the United States; Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc in Great Britain; and ~~AltaLink~~ALP in Alberta, Canada continue to have the power of eminent domain or similar rights in each of the jurisdictions in which they operate their respective facilities, but the United States and Canadian utilities do not have the power of eminent domain with respect to governmental, or Native American ~~and~~or Canadian First Nations' tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.

With respect to real property, each of the electric transmission and distribution facilities and interstate natural gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generating facilities, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) parcels where the interest derives from leases, easements (including prescriptive easements), rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and interstate natural gas pipelines. Each Registrant believes it has satisfactory title or interest to all of the real property making up their respective facilities in all material respects.

Item 3. Legal Proceedings

Each Registrant is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Each Registrant does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Each Registrant is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts. ~~Refer to Note 13 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for information regarding legal proceedings.~~


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 Reform Act is included in Exhibit 95 to this Form 10-K.

PART II


Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

BERKSHIRE HATHAWAY ENERGY

BHE's common stock is beneficially owned by Berkshire Hathaway, Mr. Walter Scott, Jr., a member of BHE's Board of Directors (along with his family members and related or affiliated entities), and Mr. Gregory E. Abel, BHE's ~~Chairman, President and Chief~~ Executive ~~Officer,~~Chairman, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. BHE has not declared or paid any cash dividends to its common shareholders since Berkshire Hathaway acquired an equity ownership interest in BHE in March 2000, and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.

For a discussion of restrictions that limit BHE's and its subsidiaries' ability to pay dividends on their common stock, refer to Note 17 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K.

PACIFICORP

All common stock of PacifiCorp is held by its parent company, PPW Holdings LLC, which is a direct, wholly owned subsidiary of BHE.

PacifiCorp declared and paid dividends to PPW Holdings LLC of ~~$950~~$600 million in ~~2015~~2017 and ~~$725~~$875 million in ~~2014.~~2016.

For a discussion of regulatory restrictions that limit PacifiCorp's ability to pay dividends on common stock, refer to "Limitations" in PacifiCorp's Item 7 in this Form 10-K and to Note 15 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.

MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY

All common stock of MidAmerican Energy is held by its parent company, MHC, which is a direct, wholly owned subsidiary of MidAmerican Funding. MidAmerican Funding is an Iowa limited liability company whose membership interest is held solely by BHE. Neither MidAmerican Funding or MidAmerican Energy declared or paid any cash distributions or dividends to its sole member or shareholder in 2017 and 2016.

For a discussion of regulatory restrictions that limit MidAmerican Energy's ability to pay dividends on common stock, refer to "Debt Authorizations and Related Matters" in MidAmerican Energy's Item 7 in this Form 10-K and to Note 89 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form ~~10‑K.~~10-K.

NEVADA POWER

All common stock of Nevada ~~Power's common stock~~Power is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE.

Nevada Power declared and paid dividends to NV Energy of ~~$13~~$548 million in ~~2015~~2017 and ~~$230~~$469 million in ~~2014.~~2016.

SIERRA PACIFIC

All common stock of Sierra ~~Pacific's common stock~~Pacific is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE.

Sierra Pacific declared and paid dividends to NV Energy of $7$45 million in ~~2015~~2017 and ~~$105~~$51 million in ~~2014.~~2016.


Item 6.	Selected Financial Data



Berkshire Hathaway Energy Company and its subsidiaries		8589
PacifiCorp and its subsidiaries		~~177~~178
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		235
Nevada Power Company and its subsidiaries		~~310~~308
Sierra Pacific Power Company and its subsidiaries		~~349~~347


Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations



Berkshire Hathaway Energy Company and its subsidiaries		8689
PacifiCorp and its subsidiaries		~~178~~179
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		235
Nevada Power Company and its subsidiaries		~~311~~308
Sierra Pacific Power Company and its subsidiaries		~~350~~347


Item 7A.	Quantitative and Qualitative Disclosures About Market Risk



Berkshire Hathaway Energy Company and its subsidiaries		~~106~~109
PacifiCorp and its subsidiaries		191
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		~~250~~249
Nevada Power Company and its subsidiaries		~~321~~317
Sierra Pacific Power Company and its subsidiaries		~~359~~355


Item 8.	Financial Statements and Supplementary Data



Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~112~~115
Consolidated Balance Sheets		~~113~~116
Consolidated Statements of Operations		~~115~~118
Consolidated Statements of Comprehensive Income		~~116~~119
Consolidated Statements of Changes in Equity		~~117~~120
Consolidated Statements of Cash Flows		~~118~~121
Notes to Consolidated Financial Statements		~~119~~122
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~195~~196
Consolidated Balance Sheets		~~196~~197
Consolidated Statements of Operations		~~198~~199
Consolidated Statements of Comprehensive Income		~~199~~200
Consolidated Statements of Changes in Equity		~~200~~201
Consolidated Statements of Cash Flows		~~201~~202
Notes to Consolidated Financial Statements		~~202~~203
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		~~254~~252
Balance Sheets		~~255~~253
Statements of Operations		~~257~~255
Statements of Comprehensive Income		~~258~~256
Statements of Changes in Equity		~~259~~257
Statements of Cash Flows		~~260~~258
Notes to Financial Statements		~~261~~259
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~293~~291
Consolidated Balance Sheets		~~294~~292
Consolidated Statements of Operations		~~296~~294
Consolidated Statements of Comprehensive Income		~~297~~295
Consolidated Statements of Changes in Equity		~~298~~296
Consolidated Statements of Cash Flows		~~299~~297
Notes to Consolidated Financial Statements		~~300~~298
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~324~~320
Consolidated Balance Sheets		~~325~~321
Consolidated Statements of Operations		~~326~~322
Consolidated Statements of Changes in Shareholder's Equity		~~327~~323
Consolidated Statements of Cash Flows		~~328~~324
Notes to Consolidated Financial Statements		~~329~~325
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~362~~358
Consolidated Balance Sheets		~~363~~359
Consolidated Statements of Operations		~~364~~360
Consolidated Statements of Changes in Shareholder's Equity		~~365~~361
Consolidated Statements of Cash Flows		~~366~~362
Notes to Consolidated Financial Statements		~~367~~363

Berkshire Hathaway Energy Company and its subsidiaries

Consolidated Financial Section


Item 6.	Selected Financial Data

~~The following table sets forth the Company's selected consolidated historical financial data, which should be read in conjunction with the information in~~Information required by Item ~~7 of this~~6 is omitted pursuant to General Instruction I(2)(a) to Form ~~10-K and with the Company's historical Consolidated Financial Statements and notes thereto in Item 8 of this Form~~ 10-K. ~~The selected consolidated historical financial data has been derived from the Company's audited historical Consolidated Financial Statements and notes thereto (in millions).~~

Years Ended December 31,

2015⁽¹⁾

2014⁽¹⁾

2013⁽¹⁾
2012 2011
Consolidated Statement of Operations Data:
Operating revenue $ 17,880
$ 17,326
$ 12,635
$ 11,548
$ 11,173
Net income 2,400
2,122
1,676
1,495
1,352
Net income attributable to BHE shareholders 2,370
2,095
1,636
1,472
1,331

As of December 31,

2015⁽¹⁾

2014⁽¹⁾

2013⁽¹⁾
2012 2011
Consolidated Balance Sheet Data:
Total assets⁽²⁾⁽³⁾
$ 83,618
$ 81,816
$ 69,591
$ 52,212
$ 47,457
Short-term debt 974
1,445
232
887
865
Long-term debt, including current maturities:
BHE senior debt⁽³⁾
7,814
7,810
6,575
4,592
5,333
BHE subordinated debt 2,944
3,794
2,594
—
22
Subsidiary debt⁽³⁾
27,214
26,848
22,645
16,007
13,605
Total BHE shareholders' equity 22,401
20,442
18,711
15,742
14,092


~~(1)~~	~~Reflects the completion of the AltaLink acquisition from December 1, 2014 and the NV Energy acquisition from December 19, 2013.~~

~~(2)~~

In December 2015, the Company retrospectively adopted Accounting Standards Update No. 2015-17, which resulted in the reclassification of certain deferred income tax balances previously recognized within other current assets in the amounts of $291 million, $211 million, $119 million, and $149 million, as of December 31, 2014, 2013, 2012 and 2011, respectively, as reductions in noncurrent deferred income tax liabilities.

~~(3)~~

In December 2015, the Company retrospectively adopted Accounting Standards Update 2015-03, which resulted in the reclassification of certain deferred debt issuance costs previously recognized within other assets in the amounts of $50 million, $41 million, $29 million, and $30 million, as of December 31, 2014, 2013, 2012 and 2011, respectively, as reductions in BHE senior debt, and certain deferred debt issuance costs previously recognized within other assets in the amounts of $147 million, $157 million, $107 million, and $82 million, as of December 31, 2014, 2013, 2012 and 2011, respectively, as reductions in subsidiary debt.


Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with Item 6 of this Form 10-K and with the Company's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.

The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as ~~"BHE~~BHE and Other," relate principally to other entities, corporate functions and intersegment eliminations. ~~BHE U.S. Transmission was previously included in BHE and Other.~~

Results of Operations

Overview

Net income for the Company's reportable segments for the years ended December 31 is summarized as follows (in millions):


	2015			2014			Change					2014			2013			Change					2017			2016			Change					2016			2015			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	697		$	700		$	(3	)	—	%	$	700		$	681		$	19		3	%	$	769		$	764		$	5		1	%	$	764		$	697		$	67		10	%
MidAmerican Funding	458			409			49			12		409			340			69			20		574			532			42			8		532			442			90			20
NV Energy	379			354			25			7		354			(43		)	397			*		346			359			(13		)	(4	)	359			379			(20		)	(5	)
Northern Powergrid	422			412			10			2		412			335			77			23		251			342			(91		)	(27	)	342			422			(80		)	(19	)
BHE Pipeline Group	243			230			13			6		230			237			(7		)	(3	)	277			249			28			11		249			243			6			2
BHE Transmission	186			56			130			*		56			33			23			70		224			214			10			5		214			186			28			15
BHE Renewables(1)	124			121			3			2		121			(20		)	141			*		864			179			685			*		179			124			55			44
HomeServices	104			83			21			25		83			73			10			14		149			127			22			17		127			104			23			22
BHE and Other	(243		)	(270		)	27			10		(270		)	—			(270		)	*		(584		)	(224		)	(360		)	*		(224		)	(227		)	3			1
Total net income attributable to BHE shareholders	$	2,370		$	2,095		$	275		13		$	2,095		$	1,636		$	459		28		$	2,870		$	2,542		$	328		13		$	2,542		$	2,370		$	172		7

* Not meaningful


(1)	Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.

Net income attributable to BHE shareholders increased ~~$275~~$328 million for ~~2015~~2017 compared to ~~2014~~2016, including a $516 million benefit as a result of 2017 Tax Reform, partially offset by a charge of $263 million from tender offers for certain long-term debt completed in December 2017. Excluding the impacts of these items, adjusted net income attributable to BHE shareholders was $2,617 million, an increase of $75 million compared to 2016.

The increase in net income attributable to BHE shareholders was due to the following with such explanations excluding the impacts of DSM and energy efficiency programs having no impact on net income:

PacifiCorp's net income increased $5 million, including $6 million of income from 2017 Tax Reform. Excluding the impact of 2017 Tax Reform, adjusted net income was $763 million, a decrease of $1 million compared to 2016, primarily due to higher depreciation and amortization of $26 million from additional plant placed in-service, lower AFUDC of $11 million, lower production tax credits of $11 million and higher property and other taxes of $7 million, partially offset by higher gross margins of $72 million. Gross margins increased due to higher retail customer volumes, lower natural gas-fueled generation, higher wholesale revenue and higher wheeling revenue, partially offset by higher purchased electricity costs, lower average retail rates and higher coal costs. Retail customer volumes increased 1.7% due to favorable impacts of weather across the service territory, higher commercial usage and an increase in the average number of residential and commercial customers primarily in Utah and Oregon, partially offset by lower residential usage in Utah and Oregon and lower irrigation usage.

MidAmerican Funding's net income increased $42 million, including after-tax charges of $17 million related to the tender offer of a portion of MidAmerican Funding's 6.927% Senior Bonds due 2029 and $10 million for 2017 Tax Reform. Excluding the impacts of these items, adjusted net income was $601 million, an increase of $69 million compared to 2016, primarily due to a higher income tax benefit from higher production tax credits of $38 million, the effects of ratemaking and lower pre-tax income, and higher electric gross margins of $76 million, partially offset by higher maintenance expense of $52 million due to additional wind-powered generating facilities and the timing of fossil-fueled generation maintenance, higher depreciation and amortization of $21 million due to wind-powered generation and other plant placed in-service and accruals for Iowa regulatory arrangements, partially offset by a December 2016 reduction in depreciation rates, and higher property and other taxes of $7 million. Electric gross margins increased due to higher recoveries through bill riders, higher retail customer volumes, higher wholesale revenue and higher transmission revenue, partially offset by higher coal and purchased power costs. Retail customer volumes increased 2.4% due to industrial growth net of lower residential and commercial volumes from milder temperatures.

NV Energy's net income decreased $13 million, including a charge of $19 million from 2017 Tax Reform. Excluding the impact of 2017 Tax Reform, adjusted net income was $365 million, an increase of $6 million compared to 2016, primarily due to higher electric gross margins of $20 million and lower interest expense of $17 million from lower deferred charges and lower rates on outstanding debt balances, partially offset by $28 million of charges related to the Nevada Power regulatory rate order. Electric gross margins increased due to higher retail customer volumes, partially offset by a decrease in wholesale revenues. Retail customer volumes increased 1.5% due to customer usage patterns, higher customer demand from the impacts of weather and an increase in the average number of customers.

Northern Powergrid's net income decreased $91 million due to higher income tax expense of $35 million primarily due to $39 million of benefits from the resolution of income tax return claims in 2016 and $17 million of deferred income tax benefits reflected in 2016 due to a 1% reduction in the United Kingdom corporate income tax rate, higher pension expense of $24 million, including the impact of settlement losses recognized in 2017 due to higher lump sum payments, lower distribution revenue of $23 million and the stronger United States dollar of $11 million. These decreases were partially offset by $19 million of asset provisions recognized in 2016 at the CE Gas business. Distribution revenue decreased due to lower units distributed, the recovery in 2016 of the December 2013 customer rebate and unfavorable movements in regulatory provisions, partially offset by higher tariff rates.

BHE Pipeline Group's net income increased $28 million, including $7 million of income from 2017 Tax Reform. Excluding the impact of 2017 Tax Reform, adjusted net income was $270 million, an increase of $21 million compared to 2016, primarily due to a reduction in expenses and regulatory liabilities related to the impact of an alternative rate structure approved by the FERC at Kern River and higher transportation and storage revenues at Northern Natural Gas, partially offset by lower transportation revenue at Kern River and higher operating expense at Northern Natural Gas.

BHE Transmission's net income increased $10 million from higher earnings at AltaLink of $18 million, partially offset by lower earnings at BHE U.S. Transmission of $8 million. Earnings at AltaLink increased primarily due to additional assets placed in-service, lower impairments of nonregulated natural gas-fueled generation assets of $21 million and the weaker United States dollar of $3 million, partially offset by more favorable regulatory decisions in 2016. BHE U.S. Transmission's earnings decreased primarily due to lower equity earnings at Electric Transmission Texas, LLC from the impacts of a regulatory rate order in March 2017.

BHE Renewables' net income increased $685 million, including $628 million of income from 2017 Tax Reform primarily resulting from reductions in deferred income tax liabilities. Excluding the impact of 2017 Tax Reform, adjusted net income was $236 million, an increase of $57 million compared to 2016, primarily due to additional wind and solar capacity placed in-service, higher generation at the Solar Star projects due to transformer related forced outages in 2016 and higher production at the Casecnan project due to higher rainfall.

HomeServices' net income increased $22 million, including $31 million of income from 2017 Tax Reform. Excluding the impact of 2017 Tax Reform, adjusted net income was $118 million, a decrease of $9 million compared to 2016, primarily due to lower earnings at acquired and existing brokerage businesses, partially offset by higher earnings at existing franchise businesses.

BHE and Other net loss increased $360 million, including after-tax charges of $246 million related to the tender offer of a portion of BHE's senior bonds and $127 million for 2017 Tax Reform. Excluding the impacts of these items, the adjusted net loss was $211 million, an improvement of $13 million compared to 2016. The $127 million of net loss from 2017 Tax Reform included an accrual for the deemed repatriation of undistributed foreign earnings and profits totaling $419 million, partially offset by $292 million of benefits from reductions in deferred income tax liabilities primarily related to the unrealized gain on the investment in BYD Company Limited.

Net income attributable to BHE shareholders increased $172 million for 2016 compared to 2015 due to the following:

PacifiCorp's net income ~~decreased~~increased $67 million due to ~~the prior year recognition~~higher gross margins of ~~insurance recoveries for a fire claim,~~$86 million, lower operations and maintenance expenses of $18 million, and higher production tax credits of $8 million, partially offset by higher depreciation and amortization of ~~$35~~$13 million, lower AFUDC of ~~$25~~$9 million and higher property taxes ~~partially offset by higher~~of $5 million. Gross margins ~~of $109 million and lower production tax credits of $9 million. Margins~~ increased primarily due to lower purchased electricity costs, higher retail rates, lower ~~purchased electricity prices,~~coal-fueled generation and lower natural gas ~~generation and~~ costs, ~~Utah mine disposition costs in 2014 and lower coal generation,~~ partially offset by ~~higher purchased electricity volumes,~~ lower wholesale electricity revenue from lower volumes and ~~prices and lower retail~~prices. Retail customer ~~load. Customer load~~volumes decreased ~~0.7%~~by 0.6% due to lower ~~industrial~~commercial customer usage in Utah and ~~Wyoming and~~ lower ~~residential~~industrial customer usage ~~across the service territory,~~primarily in Utah and Oregon, partially offset by an increase in the average number of residential customers in Utah and Oregon ~~an increase in the average number of~~and commercial customers in Utah and the impacts of weather on residential ~~commercial and irrigation~~ customer ~~loads.~~volumes.

MidAmerican Funding's net income increased $90 million due to higher ~~regulated~~ electric gross margins of ~~$119~~$172 million, higher production tax credits of ~~$27~~$39 million and lower fossil-fueled generation operations and maintenance of ~~$10~~$35 million, partially offset by higher depreciation and amortization of ~~$56~~$72 million ~~due to~~from wind-powered generation and other plant placed in-service and an accrual related to an Iowa regulatory revenue sharing arrangement, a pre-tax gain of $13 million in 2015 on the sale of a generating facility lease, higher interest expense of $12 million and higher income taxes from the effects of ratemaking and higher pre-tax income. Electric gross margins reflect higher retail sales volumes, higher retail rates in Iowa, lower ~~AFUDC~~energy costs, higher wholesale revenue and higher transmission revenue.

NV Energy's net income decreased $20 million due to higher operating expense of $27 million, ~~lower regulated natural gas margins~~higher depreciation and amortization of ~~$12~~$11 million due to ~~warmer temperatures~~higher plant in-service and lower electric gross margins of $2 million, partially offset by lower interest expense of $12 million. Operating expense increased due to benefits from changes in contingent liabilities in 2015 and regulatory disallowances in 2016. Electric gross margins decreased primarily due to lower transmission and wholesale revenue and lower customer usage offset by higher customer growth.

Northern Powergrid's net income decreased $80 million due to the stronger United States dollar of $47 million, lower distribution revenues mainly due to the recovery in 2015 of the December 2013 customer rebate and unfavorable movements in regulatory provisions, higher depreciation of $25 million from additional assets placed in service, higher write-offs of hydrocarbon well exploration costs of $15 million and higher interest expense of $9 million due to the issuance of first mortgage bonds in April 2014 and October 2015. Regulated electric margins increased primarily due to higher retail rates in Iowa and changes in rate structure related to seasonal pricing, lower purchased power costs, a lower average cost of fuel for generation and higher transmission revenue, partially offset by lower wholesale revenue. Electric retail customer load increased 1.2% as a result of strong industrial growth, partially offset by warmer winter temperatures compared to 2014.

~~NV Energy's net income increased due to higher electric margins of $76 million and lower interest expense of $21 million,~~$7 million. These adverse variances were partially offset by higher ~~depreciation~~smart meter revenue, lower operating expenses and ~~amortization of $31 million due to higher regulatory amortizations and higher operating~~lower income tax expense ~~of $30 million, primarily related to energy efficiency costs. Electric margins increased~~ primarily due to ~~higher electric retail customer load~~the resolution of ~~2.4%~~income tax return claims from ~~increased customer usage and growth and the impacts of weather.~~

~~Northern Powergrid's net income increased due to~~prior years partially offset by decreased deferred income tax benefits ~~of $41 million from~~due to a 2%1% reduction in the United Kingdom corporate income tax rate in 2016 compared to a 2% reduction in 2015.

BHE Pipeline Group's net income increased $6 million due to higher ~~distribution revenue from recovery~~storage revenues, lower operating expenses and lower interest expense due to the early redemption in December 2015 of the ~~December 2013 customer rebate and favorable movements in regulatory provisions, and lower write-offs of hydrocarbon well exploration costs of $22 million,~~6.667% Senior Notes at Kern River, partially offset by lower ~~tariff rates~~transportation revenues and ~~distributed units~~higher depreciation expense.

BHE Transmission's net income increased $28 million from higher earnings at AltaLink of $22 million and at BHE U.S. Transmission of $6 million. Earnings at AltaLink increased primarily due to additional assets placed in-service and favorable regulatory decisions, partially offset by a $26 million pre-tax impairment related to nonregulated natural gas-fueled generation assets and the stronger United States dollar of ~~$34~~$5 million.

BHE ~~Pipeline Group's net income increased due to lower operating expenses of $28 million~~U.S. Transmission's earnings improved primarily from higher equity earnings at ~~Northern Natural Gas as a result of lower in-line inspection, hydrostatic testing~~Electric Transmission Texas, LLC from continued investment and other maintenance project costs and higher transportation revenues of $7 million, partially offset by higher depreciation expense of $8 million and lower other income of $6 million due to a contract restructuring at Northern Natural Gas that expired in 2015.

BHE Transmission's net income increased due to the acquisition of AltaLink on December 1, 2014 totaling $120 million and lower operating expense primarily related to lower acquisition and project development costs.additional plant placed in-service.

BHE Renewables' net income increased ~~$18~~$55 million ~~from solar projects primarily~~ due to three tax equity investments reaching commercial operations in 2016 and higher production at wind projects, including additional ~~solar~~ capacity ~~at the Solar Star and Topaz Projects being~~ placed in-service in 2016 at two projects, partially offset by lower ~~earnings of $18 million at CE Generation~~solar revenues mainly due to ~~lower revenue from lower short run avoided cost pricing.~~forced outages and higher depreciation expense due to additional wind and solar capacity placed in-service.

HomeServices' net income increased $23 million due to a 9% increase in closed brokerage units, primarily due to acquired brokerage businesses, a 2% increase in average home sales prices and higher earnings at existing ~~brokerage,~~ mortgage and franchise ~~businesses, due to higher closed units, and acquired brokerage businesses, partially offset by $12 million of gains in 2014 from the acquisition of interests in equity method investments.~~businesses.

BHE and Other net loss ~~decreased~~improved $3 million due to lower ~~income tax~~interest expense, ~~from favorable~~an increase in consolidated deferred state income tax benefits and higher investment returns, partially offset by higher United States income taxes on foreign ~~earnings, partially offset by higher interest expense from debt issuances in the fourth quarter of 2014.~~

~~Net income attributable to BHE shareholders increased $459 million for 2014 compared to 2013 due to the following:~~

PacifiCorp's net income increased due to higher retail rates, the 2014 recognition of insurance recoveries for a fire claim and related charges in 2013, and higher average wholesale prices, partially offset by higher energy costs, lower retail customer load and higher depreciation and amortization due to the impact of a depreciation rate study effective in 2014 and higher plant in-service.

MidAmerican Funding's net income increased due to improved regulated electric margins from higher electric retail rates in Iowa, net of the impact of cooler summer temperatures in 2014, higher natural gas margins from colder winter temperatures in 2014, lower depreciation and amortization primarily from the impact of depreciation rate changes and higher AFUDC, partially offset by higher operating and interest expense.

NV Energy was acquired on December 19, 2013, and its results are included in the consolidated results beginning as of that date. Net income for 2014 totaled $354 million. The net loss for 2013 reflects a one-time bill credit to retail customers of $13 million, after-tax, charges under NV Energy's change in control policy of $19 million, after-tax, and contributions to the NV Energy Foundation of $11 million, after-tax.

Northern Powergrid's net income increased due to higher tariff rates, a one-time rebate to customers in December 2013, favorable movements in regulatory provisions in 2014 and the weaker United States dollar of $26 million, partially offset by deferred income tax benefits in 2013 of $54 million from reductions in the United Kingdom corporate income tax rate, lower distributed units and write-offs of hydrocarbon well costs.earnings.

BHE Pipeline Group's net income decreased due to higher operating expense primarily at Northern Natural Gas as a result of higher in-line inspection, hydrostatic testing and other maintenance project costs, benefits from a contract restructuring in 2013 at Northern Natural Gas and higher depreciation and amortization, partially offset by higher transportation revenue at Northern Natural Gas due to greater volumes from colder temperatures.

BHE Transmission's net income increased due to the acquisition of AltaLink on December 1, 2014 totaling $13 million and higher equity earnings at ETT due to continued investment and additional plant placed in-service, partially offset by higher operating expense primarily related to higher project development costs.

BHE Renewables' net income increased due to higher earnings from the Topaz and Solar Star Projects as additional solar capacity was placed in-service and a non-recurring goodwill impairment at CE Generation in the fourth quarter of 2013, partially offset by unfavorable changes in the valuation of the power purchase agreement derivative at Bishop Hill II and the interest rate swaps at the Pinyon Pines Projects.

HomeServices' net income increased due to higher earnings at newly acquired businesses, partially offset by lower earnings at existing franchise, brokerage and mortgage businesses due to lower units and lower overall real estate purchase and refinancing activity.

BHE and Other net loss increased due to higher interest expense from debt issuances in the fourth quarter of 2014 and 2013, one-time state deferred income tax benefits recognized in 2013 from a reduction in the apportioned state tax rate of $161 million, in part, as a result of the acquisition of NV Energy and higher charitable contributions.

Reportable Segment Results

Operating revenue and operating income for the Company's reportable segments for the years ended December 31 are summarized as follows (in millions):


	2015			2014			Change					2014			2013			Change					2017			2016			Change					2016			2015			Change
Operating revenue:
PacifiCorp	$	5,232		$	5,252		$	(20	)	—	%	$	5,252		$	5,147		$	105		2	%	$	5,237		$	5,201		$	36		1	%	$	5,201		$	5,232		$	(31	)	(1	)%
MidAmerican Funding	3,420			3,762			(342		)	(9	)	3,762			3,413			349			10		2,846			2,631			215			8		2,631			2,515			116			5
NV Energy	3,351			3,241			110			3		3,241			(20		)	3,261			*		3,015			2,895			120			4		2,895			3,351			(456		)	(14	)
Northern Powergrid	1,140			1,283			(143		)	(11	)	1,283			1,025			258			25		949			995			(46		)	(5	)	995			1,140			(145		)	(13	)
BHE Pipeline Group	1,016			1,078			(62		)	(6	)	1,078			952			126			13		993			978			15			2		978			1,016			(38		)	(4	)
BHE Transmission	592			62			530			*		62			—			62			*		699			502			197			39		502			592			(90		)	(15	)
BHE Renewables	728			623			105			17		623			355			268			75		838			743			95			13		743			728			15			2
HomeServices	2,526			2,144			382			18		2,144			1,809			335			19		3,443			2,801			642			23		2,801			2,526			275			11
BHE and Other	(125		)	(119		)	(6		)	(5	)	(119		)	(46		)	(73		)	*		594			676			(82		)	(12	)	676			780			(104		)	(13	)
Total operating revenue	$	17,880		$	17,326		$	554		3		$	17,326		$	12,635		$	4,691		37		$	18,614		$	17,422		$	1,192		7		$	17,422		$	17,880		$	(458	)	(3	)

Operating income:
PacifiCorp	$	1,344		$	1,308		$	36		3	%	$	1,308		$	1,275		$	33		3	%	$	1,462		$	1,427		$	35		2	%	$	1,427		$	1,344		$	83		6	%
MidAmerican Funding	473			423			50			12		423			357			66			18		562			566			(4		)	(1	)	566			451			115			25
NV Energy	812			791			21			3		791			(42		)	833			*		765			770			(5		)	(1	)	770			812			(42		)	(5	)
Northern Powergrid	593			674			(81		)	(12	)	674			501			173			35		436			494			(58		)	(12	)	494			593			(99		)	(17	)
BHE Pipeline Group	464			439			25			6		439			446			(7		)	(2	)	475			455			20			4		455			464			(9		)	(2	)
BHE Transmission	260			16			244			*		16			(5		)	21			*		322			92			230			*		92			260			(168		)	(65	)
BHE Renewables	255			314			(59		)	(19	)	314			223			91			41		316			256			60			23		256			255			1			—
HomeServices	184			125			59			47		125			129			(4		)	(3	)	214			212			2			1		212			184			28			15
BHE and Other	(57		)	(44		)	(13		)	(30	)	(44		)	(49		)	5			10		(38		)	(21		)	(17		)	(81	)	(21		)	(35		)	14			40
Total operating income	$	4,328		$	4,046		$	282		7		$	4,046		$	2,835		$	1,211		43		$	4,514		$	4,251		$	263		6		$	4,251		$	4,328		$	(77	)	(2	)

* Not meaningful

PacifiCorp

Operating revenue ~~decreased $20~~increased $36 million for ~~2015~~2017 compared to ~~2014~~2016 due to higher wholesale and other revenue of $50 million, partially offset by lower retail revenue of $14 million. Wholesale and other revenue increased due to higher wholesale sales volumes and short-term market prices and higher wheeling revenue. Retail revenue decreased due to lower average rates of $64 million and lower DSM program revenue (offset in operating expense) of $55 million, primarily driven by the establishment of the Utah Sustainable Transportation and Energy Plan program, partially offset by higher customer volumes of $105 million. Retail customer volumes increased 1.7% due to impacts of weather across the service territory, higher commercial usage and an increase in the average number of residential and commercial customers primarily in Utah and Oregon, partially offset by lower residential usage in Utah and Oregon and lower irrigation usage.

Operating income increased $35 million for 2017 compared to 2016 due to higher gross margins of $72 million, excluding the impact of a decrease in DSM program revenue (offset in operating expense) of $55 million, partially offset by higher depreciation and amortization of $26 million from additional plant placed in-service and higher property and other taxes of $7 million. Gross margins increased due to higher retail customer volumes, lower natural gas-fueled generation, higher wholesale revenue and higher wheeling revenue, partially offset by higher purchased electricity costs, lower average retail rates and higher coal costs.

Operating revenue decreased $31 million for 2016 compared to 2015 due to lower wholesale and other revenue of ~~$113~~$88 million, partially offset by higher retail revenue of ~~$93~~$57 million. Wholesale and other revenue decreased due to lower wholesale volumes of ~~$55 million, lower REC revenue of $31~~$65 million and lower average wholesale prices of ~~$27~~$25 million. The increase in retail revenue was primarily due to higher retail ~~rates of $109 million, partially offset~~rates. Retail customer volumes decreased by ~~lower retail customer load of $16 million. Customer load decreased 0.7%~~0.6% due to lower ~~industrial~~commercial customer usage in Utah and ~~Wyoming and~~ lower ~~residential~~industrial customer usage ~~across the service territory,~~primarily in Utah and Oregon, partially offset by an increase in the average number of residential customers in Utah and Oregon ~~an increase in the average number of~~and commercial customers in Utah and the impacts of weather on residential ~~commercial and irrigation~~ customer ~~loads.~~volumes.

Operating income increased ~~$36~~$83 million for ~~2015~~2016 compared to ~~2014~~2015 due to higher margins of ~~$109~~$86 million and lower operations and maintenance expenses of $18 million, partially offset by ~~the prior year recognition of insurance recoveries for a fire claim,~~ higher depreciation and amortization of ~~$35~~$13 million ~~primarily due to higher plant in-service including the Lake Side 2 natural gas-fueled generating facility ("Lake Side 2") placed in-service in May 2014~~ and higher property ~~taxes.~~taxes of $5 million. Margins increased due to lower energy costs of ~~$129~~$117 million, partially offset by ~~the~~ lower operating ~~revenue.~~revenue of $31 million. Energy costs decreased primarily due to lower purchased electricity ~~prices,~~costs, lower coal-fueled generation and lower natural gas ~~generation, lower average cost of natural gas, Utah mine disposition~~ costs, ~~in 2014 and lower coal generation,~~ partially offset by higher ~~purchased electricity volumes~~gas-fueled generation and higher coal costs. Operations and maintenance expenses decreased primarily due to lower plant maintenance costs associated with reduced generation and lower ~~net deferrals of incurred net power costs.~~

~~Operating revenue increased $105 million for 2014 compared to 2013~~labor and benefit costs due to ~~higher retail revenue of $73 million and higher wholesale and other revenue of $32 million. The increase in retail revenue was due to higher rates of $144 million,~~lower headcount, partially offset by ~~lower retail customer load of $71 million. Customer load decreased 1.2% due to the impacts of milder weather~~a Washington rate case decision disallowing returns on residential and commercial customers primarily in Utah and Oregon, partially offset by higher commercial and residential customer usage primarily in Utah, higher average number of residential customers and higher irrigation customer usage in Oregon. Wholesale and other revenue increased primarily due to higher average wholesale prices of $26 million, partially offset by lower REC revenue of $9 million.recent selective catalytic reduction projects.

Operating income increased $33 million for 2014 compared to 2013 due to the higher operating revenue and the 2014 recognition of insurance recoveries for a fire claim and related charges in 2013, partially offset by higher energy costs of $73 million, higher depreciation and amortization of $53 million, due to the impact of a depreciation rate study effective in 2014 and higher plant in-service including Lake Side 2. Energy costs increased due to higher natural gas volumes including Lake Side 2 generation, higher average cost of coal, lower net deferrals of incurred net power costs, Utah mine disposition costs in 2014, higher average cost of purchased electricity and higher transmission expense, partially offset by lower purchased electricity volumes, lower coal volumes, lower average cost of natural gas and higher hydroelectric generation.

MidAmerican Funding

Operating revenue ~~decreased $342~~increased $215 million for ~~2015~~2017 compared to ~~2014~~2016 due to ~~lower regulated~~higher electric operating revenue of $123 million, higher natural gas operating revenue of ~~$335~~$82 million and ~~lower nonregulated~~higher other revenue of $9 million. Electric operating revenue increased due to higher retail revenue of $88 million and higher wholesale and other revenue of $35 million. Electric retail revenue increased $73 million from higher recoveries through bill riders (substantially offset in cost of sales, operating expense and income tax expense) and $39 million from usage and growth and rate factors, including higher industrial sales volumes, partially offset by $24 million from the impact of milder temperatures in 2017. Electric retail customer volumes increased 2.4% from industrial growth, partially offset by the unfavorable impact of temperatures. Electric wholesale and other revenue increased primarily due to higher transmission revenue of $13 million, higher wholesale volumes of $12 million and higher wholesale prices of $8 million. Natural gas operating revenue increased due to a higher average per-unit cost of ~~$27~~gas sold of $67 million (offset in cost of sales), higher DSM program revenue of $3 million (offset in operating expense), 2.4% higher wholesale sales volumes and 0.1% higher retail sales volumes.

Operating income decreased $4 million for 2017 compared to 2016 due to higher maintenance expense of $52 million for additional wind-powered generating facilities and the timing of fossil-fueled generation maintenance, higher depreciation and amortization of $21 million and higher property and other taxes of $7 million, partially offset by higher ~~regulated~~electric gross margins of $76 million, excluding the impact of an increase in electric DSM program revenue of $22 million (offset in operating expense), and higher natural gas gross margins of $5 million, excluding the impact of an increase in gas DSM program revenue of $3 million (offset in operating expense). Electric gross margins were higher due to higher recoveries through bill riders, higher retail sales volumes, higher wholesale revenue and higher transmission revenue, partially offset by higher coal-fueled generation and purchased power costs. The increase in depreciation and amortization reflects $38 million related to wind generation and other plant placed in-service and higher accruals for Iowa regulatory arrangements of $14 million, partially offset by a reduction of $31 million from lower depreciation rates implemented in December 2016.

Operating revenue increased $116 million for 2016 compared to 2015 due to higher electric operating revenue of ~~$20~~$148 million, partially offset by lower natural gas operating revenue of $24 million and lower other operating revenue of $8 million. ~~Regulated natural~~Electric operating revenue increased due to higher retail revenue of $112 million and higher wholesale and other revenue of $36 million. Retail revenue increased $47 million from higher electric rates in Iowa effective January 1, 2016, $33 million from non-weather-related usage factors, including higher industrial sales volumes and $30 million from warmer cooling season temperatures, net of warmer winter temperatures in 2016. Electric retail customer volumes increased 3.8% from the favorable impact of temperatures and industrial growth. Electric wholesale and other revenue increased primarily due to higher wholesale prices of $25 million and higher transmission revenue of $17 million related to Multi-Value Projects, which are expected to increase as projects are constructed, partially offset by lower wholesale volumes of $6 million. Natural gas operating revenue decreased due to a lower average per-unit cost of gas sold of ~~$290~~$42 million, which is offset in cost of sales, and ~~16.7%~~0.5% lower retail sales volumes, primarily from warmer winter temperatures in ~~2015,~~2016, partially offset by 10.1% higher wholesale volumes. ~~Nonregulated and other~~Other operating revenue decreased primarily due to the completion of major projects of a nonregulated utility construction subsidiary in 2015.

Operating income increased $115 million for 2016 compared to 2015 due to the higher electric operating revenue, lower energy costs of $24 million reflecting lower coal-fueled generation in part due to greater wind-powered generation, higher purchased power volumes and higher natural ~~gas prices~~gas-fueled generation, lower fossil-fueled generation maintenance of $24 million from planned outages in 2015 and ~~volumes~~lower generation operations costs of ~~$91~~$7 million, partially offset by higher electricity volumes and prices of $79 million. Regulated electric operating revenue increased due to higher retail revenue of $84 million, partially offset by lower wholesale and other revenue of $64 million. Retail revenue increased $70 million from higher electric rates primarily in Iowa, $16 million from non-weather-related customer load factors and $8 million from higher recoveries through bill riders and adjustment clauses, which is substantially offset in operating expense, partially offset by $10 million from the impact of warmer winter temperatures. The increase in Iowa electric rates reflects higher retail rates and changes in rate structure related to seasonal pricing that were effective with the implementation of final base rates in August 2014 and result in a greater differential between higher rates from June to September and lower rates in the remaining months. Electric retail customer load increased 1.2% as a result of strong industrial growth, net of the impact of temperatures compared to 2014. Electric wholesale and other revenue decreased primarily due to lower average wholesale prices of $62 million and lower wholesale volumes of $24 million, partially offset by higher transmission revenue of $25 million related to Multi-Value Projects, which are expected to increase as projects are constructed over the next two years.

Operating income increased $50 million for 2015 compared to 2014 due to higher regulated electric operating income of $66 million, partially offset by lower regulated natural gas operating income of $11 million and lower nonregulated and other operating income of $5 million. Regulated electric operating income increased due to lower energy costs of $99 million from a lower average cost of fuel for generation and lower purchased power costs, the higher retail rates and changes in rate structure related to seasonal pricing, the higher transmission revenue and lower fossil-fueled generation maintenance from planned major outages in 2014 of $10 million, partially offset by the lower wholesale revenue and higher depreciation and amortization of ~~$56~~$70 million ~~due to wind~~from wind-powered generation and other plant placed ~~in-service. Regulated natural gas operating income decreased due to the lower retail sales volumes, partially offset by a one-time refund of $8 million to customers in 2014 of insurance recoveries~~in-service and an accrual related to ~~environmental matters.~~

~~Operating~~an Iowa regulatory revenue ~~increased $349 million for 2014 compared to 2013 due to~~sharing arrangement, higher ~~regulated natural gas operating revenue~~other generation maintenance of $172 million, higher nonregulated and other operating revenue of $122 million and higher regulated electric operating revenue of $55 million. Regulated natural gas operating revenue increased due to an increase in recoveries through adjustment clauses from a higher average per-unit cost of gas sold of $165 million and higher retail sales volumes from colder winter temperatures in 2014, partially offset by lower wholesale volumes. Nonregulated and other operating revenue increased due to higher natural gas and electricity prices, higher electricity volumes and higher construction services, partially offset by lower natural gas volumes. Regulated electric operating revenue increased due to higher retail revenue of $61 million, partially offset by lower wholesale and other revenue of $6 million. Retail revenue was higher due to $49 million from higher electric rates in Iowa and $22 million from higher recoveries of demand-side management program costs, partially offset by $10 million from lower retail customer load for higher-priced, weather-sensitive customers. The increase in Iowa electric rates includes the increase in base rates implemented in August 2013 and, effective with the implementation of final base rates in August 2014, changes in rate structure related to seasonal pricing that result in higher rates from June to September and lower rates in the remaining months, and new adjustment clauses for recovery of retail energy production and transmission costs. Electric retail customer load increased 1.4% compared to 2013 as a result of strong industrial growth, partially offset by cooler summer temperatures in 2014. Electric wholesale revenue increased due to higher average prices of $17 million, partially offset by lower volumes of $16$13 million primarily from the higher retail energy requirements. Transmission revenue increased $6 million due to revenue from Multi-Value Projects. Other electric revenue decreased $13 million primarily from lower steam sales, partially due to the expirationaddition of ~~a contract, and lower sales of RECs.~~

Operating income increased $66 million for 2014 compared to 2013 primarily due to higher regulated electric operating income of $64 million. Regulated electric operating income increased due to the higher regulated electric operating revenue and $54 million of lower depreciation and amortization, partially offset by higher energy costs of $15 million, primarily due to higher fossil-fueled generation costs per unit and purchased power,wind turbines and higher operating expense recovered through bill riders of ~~$30~~$14 million. Operating expense increased primarily due to higher demand-side management program costs, higher transmission costs and higher property taxes. Depreciation and amortization decreased due to $79 million from the impact of depreciation rate changes, partially offset by additional plant in-service.

NV Energy

Operating revenue increased ~~$110~~$120 million for ~~2015~~2017 compared to ~~2014 primarily~~2016 due to higher electric operating revenue of ~~$94~~$134 million, ~~and higher~~partially offset by lower natural gas operating revenue of ~~$12 million due to increased customer usage and higher rates.~~$11 million. Electric operating revenue increased due to higher retail revenue of ~~$82~~$127 million and higher transmission revenue of $9 million. Electric retail revenue increased due to $198 million from higher rates primarily from energy costs (offset in cost of sales), $40 million from higher distribution only service revenue and impact fees received due to customers purchasing energy from alternative providers and becoming distribution only service customers, $18 million from an increase in the average number customers and $10 million higher customer usage mainly from the favorable impacts of weather, partially offset by $114 million from lower commercial and industrial revenue, mainly from customers purchasing energy from alternative providers, and $23 million of lower energy efficiency program revenue (offset in operating expense). Electric retail customer volumes, including distribution only service customers, increased 1.5% compared to 2016. Natural gas operating revenue decreased due to lower energy rates, partially offset by higher customer usage.

Operating income decreased $5 million for 2017 compared to 2016 due to $25 million of operating expenses related to Nevada Power's regulatory rate review, partially offset by higher electric gross margins of $20 million, excluding the impact of a decrease in energy efficiency program revenue (offset in operating expense) of $23 million. Electric gross margins were higher due to increased electric operating revenue of $157 million, excluding the impact of decreased energy efficiency program revenues, partially offset by increased energy costs of $137 million. Energy costs increased due to lower net deferred power costs of $85 million, a higher average cost of fuel for generation of $44 million and higher purchased power costs.

Operating revenue decreased $456 million for 2016 compared to 2015 due to lower electric operating revenue of $427 million, lower natural gas operating revenue of $27 million, primarily due to lower energy rates partially offset by higher customer usage, and lower other operating revenue of $2 million. Electric operating revenue decreased due to lower retail revenue of $414 million and lower wholesale, transmission and other revenue of ~~$12 million~~$13 million. Retail revenue decreased primarily due to ~~higher transmission revenue. Retail revenue was higher due~~$431 million from lower retail rates primarily from lower energy costs which are passed on to ~~$45~~customers through deferred energy adjustment mechanisms and $28 million from lower customer usage, partially offset by $38 million from higher customer growth, ~~$31~~$11 million ~~of higher energy efficiency rate revenue, which is offset in operating expense and $22 million of~~from higher customer usage primarily due to the impacts of weather ~~partially offset by $18~~and $4 million ~~from lower retail rates as a result~~ of ~~deferred~~higher energy ~~adjustment mechanisms.~~efficiency rate revenue (offset in operating expense). Electric retail customer ~~load increased 2.4%~~volumes were flat compared to ~~2014.~~2015.

Operating income ~~increased $21~~decreased $42 million for ~~2015~~2016 compared to ~~2014~~2015 due to higher ~~electric margins~~operating expense of ~~$76~~$27 million, primarily due to benefits from ~~the higher electric operating revenue, partially offset by~~changes in contingent liabilities in 2015, regulatory disallowances in 2016 and higher energy efficiency program costs ~~of $18 million,~~(offset in operating revenue), higher depreciation and amortization of ~~$31~~$11 million due to higher plant in-service and ~~higher~~lower electric margins of $2 million. Electric margins were lower due to the lower electric operating ~~expense~~revenue offset by lower energy costs of ~~$30 million, primarily related to energy efficiency costs.~~$425 million. Energy costs ~~increased~~decreased due to ~~higher~~lower net deferred power costs of ~~$247~~$413 million ~~partially offset by~~and a lower average cost of fuel for generation of ~~$228~~$69 million, partially offset by higher purchased power costs of $57 million.

NV Energy was acquired on December 19, 2013. Operating revenue for 2014 totaled $3.2 billion and consisted of $3.1 billion of electric and $125 million of natural gas revenue. Operating income for 2014 totaled $791 million and consisted of $778 million of electric and $13 million of natural gas operating income. Operating revenue for 2013 reflects a one-time bill credit to retail customers of $20 million while operating loss for 2013 reflects the bill credit and $22 million related to charges under NV Energy's change in control policy.

Northern Powergrid

Operating revenue decreased ~~$143~~$46 million for ~~2015~~2017 compared to ~~2014~~2016 due to the stronger United States dollar of ~~$90 million, lower distribution revenue of $43~~$48 million and lower ~~contracting and other~~distribution revenues of $23 million, partially offset by higher smart meter revenue of ~~$10~~$25 million. Distribution revenue decreased primarily due to ~~lower tariff rates of $99 million mainly reflecting the impact of the new price control period effective April 1, 2015 and~~ lower units distributed of $6$13 million, ~~partially offset by~~ the recovery in 2016 of the December 2013 customer rebate of ~~$41~~$10 million and ~~favorable~~unfavorable movements inon regulatory provisions of ~~$21~~$7 million, partially offset by higher tariff rates of $5 million. Operating income decreased ~~$81~~$58 million for ~~2015~~2017 compared to ~~2014~~2016 mainly due to the stronger United States dollar of ~~$47~~$26 million, higher pension expense of $24 million, mainly due to the 2017 settlement loss recognized due to higher lump sum payments, and the lower distribution revenue, partially offset by write-offs of hydrocarbon well exploration costs in 2016 totaling $19 million.

Operating revenue decreased $145 million for 2016 compared to 2015 due to the stronger United States dollar of $127 million, lower distribution revenues of $28 million and lower contracting revenue of $5 million, partially offset by higher smart meter revenue of $18 million. Distribution revenue decreased due to the recovery in 2015 of the December 2013 customer rebate of $22 million, lower units distributed and unfavorable movements on regulatory provisions of $8 million, partially offset by higher tariff rates. Operating income decreased $99 million for 2016 compared to 2015 mainly due to the stronger United States dollar of $61 million, the lower distribution revenue, higher depreciation expense of $25 million from additional distribution and smart meter assets placed in-service and higher ~~pension costs of $9 million, partially offset by lower~~ write-offs of hydrocarbon well exploration costs of ~~$22 million.~~

Operating revenue increased $258 million for 2014 compared to 2013 due to higher distribution revenue of $183 million, the weaker United States dollar of $66 million and higher contracting revenue of $12 million. Distribution revenue increased due to higher tariff rates of $123 million, favorable movements in regulatory provisions in 2014 of $50 million and a rebate to customers in December 2013 totaling $45$15 million, partially offset by ~~a 2.9% decrease in distributed units. Operating income increased $173 million for 2014 compared to 2013 largely due to~~ the higher ~~distribution~~smart meter revenue and the weaker United States dollar of $39 million, partially offset by higher distribution exit charges, write-offs of hydrocarbon well exploration costs of $21 million and higher depreciation and amortization.lower pension costs.

BHE Pipeline Group

Operating revenue ~~decreased $62~~increased $15 million for ~~2015~~2017 compared to ~~2014~~2016 primarily due to higher transportation revenues of $33 million and higher gas sales of $19 million related to system and operational balancing activities (largely offset in cost of sales) at Northern Natural Gas, partially offset by lower transportation revenues of $40 million at Kern River. Operating income increased $20 million for 2017 compared to 2016 primarily due to the higher transportation revenues at Northern Natural Gas and a reduction in expenses and regulatory liabilities related to the impact of an alternative rate structure approved by the FERC at Kern River, partially offset by higher operating expenses at Northern Natural Gas.

Operating revenue decreased $38 million for 2016 compared to 2015 due to lower gas sales of ~~$68~~$25 million at Northern Natural Gas related to system and operational balancing activities, which are largely offset in cost of sales, and a $20 million reduction in transportation revenues, partially offset by ~~higher transportation revenues.~~a $7 million increase in storage revenues at Northern Natural Gas. Operating income ~~increased $25~~decreased $9 million for ~~2015~~2016 compared to ~~2014~~2015 due to the ~~higher~~lower transportation revenues and ~~lower operating expenses of $28 million primarily at Northern Natural Gas as a result of lower in-line inspection, hydrostatic testing and other maintenance project costs, partially offset by~~ higher depreciation expense, ~~of $8 million.~~

Operating revenue increased $126 million for 2014 compared to 2013 due to higher operating revenue at Northern Natural Gas from both higher gas sales related to system and customer balancing activities of $77 million due to price spread volatility and extreme weather conditions, which are largely offset in cost of sales, and higher transportation revenue of $50 million due to higher rates and volumes. Operating income decreased $7 million due to higher operating expense of $49 million primarily at Northern Natural Gas as a result of higher in-line inspection, hydrostatic testing and other maintenance project costs and higher depreciation and amortization of $6 million, partially offset by the higher ~~transportation revenue at Northern Natural Gas.~~storage revenues and lower operating expenses.

BHE Transmission

~~AltaLink was acquired on December 1, 2014, and its results are included in the consolidated results beginning as of that date.~~ Operating revenue ~~and operating income~~increased $197 million for ~~2015~~2017 compared to 2016 primarily due to a one-time reduction of $200 million from the 2015-2016 GTA decision received in May 2016 at AltaLink, ~~were $592~~a weaker United States dollar of $19 million and ~~$262~~$15 million ~~respectively,~~from additional assets placed in service, partially offset by more favorable regulatory decisions in 2016. Operating income increased $230 million for 2017 compared to 2016 primarily due to the higher operating revenue from the 2015-2016 GTA decision that required AltaLink to refund $200 million to customers in 2016 through reduced monthly billings for the change from receiving cash during construction for the return on construction work-in-progress in rate base to recording allowance for borrowed and equity funds used during construction related to construction expenditures during the 2011 to 2014 time period. This amount is offset with ~~$62~~higher capitalized interest and allowance for equity funds. Operating income was also favorably impacted by lower operating expense primarily due to reduced impairments of nonregulated natural gas-fueled generation assets of $21 million and ~~$31 million, respectively, for 2014. Operating income also increased for 2015 compared to 2014 due to lower acquisition and project development costs.~~a weaker United States dollar of $11 million.

Operating revenue ~~increased $62 million and operating income increased $31~~decreased $90 million for ~~2014~~2016 compared to ~~2013~~2015 due to a one-time reduction of $200 million from the 2015-2016 GTA decision received in May 2016 at AltaLink, AltaLink's change to the flow through method of recognizing income tax expense of $45 million, which is offset in income tax expense, and the stronger United States dollar of $20 million, partially offset by $175 million from additional assets placed in-service and recovery of higher costs. Operating income decreased $168 million for 2016 compared to 2015 due to the ~~acquisition of~~lower operating revenues at AltaLink, ~~in December 2014, partially offset by higher operating expense primarily~~a $26 million impairment related to ~~higher acquisition~~nonregulated natural gas-fueled generation assets and ~~project development costs.~~the stronger United States dollar of $5 million.

BHE Renewables

Operating revenue increased ~~$105~~$95 million for ~~2015~~2017 compared to ~~2014~~2016 due to ~~an increase of $160 million as~~ additional wind and solar ~~and wind~~ capacity ~~was~~ placed in-service of $57 million, higher generation at the Solar Star projects of $31 million due to transformer related forced outages in 2016 and ~~an increase from~~higher production at the ~~acquisition~~Casecnan project of ~~the remaining 50% interest in CE Generation in June 2014 of $55~~$24 million due to higher rainfall, partially offset by ~~an $88~~lower generation of $11 million ~~decrease~~ at ~~CalEnergy Philippines~~the existing wind projects due to a lower wind resource and lower generation at the Topaz project of $6 million due to a scheduled maintenance outage. Operating income increased $60 million for 2017 compared to 2016 due to the ~~adoption of ASC 853 and lower wind generation at existing projects. Operating income decreased $59 million for 2015 compared to 2014 as the higher~~increase in operating revenue, ~~was more than~~partially offset by ~~higher operating expense of $101 million and~~ higher depreciation and amortization of ~~$64 million.~~$21 million and higher operating expense of $18 million, each primarily due to additional wind and solar capacity placed in-service. Operating expense also increased ~~due to $69~~from the scope and timing of maintenance at certain geothermal plants. The higher depreciation and amortization is offset by a reduction of $8 million from the ~~CE Generation acquisition, $22~~extension of the useful life of certain wind-generating facilities from 25 years to 30 years effective January 2017.

Operating revenue increased $15 million ~~from additional solar and wind capacity placed in-service. Depreciation and amortization increased~~for 2016 compared to 2015 due to ~~$52~~higher wind generation at the Pinyon Pines and Jumbo Road projects of $21 million, ~~from~~ additional ~~solar and~~ wind capacity placed in-service of $14 million, a favorable change in the valuation of a power purchase agreement derivative of $6 million and ~~$33 million from the CE Generation acquisition, partially offset by a $23 million decrease at CalEnergy Philippines due to the adoption~~higher hydro generation of ~~ASC 853.~~

Operating revenue increased $268 million for 2014 compared to 2013 due to an increase from the Topaz and Solar Star Projects of $165 million as additional solar capacity was placed in-service and an increase from the acquisition of the remaining 50% interest in CE Generation in June 2014 of $147$6 million, partially offset by ~~an unfavorable movement in the valuation~~lower geothermal generation of ~~the power purchase agreement derivative at Bishop Hill II of $26~~$18 million and lower ~~variable fees earned in 2014 at the Casecnan Project~~solar generation of ~~$22 million.~~$14 million mainly due to forced outages. Operating income increased ~~$91~~$1 million for ~~2014~~2016 compared to ~~2013~~2015 due to the higher operating revenue ~~partially~~being offset by higher ~~operating costs and expenses~~depreciation expense of ~~$127~~$14 million from ~~the CE Generation acquisition~~additional wind and ~~$50 million from additional~~ solar capacity placed in-service.

HomeServices

Operating revenue increased ~~$382~~$642 million for ~~2015~~2017 compared to ~~2014~~2016 due to ~~a 12.0%~~an increase ~~in closed brokerage units~~from acquired businesses totaling $542 million and a 3%4% increase in average home sales ~~prices. The increase in~~prices for existing brokerage businesses. Operating income increased $2 million for 2017 compared to 2016 primarily due to higher earnings from franchise businesses, partially offset by lower earnings from brokerage businesses mainly due to higher operating expenses at existing businesses.

Operating revenue ~~was~~increased $275 million for 2016 compared to 2015 due to an increase from ~~existing businesses totaling $225 million and an increase in~~ acquired businesses totaling ~~$157 million. The increase in existing businesses reflects an 8%~~$169 million, a 2% increase in closed brokerage units and a 2% increase in average home sales ~~prices.~~prices for existing brokerage businesses and $34 million of higher mortgage revenue. Operating income increased ~~$59~~$28 million for ~~2015~~2016 compared to ~~2014~~2015 due to the higher mortgage revenue and from higher earnings from brokerage businesses mainly due to higher net revenues, partially offset by higher ~~costs, primarily commission expense, at existing businesses of $53 million and higher earnings at acquired businesses of $6 million.~~

~~Operating revenue increased $335 million for 2014 compared to 2013 due to an 8% increase in closed brokerage units and an 11% increase in average home sales prices. The increase in~~ operating revenue was due to acquired businesses totaling $389 million, partially offset by a decrease in existing businesses totaling $54 million. The decrease in existing businesses reflects a 6% decrease in closed brokerage units and lower franchise revenue, partially offset by a 5% increase in average home sales prices. Operating income decreased $4 million for 2014 compared to 2013 as the higher earnings at acquired businesses totaling $22 million were more than offset by lower earnings at existing businesses of $26 million primarily due to the lower franchise business and brokerage businesses revenue and higher operating expense related to Berkshire Hathaway HomeServices rebranding activities at the franchise business.expenses.

BHE and Other

Operating revenue decreased $82 million for 2017 compared to 2016 primarily due to lower electricity and natural gas volumes and lower electricity prices at MidAmerican Energy Services, LLC. Operating loss increased ~~$13~~$17 million for ~~2015~~2017 compared to ~~2014~~2016 primarily due to ~~higher other operating costs.~~lower margins at MidAmerican Energy Services, LLC.

Operating revenue decreased ~~$73~~$104 million for ~~2014~~2016 compared to ~~2013~~2015 primarily due to lower electricity volumes and natural gas prices at MidAmerican Energy Services, LLC. Operating loss improved $14 million for 2016 compared to 2015 primarily due to higher ~~intersegment eliminations related to the acquisition of NV~~margins at MidAmerican Energy ~~in December 2013.~~Services, LLC.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense for the years ended December 31 is summarized as follows (in millions):

2015 2014 Change 2014 2013 Change

Subsidiary debt $ 1,392
$ 1,280
$ 112
9 % $ 1,280
$ 919
$ 361
39 %
BHE senior debt and other 408
353
55
16
353
300
53
18
BHE junior subordinated debentures 104
78
26
33
78
3
75
*
Total interest expense $ 1,904
$ 1,711
$ 193
11
$ 1,711
$ 1,222
$ 489
40

* Not meaningful



	2017		2016		Change					2016		2015		Change

Subsidiary debt	$	1,399	$	1,378	$	21		2	%	$	1,378	$	1,392	$	(14	)	(1	)%
BHE senior debt and other	423		411		12			3		411		408		3			1
BHE junior subordinated debentures	19		65		(46		)	(71	)	65		104		(39		)	(38	)
Total interest expense	$	1,841	$	1,854	$	(13	)	(1	)	$	1,854	$	1,904	$	(50	)	(3	)

Interest expense ~~on subsidiary debt increased $112~~decreased $13 million for ~~2015~~2017 compared to ~~2014~~2016 due to $132 million from the acquisition of AltaLink in December 2014, partially offset by $11 million from the impact of the foreign currency exchange rate. Interest expense on subsidiary debt increased $361 million for 2014 compared to 2013 due to $283 million from the acquisition of NV Energy in December 2013, $14 million from the acquisition of AltaLink in December 2014, $10 million from the impact of the foreign currency exchange rate and $9 million from the acquisition of the remaining 50% interest in CE Generation in June 2014. Debt issuances at PacifiCorp, MidAmerican Funding, Northern Powergrid and BHE Renewables increased interest expense, partially offset by scheduled maturities and principal repayments.

Interest expense on BHE senior debt and other increased $55 million for 2015 compared to 2014 and $53 million for 2014 compared to 2013 due to the issuance of $2.0 billion of BHE senior debt in November 2013 and $1.5 billion of BHE senior debt in December 2014, partially offset by scheduled maturities of BHE senior debt totaling $250 million in 2014.

Interest expense on BHE junior subordinated debentures increased $26 million for 2015 compared to 2014 and $75 million for 2014 compared to 2013 from junior subordinated debentures issued to certain Berkshire Hathaway subsidiaries, partially offset by repayments ~~at par value~~ of BHE junior subordinated debentures ~~due December 2043.~~of $944 million in 2017 and $2.0 billion in 2016, scheduled maturities and principal payments and early redemptions of subsidiary debt, partially offset by debt issuances at MidAmerican Funding, Northern Powergrid, AltaLink and BHE Renewables and higher short-term borrowings at BHE.

Interest expense decreased $50 million for 2016 compared to 2015 due to repayments of BHE junior subordinated debentures of $2.0 billion in 2016, scheduled maturities and principal payments and by the impact of foreign currency exchange rate movements of $23 million, partially offset by debt issuances at MidAmerican Funding, NV Energy, Northern Powergrid, AltaLink and BHE Renewables.

Capitalized Interest

Capitalized interest decreased ~~$15~~$94 million for ~~2015~~2017 compared to ~~2014 as $25~~2016 primarily due to $96 million recorded in the second quarter of 2016 from the 2015-2016 GTA decision received in May 2016 at AltaLink, ~~was more than~~which is offset in operating revenue, and lower construction work-in-progress balances at BHE Renewables, partially offset by higher construction work-in-progress balances at MidAmerican Energy.

Capitalized interest increased $65 million for 2016 compared to 2015 primarily due to $96 million recorded in the second quarter of 2016 from the 2015-2016 GTA decision received in May 2016 at AltaLink, which is offset in operating revenue, partially offset by lower construction work-in-progress balances at ~~BHE Renewables, MidAmerican Energy~~AltaLink and PacifiCorp.

Capitalized interest increased $5 million for 2014 compared to 2013 due to higher construction work-in-progress balances related to additional wind-powered generation at MidAmerican Energy, the Jumbo Road Project, the Solar Star Projects and a full year of activity from NV Energy, partially offset by lower construction work-in-progress balances related to the Topaz Project and at PacifiCorp as Lake Side 2 was placed in-service in the second quarter of 2014.

Allowance for Equity Funds

Allowance for equity funds decreased $7$82 million for ~~2015~~2017 compared to ~~2014 as $29~~2016 primarily due to $104 million recorded in the second quarter of 2016 from the 2015-2016 GTA decision received in May 2016 at AltaLink, ~~was more than~~which is offset in operating revenue, partially offset by ~~lower~~higher construction work-in-progress balances at MidAmerican ~~Energy and PacifiCorp.~~Energy.

Allowance for equity funds increased ~~$20~~$67 million for ~~2014~~2016 compared to ~~2013~~2015 primarily due to ~~higher construction work-in-progress balances related to additional wind-powered generation~~$104 million recorded in the second quarter of 2016 from the 2015-2016 GTA decision received in May 2016 at ~~MidAmerican Energy and a full year of activity from NV Energy,~~AltaLink, which is offset in operating revenue, partially offset by lower construction work-in-progress balances at ~~PacifiCorp as Lake Side 2 was placed in-service in the second quarter of 2014.~~AltaLink and PacifiCorp.

Interest and Dividend Income

Interest and dividend income ~~increased $69~~decreased $9 million for ~~2015~~2017 compared to ~~2014~~2016 primarily due to ~~the recognition of interest income on the~~a lower financial asset ~~established as a result of~~balance at the ~~adoption of ASC 853 at CalEnergy Philippines.~~Casecnan project and lower dividends from BYD Company Limited.

Interest and dividend income increased ~~$23~~$13 million for ~~2014~~2016 compared to ~~2013~~2015 primarily due to a ~~full year of activity~~dividend from ~~NV Energy.~~

~~Other, Net~~BYD Company Limited.

Other, net

Other, net decreased $3$434 million for ~~2015~~2017 compared to ~~2014~~2016 primarily due to ~~gains from the acquisition~~charges of interests in equity method investments at HomeServices of $12 million in 2014, lower investment returns, lower income from a contract restructuring at Northern Natural Gas that expired in 2015 and the costs associated with the early redemption of the 6.676% Senior Notes at Kern River in 2015 of $5 million, partially offset by lower charitable contributions in 2015 and favorable movements in the Pinyon Pines interest rate swaps of $7 million.

Other, net decreased $9 million for 2014 compared to 2013 due to higher investment gains in 2013, an unfavorable movement on the Pinyon Pines interest rate swaps, benefits from a contract restructuring at Northern Natural Gas of $12 million in 2013 and higher charitable contributions in 2014, partially offset by a full year of activity from NV Energy of $16 million, contributions of $16 million to the NV Energy Foundation in 2013 and gains of $12$439 million from ~~the acquisition of interests~~tender offers related to certain long-term debt completed in ~~equity method investments at HomeServices.~~December 2017.

Income Tax (Benefit) Expense

Income tax expense decreased ~~$139~~$957 million for ~~2015~~2017 compared to ~~2014~~2016 and the effective tax rate was (22)% for 2017 and 14% for 2016. The effective tax rate decreased primarily due to the net impacts of 2017 Tax Reform of $731 million, higher production tax credits of $97 million and the favorable impacts of rate making of $33 million, partially offset by benefits from the resolution of income tax return claims in 2016 of $39 million and deferred income tax benefits of $16 million reflected in 2016 due to a 1% reduction in the United Kingdom corporate income tax rate.

The 2017 Tax Reform most notably lowered the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018, and created a one-time repatriation tax on undistributed foreign earnings and profits. The $731 million of lower income tax expense was comprised of benefits from reductions in deferred income tax liabilities of $1,150 million, partially offset by an accrual for the deemed repatriation of undistributed foreign earnings and profits totaling $419 million.

Income tax expense decreased $47 million for 2016 compared to 2015 and the effective tax rate was 14% for 2016 and 16% for ~~2015 and 23% for 2014.~~2015. The effective tax rate decreased due to higher production tax credits of $107 million, the resolution of income tax return claims from prior years of $28 million and favorable impacts of rate making of $24 million, partially offset by unfavorable United States income taxes on foreign earnings of $46 million and lower deferred income tax benefits of ~~$39~~$23 million ~~from~~due to a 2%1% reduction in the United Kingdom corporate income tax rate favorable United States income taxes on foreign earnings of $36 million, favorable consolidated state income tax benefits of $35 million, favorable impacts of rate making of $34 million and higher production tax credits recognized of $33 million.

~~Income tax expense increased $459 million for 2014~~in 2016 compared to ~~2013 and the effective tax rate was 23% for 2014 and 7% for 2013. The effective tax rate increased due to deferred state income tax benefits~~a 2% reduction in 2013 from the impact of the NV Energy acquisition of $89 million, a change in estimate in 2013 related to state apportionment of $72 million, deferred income tax benefits in 2013 of $54 million from reductions in the United Kingdom corporate income tax rate and higher pre-tax earnings, partially offset by the tax effect of the nondeductible impairment charges related to CE Generation of $21 million in 2013 and higher production tax credits of $11 million in 2014.

Income tax effect of foreign income includes, among other items, deferred income tax benefits of $39 million in 2015 and $54 million in 2013 related to the enactment of reductions in the United Kingdom corporate income tax rate. In November 2015 the corporate tax rate was reduced from 20% to 19% effective April 1, 2017, with a further reduction to 18% effective April 1, 2020. In July 2013 the corporate income tax rate was reduced from 23% to 21% effective April 1, 2014, with a further reduction to 20% effective April 1, 2015.

Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law and are eligible for the credit for 10 years from the date the qualifying generating facilities are placed in-service. A credit of $0.024 per kilowatt hour was applied to 2017 production and a credit of $0.023 per kilowatt hour was applied to ~~2015, 2014~~2016 and ~~2013~~2015 production, respectively, which resulted in production tax credits of $495 million in 2017, $398 million in 2016 and $291 million ~~$258 million and $247 million, respectively,~~ in ~~recognized production tax credits.~~2015.

Equity (Loss) Income ~~(Loss)~~

Equity (loss) income ~~(loss)~~ for the years ended December 31 is summarized as follows (in millions):


	2015		2014			Change					2014			2013			Change					2017			2016			Change					2016			2015			Change
Equity income (loss):
Equity (loss) income:
ETT	$	81	$	80		$	1		1	%	$	80		$	46		$	34		74	%	$	(62	)	$	95		$	(157	)	*		$	95		$	81		$	14		17	%
Tax equity investments																						(120		)	(10		)	(110		)	*		(10		)	(1		)	(9		)	*
Agua Caliente	24		27			(3		)	(11	)	27			30			(3		)	(10	)	24			25			(1		)	(4	)%	25			24			1			4
CE Generation	—		(8		)	8			*		(8		)	(126		)	118			94
HomeServices	6		2			4			*		2			10			(8		)	(80	)	6			6			—			—		6			6			—			—
Other	4		8			(4		)	(50	)	8			5			3			60		1			7			(6		)	(86	)	7			5			2			40
Total equity income (loss)	$	115	$	109		$	6		6		$	109		$	(35	)	$	144		*
Total equity (loss) income																						$	(151	)	$	123		$	(274	)	*		$	123		$	115		$	8		7

* Not meaningful

Equity (loss) income ~~increased $6~~decreased $274 million for ~~2015~~2017 compared to ~~2014~~2016 primarily due to the ~~acquisition~~impacts of 2017 Tax Reform, which decreased equity income by $228 million mainly due to equity earnings charges recognized totaling $154 million for amounts to be returned to the ~~remaining interest~~customers of equity investments in ~~CE Generation on June 1, 2014 resulting~~regulated entities. These investments include pass-through entities for income tax purposes and the lower equity income is entirely offset by lower income tax expense as a result of benefits from reductions in ~~consolidation~~deferred income tax liabilities. Equity income also decreased due to lower pre-tax equity earnings from tax equity investments mainly due to unfavorable operating results and lower equity earnings at Electric Transmission Texas, LLC primarily due to the impacts of ~~the activity~~new retail rates effective ~~on this date.~~March 2017.

Equity income ~~(loss)~~ increased ~~$144~~$8 million for ~~2014~~2016 compared to ~~2013~~2015 primarily due to a $116 million impairment charge related to CE Generation in 2013, the acquisition of the remaining interest in CE Generation on June 1, 2014 resulting in consolidation of the activity effective on this date and higher equity earnings of $14 million at ~~ETT~~Electric Transmission Texas, LLC from continued investment and additional plant placed in-service, partially offset by ~~lower~~a pre-tax loss of $9 million from tax equity ~~earnings~~investments at HomeServices due to lower refinancing activity and the acquisition of the remaining 50.1% interest of HomeServices Lending on October 1, 2014 resulting in consolidation of the activity effective on this date.BHE Renewables.

Net Income Attributable to Noncontrolling Interests

Net income attributable to noncontrolling interests increased $3$12 million for ~~2015~~2017 compared to ~~2014~~2016 mainly due to higher earnings at HSF Affiliates. Net income attributable to noncontrolling interest decreased $13 million for 2014 compared to 2013 due to lower earnings at HSF Affiliates and PacifiCorp's redemption of all outstanding shares of its redeemable preferred stock totaling $40 million, plus accrued and unpaid dividends, in 2013.HomeServices' franchise business.

Liquidity and Capital Resources

Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt ~~of subsidiaries~~ may include provisions that allow ~~BHE's~~BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of December 31, ~~2015,~~2017, the Company's total net liquidity was ~~$6.1 billion~~ as follows (in millions):


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

Cash and cash equivalents	$	23		$	12		$	103		$	634	$	85	$	10		$	241		$	1,108		$	346		$	14		$	172		$	62		$	55	$	44		$	242		$	935

Credit facilities(1)	2,000			1,200			609			650		221		813			928			6,421			3,600			1,000			909			650			203		1,054			1,635			9,051
Less:
Short-term debt	(253		)	(20		)	—			—		—		(401		)	(300		)	(974		)	(3,331		)	(80		)	—			—			—		(345		)	(732		)	(4,488		)
Tax-exempt bond support and letters of credit	(51		)	(160		)	(195		)	—		—		(9		)	—			(415		)	(7		)	(130		)	(370		)	(80		)	—		(7		)	—			(594		)
Net credit facilities	1,696			1,020			414			650		221		403			628			5,032			262			790			539			570			203		702			903			3,969

Total net liquidity	$	1,719		$	1,032		$	517		$	1,284	$	306	$	413		$	869		$	6,140		$	608		$	804		$	711		$	632		$	258	$	746		$	1,145		$	4,904
Credit facilities:
Maturity dates	2017			2017, 2018			2016, 2018			2018		2020		2017, 2020			2016, 2018						2018, 2020			2020			2018, 2020			2020			2020		2018, 2019, 2022			2018, 2022

(1) Includes amounts borrowed on a short-term loan totaling $600 million at BHE that was repaid in full in January 2018.

Refer to ~~Notes~~Note 8 ~~and 16~~ of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities, letters of credit, equity commitments and other related items.

Operating Activities

Net cash flows from operating activities for the years ended December 31, ~~2015~~2017 and ~~2014~~2016 were ~~$7.0~~$6.07 billion and ~~$5.1~~$6.06 billion, respectively. ~~Higher income tax receipts of $1.0 billion,~~The increase was primarily due to improved operating results, ~~of $653 million, including $403 million from AltaLink, and other~~ changes in working capital ~~were~~and the payment for the USA Power litigation in 2016, partially offset by ~~higher interest payments of $179 million. As of December 31, 2015, the Company had~~ a ~~current~~reduction in income tax ~~receivable of $319 million.~~receipts.

Net cash flows from operating activities for the years ended December 31, ~~2014~~2016 and ~~2013~~2015 were ~~$5.1~~$6.1 billion and ~~$4.7~~$7.0 billion, respectively. The ~~increase~~change was primarily due to ~~$1.7 billion of improved operating results, including $1.2 billion from NV Energy, partially offset by $512 million of higher interest payments, $470 million of~~ lower income tax receipts of $618 million and ~~other changes in working capital. As~~payment for the USA Power litigation of ~~December 31, 2014, the Company had a current income tax receivable of $1.2 billion.~~$123 million.

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

~~In December 2014,~~The 2017 Tax Reform reduces the ~~Tax Increase Prevention Act of 2014 (the "Act") was signed into law, extending the 50% bonus depreciation for qualifying property purchased and placed in-service before~~federal corporate tax rate from 35% to 21% effective January 1, ~~2015~~2018, creates a one-time repatriation tax of foreign earnings and ~~before January 1, 2016 for certain longer-lived assets. Production tax credits were extended for wind power and other forms of non-solar renewable energy projects that begin construction before~~profits to be paid over the ~~end of 2014. As a result of the Act, the Company's cash flows from operations benefited in 2015 due to~~next eight years, eliminates bonus depreciation on qualifying regulated utility assets ~~placed in-service~~acquired after September 27, 2017 and extends and modifies the additional first-year bonus depreciation for ~~production~~non-regulated property. BHE's regulated subsidiaries anticipate passing the benefits of lower tax ~~credits earned~~expense to customers through regulatory mechanisms. The 2017 Tax Reform and the related regulatory outcomes will result in lower revenue, income taxes and cash flow in future years. BHE does not expect the 2017 Tax Reform and related regulatory treatment to have a material adverse impact on ~~qualifying projects.~~its cash flows, subject to actual regulatory outcomes, which will be determined based on rulings by regulatory commissions expected in 2018.

In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates ~~will be~~were set at 50% in 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Production tax credits were extended and phased-out for wind power and other forms of non-solar renewable energy projects that begin construction before the end of 2019. Production tax credits are maintained at full value through 2016, at 80% of ~~value~~the published rate in 2017, at 60% of ~~value~~the published rate in 2018, and 40% of ~~value~~the published rate in 2019. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). ~~As a result of PATH, the~~The Company's cash flows from operations are expected to benefit ~~in 2016 and beyond~~from PATH due to bonus depreciation on qualifying assets ~~placed in-service~~through 2019 and from the 2017 Tax Reform for non-regulated property through 2026, production tax credits through 2029 and investment tax credits earned on qualifying wind and solar projects through 2021, respectively. As a result of 2017 Tax Reform, bonus depreciation on qualifying assets acquired after September 27, 2017 is eliminated for regulated utility property and is extended and modified for non-regulated property. The Company believes property acquired on or before September 27, 2017 will remain subject to PATH.

Investing Activities

Net cash flows from investing activities for the years ended December 31, ~~2015~~2017 and ~~2014~~2016 were $~~(6.2)~~(6.1) billion and $~~(9.4)~~(5.7) billion, respectively. The change was primarily due to ~~lower~~higher cash paid for acquisitions ~~totaling $164 million in 2015 compared to $3.0~~of $1.0 billion, ~~in 2014($2.7 billion for AltaLink) and~~partially offset by lower capital expenditures of ~~$680 million, partially offset by changes in restricted cash and investments of $201~~$519 million and ~~higher~~lower funding of tax equity ~~method investments of $165 million.~~investments. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Net cash flows from investing activities for the years ended December 31, ~~2014~~2016 and ~~2013~~2015 were $~~(9.4)~~(5.7) billion and $~~(10.2)~~(6.2) billion, respectively. The change was primarily due to lower capital expenditures of $785 million, partially offset by higher funding of tax equity investments.

Acquisitions ~~in 2014 included~~

In 2017, the ~~$2.7 billion AltaLink acquisition and other~~Company completed various acquisitions totaling ~~$243 million~~$1.1 billion, net of cash acquired. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which primarily ~~for the remaining 50% interest in CE Generation, the Jumbo Road Project and~~related to residential real estate brokerage businesses, development and ~~mortgage businesses. Acquisitions~~construction costs for the 110-megawatt Alamo 6 and the 50-megawatt Pearl solar projects, and the remaining 25% interest in ~~2013 included~~ the ~~$5.6~~Silverhawk natural gas-fueled generation facility at Nevada Power. As a result of the various acquisitions, the Company acquired assets of $1.1 billion, ~~NV Energy~~assumed liabilities of $487 million and recognized goodwill of $508 million.

In 2016 and 2015, the Company completed various acquisitions totaling $66 million and $164 million, net of cash acquired, respectively. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed. The assets acquired consisted of property, plant and equipment, development and construction costs for renewable projects, other working capital items, goodwill of $50 million and $33 million, respectively, and other acquisitions totaling $240 million for real estate brokerage and mortgage businesses. Additionally, higher capital expenditures of $2.2 billion, including NV Energy, were partially offset by changes in restricted cash and investments of $407identifiable intangible assets. The liabilities assumed totaled $54 million and ~~lower equity method investments of $56 million.~~$84 million, respectively.

Financing Activities

Net cash flows from financing activities for the year ended December 31, 2017 were $274 million. Sources of cash totaled $4.1 billion and consisted of net proceeds from short-term debt of $2.4 billion and proceeds from subsidiary debt issuances totaling $1.7 billion. Uses of cash totaled $3.9 billion and consisted mainly of $2.3 billion for repayments of BHE senior debt and junior subordinated debentures, $1.0 billion for repayments of subsidiary debt and tender offer premiums paid of $435 million.

Net cash flows from financing activities for the year ended December 31, 2016 were $(690) million. Sources of cash totaled $3.2 billion and consisted mainly of proceeds from subsidiary debt totaling $2.3 billion and net proceeds from short-term debt of $880 million. Uses of cash totaled $3.9 billion and consisted mainly of $1.8 billion for repayments of subsidiary debt and repayments of BHE subordinated debt totaling $2 billion.

Net cash flows from financing activities for the year ended December 31, 2015 were $(255) million. Sources of cash totaled $2.5 billion and consisted of proceeds from subsidiary debt. Uses of cash totaled $2.7 billion and consisted mainly of $1.4 billion for repayments of subsidiary debt, repayments of BHE subordinated debt totaling $850 million and net repayments of short-term debt of $421 million.

In December 2015, Northern Powergrid (Northeast) Limited issued £120 million of notes at 2.564% due 2027 under its finance contract with the European Investment Bank. The net proceeds were used for general corporate purposes, including the repayment of short-term debt.

In December 2015, Northern Powergrid (Yorkshire) plc issued £130 million of notes at 2.564% due 2027 under its finance contract with the European Investment Bank. The net proceeds were used for general corporate purposes, including the repayment of short-term debt.

In October 2015, MidAmerican Energy issued $200 million of its 3.50% First Mortgage Bonds due October 2024 and $450 million of its 4.25% First Mortgage Bonds due May 2046. The net proceeds were used for the repayment of $426 million of long-term debt that matured December 31, 2015, and for general corporate purposes.

In September 2015, TX Jumbo Road Wind, LLC issued a $230 million Term Loan due September 2025. The Term Loan has an underlying variable interest rate based on LIBOR plus a fixed credit spread with a one-time increase during the term of the loan. The Company has entered into interest rate swaps that fix the underlying interest rate on 100% of the outstanding debt.

In June 2015, PacifiCorp issued $250 million of its 3.35% First Mortgage Bonds due July 2025. The net proceeds were used to fund capital expenditures and for general corporate purposes, including retirement of short-term debt.

~~In June 2015, ALP issued C$350 million of its 4.09% Series 2015-1 Medium-Term Notes due June 2045. The net proceeds were used to repay short-term debt.~~

In April 2015, Northern Powergrid (Yorkshire) plc issued £150 million of its 2.50% Bonds due April 2025. The net proceeds were used for general corporate purposes, including the repayment of short-term debt.

In March 2015, Solar Star Funding, LLC issued $325 million of its 3.95% Series B Senior Secured Notes. The principal of the notes amortizes beginning June 2016 with a final maturity in June 2035. The net proceeds were used to fund the repayment or reimbursement of amounts provided by BHE for the costs related to the development, construction and financing of the Solar Star Projects.

In March 2015, AltaLink Investments, L.P. issued C$200 million of its 2.244% Series 15-1 Senior Bonds due March 2022. The net proceeds were used to repay short-term debt, provide equity to ALP and for general corporate purposes.

~~Net cash flows from financing activities for the year ended December 31,~~ ~~2014~~ ~~were~~ ~~$3.7 billion~~. Sources of cash totaled $5.3 billion and consisted of proceeds from BHE junior subordinated debentures totaling $1.5 billion, proceeds from subsidiary debt totaling $1.3 billion, proceeds from BHE senior debt totaling $1.5 billion and net proceeds from short-term debt totaling $1.1 billion. Uses of cash totaled $1.6 billion and consisted mainly of $1.0 billion for repayments of subsidiary debt and repayments of BHE senior and subordinated debt totaling $550 million.

On December 1, 2014, BHE completed its acquisition of AltaLink. Following completion of the acquisition, AltaLink became an indirect wholly owned subsidiary of BHE. Under the terms of the Share Purchase Agreement, dated May 1, 2014, among BHE and SNC-Lavalin Group Inc., BHE paid C$3.1 billion (US$2.7 billion) in cash to SNC-Lavalin Group Inc. for 100% of the equity interests of AltaLink. BHE funded the total purchase price with $1.5 billion of junior subordinated debentures issued and sold to subsidiaries of Berkshire Hathaway, $1.0 billion borrowed under its commercial paper program and cash on hand. On December 4, 2014, BHE issued $350 million of 2.40% Senior Notes due 2020, $400 million of 3.50% Senior Notes due 2025 and $750 million of 4.50% Senior Notes due 2045 and used the proceeds to repay commercial paper borrowings.

~~Net cash flows from financing activities for the year ended December 31,~~ ~~2013~~ ~~were~~ ~~$5.9 billion~~. Sources of cash totaled $8.1 billion and consisted of proceeds from BHE junior subordinated debentures totaling $2.6 billion, proceeds from subsidiary debt totaling $2.5 billion, proceeds from BHE senior debt totaling $2.0 billion and proceeds from the issuance of common stock of $1.0 billion. Uses of cash totaled $2.2 billion and consisted mainly of $1.2 billion for repayments of subsidiary debt and net repayments of short-term debt totaling $849 million.

BHE funded the NV Energy acquisition by issuing $1.0 billion of common stock on December 19, 2013, issuing $2.6 billion of junior subordinated debentures to certain Berkshire Hathaway subsidiaries on December 19, 2013, and using $2.0 billion of cash, including certain proceeds from BHE’s $2.0 billion senior debt issuance on November 8, 2013.

The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.

The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years ended December 31 are as follows (in millions):


	Historical						Forecast						Historical						Forecast
	2013		2014		2015		2016		2017		2018		2015		2016		2017		2018		2019		2020

PacifiCorp	$	1,065	$	1,066	$	916	$	795	$	780	$	846	$	916	$	903	$	769	$	1,212	$	2,100	$	1,802
MidAmerican Funding	1,027		1,527		1,448		1,204		602		401		1,448		1,637		1,776		2,396		1,711		897
NV Energy	—		558		571		435		403		340		571		529		456		524		557		448
Northern Powergrid	675		675		674		640		564		533		674		579		579		700		621		478
BHE Pipeline Group	177		257		240		236		312		132		240		226		286		435		344		234
BHE Transmission	—		222		966		514		562		603		966		466		334		243		221		292
BHE Renewables	1,329		2,221		1,034		561		74		65		1,034		719		323		869		86		87
HomeServices	21		17		16		25		17		17		16		20		37		48		29		29
BHE and Other	13		12		10		24		24		14		10		11		11		16		13		12
Total	$	4,307	$	6,555	$	5,875	$	4,434	$	3,338	$	2,951	$	5,875	$	5,090	$	4,571	$	6,443	$	5,682	$	4,279


	Historical						Forecast						Historical						Forecast
	2013		2014		2015		2016		2017		2018		2015		2016		2017		2018		2019		2020

Wind generation													$	1,177	$	1,712	$	1,291	$	2,662	$	2,219	$	1,192
Solar generation	$	1,323	$	1,896	$	786	$	17	$	8	$	—	786		69		129		36		42		18
Wind generation	404		1,052		1,177		1,293		—		—
Electric transmission	341		547		936		505		539		509		936		448		343		248		365		551
Environmental	228		258		134		78		130		108		134		70		91		104		29		53
Other developmental projects	156		178		63		34		247		20
Electric distribution and other operating	1,855		2,624		2,779		2,507		2,414		2,314
Other growth													394		414		560		741		609		258
Operating													2,448		2,377		2,157		2,652		2,418		2,207
Total	$	4,307	$	6,555	$	5,875	$	4,434	$	3,338	$	2,951	$	5,875	$	5,090	$	4,571	$	6,443	$	5,682	$	4,279

The Company's historical and forecast capital expenditures consisted mainly of the following:

~~Solar generation includes the following:~~


◦	Construction of the Topaz Project totaling $49 million for 2015, $814 million for 2014 and $652 million for 2013. Final completion under the engineering, procurement and construction agreement occurred February 28, 2015, and project completion was achieved under the financing documents on March 30, 2015.

◦

Construction of the Solar Star Projects totaling $689 million for 2015, $1.1 billion for 2014 and $671 million for 2013. Both projects declared July 1, 2015 as the commercial operation date in accordance with the power purchase agreements. Final completion under the engineering, procurement and construction agreements occurred November 30, 2015 and project completion was achieved under the financing documents on December 15, 2015.

Wind generation includes the following:

◦

Construction of wind-powered generating facilities at MidAmerican Energy totaling $657 million for 2017, $943 million for 2016 and $931 million for ~~2015, $767 million for 2014 and $401 million for 2013.~~2015. MidAmerican Energy placed in-service 334 MW (nominal ratings) during 2017, 600 MW (nominal ratings) during 2016 and 608 MW (nominal ratings) during ~~2015, 511 MW (nominal ratings) during 2014 and 44 MW (nominal ratings) during 2013. MidAmerican Energy is constructing an additional 551 MW (nominal ratings) approved by~~2015. In August 2016, the IUB ~~in August 2015 that are expected to be placed in-service in 2016. In April 2015, MidAmerican Energy filed with the IUB~~issued an ~~application for~~order approving ratemaking principles related to ~~the~~MidAmerican Energy's construction of up to ~~552~~2,000 MW (nominal ratings) of additional wind-powered generating facilities, including the additions in 2017 and facilities expected to be placed in-service ~~by the end of 2016. In June 2015,~~in 2018 and 2019. MidAmerican Energy expects to spend $1,132 million in 2018, $1,038 million in 2019 and ~~the Iowa Office of Consumer Advocate ("OCA") entered into a settlement agreement relating to the proposal.~~$329 million in 2020 for these additional wind-powered generating facilities. The ~~settlement agreement established~~ratemaking principles establish a cost cap of ~~$903 million,~~$3.6 billion, including AFUDC, and ~~provides for~~ a fixed rate of return on equity of ~~11.35%~~11.0% over the proposed ~~30-year~~40-year useful lives of those facilities in any future Iowa rate proceeding. ~~In August 2015, the IUB approved the settlement agreement except for a reduction of the cost cap to $889 million, including AFUDC, to which MidAmerican Energy and the OCA agreed.~~ The cost cap ensures that as long as total costs are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. Additionally, the ratemaking principles modify the revenue sharing mechanism currently in effect. The revised sharing mechanism will be effective in 2018 and will be triggered each year by actual equity returns exceeding a weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of the federal production tax ~~credits. MidAmerican Energy continues~~credits available.

◦

Construction of wind-powered generating facilities at PacifiCorp totaling $5 million for 2017 and $31 million for 2016. The new wind-powered generating facilities are expected to ~~evaluate additional cost effective~~be placed in-service in 2020. Planned spending for the new wind-powered ~~generation.~~generating facilities totals $200 million in 2018, $421 million in 2019 and $588 million in 2020, plus approximately $300 million for an assumed vendor supplied financing transaction to be paid in 2020 that is not included in the table above. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal production tax credits available.

◦

Construction of wind-powered generating facilities at BHE Renewables totaling $109 million for 2017, $602 million for 2016 and $246 million for ~~2015, $286~~2015. BHE Renewables placed in-service 472 MW during 2016 and 300 MW during 2015. BHE Renewables anticipates costs will total an additional $734 million in 2018 for development and construction of up to 512 MW of wind-powered generating facilities.

◦

Repowering certain existing wind-powered generating facilities at PacifiCorp and MidAmerican Energy totaling $520 million for ~~2014~~2017 and $147 million for 2016. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $596 million in 2018, $758 million in 2019 and $276 million in 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal production tax credits available for ten years following each facility's return to service.

Solar generation includes the following:

◦

Construction of the community solar gardens project in Minnesota totaling $121 million for 2017, $56 million for 2016 and $3 million for ~~2013. The Jumbo Road Project with a total capacity of 300 MW achieved commercial operation in April~~ 2015. In addition, BHE Renewables acquired in 2015 for cash consideration totaling $111 million certain assets that will facilitate the development of up to 472 MW of wind-powered generating facilities in Nebraska and Kansas. BHE Renewables anticipates costs for wind-powered generating facilities will total $461 million in 2016. BHE Renewables expects ~~all~~to spend an additional $26 million in 2018 to complete the project, which will be comprised of ~~these wind-powered generating~~28 locations with a nominal facilities ~~to qualify~~capacity of 98 MW.


◦	Final construction costs for ~~federal production tax credits.~~the Solar Star and Topaz Projects totaling $738 million for 2015. Both projects declared the commercial operation date in accordance with the respective power purchase agreements and achieved completion under the respective engineering, procurement and construction agreements and financing documents in 2015.

Electric transmission includes ~~investments for ALP's transmission system including directly assigned projects from the AESO,~~ PacifiCorp's costs ~~primarily~~ associated with main grid reinforcement and the Energy Gateway Transmission Expansion Program, ~~and~~ MidAmerican Energy's MVPs approved by the MISO for the construction of ~~245~~approximately 250 miles of 345 kV transmission line located in Iowa and ~~Illinois.~~Illinois and ALP's directly assigned projects from the AESO, .

Environmental includes the installation of new or the replacement of existing emissions control equipment at certain generating facilities at the Utilities, including installation or upgrade of selective catalytic reduction control systems and low nitrogen oxide burners to reduce nitrogen oxides, particulate matter control systems, sulfur dioxide emissions control systems and mercury emissions control systems, as well as expenditures for the management of coal combustion residuals.

~~Electric distribution~~

Other growth includes projects to deliver power and ~~other operating~~services to new markets, new customer connections and enhancements to existing customer connections.

Operating includes ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid and investments in routine expenditures for generation, transmission, ~~generation~~distribution and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

The Company has contractual cash obligations that may affect its consolidated financial condition. The following table summarizes the Company's material contractual cash obligations as of December 31, ~~2015~~2017 (in millions):


	Payments Due By Periods										Payments Due By Periods
			2017-		2019-		2021 and						2019-		2021-		2023 and
	2016		2018		2020		After		Total		2018		2020		2022		After		Total

BHE senior debt	$	—	$	1,400	$	350	$	6,125	$	7,875	$	1,000	$	350	$	—	$	5,146	$	6,496
BHE junior subordinated debentures	—		—		—		2,944		2,944		—		—		—		100		100
Subsidiary debt	1,148		3,105		3,309		19,752		27,314		2,431		3,427		2,724		20,198		28,780
Interest payments on long-term debt⁽¹⁾	1,855		3,584		3,100		21,342		29,881		1,769		3,040		2,760		16,457		24,026
Short-term debt	974		—		—		—		974		4,488		—		—		—		4,488
Fuel, capacity and transmission contract commitments⁽¹⁾	2,214		3,105		2,358		9,494		17,171		2,098		3,072		2,265		10,044		17,479
Construction commitments⁽¹⁾	1,544		36		6		5		1,591		1,120		62		—		—		1,182
Operating leases and easements⁽¹⁾	143		213		143		1,007		1,506		180		298		232		1,297		2,007
Other⁽¹⁾	219		508		412		988		2,127		290		572		571		1,189		2,622
Total contractual cash obligations	$	8,097	$	11,951	$	9,678	$	61,657	$	91,383	$	13,376	$	10,821	$	8,552	$	54,431	$	87,180


(1)	Not reflected on the Consolidated Balance Sheets.

The Company has other types of commitments that arise primarily from unused lines of credit, letters of credit or relate to construction and other development costs (Liquidity and Capital Resources included within this Item 7 and Note 8), uncertain tax positions (Note 11) and asset retirement obligations (Note 13), which have not been included in the above table because the amount and timing of the cash payments are not certain. Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.

Additionally, the Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made contributions of ~~approximately~~$403 million, $584 million and $170 million in 2017, 2016 and 2015, respectively, and ~~expects~~has commitments as of December 31, 2017, subject to ~~contribute $563~~satisfaction of certain specified conditions, to provide equity contributions of $265 million in ~~2016~~2018 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a project achieves commercial operation, the Company ~~will enter~~enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits ~~generated by~~from the project.

Regulatory Matters

The Company is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further discussion regarding the Company's general regulatory framework and current regulatory matters.

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, ~~has stated that it is evaluating the economic value of several of~~announced on June 2, 2016, its ~~nuclear generating facilities, including Quad Cities Station. Included in such evaluation is the possibility of early retirement of~~intention to shut down Quad Cities Station ~~prior to the expiration~~on June 1, 2018, as a result of ~~its operating license in 2032. Exelon Generation has~~Illinois not ~~provided MidAmerican Energy with notice of any decision to retire~~passing adequate legislation and Quad Cities ~~Station.~~Station not clearing the 2019-2020 PJM Interconnection, L.L.C. capacity auction. MidAmerican Energy ~~has~~ expressed to Exelon Generation its desire for the continued operation of the facility through the end of its operating ~~license.~~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 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.

~~A decision by Exelon Generation to retire~~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 U.S. Constitution. Both complaints argue that the Illinois zero emission credit program will distort the FERC’s energy and capacity market auction system of setting wholesale prices. As majority owner and operator of Quad Cities Station, ~~before~~Exelon Generation intervened and filed motions to dismiss in both lawsuits. On July 14, 2017, the ~~end~~Northern District of ~~its operating license would require~~Illinois granted the motions to dismiss. On July 17, 2017, the plaintiffs filed appeals with the United States Court of Appeals for the Seventh Circuit. Parties have filed briefs and presented oral argument. MidAmerican Energy cannot predict the outcome of these lawsuits.

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 ~~evaluation~~expanded MOPR could result in an increased risk of ~~the carrying value and classification of assets and liabilities related to~~ Quad Cities Station ~~on MidAmerican Energy’s balance sheets.~~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 timing of the FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

~~100~~

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, RPS, 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 its 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 federal, state, local and international 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 the Company is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. The Company believes it is in material compliance with all applicable laws and ~~regulations.~~

regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations and "Liquidity and Capital Resources" for discussion of the Company's forecast environmental-related capital expenditures.

Collateral and Contingent Features

Debt of BHE and debt and preferred securities of certain of its subsidiaries are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the rated company's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

BHE and its subsidiaries have no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of December 31, ~~2015~~2017, the applicable entities' credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, ~~2015~~2017, the Company would have been required to post $~~615~~440 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. Refer to Note 14 of Notes to Consolidated Financial Statements for a discussion of the Company's collateral requirements specific to its derivative contracts.

The Company is a party to derivative contracts, including over-the-counter derivative contracts. The Dodd-Frank Reform Act provides for extensive new regulation of over-the-counter derivative contracts and certain market participants, including imposition of position limits, mandatory clearing, exchange trading, capital, margin, reporting, recordkeeping and business conduct requirements. Many of these requirements are primarily for "swap dealers" and "major swap participants," but many of these also impose some requirements on almost all market participants, including the Company. The Dodd-Frank Reform Act provides certain exemptions from many of these requirements for commercial end-users when using derivatives to hedge or mitigate commercial risk of their businesses. The Company qualifies or believes it will qualify for many of these exemptions. The Company generally does not enter into over-the-counter derivative contracts for purposes unrelated to hedging or mitigating commercial risk and has determined that it is not a swap dealer or major swap participant. The outcome of pending and remaining Dodd-Frank Reform Act rulemaking proceedings cannot be predicted but requirements resulting from these proceedings could directly impact the Company or could have impacts to energy and other markets in general that could have an impact on the Company's consolidated financial results.

~~101~~

Inflation

Historically, overall inflation and changing prices in the economies where BHE's subsidiaries operate have not had a significant impact on the Company's consolidated financial results. In the United States and Canada, the Regulated Businesses operate under cost-of-service based rate structures administered by various state and provincial commissions and the FERC. Under these rate structures, the Regulated Businesses are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the Northern Powergrid Distribution Companies incorporates the rate of inflation in determining rates charged to customers. BHE's subsidiaries attempt to minimize the potential impact of inflation on their operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.

Off-Balance Sheet Arrangements

The Company has certain investments that are accounted for under the equity method in accordance with ~~accounting principles generally accepted in the United States of America ("GAAP").~~GAAP. Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments. Certain equity investments are presented on the Consolidated Balance Sheets net of investment tax credits.

As of December 31, ~~2015~~2017, the Company's investments that are accounted for under the equity method had short- and long-term debt of $2.5 billion, unused revolving credit facilities of ~~$225~~$365 million and letters of credit outstanding of $88 million. As of December 31, ~~2015~~2017, the Company's pro-rata share of such short- and long-term debt was $1.2 billion, unused revolving credit facilities was ~~$81~~$151 million and outstanding letters of credit was $43 million. The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. The entire amount of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

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. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

Accounting for the Effects of Certain Types of Regulation

The Regulated Businesses prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

~~102~~

The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at ~~both~~ the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI"). Total regulatory assets were $~~4.3~~3.0 billion and total regulatory liabilities were $~~3.0~~7.5 billion as of December 31, ~~2015~~2017. Refer to Note 6 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Regulated Businesses' regulatory assets and liabilities.

Derivatives

The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate short- and long-term debt, future debt issuances and mortgage commitments. Additionally, BHE is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain and Canada. Each of BHE's business platforms has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report each of the various types of risk involved in its business. The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. The Company manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, the Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, forward sale commitments, or mortgage interest rate lock commitments, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price, interest rate and foreign currency exchange rate risks, thereby exposing the unhedged portion to changes in market prices. Refer to Notes 14 and 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's derivative contracts.

Measurement Principles

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. As of December 31, ~~2015~~2017, the Company had a net derivative liability of $~~288~~120 million related to contracts valued using either quoted prices or forward price curves based upon observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. The assumptions used in these models are important because any changes in assumptions could have a significant impact on the estimated fair value of the contracts. As of December 31, ~~2015~~2017, the Company had a net derivative asset of $51103 million related to contracts where the Company uses internal models with significant unobservable inputs.

~~103~~

Classification and Recognition Methodology

The majority of the Company's commodity derivative contracts are probable of inclusion in the rates of its rate-regulated subsidiaries, and changes in the estimated fair value of derivative contracts are generally recorded as net regulatory assets or liabilities. Accordingly, amounts are generally not recognized in earnings until the contracts are settled and the forecasted transaction has occurred. As of December 31, ~~2015~~2017, the Company had $~~250~~119 million recorded as net regulatory assets related to derivative contracts on the Consolidated Balance Sheets.

Impairment of Goodwill and Long-Lived Assets

The Company's Consolidated Balance Sheet as of December 31, ~~2015~~2017 includes goodwill of acquired businesses of ~~$9.1~~$9.7 billion. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, ~~2015~~2017. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors. Refer to Note 21 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's goodwill.

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As substantially all property, plant and equipment was used in regulated businesses as of December 31, ~~2015~~2017, the impacts of regulation are considered when evaluating the carrying value of regulated assets.

The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.

Pension and Other Postretirement Benefits

Certain of the Company's subsidiaries sponsor defined benefit pension and other postretirement benefit plans that cover the majority of employees. The Company recognizes the funded status of the defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, ~~2015~~2017, the Company recognized a net liability totaling $~~389~~63 million for the funded status of the defined benefit pension and other postretirement benefit plans. As of December 31, ~~2015~~2017, amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets totaled $~~765~~606 million and in AOCI totaled $~~605~~530 million.

The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, ~~2015~~2017.

~~104~~

The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.

In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.

The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5.00% by 2025, at which point the rate of increase is assumed to remain constant. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for healthcare cost trend rate sensitivity disclosures.

The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Consolidated Financial Statements would be as follows (dollars in millions):


	Domestic Plans															Domestic Plans
						Other Postretirement					United Kingdom										Other Postretirement					United Kingdom
	Pension Plans					Benefit Plans					Pension Plan					Pension Plans					Benefit Plans					Pension Plan
	+0.5%			-0.5%		+0.5%			-0.5%		+0.5%			-0.5%		+0.5%			-0.5%		+0.5%			-0.5%		+0.5%			-0.5%

Effect on December 31, 2015
Effect on December 31, 2017
Benefit Obligations:
Discount rate	$	(146	)	$	162	$	(31	)	$	34	$	(172	)	$	197	$	(155	)	$	170	$	(31	)	$	34	$	(197	)	$	222

Effect on 2015 Periodic Cost:
Effect on 2017 Periodic Cost:
Discount rate	$	(7	)	$	10	$	—		$	1	$	(17	)	$	17	$	(2	)	$	—	$	1		$	—	$	(18	)	$	19
Expected rate of return on plan assets	(12		)	12		(4		)	4		(11		)	11		(12		)	12		(3		)	3		(10		)	10

A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and the Company's funding policy for each plan.

Income Taxes

In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory jurisdictions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. Refer to Note 11 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes.

~~The Utilities are required to~~It is probable the Company's regulated businesses will pass income tax benefits and expense related to the federal tax rate change from 35% to 21%, certain property-related basis differences and other various differences on to their customers in certain state and provincial jurisdictions. As of December 31, ~~2015~~2017, these amounts were recognized as a ~~regulatory asset of~~ ~~$1.5 billion~~ ~~and a~~net regulatory liability of ~~$29 million~~$4.0 billion and will be included in regulated rates when the temporary differences reverse.

~~105~~

The ~~Company has not established deferred income taxes~~2017 Tax Reform creates a one-time repatriation tax on the Company's undistributed foreign corporations' post-1986 accumulated earnings ~~of Northern Powergrid or AltaLink or~~and profits. Therefore, the ~~related currency translation adjustment that have been determined by management to be reinvested indefinitely. The~~ cumulative undistributed foreign earnings were ~~approximately~~ ~~$3.0 billion~~deemed repatriated to the United States as of December 31, ~~2015~~.2017. The Company currently does not believe the deemed repatriation has altered the Company's existing assertion that undistributed earnings will be reinvested indefinitely; however, the Company periodically evaluates its capital ~~requirements. If circumstances change in~~requirements and that conclusion could change. As a result of the 2017 Tax Reform, future ~~and a portion of Northern Powergrid's or AltaLink's~~ undistributed earnings ~~were repatriated, the dividends would~~are not expected to be subject to ~~taxation~~tax in the United States. However, any United States income tax liability would be offset, in part, by available United States income tax credits with respect to corporate income taxes previously paid in the United Kingdom and Canada. Because of the availability of foreign income tax credits, it is not practicable to determine the United States income tax liability that would be recognized if such cumulative earnings were not reinvested indefinitely. The Company has established deferred income taxes on all other undistributed foreign earnings. If opportunities become available to repatriate any available cash without triggering incremental United States income tax expense, the Company may distribute certain foreign earnings of Northern Powergrid and AltaLink.

Revenue Recognition - Unbilled Revenue

Revenue from energy business customers is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of the Great Britain distribution businesses, when information is received from the national settlement system. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $~~660~~665 million as of December 31, ~~2015~~2017. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. ~~Estimates are~~Unbilled revenue is reversed in the following month and ~~actual~~billed revenue is recorded based on the subsequent meter readings.


Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

The Company's Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. The Company's significant market risks are primarily associated with commodity prices, interest rates, equity prices, foreign currency exchange rates and the extension of credit to counterparties with which the Company transacts. The following discussion addresses the significant market risks associated with the Company's business activities. Each of the Company's business platforms has established guidelines for credit risk management. Refer to Notes 2 and 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's contracts accounted for as derivatives.

Commodity Price Risk

The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of the Utilities as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold and natural gas supply for retail customers. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage and transmission and transportation constraints. The Company does not engage in a material amount of proprietary trading activities. To mitigate a portion of its commodity price risk, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company does not hedge all of its commodity price risk, thereby exposing the unhedged portion to changes in market prices. The Company's exposure to commodity price risk is generally limited by its ability to include commodity costs in regulated rates, which is subject to regulatory lag that occurs between the time the costs are incurred and when the costs are included in regulated rates, as well as the impact of any customer sharing resulting from cost adjustment mechanisms.

~~106~~

The table that follows summarizes the Company's price risk on commodity contracts accounted for as derivatives, excluding collateral netting of $~~103~~76 million and $7574 million, respectively, as of December 31, ~~2015~~2017 and ~~2014~~2016, ~~respectively,~~ and shows the effects of a hypothetical 10% increase and 10% decrease in forward market prices with the contracted or expected volumes. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions).


	Fair Value -			Estimated Fair Value after						Fair Value -			Estimated Fair Value after
	Net Asset			Hypothetical Change in Price						Net Asset			Hypothetical Change in Price
	(Liability)			10% increase			10% decrease			(Liability)			10% increase			10% decrease
As of December 31, 2015:
As of December 31, 2017:
Not designated as hedging contracts	$	(186	)	$	(148	)	$	(224	)	$	(32	)	$	(18	)	$	(46	)
Designated as hedging contracts	(47		)	(4		)	(89		)	(1		)	35			(37		)
Total commodity derivative contracts	$	(233	)	$	(152	)	$	(313	)	$	(33	)	$	17		$	(83	)

As of December 31, 2014:
As of December 31, 2016
Not designated as hedging contracts	$	(156	)	$	(120	)	$	(191	)	$	(71	)	$	(37	)	$	(105	)
Designated as hedging contracts	(36		)	9			(81		)	(16		)	19			(51		)
Total commodity derivative contracts	$	(192	)	$	(111	)	$	(272	)	$	(87	)	$	(18	)	$	(156	)


~~(2)~~	(2)Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The Consolidated Financial Statements include the accounts of BHE and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. The Consolidated Statements of Operations include the revenue and expenses of any acquired entities from the date of acquisition. Intercompany accounts and transactions have been eliminated.

Use of Estimates in Preparation of Financial Statements

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; fair value of assets acquired and liabilities assumed in business combinations; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, Northern Natural Gas, Kern River and ALP (the "Regulated Businesses") prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.

~~119~~

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. ~~Different~~Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

Cash Equivalents and Restricted Cash and Investments

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and investments and restricted cash and investments on the Consolidated Balance Sheets.

Investments

The Company's management determines the appropriate classification of investments in debt and equity securities at the acquisition date and reevaluates the classification at each balance sheet date. Investments and restricted cash and investments that management does not intend to use or is restricted from using in current operations are presented as noncurrent on the Consolidated Balance Sheets.

Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory liability since the Company expects to recover costs for these activities through regulated rates. Trading securities are carried at fair value with realized and unrealized gains and losses recognized in earnings. Held-to-maturity securities are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity.

The Company utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when an investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, the Company records the investment at cost and subsequently increases or decreases the carrying value of the investment by the Company's ~~proportionate~~ share of the net earnings or losses and other comprehensive income (loss) ("OCI") of the investee. The Company records dividends or other equity distributions as reductions in the carrying value of the investment. Certain equity investments are presented on the Consolidated Balance Sheets net of related investment tax credits.

~~120~~

Investments gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired. If a decline in value of an investment below cost is deemed other than temporary, the cost of the investment is written down to fair value, with a corresponding charge to earnings. Factors considered in judging whether an impairment is other than temporary include: the financial condition, business prospects and creditworthiness of the issuer; the relative amount of the decline; the Company's ability and intent to hold the investment until the fair value recovers; and the length of time that fair value has been less than cost. Impairment losses on equity securities are charged to earnings. With respect to an investment in a debt security, any resulting impairment loss is recognized in earnings if the Company intends to sell, or expects to be required to sell, the debt security before its amortized cost is recovered. If the Company does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in OCI. For regulated investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.

Allowance for Doubtful Accounts

Trade receivables are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on the Company's assessment of the collectibility of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. As of December 31, ~~2015~~2017 and ~~2014~~2016, the allowance for doubtful accounts totaled $3140 million and $3733 million, respectively, and is included in trade receivables, net on the Consolidated Balance Sheets.

Derivatives

The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.

Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of sales on the Consolidated Statements of Operations.

For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For the Company's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as regulatory assets and liabilities, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts; cost of sales and operating expense for purchase contracts and electricity, natural gas and fuel swap contracts; and other, net for interest rate swap derivatives.

For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.

Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.

~~121~~

Inventories

Inventories consist mainly of fuel, which includes coal stocks, stored gas and fuel oil, totaling $~~353~~352 million and $~~320~~402 million as of December 31, ~~2015~~2017 and ~~2014~~2016, respectively, and materials and supplies totaling $~~529~~536 million and $~~506~~523 million as of December 31, ~~2015~~2017 and ~~2014~~2016, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using the average cost method. The cost of stored gas is determined using either the last-in-first-out ("LIFO") method or the lower of average cost or market. With respect to inventories carried at LIFO cost, the replacement cost would be $822 million and $4127 million higher as of December 31, ~~2015~~2017 and ~~2014~~2016, respectively.

Property, Plant and Equipment, Net

General

Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable to the Regulated Businesses. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which the carrying cost of certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds.

Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Regulated Businesses to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by the Regulated Businesses as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC") and the Alberta Utilities Commission ("AUC"). After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.

Asset Retirement Obligations

The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily related to the decommissioning of nuclear generating facilities and obligations associated with its other generating facilities and offshore natural gas pipelines. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For the Regulated Businesses, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.

~~122~~

Impairment

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. The impacts of regulation are considered when evaluating the carrying value of regulated assets.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, the Company estimates the fair value of the reporting unit. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate.In estimating future cash flows, the Company incorporates current market information, as well as historical factors. As such, the determination of fair value incorporates significant unobservable inputs. During ~~2015~~2017, 2016 and ~~2014,~~2015, the Company did not record any material goodwill impairments. ~~The Company recognized a goodwill impairment of $53 million during 2013.~~

Revenue Recognition

~~Energy Businesses~~AltaLink

~~Revenue~~AltaLink's primary source of operating revenue is the AESO, an entity rated AA- by Standard and Poor's. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations would significantly impair AltaLink's ability to meet its existing and future obligations. Total operating revenue for AltaLink was $699 million for the year ended December 31, 2017.

BHE Renewables

BHE Renewables owns independent power projects in the United States and the Philippines that generally have separate project financing agreements. These projects source of operating revenue is derived primarily from long-term power purchase agreements with single customers, primarily utilities, which expire between 2017 and 2040. Because of the dependence generally from a single customer at each project, any material failure of the customer to fulfill its obligations would significantly impair that project's ability to meet its existing and future obligations. Total operating revenue for BHE Renewables was $838 million for the year ended December 31, 2017.

Other Energy Business

MidAmerican Energy Services, LLC ("MES") is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with financial institutions and other market participants. Credit risk may be concentrated to the extent that MES' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MES analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, MES enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, MES exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

As of December 31, 2017, MES' aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.


Item 8.	Financial Statements and Supplementary Data



Report of Independent Registered Public Accounting Firm		115

Consolidated Balance Sheets		116

Consolidated Statements of Operations		118

Consolidated Statements of Comprehensive Income		119

Consolidated Statements of Changes in Equity		120

Consolidated Statements of Cash Flows		121

Notes to Consolidated Financial Statements		122

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Des Moines, Iowa

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and the schedules listed in the Index at Item 15(a)(ii) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.


/s/	Deloitte & Touche LLP

Des Moines, Iowa

February 23, 2018

We have served as the Company's auditor since 1991.

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in millions)



	As of December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	935	$	721
Restricted cash and short-term investments	327		211
Trade receivables, net	2,014		1,751
Income taxes receivable	334		—
Inventories	888		925
Mortgage loans held for sale	465		359
Other current assets	815		706
Total current assets	5,778		4,673

Property, plant and equipment, net	65,871		62,509
Goodwill	9,678		9,010
Regulatory assets	2,761		4,307
Investments and restricted cash and investments	4,872		3,945
Other assets	1,248		996

Total assets	$	90,208	$	85,440

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(Amounts in millions)



	As of December 31,
	2017			2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,519		$	1,317
Accrued interest	488			454
Accrued property, income and other taxes	354			389
Accrued employee expenses	274			261
Short-term debt	4,488			1,869
Current portion of long-term debt	3,431			1,006
Other current liabilities	1,049			1,017
Total current liabilities	11,603			6,313

BHE senior debt	5,452			7,418
BHE junior subordinated debentures	100			944
Subsidiary debt	26,210			26,748
Regulatory liabilities	7,309			2,933
Deferred income taxes	8,242			13,879
Other long-term liabilities	2,984			2,742
Total liabilities	61,900			60,977

Commitments and contingencies (Note 16)

Equity:
BHE shareholders' equity:
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding	—			—
Additional paid-in capital	6,368			6,390
Retained earnings	22,206			19,448
Accumulated other comprehensive loss, net	(398		)	(1,511		)
Total BHE shareholders' equity	28,176			24,327
Noncontrolling interests	132			136
Total equity	28,308			24,463

Total liabilities and equity	$	90,208		$	85,440

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in millions)



	Years Ended December 31,
	2017			2016			2015
Operating revenue:
Energy	$	15,171		$	14,621		$	15,354
Real estate	3,443			2,801			2,526
Total operating revenue	18,614			17,422			17,880

Operating costs and expenses:
Energy:
Cost of sales	4,518			4,315			5,079
Operating expense	3,773			3,707			3,732
Depreciation and amortization	2,580			2,560			2,399
Real estate	3,229			2,589			2,342
Total operating costs and expenses	14,100			13,171			13,552

Operating income	4,514			4,251			4,328

Other income (expense):
Interest expense	(1,841		)	(1,854		)	(1,904		)
Capitalized interest	45			139			74
Allowance for equity funds	76			158			91
Interest and dividend income	111			120			107
Other, net	(398		)	36			39
Total other income (expense)	(2,007		)	(1,401		)	(1,593		)

Income before income tax (benefit) expense and equity (loss) income	2,507			2,850			2,735
Income tax (benefit) expense	(554		)	403			450
Equity (loss) income	(151		)	123			115
Net income	2,910			2,570			2,400
Net income attributable to noncontrolling interests	40			28			30
Net income attributable to BHE shareholders	$	2,870		$	2,542		$	2,370

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Amounts in millions)



	Years Ended December 31,
	2017		2016			2015

Net income	$	2,910	$	2,570		$	2,400

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $9, $11 and $17	64		(9		)	52
Foreign currency translation adjustment	546		(583		)	(680		)
Unrealized gains (losses) on available-for-sale securities, net of tax of $270, $(19) and $129	500		(30		)	225
Unrealized gains (losses) on cash flow hedges, net of tax of $(7), $13 and $(7)	3		19			(11		)
Total other comprehensive income (loss), net of tax	1,113		(603		)	(414		)

Comprehensive income	4,023		1,967			1,986
Comprehensive income attributable to noncontrolling interests	40		28			30
Comprehensive income attributable to BHE shareholders	$	3,983	$	1,939		$	1,956

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Amounts in millions)



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

Balance, December 31, 2014	77	$	—	$	6,423		$	14,513		$	(494	)	$	131		$	20,573
Adoption of ASC 853	—	—		—			56			—			11			67
Net income	—	—		—			2,370			—			18			2,388
Other comprehensive loss	—	—		—			—			(414		)	—			(414		)
Distributions	—	—		—			—			—			(21		)	(21		)
Common stock purchases	—	—		(3		)	(33		)	—			—			(36		)
Other equity transactions	—	—		(17		)	—			—			(5		)	(22		)
Balance, December 31, 2015	77	—		6,403			16,906			(908		)	134			22,535
Net income	—	—		—			2,542			—			14			2,556
Other comprehensive loss	—	—		—			—			(603		)	—			(603		)
Distributions	—	—		—			—			—			(20		)	(20		)
Other equity transactions	—	—		(13		)	—			—			8			(5		)
Balance, December 31, 2016	77	—		6,390			19,448			(1,511		)	136			24,463
Net income	—	—		—			2,870			—			22			2,892
Other comprehensive income	—	—		—			—			1,113			—			1,113
Distributions	—	—		—			—			—			(22		)	(22		)
Common stock purchases	—	—		(1		)	(18		)	—			—			(19		)
Common stock exchange	—	—		(6		)	(94		)	—			—			(100		)
Other equity transactions	—	—		(15		)	—			—			(4		)	(19		)
Balance, December 31, 2017	77	$	—	$	6,368		$	22,206		$	(398	)	$	132		$	28,308

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in millions)



	Years Ended December 31,
	2017			2016			2015
Cash flows from operating activities:
Net income	$	2,910		$	2,570		$	2,400
Adjustments to reconcile net income to net cash flows from operating activities:
Loss (gain) on other items, net	455			62			(8		)
Depreciation and amortization	2,646			2,591			2,428
Allowance for equity funds	(76		)	(158		)	(91		)
Equity loss (income), net of distributions	260			(67		)	(38		)
Changes in regulatory assets and liabilities	31			(34		)	356
Deferred income taxes and amortization of investment tax credits	19			1,090			1,265
Other, net	(2		)	(142		)	19
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(86		)	(158		)	(9		)
Derivative collateral, net	(22		)	32			(14		)
Pension and other postretirement benefit plans	(91		)	(79		)	(11		)
Accrued property, income and other taxes	(28		)	377			877
Accounts payable and other liabilities	50			(28		)	(194		)
Net cash flows from operating activities	6,066			6,056			6,980

Cash flows from investing activities:
Capital expenditures	(4,571		)	(5,090		)	(5,875		)
Acquisitions, net of cash acquired	(1,113		)	(66		)	(164		)
Increase in restricted cash and investments	(81		)	(36		)	(28		)
Purchases of available-for-sale securities	(190		)	(141		)	(144		)
Proceeds from sales of available-for-sale securities	202			191			142
Equity method investments	(368		)	(570		)	(202		)
Other, net	(12		)	(34		)	41
Net cash flows from investing activities	(6,133		)	(5,746		)	(6,230		)

Cash flows from financing activities:
Repayments of BHE senior debt and junior subordinated debentures	(2,323		)	(2,000		)	(850		)
Common stock purchases	(19		)	—			(36		)
Proceeds from subsidiary debt	1,763			2,327			2,479
Repayments of subsidiary debt	(1,000		)	(1,831		)	(1,354		)
Net proceeds from (repayments of) short-term debt	2,361			879			(421		)
Tender offer premium paid	(435		)	—			—
Other, net	(73		)	(65		)	(73		)
Net cash flows from financing activities	274			(690		)	(255		)

Effect of exchange rate changes	7			(7		)	(4		)

Net change in cash and cash equivalents	214			(387		)	491
Cash and cash equivalents at beginning of period	721			1,108			617
Cash and cash equivalents at end of period	$	935		$	721		$	1,108

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)	Organization and Operations

Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The Company's operations are organized as eightbusiness segments: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. ("NV Energy") (which primarily consists of Nevada Power Company ("Nevada Power") and Sierra Pacific Power Company ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("AltaLink") (which primarily consists of AltaLink, L.P. ("ALP")) and BHE U.S. Transmission, LLC), BHE Renewables and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). The Company, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, two interstate natural gas pipeline companies in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in solar, wind, geothermal and hydroelectric projects, the second largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States.

(2)Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

Use of Estimates in Preparation of Financial Statements

Accounting for the Effects of Certain Types of Regulation

The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

Cash Equivalents and Restricted Cash and Investments

Investments

The Company utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when an investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, the Company records the investment at cost and subsequently increases or decreases the carrying value of the investment by the Company's share of the net earnings or losses and other comprehensive income (loss) ("OCI") of the investee. The Company records dividends or other equity distributions as reductions in the carrying value of the investment. Certain equity investments are presented on the Consolidated Balance Sheets net of related investment tax credits.

Investments gains and losses arise when investments are sold (as determined on a specific identification basis) or are other-than-temporarily impaired. If a decline in value of an investment below cost is deemed other than temporary, the cost of the investment is written down to fair value, with a corresponding charge to earnings. Factors considered in judging whether an impairment is other than temporary include: the financial condition, business prospects and creditworthiness of the issuer; the relative amount of the decline; the Company's ability and intent to hold the investment until the fair value recovers; and the length of time that fair value has been less than cost. Impairment losses on equity securities are charged to earnings. With respect to an investment in a debt security, any resulting impairment loss is recognized ~~as electricity~~in earnings if the Company intends to sell, or ~~natural gas~~expects to be required to sell, the debt security before its amortized cost is ~~delivered~~recovered. If the Company does not expect to ultimately recover the amortized cost basis even if it does not intend to sell the security, the credit loss component is recognized in earnings and any difference between fair value and the amortized cost basis, net of the credit loss, is reflected in OCI. For regulated investments, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in regulated rates is probable.

Allowance for Doubtful Accounts

Trade receivables are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on the Company's assessment of the collectibility of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or ~~services are provided.~~ ~~Revenue recognized includes billed and unbilled amounts.~~the outcome of any pending disputes. As of December 31, ~~2015~~2017 and ~~2014~~2016, ~~unbilled revenue was~~the allowance for doubtful accounts totaled $~~660~~40 million and $~~666~~33 million, respectively, and is included in trade receivables, net on the Consolidated Balance Sheets. ~~Rates~~

Derivatives

The Company employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for ~~energy businesses~~the exception afforded by GAAP. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.

Commodity derivatives used in normal business operations that are ~~established~~settled by ~~regulators or contractual arrangements. When preliminary regulated rates~~physical delivery, among other criteria, are ~~permitted to be billed prior to final approval by the applicable regulator, certain revenue collected~~eligible for and may be ~~subject to refund~~designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and ~~a liability for estimated refunds is accrued. The Company records~~settled amounts are recognized as operating revenue or cost of sales ~~franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis~~ on the Consolidated Statements of Operations.

~~Real Estate Commission Revenue, Mortgage Revenue~~For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and ~~Franchise Royalty Fees~~losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. For the Company's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as regulatory assets and liabilities, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts; cost of sales and operating expense for purchase contracts and electricity, natural gas and fuel swap contracts; and other, net for interest rate swap derivatives.

~~Commission revenue from real estate brokerage transactions~~For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and ~~related amounts due to agents are recognized when~~thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.

Changes in the estimated fair value of a ~~real estate transaction is closed. Title~~derivative contract designated and ~~escrow closing fee revenue from real estate transactions and related amounts due~~qualified as a cash flow hedge, to the ~~title insurer~~extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized ~~at closing. Mortgage fee revenue consists~~in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of ~~amounts earned~~the derivative contract are charged to earnings. Gains and losses related to ~~application~~discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and ~~underwriting fees, and fees on canceled loans. Fees~~the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated ~~with the origination and acquisition of mortgage loans~~deferred amounts in AOCI are immediately recognized ~~as earned. Franchise royalty fees are based on a percentage of commissions earned by franchisees on real estate sales and are recognized when the sale closes.~~

~~Unamortized Debt Premiums, Discounts and Debt Issuance Costs~~

~~Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.~~

~~123~~

~~Foreign Currency~~

The accounts of foreign-based subsidiaries are measured in most instances using the local currency of the subsidiary as the functional currency. Revenue and expenses of these businesses are translated into United States dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in equity as a component of AOCI. Gains or losses arising from transactions denominated in a currency other than the functional currency of the entity that is party to the transaction are included in earnings.

~~Income Taxes~~

~~Berkshire Hathaway includes the Company in its United States federal income tax return. The Company's provision for income taxes has been computed on a stand-alone basis.~~Inventories

~~Deferred income tax assets~~Inventories consist mainly of fuel, which includes coal stocks, stored gas and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with income tax benefits and expense for certain property-related basis differences and other various differences that PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific (the "Utilities") are required to pass on to their customers in most state jurisdictions are charged or credited directly to a regulatory asset or liability. As of December 31,fuel oil, totaling ~~2015~~ ~~and~~ ~~2014, these amounts were recognized as regulatory assets of~~ $~~1.5 billion~~ ~~and~~ ~~$1.4 billion, respectively, and regulatory liabilities of~~ ~~$29~~352 million and $24402 million, respectively, and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory jurisdictions.

The Company has not established deferred income taxes on the undistributed foreign earnings of Northern Powergrid or AltaLink or the related currency translation adjustment that have been determined by management to be reinvested indefinitely. The cumulative undistributed foreign earnings were approximately~~$3.0 billion~~ as of December 31, ~~2015~~2017. and 2016, respectively, and materials and supplies totaling $536 million and $523 million as of December 31, 2017 and 2016, respectively. The ~~Company periodically evaluates its capital requirements. If circumstances change in~~cost of materials and supplies, coal stocks and fuel oil is determined primarily using the ~~future and a portion~~average cost method. The cost of ~~Northern Powergrid's~~stored gas is determined using either the last-in-first-out ("LIFO") method or ~~AltaLink's undistributed earnings were repatriated,~~ the ~~dividends~~lower of average cost or market. With respect to inventories carried at LIFO cost, the replacement cost would be subject to taxation in the United States. However, any United States income tax liability would be offset, in part, by available United States income tax credits with respect to corporate income taxes previously paid in the United Kingdom$22 million and ~~Canada. Because~~$27 million higher as of the availability of foreign income tax credits, it is not practicable to determine the United States income tax liability that would be recognized if such cumulative earnings were not reinvested indefinitely. The Company has established deferred income taxes on all other undistributed foreign earnings. If opportunities become available to repatriate any available cash without triggering incremental United States income tax expense, the Company may distribute certain foreign earnings of Northern PowergridDecember 31, 2017 and ~~AltaLink.~~2016, respectively.

~~In determining~~Property, Plant and Equipment, Net

General

Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable to the ~~Company's income taxes, management is required to interpret complex income tax laws~~Regulated Businesses. The cost of additions and ~~regulations,~~betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. Additionally, MidAmerican Energy has regulatory arrangements in Iowa in which ~~includes consideration~~the carrying cost of ~~regulatory implications imposed~~certain utility plant has been reduced for amounts associated with electric returns on equity exceeding specified thresholds.

Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory ~~jurisdictions. The Company's income tax returns~~authorities. Depreciation studies are ~~subject~~completed by the Regulated Businesses to ~~continuous examinations~~determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by ~~federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to~~ the ~~nature~~applicable regulatory commission. Net salvage includes the estimated future residual values of the ~~examination process, it generally takes years before these examinations~~assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are ~~completed and these matters are resolved. The Company recognizes the tax benefit from~~recorded as either a cost of removal regulatory liability or an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. ~~The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities~~ARO liability on the Consolidated Balance ~~Sheets. Estimated interest~~Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

Generally when the Company retires or sells a component of regulated property, plant and ~~penalties, if~~equipment, it charges the original cost, net of any ~~related~~proceeds from the disposition, to ~~uncertain tax positions are included~~accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.

Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by the Regulated Businesses as a component of ~~income tax~~property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the Federal Energy Regulatory Commission ("FERC") and the Alberta Utilities Commission ("AUC"). After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.

Asset Retirement Obligations

Impairment

~~124~~

~~New Accounting Pronouncements~~ The impacts of regulation are considered when evaluating the carrying value of regulated assets.

~~In January 2016,~~Goodwill

Goodwill represents the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-01, which amends FASB Accounting Standards Codification ("ASC") Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidationexcess of the ~~investee be measured at~~purchase price over the fair value ~~with changes~~of identifiable net assets acquired in business combinations. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, the Company estimates the fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In November 2015, the FASB issued ASU No. 2015-17, which amends FASB ASC Topic 740, "Income Taxes." The amendments in this guidance require that deferred income tax liabilities and assets be classified as noncurrent in the balance sheet. This guidance is effective for interim and annual reporting periods beginning after December 15, 2016, with early adoption permitted, and may be adopted prospectively or retrospectively for each period presented to reflect the new guidance. The Company early adopted this guidance as of December 31, 2015 under a retrospective method, resulting in decreases in other current assets of $291 million, other current liabilities of $3 million and noncurrent deferred income tax liabilities of $288 million as of December 31, 2014.

In April 2015, the FASB issued ASU No. 2015-03, which amends FASB ASC Subtopic 835-30, "Interest - Imputation of Interest." The amendments in this guidance require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction fromunit. If the carrying amount of ~~that debt liability instead~~a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an ~~asset. This guidance~~impairment loss. Significant judgment is ~~effective for interim~~required in estimating the fair value of the reporting unit and annual reporting periods beginning after December 15, 2015, with early adoption permitted. This guidance must be adopted retrospectively, wherein the balance sheet of each period presented should be adjusted to reflect the new guidance.performing goodwill impairment tests. The Company ~~early adopted this guidance as~~uses a variety of ~~December 31, 2015 under~~methods to estimate a ~~retrospective method, resulting in a decrease in other assets~~reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of ~~$197 million, BHE senior debt~~estimated future cash flows; multiples of ~~$50 million~~earnings; and ~~subsidiary debt of $147 million as of December 31, 2014.~~

an appropriate discount rate. In ~~May 2014,~~estimating future cash flows, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitativeCompany incorporates current market information, ~~regarding the nature and amount of revenues arising from contracts with customers,~~ as well as ~~other information about~~historical factors. As such, the determination of fair value incorporates significant ~~judgments~~unobservable inputs. During 2017, 2016 and ~~estimates used in recognizing revenues from contracts with customers. In August~~ 2015, the ~~FASB issued ASU No. 2015-14,~~Company did not record any material goodwill impairments.

The Company records goodwill adjustments for (a) the tax benefit associated with the excess of tax-deductible goodwill over the reported amount of goodwill and (b) changes to the purchase price allocation prior to the end of the measurement period, which ~~defers the effective date of ASU No. 2014-09~~is not to exceed one year ~~to interim and annual reporting periods beginning after December 15, 2017. This guidance may be adopted retrospectively or under a modified retrospective method where~~from the cumulative effect is recognized at the date of initial application. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.acquisition date.

In January 2014, the FASB issued ASU No. 2014-05, which amends FASB ASC Topic 853, "Service Concession Arrangements" ("ASC 853"). The amendments in this guidance require an entity to not account for service concession arrangements as a lease and should also not recognize them as property, plant and equipment. This guidance is effective for interim and annual reporting periods beginning after December 15, 2014. The Company adopted this guidance effective January 1, 2015 under a modified retrospective method where the cumulative effect is recognized at the date of initial application. The adoption resulted in the establishment of a financial asset with a related recognition of interest income, the elimination of a portion of previously recognized property, plant and equipment, the elimination of recognizing guaranteed water and energy delivery fees in operating revenue and increases to retained earnings attributable to the Company of $56 million and noncontrolling interests of $11 million.Revenue Recognition

~~125~~

~~(3) Business Acquisitions~~

BHE owns a highly diversified portfolio of businesses comprised primarily of regulated utilities. Consistent with BHE's strategy to grow and further diversify through a disciplined acquisition approach, the Company closed on several acquisitions during 2015, 2014 and 2013.

AltaLink

~~Transaction Description~~AltaLink's primary source of operating revenue is the AESO, an entity rated AA- by Standard and Poor's. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations would significantly impair AltaLink's ability to meet its existing and future obligations. Total operating revenue for AltaLink was $699 million for the year ended December 31, 2017.

~~On December 1, 2014,~~ BHE ~~completed its acquisition~~Renewables

BHE Renewables owns independent power projects in the United States and the Philippines that generally have separate project financing agreements. These projects source of ~~AltaLink~~operating revenue is derived primarily from long-term power purchase agreements with single customers, primarily utilities, which expire between 2017 and ~~AltaLink became an indirect wholly owned subsidiary of BHE ("AltaLink Transaction"). Under the terms~~2040. Because of the ~~Share Purchase Agreement, dated May 1, 2014, among BHE and SNC-Lavalin Group Inc. ("SNC-Lavalin"), BHE paid C$3.1 billion (US$2.7 billion) in cash to SNC-Lavalin for 100%~~dependence generally from a single customer at each project, any material failure of the ~~equity interests~~customer to fulfill its obligations would significantly impair that project's ability to meet its existing and future obligations. Total operating revenue for BHE Renewables was $838 million for the year ended December 31, 2017.

Other Energy Business

MidAmerican Energy Services, LLC ("MES") is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with financial institutions and other market participants. Credit risk may be concentrated to the extent that MES' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MES analyzes the financial condition of ~~AltaLink. BHE funded~~each significant wholesale counterparty, establishes limits on the ~~total purchase price with $1.5 billion~~amount of ~~junior subordinated debentures issued~~unsecured credit to be extended to each counterparty and ~~sold to subsidiaries~~evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, MES enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, MES exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

As of December 31, 2017, MES' aggregate credit exposure from energy related transactions, based on settlement and mark-to-market exposures, net of collateral, was not material.


Item 8.	Financial Statements and Supplementary Data



Report of Independent Registered Public Accounting Firm		115

Consolidated Balance Sheets		116

Consolidated Statements of Operations		118

Consolidated Statements of Comprehensive Income		119

Consolidated Statements of Changes in Equity		120

Consolidated Statements of Cash Flows		121

Notes to Consolidated Financial Statements		122

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Berkshire Hathaway Energy Company

Des Moines, Iowa

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Berkshire Hathaway ~~$1.0 billion borrowed under its commercial paper program~~Energy Company and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, changes in equity, and cash ~~on hand.~~flows for each of the three years in the period ended December 31, 2017, and the related notes and the schedules listed in the Index at Item 15(a)(ii) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

~~ALP~~Basis for Opinion


/s/	Deloitte & Touche LLP

Des Moines, Iowa

February 23, 2018

We have served as the Company's auditor since 1991.

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in millions)



	As of December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	935	$	721
Restricted cash and short-term investments	327		211
Trade receivables, net	2,014		1,751
Income taxes receivable	334		—
Inventories	888		925
Mortgage loans held for sale	465		359
Other current assets	815		706
Total current assets	5,778		4,673

Property, plant and equipment, net	65,871		62,509
Goodwill	9,678		9,010
Regulatory assets	2,761		4,307
Investments and restricted cash and investments	4,872		3,945
Other assets	1,248		996

Total assets	$	90,208	$	85,440

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(Amounts in millions)



	As of December 31,
	2017			2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,519		$	1,317
Accrued interest	488			454
Accrued property, income and other taxes	354			389
Accrued employee expenses	274			261
Short-term debt	4,488			1,869
Current portion of long-term debt	3,431			1,006
Other current liabilities	1,049			1,017
Total current liabilities	11,603			6,313

BHE senior debt	5,452			7,418
BHE junior subordinated debentures	100			944
Subsidiary debt	26,210			26,748
Regulatory liabilities	7,309			2,933
Deferred income taxes	8,242			13,879
Other long-term liabilities	2,984			2,742
Total liabilities	61,900			60,977

Commitments and contingencies (Note 16)

Equity:
BHE shareholders' equity:
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding	—			—
Additional paid-in capital	6,368			6,390
Retained earnings	22,206			19,448
Accumulated other comprehensive loss, net	(398		)	(1,511		)
Total BHE shareholders' equity	28,176			24,327
Noncontrolling interests	132			136
Total equity	28,308			24,463

Total liabilities and equity	$	90,208		$	85,440

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in millions)



	Years Ended December 31,
	2017			2016			2015
Operating revenue:
Energy	$	15,171		$	14,621		$	15,354
Real estate	3,443			2,801			2,526
Total operating revenue	18,614			17,422			17,880

Operating costs and expenses:
Energy:
Cost of sales	4,518			4,315			5,079
Operating expense	3,773			3,707			3,732
Depreciation and amortization	2,580			2,560			2,399
Real estate	3,229			2,589			2,342
Total operating costs and expenses	14,100			13,171			13,552

Operating income	4,514			4,251			4,328

Other income (expense):
Interest expense	(1,841		)	(1,854		)	(1,904		)
Capitalized interest	45			139			74
Allowance for equity funds	76			158			91
Interest and dividend income	111			120			107
Other, net	(398		)	36			39
Total other income (expense)	(2,007		)	(1,401		)	(1,593		)

Income before income tax (benefit) expense and equity (loss) income	2,507			2,850			2,735
Income tax (benefit) expense	(554		)	403			450
Equity (loss) income	(151		)	123			115
Net income	2,910			2,570			2,400
Net income attributable to noncontrolling interests	40			28			30
Net income attributable to BHE shareholders	$	2,870		$	2,542		$	2,370

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Amounts in millions)



	Years Ended December 31,
	2017		2016			2015

Net income	$	2,910	$	2,570		$	2,400

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $9, $11 and $17	64		(9		)	52
Foreign currency translation adjustment	546		(583		)	(680		)
Unrealized gains (losses) on available-for-sale securities, net of tax of $270, $(19) and $129	500		(30		)	225
Unrealized gains (losses) on cash flow hedges, net of tax of $(7), $13 and $(7)	3		19			(11		)
Total other comprehensive income (loss), net of tax	1,113		(603		)	(414		)

Comprehensive income	4,023		1,967			1,986
Comprehensive income attributable to noncontrolling interests	40		28			30
Comprehensive income attributable to BHE shareholders	$	3,983	$	1,939		$	1,956

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Amounts in millions)



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

Balance, December 31, 2014	77	$	—	$	6,423		$	14,513		$	(494	)	$	131		$	20,573
Adoption of ASC 853	—	—		—			56			—			11			67
Net income	—	—		—			2,370			—			18			2,388
Other comprehensive loss	—	—		—			—			(414		)	—			(414		)
Distributions	—	—		—			—			—			(21		)	(21		)
Common stock purchases	—	—		(3		)	(33		)	—			—			(36		)
Other equity transactions	—	—		(17		)	—			—			(5		)	(22		)
Balance, December 31, 2015	77	—		6,403			16,906			(908		)	134			22,535
Net income	—	—		—			2,542			—			14			2,556
Other comprehensive loss	—	—		—			—			(603		)	—			(603		)
Distributions	—	—		—			—			—			(20		)	(20		)
Other equity transactions	—	—		(13		)	—			—			8			(5		)
Balance, December 31, 2016	77	—		6,390			19,448			(1,511		)	136			24,463
Net income	—	—		—			2,870			—			22			2,892
Other comprehensive income	—	—		—			—			1,113			—			1,113
Distributions	—	—		—			—			—			(22		)	(22		)
Common stock purchases	—	—		(1		)	(18		)	—			—			(19		)
Common stock exchange	—	—		(6		)	(94		)	—			—			(100		)
Other equity transactions	—	—		(15		)	—			—			(4		)	(19		)
Balance, December 31, 2017	77	$	—	$	6,368		$	22,206		$	(398	)	$	132		$	28,308

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in millions)



	Years Ended December 31,
	2017			2016			2015
Cash flows from operating activities:
Net income	$	2,910		$	2,570		$	2,400
Adjustments to reconcile net income to net cash flows from operating activities:
Loss (gain) on other items, net	455			62			(8		)
Depreciation and amortization	2,646			2,591			2,428
Allowance for equity funds	(76		)	(158		)	(91		)
Equity loss (income), net of distributions	260			(67		)	(38		)
Changes in regulatory assets and liabilities	31			(34		)	356
Deferred income taxes and amortization of investment tax credits	19			1,090			1,265
Other, net	(2		)	(142		)	19
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(86		)	(158		)	(9		)
Derivative collateral, net	(22		)	32			(14		)
Pension and other postretirement benefit plans	(91		)	(79		)	(11		)
Accrued property, income and other taxes	(28		)	377			877
Accounts payable and other liabilities	50			(28		)	(194		)
Net cash flows from operating activities	6,066			6,056			6,980

Cash flows from investing activities:
Capital expenditures	(4,571		)	(5,090		)	(5,875		)
Acquisitions, net of cash acquired	(1,113		)	(66		)	(164		)
Increase in restricted cash and investments	(81		)	(36		)	(28		)
Purchases of available-for-sale securities	(190		)	(141		)	(144		)
Proceeds from sales of available-for-sale securities	202			191			142
Equity method investments	(368		)	(570		)	(202		)
Other, net	(12		)	(34		)	41
Net cash flows from investing activities	(6,133		)	(5,746		)	(6,230		)

Cash flows from financing activities:
Repayments of BHE senior debt and junior subordinated debentures	(2,323		)	(2,000		)	(850		)
Common stock purchases	(19		)	—			(36		)
Proceeds from subsidiary debt	1,763			2,327			2,479
Repayments of subsidiary debt	(1,000		)	(1,831		)	(1,354		)
Net proceeds from (repayments of) short-term debt	2,361			879			(421		)
Tender offer premium paid	(435		)	—			—
Other, net	(73		)	(65		)	(73		)
Net cash flows from financing activities	274			(690		)	(255		)

Effect of exchange rate changes	7			(7		)	(4		)

Net change in cash and cash equivalents	214			(387		)	491
Cash and cash equivalents at beginning of period	721			1,108			617
Cash and cash equivalents at end of period	$	935		$	721		$	1,108

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)	Organization and Operations

Berkshire Hathaway Energy Company ("BHE") is a ~~regulated~~holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The Company's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. ("NV Energy") (which primarily consists of Nevada Power Company ("Nevada Power") and Sierra Pacific Power Company ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("AltaLink") (which primarily consists of AltaLink, L.P. ("ALP")) and BHE U.S. Transmission, LLC), BHE Renewables and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). The Company, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, two interstate natural gas pipeline companies in the United States, an electric transmission business ~~headquartered~~ in ~~Calgary, Alberta.~~Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in solar, wind, geothermal and hydroelectric projects, the second largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States.

(2)Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

Use of Estimates in Preparation of Financial Statements

Accounting for the Effects of Certain Types of Regulation

PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, Northern Natural Gas, Kern River and ALP ~~owns 8,100 miles~~(the "Regulated Businesses") prepare their financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of ~~transmission lines~~regulation. Accordingly, the Regulated Businesses defer the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and ~~300 substations~~liabilities are established to reflect the impacts of these deferrals, which will be recognized in ~~Alberta~~earnings in the periods the corresponding changes in regulated rates occur.

The Company continually evaluates the applicability of the guidance for regulated operations and ~~operates~~whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Regulated Businesses' ability to recover their costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal, state and provincial levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").

Fair Value Measurements

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a ~~cost-of-service~~liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.

Cash Equivalents and Restricted Cash and Investments

Investments

Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. Realized and unrealized gains and losses on securities in a trust related to the decommissioning of nuclear generation assets are recorded as a net regulatory ~~model,~~liability since the Company expects to recover costs for these activities through regulated rates. Trading securities are carried at fair value with realized and unrealized gains and losses recognized in earnings. Held-to-maturity securities are carried at amortized cost, reflecting the ability and intent to hold the securities to maturity.

The Company utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when an investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, the Company records the investment at cost and subsequently increases or decreases the carrying value of the investment by the Company's share of the net earnings or losses and other comprehensive income (loss) ("OCI") of the investee. The Company records dividends or other equity distributions as reductions in the carrying value of the investment. Certain equity investments are presented on the Consolidated Balance Sheets net of related investment tax credits.

Allowance for Doubtful Accounts

Trade receivables are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on the Company's assessment of the collectibility of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. As of December 31, 2017 and 2016, the allowance for doubtful accounts totaled $40 million and $33 million, respectively, and is included in trade receivables, net on the Consolidated Balance Sheets.

Derivatives

Inventories

Inventories consist mainly of fuel, which includes coal stocks, stored gas and fuel oil, totaling $352 million and $402 million as of December 31, 2017 and 2016, respectively, and materials and supplies totaling $536 million and $523 million as of December 31, 2017 and 2016, respectively. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using the average cost method. The cost of stored gas is determined using either the last-in-first-out ("LIFO") method or the lower of average cost or market. With respect to inventories carried at LIFO cost, the replacement cost would be $22 million and $27 million higher as of December 31, 2017 and 2016, respectively.

Property, Plant and Equipment, Net

General

Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Regulated Businesses to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a ~~forward test year, overseen~~cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.

Asset Retirement Obligations

The ~~transaction was approved by both the SNC-Lavalin and BHE boards~~Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of ~~directors in May 2014. In June 2014,~~ an Advance Ruling Certificate was received from the Commissioner of Competition, providing clearance for the AltaLink acquisition. In July 2014, the Canadian Minister of Industry approved the transaction under the Investment Canada Act, determining that the AltaLink Transaction constitutes a net benefit to Canada. In November 2014, approval by the AUC was received. In connection with the approval of the transaction under the Investment Canada Act, various commitments were madeasset. The Company's AROs are primarily related to the ~~Canadian Minister~~decommissioning of ~~Industry. The commitments included, among others:~~

~~AltaLink will remain locally managed~~nuclear generating facilities and ~~incorporated under the laws of Canada,~~obligations associated with its ~~headquarters, senior management team~~other generating facilities and ~~operations located in Alberta.~~

~~AltaLink's independent board of directors will continue to be comprised of a majority of Canadians.~~

~~There will be no reductions in employment levels at AltaLink as a result of the transaction.~~

Reinvest 100% of AltaLink’s earnings back into AltaLink, elsewhere in Alberta or other regions of Canada for five years. This commitment will support AltaLink’s C$2.7 billion investment in Alberta's energy infrastructure planned over the next three years, subject to continued oversight by the AUC and the Alberta Electric System Operator.

~~Spend at least C$27 million to pursue joint development opportunities with Canadian partners in Canada and the United States.~~

~~Invest at least C$3 million of new funds to support Alberta-based academic programs focused on energy-related topics, cultural organizations and community-based programs.~~

~~Maintain AltaLink's commitment to provide C$3 million over three years in community and charitable contributions across Alberta.~~

~~Share best practices with AltaLink on safety, customer satisfaction, cybersecurity and supplier diversity at no cost.~~

~~Provide opportunities for Albertan and other Canadian companies to supply products and services to other BHE businesses.~~

Included in BHE's Consolidated Statement of Operations within the BHE Transmission reportable segment for the year ended December 31, 2014 is $13 million of net income as a result of including AltaLink's revenue and expenses from December 1, 2014. Additionally, BHE incurred $3 million of direct transaction costs associated with the AltaLink Transaction that are included in operating expense on the Consolidated Statement of Operations for the year ended December 31, 2014.

~~126~~

~~Allocation of Purchase Price~~

The operations of ALP are subject to the rate-setting authority of the AUC and are accounted for pursuant to GAAP, including the authoritative guidance for regulated operations. The rate-setting and cost recovery provisions establish rates on a cost-of-service basis designed to allow ALP an opportunity to recover its costs of providing service and a return on its investment in rate base. Except for certain assets not currently in rates, the fair value of ALP's assets acquired and liabilities assumed subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, no fair value adjustments have been reflected related to these amounts.

offshore natural gas pipelines. The fair value of ~~AltaLink's assets acquired~~an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and ~~liabilities assumed not subject~~is added to the rate-setting provisions discussed above was determined using an income approach. This approach is based on significant estimates and assumptions, including Level 3 inputs, which are judgmental in nature. The estimates and assumptions include the projected timing andcarrying amount of ~~future~~the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows ~~discount~~(with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For the Regulated Businesses, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates ~~reflecting the risk inherent in the future cash flows and future market prices.~~to satisfy such liabilities is recorded as a regulatory asset or liability.

AltaLink's non-regulated assets acquired and liabilities assumed consist principally of AltaLink Investments, L.P.'s and AltaLink Holdings, L.P.'s senior bonds and debentures. The fair value of these liabilities was determined based on quoted market prices.

Impairment

The ~~following table summarizes~~Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the ~~fair values~~carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the ~~assets acquired and liabilities assumed as~~asset plus the residual value from the ultimate disposal exceeds the carrying value of the ~~acquisition date (in millions):~~

Fair Value

Current assets, including cash and cash equivalents of $15 $ 174
Property, plant and equipment 5,610
Goodwill 1,744
Other long-term assets 141
Total assets 7,669

Current liabilities, including current portion of long-term debt of $79 866
Subsidiary debt, less current portion 3,772
Deferred income taxes 85
Other long-term liabilities 218
Total liabilities 4,941

Net assets acquired $ 2,728

~~During 2015,~~asset. If the ~~Company made revisions~~carrying value exceeds the estimated recoverable amounts, the asset is written down to ~~certain assets not currently in rates,~~ the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of ~~certain contracts and certain contingencies based upon~~Operations. The impacts of regulation are considered when evaluating the ~~receipt~~carrying value of additional information about the facts and circumstances that existed as of the acquisition date. Provisional amounts were subject to further revision for up to 12 months following the acquisition date until the related valuations were completed.regulated assets.

Goodwill

~~The~~Goodwill represents the excess of the purchase price ~~paid~~over the fair value of identifiable net assets acquired in business combinations. The Company evaluates goodwill for impairment at least annually and completed its annual review as of October 31. When evaluating goodwill for impairment, the Company estimates the fair value of the reporting unit. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. In estimating future cash flows, the Company incorporates current market information, as well as historical factors. As such, the determination of fair value incorporates significant unobservable inputs. During 2017, 2016 and 2015, the Company did not record any material goodwill impairments.

Revenue Recognition

Energy Businesses

Revenue from energy business customers is recognized as electricity or natural gas is delivered or services are provided. Revenue recognized includes billed and unbilled amounts. As of December 31, 2017 and 2016, unbilled revenue was $665 million and $643 million, respectively, and is included in trade receivables, net on the Consolidated Balance Sheets. Rates for energy businesses are established by regulators or contractual arrangements. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

Real Estate Commission Revenue, Mortgage Revenue and Franchise Royalty Fees

Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title and escrow closing fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing. Mortgage fee revenue consists of amounts earned related to application and underwriting fees, and fees on canceled loans. Fees associated with the origination and acquisition of mortgage loans are recognized as earned. Franchise royalty fees are based on a percentage of commissions earned by franchisees on real estate sales and are recognized when the sale closes.

Unamortized Debt Premiums, Discounts and Debt Issuance Costs

Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

Foreign Currency

Income Taxes

Berkshire Hathaway includes the Company in its consolidated United States federal income tax return. The Company's provision for income taxes has been computed on a stand-alone basis.

Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. On December 22, 2017, the Tax Cuts and Jobs Act ("2017 Tax Reform") was signed into law which, among other items, reduces the federal corporate tax rate from 35% to 21%. Changes in deferred income tax assets and liabilities that are associated with income tax benefits and expense for the federal tax rate change from 35% to 21%, certain property-related basis differences and other various differences that the Company's regulated businesses deems probable to be passed on to their customers in most state and provincial jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated ~~fair values~~useful lives of the ~~identifiable assets acquired and liabilities assumed totaled $1.7 billion and is reflected~~related properties or as goodwill in the BHE Transmission reportable segment. The goodwill reflects the value for the opportunities to invest in Alberta's electric transmission infrastructure and to develop solutions to meet the long-term energy needs of Alberta. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. None of the goodwill recognized is deductible for income tax purposes, and no deferred income taxes have been recorded related to the goodwill.

~~127~~

~~Pro Forma Financial Information~~prescribed by various regulatory jurisdictions.

The ~~following unaudited pro forma financial information reflects~~2017 Tax Reform also creates a one-time repatriation tax on the ~~consolidated results~~Company's undistributed foreign corporations' post-1986 accumulated earnings and profits. Therefore, the cumulative undistributed foreign earnings were deemed repatriated to the United States as of ~~operations of BHE, non-recurring transaction costs incurred by both BHE~~December 31, 2017. The Company currently does not believe the deemed repatriation has altered the Company's existing assertion that undistributed earnings will be reinvested indefinitely; however, the Company periodically evaluates its capital requirements and ~~AltaLink during 2014 and the amortization~~that conclusion could change. As a result of the ~~purchase price adjustments each assuming~~2017 Tax Reform, future undistributed earnings are not expected to be subject to tax in the ~~acquisition had taken place on January 1, 2013 (in millions):~~

2014 2013

Operating revenue $ 17,888
$ 13,130

Net income attributable to BHE shareholders $ 2,155
$ 1,667
United States.

In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory jurisdictions. The ~~unaudited pro forma financial information~~Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has ~~been presented~~made adequate provisions for ~~illustrative purposes only and~~these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not ~~necessarily indicative of~~expected to have a material impact on the Company's consolidated ~~results of operations that would have been achieved or~~financial results. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the ~~future consolidated results of operations of BHE.~~

~~NV Energy, Inc.~~

~~Transaction Description~~

~~On December 19, 2013, BHE completed the merger contemplated by the Agreement~~Consolidated Balance Sheets. Estimated interest and Plan of Merger dated May 29, 2013, among BHE, Silver Merger Sub, Inc. ("Merger Sub"), BHE's wholly-owned subsidiary, and NV Energy, Inc. ("NV Energy"), whereby Merger Sub was merged into NV Energy and NV Energy became an indirect wholly-owned subsidiary of BHE ("NV Energy Transaction"). BHE funded the total purchase price of $5.6 billion, or $23.75 per share for 100% of NV Energy’s outstanding common stock, by issuing $1.0 billion of common stock on December 19, 2013, issuing $2.6 billion of junior subordinated debenturespenalties, if any, related to ~~certain Berkshire Hathaway subsidiaries on December 19, 2013, and using $2.0 billion of cash, including certain proceeds from BHE's $2.0 billion senior debt issuance on November 8, 2013.~~

NV Energy owns two regulated public utilities, Nevada Power and Sierra Pacific (together, the "Nevada Utilities"), that provide electric service to 1.2 million regulated retail electric customers and 0.2 million regulated retail natural gas customers in Nevada.

~~Included in BHE's Consolidated Statement of Operations within the NV Energy reportable segment for the year ended December 31, 2013~~uncertain tax positions are costs totaling $38 million, consisting of $22 million for amounts payable under NV Energy's change in control policy and $16 million for donations to NV Energy's charitable foundation, and a $20 million one-time bill credit to retail customers included as a ~~reduction to operating revenue. Additionally, BHE incurred $5 million~~component of ~~direct transaction costs associated with the NV Energy Transaction that are included in operating~~income tax expense on the Consolidated ~~Statement~~Statements of ~~Operations for the year ended December 31, 2013.~~

~~Pro Forma Financial Information~~

The following unaudited pro forma financial information reflects the consolidated results of operations of BHE, non-recurring transaction, integration and other costs incurred by both BHE and NV Energy during 2013 totaling $74 million, after-tax, a one-time bill credit to retail customers of $13 million, after-tax, and the amortization of the purchase price adjustments each assuming the acquisition had taken place on January 1, 2012 (in millions):

2013

Operating revenue $ 15,561

Net income attributable to BHE shareholders $ 1,867

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of BHE.Operations.

~~128~~

~~Other~~New Accounting Pronouncements

In February 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2018-02, which amends FASB Accounting Standards Codification ("ASC") Topic 220, "Income Statement - Reporting Comprehensive Income." The amendments in this guidance require a reclassification from accumulated other comprehensive income to retained earnings for the stranded tax effects that were created from the enactment of the 2017 Tax Reform. The reclassification is the difference between the historical income tax rates and the enacted rate for the items previously recorded in accumulated other comprehensive income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted retrospectively to each period(s) in which the effect of the change in the 2017 Tax Reform is recognized. Considering the significant components of the Company's accumulated other comprehensive income relate to (a) unrecognized amounts on retirement benefits of foreign pension plans and (b) unrealized gains on available-for-sale securities, which were reclassified as required by ASU No. 2016-01 that was adopted on January 1, 2018, the adoption of ASU No. 2018-02 will not have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In August 2017, the FASB issued ASU No. 2017-12, which amends FASB ASC Topic 815, "Derivatives and Hedging." The amendments in this guidance update the hedge accounting model to enable entities to better portray the economics of their risk management activities in the financial statements, expands an entity's ability to hedge non-financial and financial risk components and reduces complexity in fair value hedges of interest rate risk. In addition, it eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be presented in the same income statement line as the hedged item and also eases certain documentation and assessment requirements. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach by means of a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In March 2017, the FASB issued ASU No. 2017-07, which amends FASB ASC Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. The Company adopted this guidance effective January 1, 2018 and the adoption will not have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, “Statement of Cash Flows - Overall.” The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. The Company adopted this guidance effective January 1, 2018 and the adoption will not have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. The Company adopted this guidance effective January 1, 2018 and the adoption will not have a material impact on its Consolidated Financial Statements.

In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. In January 2018, the FASB issued ASU No. 2018-01 that provides for an optional transition practical expedient allowing companies to not have to evaluate existing land easements if they were not previously accounted for under ASC Topic 840, "Leases." This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. The Company plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The Company adopted this guidance effective January 1, 2018 with a cumulative-effect increase to retained earnings of $1,085 million and a corresponding decrease to AOCI.

In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company adopted this guidance effective January 1, 2018 under the modified retrospective method and the adoption will not have an impact on its Consolidated Financial Statements but will increase the disclosures included within Notes to Consolidated Financial Statements. The timing and amount of revenue recognized after adoption of the new guidance will not be different than before as a majority of revenue is recognized when the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date. The Company's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by regulated energy, nonregulated energy and real estate, with further disaggregation of regulated energy by customer class and line of business and real estate by line of business.

(3) Business Acquisitions

In 2017, the Company completed various ~~other~~ acquisitions totaling ~~$164 million.~~$1.1 billion, net of cash acquired. The purchase ~~prices were~~price for each acquisition was allocated to the assets acquired and liabilities assumed, which primarily related to residential real estate brokerage businesses, development and construction costs for the 110-megawatt Alamo 6 and the 50-megawatt Pearl solar projects, and the remaining 25% interest in the Silverhawk natural gas-fueled generation facility at Nevada Power. As a result of the various acquisitions, the Company acquired assets of $1.1 billion, assumed liabilities of $487 million and recognized goodwill of $508 million.

In 2016 and 2015, the Company completed various acquisitions totaling $66 million and $164 million, net of cash acquired, respectively. The purchase price for each ~~acquisition.~~acquisition was allocated to the assets acquired and liabilities assumed. The assets acquired consisted of property, plant and equipment, development and construction costs for renewable projects, other working capital items, goodwill of $50 million and $33 million, respectively, and other identifiable intangible assets. The liabilities assumed totaled ~~$84 million.~~

In 2014, the Company completed various other acquisitions totaling $243 million. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related primarily to property, plant and equipment of $641 million, goodwill of $80 million, long-term debt of $231$54 million and ~~noncurrent deferred income tax liabilities of $170~~$84 million, for the remaining 50% interest in CE Generation, LLC ("CE Generation"), development and construction costs for the 300-megawatt ("MW") TX Jumbo Road Wind, LLC wind-powered generation project ("Jumbo Road Project") and real estate brokerage and mortgage businesses. There were no other material assets acquired or liabilities assumed.respectively.

In 2013, the Company completed various other acquisitions of residential real estate brokerage and mortgage businesses totaling $240 million. The purchase prices were allocated to the assets acquired and liabilities assumed in each acquisition. The assets acquired consisted of loans receivable and other working capital items, goodwill of $188 million and other identifiable intangible assets. The liabilities assumed totaled $271 million primarily related to mortgage lines of credit secured by the loans receivable acquired and other working capital items.

~~129~~

(4) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following as of December 31 (in millions):


	Depreciable							Depreciable
	Life	2015			2014			Life	2017			2016
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	69,248		$	64,645		5-80 years	$	74,660		$	71,536
Interstate natural gas pipeline assets	3-80 years	6,755			6,660			3-80 years	7,176			6,942
		76,003			71,305				81,836			78,478
Accumulated depreciation and amortization		(22,682		)	(21,447		)		(24,478		)	(23,603		)
Regulated assets, net		53,321			49,858				57,358			54,875

Nonregulated assets:
Independent power plants	5-30 years	4,751			4,362			5-30 years	6,010			5,594
Other assets	3-30 years	875			673			3-30 years	1,489			1,002
		5,626			5,035				7,499			6,596
Accumulated depreciation and amortization		(805		)	(839		)		(1,542		)	(1,060		)
Nonregulated assets, net		4,821			4,196				5,957			5,536

Net operating assets		58,142			54,054				63,315			60,411
Construction work-in-progress		2,627			5,194				2,556			2,098
Property, plant and equipment, net		$	60,769		$	59,248			$	65,871		$	62,509

Construction work-in-progress includes $~~2.3~~2.2 billion and $~~4.3~~1.8 billion as of December 31, ~~2015~~2017 and ~~2014~~2016, respectively, related to the construction of regulated assets.

PacifiCorp revised its depreciation rates effective January 1, 2014 based on results of a depreciation study approved by its state regulatory commissions. The approved depreciation rates resulted in an increase in depreciation expense of $35 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013.

During the ~~third~~fourth quarter of ~~2013,~~2016, MidAmerican Energy revised its electric and gas depreciation rates ~~for certain electric generating facilities~~ based on the results of a new depreciation ~~study. The new rates reflect~~study, the most significant impact of which was longer estimated useful lives for certain wind-powered ~~generating facilities placed in-service in 2011 and 2012 and a lower accrual rate for the cost of removal regulatory liability related to coal-fueled~~ generating facilities. The effect of this change was to reduce depreciation and amortization expense by ~~$20~~$3 million in ~~2013~~2016 and $49 million annually based on depreciable plant balances at the time of the change. Effective January 1, 2014, MidAmerican Energy revised depreciation rates for certain electric generating facilities based on the results of its 2013 Iowa electric retail rate case. The new depreciation rates reflect longer estimated useful lives for certain generating facilities. The effect of this change was to reduce depreciation and amortization expense by $50$34 million annually based on depreciable plant balances at the time of the change.

~~130~~


(5)	Jointly Owned Utility Facilities

Under joint facility ownership agreements, the Domestic Regulated Businesses, as tenants in common, have undivided interests in jointly owned generation, transmission, distribution and pipeline common facilities. The Company accounts for its proportionate share of each facility and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include the Company's share of the expenses of these facilities.

The amounts shown in the table below represent the Company's share in each jointly owned facility included in property, plant and equipment, net as of December 31, ~~2015~~2017 (dollars in millions):


					Accumulated		Construction						Accumulated		Construction
	Company		Facility In		Depreciation and		Work-in-		Company		Facility In		Depreciation and		Work-in-
	Share		Service		Amortization		Progress		Share		Service		Amortization		Progress
PacifiCorp:
Jim Bridger Nos. 1-4	67	%	$	1,289	$	566	$	83	67	%	$	1,442	$	616	$	12
Hunter No. 1	94		469		154		—		94		474		172		7
Hunter No. 2	60		293		94		—		60		297		106		1
Wyodak	80		457		198		3		80		469		216		1
Colstrip Nos. 3 and 4	10		239		128		2		10		247		131		4
Hermiston⁽¹⁾	50		177		71		1		50		180		81		1
Craig Nos. 1 and 2	19		325		213		18		19		365		231		3
Hayden No. 1	25		76		30		—		25		74		34		—
Hayden No. 2	13		30		18		7		13		43		21		—
Foote Creek	79		39		24		—		79		40		26		—
Transmission and distribution facilities	Various		577		178		46		Various		794		238		67
Total PacifiCorp			3,971		1,674		160				4,425		1,872		96
MidAmerican Energy:
Louisa No. 1	88	%	757		405		7		88	%	807		432		8
Quad Cities Nos. 1 and 2⁽²⁾⁽¹⁾	25		672		340		27		25		698		387		20
Walter Scott, Jr. No. 3	79		608		297		6		79		617		316		8
Walter Scott, Jr. No. 4⁽³⁾⁽²⁾	60		448		91		—		60		456		112		1
George Neal No. 4	41		305		148		1		41		307		159		1
Ottumwa No. 1	52		554		184		3		52		567		206		40
George Neal No. 3	72		415		153		—		72		425		183		7
Transmission facilities	Various		245		83		2		Various		249		87		1
Total MidAmerican Energy			4,004		1,701		46				4,126		1,882		86
NV Energy:
Navajo	11	%	203		141		1		11	%	220		152		—
Silverhawk	75		247		58		2
Valmy	50		382		209		2		50		388		233		1
Transmission facilities	Various		224		39		1		Various		206		45		—
Total NV Energy			1,056		447		6				814		430		1
BHE Pipeline Group - common facilities	Various		285		158		1		Various		286		169		—
Total			$	9,316	$	3,980	$	213			$	9,651	$	4,353	$	183


(1)	~~PacifiCorp has contracted to purchase the remaining~~ ~~50%~~ ~~of the output of the Hermiston generating facility.~~


~~(2)~~	Includes amounts related to nuclear fuel.


~~(3)~~(2)	Facility in-service and accumulated depreciation and amortization amounts are net of credits applied under Iowa revenue sharing arrangements totaling $319 million and $6781 million, respectively.

~~131~~

(6) Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future regulated rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):


	Weighted					Weighted
	Average					Average
	Remaining Life	2015		2014		Remaining Life	2017		2016

Deferred income taxes⁽¹⁾	26 years	$	1,577	$	1,468
Employee benefit plans⁽²⁾	9 years	778		747
Asset disposition costs⁽³⁾	Various	307		329
Employee benefit plans⁽¹⁾						16 years	$	675	$	816
Asset disposition costs						Various	387		281
Asset retirement obligations						13 years	334		301
Abandoned projects						3 years	156		159
Deferred operating costs						13 years	147		97
Deferred income taxes⁽²⁾						Various	143		1,754
Unrealized loss on regulated derivative contracts						4 years	122		154
Unamortized contract values						6 years	89		98
Deferred net power costs	1 year	140		277		2 years	58		38
Asset retirement obligations	8 years	281		239
Unrealized loss on regulated derivative contracts	5 years	250		223
Abandoned projects	5 years	136		159
Unamortized contract values	8 years	110		123
Other	Various	706		688		Various	839		759
Total regulatory assets		$	4,285	$	4,253		$	2,950	$	4,457

Reflected as:
Current assets		$	130	$	253		$	189	$	150
Noncurrent assets		4,155		4,000			2,761		4,307
Total regulatory assets		$	4,285	$	4,253		$	2,950	$	4,457


(1)	Amounts primarily represent income tax benefits related to state accelerated tax depreciation and certain property-related basis differences that were previously flowed through to customers and will be included in regulated rates when the temporary differences reverse.


~~(2)~~	Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

~~(3)~~(2)

~~Includes amounts established as a result of~~Amounts primarily represent income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the Utah mine disposition discussed below for the net property, plant and equipment not considered probable of disallowance and for the portion of losses associated with the assets held for sale, UMWA 1974 Pension Plan withdrawal and closure costs incurred to date considered probable of recovery.temporary differences reverse.

The Company had regulatory assets not earning a return on investment of ~~$2.3~~$1.1 billion and ~~$2.6~~$2.8 billion as of December 31, ~~2015~~2017 and ~~2014~~2016, respectively.

~~132~~

Regulatory Liabilities

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):


	Weighted					Weighted
	Average					Average
	Remaining Life	2015		2014		Remaining Life	2017		2016

Cost of removal⁽¹⁾	28 years	$	2,167	$	2,215
Deferred income taxes⁽¹⁾						Various	$	4,143	$	25
Cost of removal⁽²⁾						27 years	2,349		2,242
Levelized depreciation						22 years	332		244
Asset retirement obligations						35 years	177		122
Impact fees						6 years	89		90
Employee benefit plans⁽³⁾						11 years	69		25
Deferred net power costs	2 years	206		—		2 years	8		64
Asset retirement obligations	22 years	147		169
Levelized depreciation	26 years	199		169
Employee benefit plans⁽²⁾	12 years	13		20
Unrealized gain on regulated derivative contracts						1 year	3		6
Other	Various	301		259		Various	341		302
Total regulatory liabilities		$	3,033	$	2,832		$	7,511	$	3,120

Reflected as:
Current liabilities		$	402	$	163		$	202	$	187
Noncurrent liabilities		2,631		2,669			7,309		2,933
Total regulatory liabilities		$	3,033	$	2,832		$	7,511	$	3,120

(1)

Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse. See Note 11 for further discussion of 2017 Tax Reform impacts.


(2)	Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.


~~(2)~~(3)	Represents amounts not yet recognized as a component of net periodic benefit cost that are to be returned to customers in future periods when recognized.

~~Utah Mine Disposition~~

Due to quality issues with the coal reserves at PacifiCorp's Deer Creek mine in Utah and rising costs at PacifiCorp's wholly owned subsidiary, Energy West Mining Company, PacifiCorp believes the Deer Creek coal reserves are no longer able to be economically mined. As a result, in December 2014, PacifiCorp filed applications with the Utah Public Service CommissionALP General Tariff Application ("~~UPSC"~~GTA"), the Oregon Public Utility Commission ("OPUC"), the Wyoming Public Service Commission ("WPSC") and the Idaho Public Utilities Commission ("IPUC") seeking certain approvals, prudence determinations and accounting orders to close its Deer Creek mining operations, sell certain Utah mining assets, enter into a replacement coal supply agreement, amend an existing coal supply agreement, withdraw from the United Mine Workers of America ("UMWA") 1974 Pension Plan and settle PacifiCorp's other postretirement benefit obligation for UMWA participants (collectively, the "Utah Mine Disposition").

In ~~April 2015, PacifiCorp~~November 2014, ALP filed ~~all-party settlement stipulations with~~a GTA requesting the ~~UPSC and the WPSC finding that the decision~~Alberta Utilities Commission ("AUC") to ~~enter into the Utah Mine Disposition transaction was prudent and in the public interest. The UPSC approved the stipulation in April~~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 ~~WPSC approved~~Alberta Electric System Operator. ALP amended the ~~stipulation~~GTA in ~~May 2015. In May~~June 2015 ~~the OPUC issued its final order concluding that the Utah Mine Disposition transaction produces net benefits~~to propose transmission tariff relief measures for customers and ~~was~~modifications to its capital structure. ALP also amended and updated the GTA in October 2015, reducing the requested revenue requirements to C$672 million for 2015 and C$704 million for 2016. 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.

The compliance filing requested the AUC to approve revenue requirements of C$599 million for 2015 and C$685 million for 2016. The decreased revenue requirements requested in the ~~public interest. The IPUC also issued an order~~compliance filing, as compared to the 2015-2016 GTA filing updated in October 2015, were primarily due to the AUC approval of ALP's proposed immediate tariff relief of C$415 million for customers for 2015 and 2016, through (i) the discontinuance of construction work-in-progress ("CWIP") in rate base and the return to allowance for funds used during construction ("AFUDC") accounting effective January 1, 2015, resulting in a C$82 million reduction of revenue requirement and the refund of C$277 million previously collected as CWIP in rate base as part of ALP's transmission tariffs during 2011-2014 less related returns of C$12 million and (ii) a change to the flow through method for calculating income taxes for 2016, resulting in further tariff relief of C$68 million.

Operating revenue for the year ended December 31, 2016, included a one-time reduction of $200 million from the 2015-2016 GTA decision received in May ~~2015, approving~~2016 at ALP. The 2015-2016 GTA decision required ALP to refund $200 million to customers in 2016 through reduced monthly billings for the ~~Utah Mine Disposition~~change from receiving cash during construction for the return on CWIP in rate base to recording allowance for borrowed and ~~ruling that~~equity funds used during construction related to construction expenditures during the 2011 to 2014 time period. This amount is offset with higher capitalized interest and allowance for equity funds in the Consolidated Statements of Operations. In addition, the decision required ALP to ~~enter into~~change to the ~~transaction was prudent and~~flow through method of recognizing income tax expense effective January 1, 2016. This change reduced operating revenue by $45 million for the year ended December 31, 2016, with offsetting impacts to income tax expense in the ~~public interest. Accordingly, in June 2015, PacifiCorp sold the specified Utah mining assets and the replacement and amended coal supply agreements became effective. Refer to Note 12 for discussion~~Consolidated Statements of the UMWA 1974 Pension Plan withdrawal and the settlement of the other postretirement benefit obligation for UMWA participants. The Deer Creek mine is currently idled and closure activities have begun.Operations.

In December 2014, PacifiCorp also filed an advice letter with the California Public Utilities Commission ("CPUC"). In July 2015, the CPUC Energy Division issued a letter requiring PacifiCorp to file a formal application for approval of the sale of certain Utah mining assets. Accordingly, in September 2015, PacifiCorp filed an application with the CPUC.

~~133~~

(7) Investments and Restricted Cash and Investments

Investments and restricted cash and investments consists of the following as of December 31 (in millions):


	2015		2014		2017		2016
Investments:
BYD Company Limited common stock	$	1,238	$	881	$	1,961	$	1,185
Rabbi trusts	380		386		441		403
Other	130		126		124		106
Total investments	1,748		1,393		2,526		1,694

Equity method investments:
Tax equity investments					1,025		741
Electric Transmission Texas, LLC	585		515		524		672
Bridger Coal Company	190		192		137		165
BHE Renewables tax equity investments	168		—
Other	160		161		148		142
Total equity method investments	1,103		868		1,834		1,720

Restricted cash and investments:
Quad Cities Station nuclear decommissioning trust funds	429		424		515		460
Solar Star and Topaz Projects	95		66
Other	129		167		348		282
Total restricted cash and investments	653		657		863		742

Total investments and restricted cash and investments	$	3,504	$	2,918	$	5,223	$	4,156

Reflected as:
Current assets	$	137	$	115	$	351	$	211
Noncurrent assets	3,367		2,803		4,872		3,945
Total investments and restricted cash and investments	$	3,504	$	2,918	$	5,223	$	4,156

Investments

BHE's investment in BYD Company Limited common stock is accounted for as an available-for-sale security with changes in fair value recognized in AOCI. Upon adoption of ASU No. 2016-01 effective January 1, 2018, all changes in fair value (whether realized or unrealized) will be recognized as gains or losses in the Consolidated Statements of Operations with a cumulative-effect increase to retained earnings as of the date of adoption totaling $1,085 million. The fair value of BHE's investment in BYD Company Limited common stock reflects a pre-tax unrealized gain of $~~1.0 billion~~1,729 million and $~~649~~953 million as of December 31, ~~2015~~2017 and ~~2014~~2016, respectively.

Rabbi trusts primarily hold corporate-owned life insurance on certain current and former key executives and directors. The Rabbi trusts were established to hold investments used to fund the obligations of various nonqualified executive and director compensation plans and to pay the costs of the trusts. The amount represents the cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value.

~~Equity Method Investments~~AltaLink

ALP, an indirect wholly owned subsidiary of BHE acquired on December 1, 2014, is a regulated electric transmission-only company headquartered in Alberta, Canada serving approximately 85% of Alberta's population. ALP connects generation plants to major load centers, cities and large industrial plants throughout its 87,000 square mile service territory, which covers a diverse geographic area including most major urban centers in central and southern Alberta. ALP's transmission facilities, consisting of approximately 8,100 miles of transmission lines and 310 substations as of December 31, 2017, are an integral part of the Alberta Integrated Electric System ("AIES").

The AIES is a network or grid of transmission facilities operating at high voltages ranging from 69kV to 500kV. The grid delivers electricity from generating units across Alberta, Canada through approximately 16,000 miles of transmission. The AIES is interconnected to British Columbia's transmission system that links Alberta with the North American western interconnected system.

ALP is a transmission facility owner within the electricity industry in Alberta and is permitted to charge a tariff rate for the use of its transmission facilities. Such tariff rates are established on a cost-of-service basis, which are designed to allow ALP an opportunity to recover its costs of providing services and to earn a reasonable return on its investments. Transmission tariffs are approved by the AUC and are collected from the AESO.

The electricity industry in Alberta consists of four principal segments. Generators sell wholesale power into the power pool operated by the AESO and through direct contractual arrangements. Alberta's transmission system or grid is composed of high voltage power lines and related facilities that transmit electricity from generating facilities to distribution networks and directly connected end-users. Distribution facility owners are regulated by the AUC and are responsible for arranging for, or providing, regulated rate and regulated default supply services to convey electricity from transmission systems and distribution-connected generators to end-use customers. Retailers can procure energy through the power pool, through direct contractual arrangements with energy suppliers or ownership of generation facilities and arrange for its distribution to end-use customers.

The AESO mandate is defined in the Electric Utilities Act and its regulations, and requires the AESO to assess both current and future needs of Alberta's interconnected electrical system. In July 2017, the AESO released the 2017 Long-Term Outlook ("LTO"), which is a forecast used as one input to guide the AESO in planning Alberta's transmission system. In January 2018, the AESO finalized and made available the 2017 Long-Term Transmission Plan ("LTP"). The 2017 LTP places increased focus on the evolving economy, policy changes and environmental initiatives, including renewable generation additions and the phase-out of coal-fueled generation whenever possible. The plan was developed with the goal of efficient utilization of existing and planned transmission systems in areas where high renewables potential exists, and timely addition of necessary new transmission developments. The AESO has forecast Alberta's electricity demand to grow at an annual rate of 0.9 percent until 2037. Future generation investments are expected to keep pace with load growth and coal-fueled generation replacements, as well as generation additions primarily through the Renewable Electricity Program. The 2017 LTP identifies 15 transmission developments across Alberta proposed over the next five years valued at approximately C$1 billion. Regulatory approval for all identified developments is still required.

BHE U.S. Transmission

BHE U.S. Transmission is engaged in various joint ventures to develop, own and operate transmission assets and is pursuing additional investment opportunities in the United States. Currently, BHE U.S. Transmission has two joint ventures with transmission assets that are operational.

BHE ~~through~~U.S. Transmission indirectly owns a ~~subsidiary, owns~~ 50% interest in ETT, along with subsidiaries of American Electric ~~Transmission Texas, LLC, which~~Power Company, Inc. ("AEP"). ETT owns and operates electric transmission assets in the ~~Electric Reliability Council~~ERCOT and, as of December 31, 2017, had total assets of $3.0 billion. ETT is regulated by the Public Utility Commission of Texas. A total of $2.9 billion of transmission projects were in-service as of December 31, 2017, with $0.2 billion of projects forecast to be completed in 2018 through 2021. ETT's transmission system includes approximately 1,200 miles of transmission lines and 36 substations as of December 31, 2017.

BHE U.S. Transmission also indirectly owns a 25% interest in Prairie Wind Transmission, LLC, a joint venture with AEP and Westar Energy, Inc., to build, own and operate a 108-mile, 345 kV transmission project in Kansas. The project cost $158 million and was fully placed in-service in November 2014.

BHE RENEWABLES

The subsidiaries comprising the BHE Renewables reportable segment own interests in several independent power projects that are in-service or under construction in the United States and in the Philippines. The following table presents certain information concerning these independent power projects as of December 31, 2017:



				Power		Facility	Net
				Purchase		Net	Owned
		Energy		Agreement	Power	Capacity	Capacity
Generating Facility	Location	Source	Installed	Expiration	Purchaser⁽¹⁾	(MW)⁽²⁾	(MW)⁽²⁾
SOLAR:
Topaz	California	Solar	2013-2014	2040	PG&E	550	550
Solar Star 1	California	Solar	2013-2015	2035	SCE	310	310
Solar Star 2	California	Solar	2013-2015	2035	SCE	276	276
Agua Caliente	Arizona	Solar	2012-2013	2039	PG&E	290	142
Community Solar Gardens⁽⁶⁾	Minnesota	Solar	2016-2017	2041-2042	(5)	74	74
Alamo 6	Texas	Solar	2017	2042	CPS	110	110
Pearl	Texas	Solar	2017	2042	CPS	50	50
						1,660	1,512
WIND:
Bishop Hill II	Illinois	Wind	2012	2032	Ameren	81	81
Pinyon Pines I	California	Wind	2012	2035	SCE	168	168
Pinyon Pines II	California	Wind	2012	2035	SCE	132	132
Jumbo Road	Texas	Wind	2015	2033	AE	300	300
Marshall	Kansas	Wind	2016	2036	MJMEC, KPP, KMEA & COIMO	72	72
Grand Prairie	Nebraska	Wind	2016	2036	OPPD	400	400
						1,153	1,153
GEOTHERMAL:
Imperial Valley Projects	California	Geothermal	1982-2000	(3)	(3)	338	338

HYDROELECTRIC:
Casecnan Project⁽⁴⁾	Philippines	Hydroelectric	2001	2021	NIA	150	128
Wailuku	Hawaii	Hydroelectric	1993	2023	HELCO	10	10
						160	138
NATURAL GAS:
Saranac	New York	Natural Gas	1994	2019	TEMUS	245	196
Power Resources	Texas	Natural Gas	1988	2018	EDF	212	212
Yuma	Arizona	Natural Gas	1994	2024	SDG&E	50	50
Cordova	Illinois	Natural Gas	2001	2019	EGC	512	512
						1,019	970

Total Available Generating Capacity						4,330	4,111

PROJECTS UNDER CONSTRUCTION:

Community Solar Gardens	Minnesota	Solar	2018	2043	(5)	24	24
Walnut Ridge	Illinois	Wind	2018	2028	USGSA	212	212
						236	236

						4,566	4,347

(1)

TransAlta Energy Marketing U.S. ("TEMUS"); EDF Energy Services, LLC ("EDF"); San Diego Gas & Electric Company ("SDG&E"); Exelon Generation Company, LLC ("EGC"); Pacific Gas and Electric Company ("PG&E"), Ameren Illinois Company ("Ameren"), Southern California Edison ("SCE"), the Philippine National Irrigation Administration ("NIA"); Hawaii Electric Light Company, Inc. ("HELCO"); Austin Energy ("AE"); Omaha Public Power District ("OPPD"); U.S. General Services Administration ("USGSA"); Missouri Joint Municipal Electric Commission ("MJMEC"); Kansas Power Pool ("KPP"); Kansas Municipal Energy Agency ("KMEA"); City of Independence, MO ("COIMO"); and CPS Energy ("CPS").

(2)

Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MW) under specified conditions. Net Owned Capacity indicates BHE Renewables' ownership of Facility Net Capacity.


(3)	The majority of the Imperial Valley Projects' Contract Capacity is currently sold to Southern California Edison Company under long-term power purchase agreements expiring in 2018 through 2026. Certain long-term power purchase agreement renewals have been entered into with other parties that begin upon the existing contracts' expiration and expire in 2039.


(4)	Under the terms of the agreement with the NIA, CalEnergy Philippines will own and operate the Casecnan project for a 20-year cooperation period which ends December 11, 2021, after which ownership and operation of the project will be transferred to the NIA at no cost on an "as-is" basis. NIA also pays CalEnergy Philippines for delivery of water pursuant to the agreement.


(5)	The power purchasers are commercial, industrial and not-for-profit organizations.


(6)	The community solar gardens project is consolidated in the table above for convenience as it consists of 74 distinct entities that each own an approximately 1 MW solar garden with independent but substantially similar terms and conditions.

Additionally, BHE Renewables has invested $1.2 billion in seven wind projects sponsored by third parties, commonly referred to as tax equity investments.

BHE Renewables' operating revenue is derived from the following business activities for the years ended December 31 (in millions):



	2017		2016		2015

Solar	52	%	49	%	52	%
Wind	17		19		14
Geothermal	19		20		23
Hydro	6		4		3
Natural gas	6		8		8
Total operating revenue	100		100	%	100	%

HOMESERVICES

HomeServices, a majority-owned subsidiary of BHE, is the second-largest residential real estate brokerage firm in the United States. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations and mortgage banking; title and closing services; property and casualty insurance; home warranties; relocation services; and other home-related services. HomeServices' real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices' operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices' owned brokerages currently operate in nearly 840 offices in 30 states and the District of Columbia with nearly 41,000 real estate agents under 42 brand names. The United States residential real estate brokerage business is subject to the general real estate market conditions, is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions. In October 2014, HomeServices acquired the remaining 50.1% of HomeServices Lending, a mortgage origination company.

In October 2012, HomeServices acquired a 66.7% interest in one of the largest residential real estate brokerage franchise networks in the United States, which offers and sells independently owned and operated residential real estate brokerage franchises. The noncontrolling interest member has the right to put the remaining 33.3% interest in the franchise business to HomeServices after March 2015 and HomeServices has the right to call the remaining 33.3% interest in the franchise business after completion and receipt of the 2017 financial statement audit at an option exercise formula based on historical financial performance.

HomeServices' franchise network currently includes over 365 franchisees in over 1,500 brokerage offices in 47 states with over 48,000 real estate agents under three brand names. In exchange for certain fees, HomeServices provides the right to use the Berkshire Hathaway HomeServices, Prudential or Real Living brand names and other related service marks, as well as providing orientation programs, training and consultation services, advertising programs and other services.

OTHER ENERGY BUSINESSES

Effective January 1, 2016, MidAmerican Energy Company transferred its nonregulated energy operations to MidAmerican Energy Services, LLC ("MES"), a subsidiary of BHE. MES is a nonregulated energy business consisting of competitive electricity and natural gas retail sales. MES' electric operations predominantly include sales to retail customers in Illinois, Texas, ~~footprint. BHE,~~Ohio, Maryland and other states that allow customers to choose their energy supplier. MES' natural gas operations predominantly include sales to retail customers in Iowa and Illinois. Electricity and natural gas are purchased from producers and third party energy marketing companies and sold directly to commercial, industrial and governmental end-users. MES does not own electricity or natural gas production assets but hedges its contracted sales obligations either with physical supply arrangements or financial products. As of December 31, 2017, MES' contracts in place for the sale of electricity totaled 19,225 GWh with a weighted average life of 2.1 years and for the sale of natural gas totaled 28,605,700 Dth with a weighted average life of 1.3 years. In addition, MES manages natural gas supplies for a number of smaller commercial end-users, which includes the sale of natural gas to these customers to meet their supply requirements. Refer to Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.

The percentages of electricity sold to MES' retail customers by state for the years ended December 31 were as follows:



	2017		2016		2015

Illinois	46	%	48	%	51	%
Ohio	23		21		18
Texas	15		13		15
Maryland	7		7		7
Other	9		11		9
	100	%	100	%	100	%

The percentages of natural gas sold to MES' customers by state for the years ended December 31 were as follows:



	2017		2016		2015

Iowa	86	%	86	%	87	%
Illinois	9		9		8
Other	5		5		5
	100	%	100	%	100	%

GENERAL REGULATION

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive governmental regulation, which significantly influences their operating environment, prices charged to customers, capital structure, costs and, ultimately, their ability to recover costs and earn a reasonable return on invested capital. In addition to the discussion contained herein regarding general regulation, refer to "Regulatory Matters" in Item 1 of this Form 10-K for further discussion regarding certain regulatory matters.

Domestic Regulated Public Utility Subsidiaries

The Utilities are subject to comprehensive regulation by various state, federal and local agencies. The more significant aspects of this regulatory framework are described below.

State Regulation

Historically, state regulatory commissions have established retail electric and natural gas rates on a cost-of-service basis, which are designed to allow a utility the opportunity to recover what each state regulatory commission deems to be the utility's reasonable costs of providing services, including a fair opportunity to earn a reasonable return on its investments based on its cost of debt and equity. In addition to return on investment, a utility's cost of service generally reflects a representative level of prudent expenses, including cost of sales, operating expense, depreciation and amortization and income and other tax expense, reduced by wholesale electricity and other revenue. The allowed operating expenses are typically based on actual historical costs adjusted for known and measurable or forecasted changes. State regulatory commissions may adjust cost of service for various reasons, including pursuant to a review of: (a) the utility's revenue and expenses during a defined test period, (b) the utility's level of investment and (c) changes in income tax laws. State regulatory commissions typically have the authority to review and change rates on their own initiative; however, they may also initiate reviews at the request of a utility, utility customers or organizations representing groups of customers. In certain jurisdictions, the utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.

The retail electric rates of the Utilities are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. The Utilities have established energy cost adjustment mechanisms and other cost recovery mechanisms in certain states, which help mitigate their exposure to changes in costs from those assumed in establishing base rates.

With certain limited exceptions, the Utilities have an exclusive right to serve retail customers within their service territories and, in turn, have an obligation to provide service to those customers. In some jurisdictions, certain classes of customers may choose to purchase all or a portion of their energy from alternative energy suppliers, and in some jurisdictions retail customers can generate all or a portion of their own energy. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electricity distribution services to all residential and nonresidential customers within its allocated service territory; however, nonresidential customers have the right to choose an alternative provider of energy supply. The impact of this right on PacifiCorp's consolidated financial results has not been material. In Washington, state law does not provide for exclusive service territory allocation. PacifiCorp's service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the WUTC. In Illinois, state law has established a competitive environment so that all Illinois customers are free to choose their retail service supplier. For customers that choose an alternative retail energy supplier, MidAmerican Energy continues to have an ongoing obligation to deliver the supplier's energy to the retail customer. MidAmerican Energy bills the retail customer for such delivery services. MidAmerican Energy also has an obligation to serve customers at regulated cost-based rates and has a continuing obligation to serve customers who have not selected a competitive electricity provider. The impact of this right on MidAmerican Energy's financial results has not been material. In Nevada, state law allows retail electric customers with an average annual load of one MW or more to file a letter of intent and application with the PUCN to acquire electric energy and ancillary services from another energy supplier. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN to meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Nevada Utilities, the departure must not burden the Nevada Utilities with increased costs or cause any remaining customers to pay increased costs and the departing customers must pay their portion of any deferred energy balances, all as determined by the PUCN. Also, the Utilities and the state regulatory commissions are individually evaluating how best to integrate private generation resources into their service and rate design, including considering such factors as maintaining high levels of customer safety and service reliability, minimizing adverse cost impacts and fairly allocating costs among all customers.

Also in Nevada, large natural gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the incentive natural gas rate tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose its source of natural gas. In addition, natural gas customers using greater than 1,000 therms per day have the ability to secure their own natural gas supplies under the gas transportation tariff.

PacifiCorp

In addition to recovery through base rates, PacifiCorp also achieves recovery of certain costs through various adjustment mechanisms as summarized below.



State Regulator	Base Rate Test Period	Adjustment Mechanism
UPSC	Forecasted or historical with known and measurable changes⁽¹⁾	EBA under which 100% (beginning in June 2016) of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Wheeling revenue is also included in the mechanism. Prior to June 2016, the amount deferred was 70% of the difference as noted above.

		Balancing account to provide for 100% recovery or refund of the difference between the level of REC revenues included in base rates and actual REC revenues after adjusting for a REC incentive authorized by the UPSC.

		Recovery mechanism for single capital investments that in total exceed 1% of existing rate base when a general rate case has occurred within the preceding 18 months.

OPUC	Forecasted	PCAM under which 90% of the difference between forecasted net variable power costs and production tax credits established under the annual TAM and actual net variable power costs and production tax credits is deferred and reflected in future rates. The difference between the forecasted and actual net variable power costs and production tax credits must fall outside of an established asymmetrical deadband range and is also subject to an earnings test.

		Annual TAM based on forecasted net variable power costs and production tax credits. Production tax credits were not included in forecasted net variable power costs prior to 2017.

		Renewable Adjustment Clause to recover the revenue requirement of new renewable resources and associated transmission costs that are not reflected in general rates.

		Balancing account for proceeds from the sale of RECs.

WPSC	Forecasted or historical with known and measurable changes⁽¹⁾	ECAM under which 70% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Chemical costs and start-up fuel costs are also included in the mechanism starting in 2016.

		REC and sulfur dioxide revenue adjustment mechanism to provide for recovery or refund of 100% of any difference between actual REC and sulfur dioxide revenues and the level in rates.

WUTC	Historical with known and measurable changes	PCAM under which the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates after applying a $4 million deadband for positive or negative net power cost variances. For net power cost variances between $4 million and $10 million, amounts to be recovered from customers are allocated 50/50 and amounts to be credited to customers are allocated 75/25 (customers/PacifiCorp). Positive or negative net power cost variances in excess of $10 million are allocated 90/10 (customers/PacifiCorp).

		Deferral mechanism of costs for up to 24 months of new base load generation resources and eligible renewable resources and related transmission that qualify under the state's emissions performance standard and are not reflected in base rates.

		REC revenue tracking mechanism to provide credit of 100% of Washington-allocated REC revenues.

		Decoupling mechanism under which the difference between actual annual revenues and authorized revenues per customer is deferred and reflected in future rates, subject to an earnings test. To trigger a rate adjustment, the deferral balance must exceed plus or minus 2.5% of the authorized revenue at the end of each deferral period by rate class. Rate adjustments must not exceed a surcharge of 5% of the actual normalized revenue by class.

IPUC	Historical with known and measurable changes	ECAM under which 90% of the difference between base net power costs set during a general rate case and actual net power costs is deferred and reflected in future rates. Also provides for recovery or refund of 100% of the difference between the level of REC revenues included in base rates and actual REC revenues and differences in actual production tax credits compared to the amount in base rates.

CPUC	Forecasted	PTAM for major capital additions that allows for rate adjustments outside of the context of a traditional general rate case for the revenue requirement associated with capital additions exceeding $50 million on a total-company basis. Filed as eligible capital additions are placed into service.

		ECAC that allows for an annual update to actual and forecasted net power costs.

		PTAM for attrition, a mechanism that allows for an annual adjustment to costs other than net power costs.


(1)	PacifiCorp has relied on both historical test periods with known and measurable adjustments, as well as forecasted test periods.

MidAmerican Energy

Iowa law also permits rate-regulated utilities to seek ratemaking principles with the IUB prior to the construction of certain types of new generating facilities. Pursuant to this law, MidAmerican Energy has applied for and obtained IUB ratemaking principles orders for a 484-MW (MidAmerican Energy's share) coal-fueled generating facility, a 495-MW combined cycle natural gas-fueled generating facility and 6,048 MW (nominal ratings) of wind-powered generating facilities, including 1,666 MW (nominal ratings) under construction, as of December 31, 2017. These ratemaking principles established cost caps for the projects and authorized a fixed rate of return on equity for the respective generating facilities over the regulatory life of the facilities in any future Iowa rate proceeding. As of December 31, 2017, the generating facilities in service totaled $5.9 billion, or 42%, of MidAmerican Energy's regulated property, plant and equipment, net and were subject to these ratemaking principles at a weighted average return on equity of 11.7% with a weighted average remaining life of 31 years.

Under its current Iowa, Illinois and South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in electric energy costs for its retail electric sales through fuel, or energy, cost adjustment mechanisms. The Iowa mechanism also includes production tax credits associated with wind-powered generation placed in-service prior to 2013, except for production tax credits earned by repowered facilities, which totaled 414 MW as of December 31, 2017. Eligibility for production tax credits associated with MidAmerican Energy's earliest projects began expiring in 2014. Additionally, MidAmerican Energy has transmission adjustment clauses to recover certain transmission charges related to retail customers in all jurisdictions. The adjustment mechanisms reduce the regulatory lag for the recovery of energy and transmission costs related to retail electric customers in these jurisdictions.

Of the wind-powered generating facilities placed in-service as of December 31, 2017, 2,097 MW (nominal ratings) have not been included in the determination of MidAmerican Energy's Iowa retail electric base rates. In accordance with the related ratemaking principles, until such time as these generation assets are reflected in base rates and ceasing thereafter, MidAmerican Energy reduced its revenue from Iowa energy adjustment clause recoveries by $5 million in 2015 and $9 million in 2016 and is to reduce its recoveries by $12 million for each calendar year thereafter.

MidAmerican Energy's cost of gas is collected for each jurisdiction in its gas rates through a ~~subsidiary, owns~~ ~~66.67%~~ ~~of Bridger Coal Company ("Bridger Coal"),~~uniform PGA, which is updated monthly to reflect changes in actual costs. Subject to prudence reviews, the PGA accomplishes a ~~coal mining joint venture~~pass-through of MidAmerican Energy's cost of gas to its customers and, accordingly, has no direct effect on net income. MidAmerican Energy's DSM program costs are collected through separately established rates that ~~supplies coal~~are adjusted annually based on actual and expected costs, as approved by the respective state regulatory commission. As such, recovery of DSM program costs has no direct impact on net income.

NV Energy (Nevada Power and Sierra Pacific)

Rate Filings

Nevada statutes require the Nevada Utilities to file electric general rate cases at least once every three years with the PUCN. Sierra Pacific may also file natural gas general rate cases with the PUCN. The Nevada Utilities are also subject to a two-part fuel and purchased power adjustment mechanism. The Nevada Utilities make quarterly filings to reset BTER, based on the last 12 months of fuel and purchased power costs. The difference between actual fuel and purchased power costs and the revenue collected in the BTER is deferred into a balancing account. Nevada regulations allow an electric or natural gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. The Nevada Utilities received approval from the PUCN and file quarterly adjustments to the ~~Jim Bridger generating facility. Bridger Coal~~DEAA rate to clear amounts deferred into the balancing account. During required annual DEAA proceedings, the prudence of fuel and purchased power costs is ~~being accounted~~reviewed, and if any costs are disallowed on such grounds, the disallowances will be incorporated into the next quarterly BTER rate change. Also, on an annual basis, the Nevada Utilities (a) seek a determination that energy efficiency program expenditures were reasonable, (b) request that the PUCN reset base and amortization energy efficiency program rates, and (c) request that the PUCN reset base and amortization energy efficiency implementation rates. When the Nevada Utilities' regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, they are obligated to refund energy efficiency implementation revenue previously collected for that year.

Energy Choice Initiative - Deregulation

Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Natural Gas Act ("NGA"), the Energy Policy Act of 2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding companies; accounting and records retention; securities issuances; construction and operation of hydroelectric facilities; and other matters. The FERC also has the enforcement authority to assess civil penalties of up to $1.2 million per day per violation of rules, regulations and orders issued under the ~~equity method of accounting as the power to direct the activities~~Federal Power Act. The Utilities have implemented programs and procedures that ~~most significantly impact Bridger Coal's economic performance are shared~~facilitate and monitor compliance with the ~~joint venture partner.~~FERC's regulations described below. MidAmerican Energy is also subject to regulation by the NRC pursuant to the Atomic Energy Act of 1954, as amended ("Atomic Energy Act"), with respect to its ownership interest in the Quad Cities Station.

Wholesale Electricity and Capacity

The FERC regulates the Utilities' rates charged to wholesale customers for electricityand transmission capacity and related services. Much of the Utilities' wholesale electricity sales and purchases occur under market-based pricing allowed by the FERC and are therefore subject to market volatility. As a result of a 2016 order from the FERC following BHE's acquisition of NV Energy, the Utilities are precluded from selling at market-based rates in the PacifiCorp-East, PacifiCorp-West, Idaho Power Company and NorthWestern Energy balancing authority areas. The Utilities had previously relinquished their market-based rate authority in the NV Energy balancing authority area. Wholesale electricity sales in those specific balancing authority areas are permitted at cost-based rates. On October 30, 2017, the FERC granted the application of PacifiCorp, Nevada Power and Sierra Pacific for authority to bid into the California EIM at market-based rates.

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~~Restricted Cash~~The Utilities' authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the Utilities are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and ~~Investments~~electric generation capacity in their respective market areas. PacifiCorp, the Nevada Utilities and certain affiliates, representing the BHE Northwest Companies, file together for market power study purposes. The BHE Northwest Companies' most recent triennial filing was made in June 2016 and, as to its non-mitigated balancing authority areas, was approved in November 2017. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2017 and an order accepting it was issued in January 2018. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2017 and is currently pending with the FERC. Under the FERC's market-based rules, the Utilities must also file with the FERC a notice of change in status when there is a change in the conditions that the FERC relied upon in granting market-based rate authority.

Transmission

MidAmerican Energy has approval from the MISO to construct and own four Multi-Value Projects ("MVPs") located in Iowa and Illinois that will have added approximately 250 miles of 345 kV transmission line to MidAmerican Energy's transmission system since 2012, of which 224 miles have been placed in-service as of December 31, 2017. The MISO OATT allows for broad cost allocation for MidAmerican Energy's MVPs, including similar MVPs of other MISO participants. Accordingly, a significant portion of the revenue requirement associated with MidAmerican Energy's MVP investments will be shared with other MISO participants based on the MISO's cost allocation methodology, and a portion of the revenue requirement of the other participants' MVPs will be allocated to MidAmerican Energy. Additionally, MidAmerican Energy has approval from the FERC to include 100% of construction work in progress in the determination of rates for its MVPs and to use a forward-looking rate structure for all of its transmission investments and costs. The transmission assets and financial results of MidAmerican Energy's MVPs are excluded from the determination of its retail electric rates.

The FERC has established an extensive number of mandatory reliability standards developed by the NERC and the WECC, including planning and operations, critical infrastructure protection and regional standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the FERC; the NERC; and the WECC for PacifiCorp, Nevada Power, and Sierra Pacific; and the Midwest Reliability Organization for MidAmerican Energy.

Hydroelectric

The FERC licenses and regulates the operation of hydroelectric systems, including license compliance and dam safety programs. Most of PacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Under the Federal Power Act, 17 dams associated with PacifiCorp's hydroelectric generating facilities licensed with the FERC are classified as "high hazard potential," meaning it is probable in the event of dam failure that loss of human life in the downstream population could occur. The FERC provides guidelines utilized by PacifiCorp in development of public safety programs consisting of a dam safety program and emergency action plans.

PacifiCorp's Klamath River hydroelectric system is the only significant hydroelectric system for which PacifiCorp has a pending relicensing process with the FERC. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 13 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for an update regarding hydroelectric relicensing for PacifiCorp's Klamath River hydroelectric system.

Nuclear Regulatory Commission

General

The NRC also regulates the decommissioning of nuclear-powered generating facilities, including the planning and funding for the eventual decommissioning of the facilities. In accordance with these regulations, MidAmerican Energy submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay its share of the costs of decommissioning Quad Cities Station. MidAmerican Energy has established a trust for the investment of funds collected for nuclear decommissioning ~~the~~of Quad Cities Station.

Nuclear Insurance

Exelon Generation purchases private market nuclear liability insurance for Quad Cities Station in the maximum available amount of $450 million, which includes coverage for MidAmerican Energy's ownership. In accordance with Price-Anderson, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Quad Cities Station is approximately $64 million per incident, payable in installments not to exceed $10 million annually.

The insurance for nuclear property damage losses covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Exelon Generation purchases primary and excess property insurance protection for the combined interests in Quad Cities Station, with coverage limits for nuclear damage losses up to $1.5 billion and non-nuclear property damage losses up to $2.1 billion. MidAmerican Energy also directly purchases extra expense coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments to be called upon based on the industry mutual board of directors' discretion for adverse loss experience. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $9 million.

The master nuclear worker liability coverage, which is purchased by Exelon Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of $450 million for the nuclear industry as a whole, which is in effect to cover tort claims of workers in nuclear-related industries.

United States Mine Safety

Interstate Natural Gas Pipeline Subsidiaries

The Pipeline Companies are regulated by the FERC, pursuant to the NGA and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (a) rates, charges, terms and conditions of service and (b) the construction and operation of interstate pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities. The Pipeline Companies hold certificates of public convenience and necessity issued by the FERC, which authorize them to construct, operate and maintain their pipeline and related facilities and services.

FERC regulations and the Pipeline Companies' tariffs allow each of the Pipeline Companies to charge approved rates for the services set forth in their respective tariff. Generally, these rates are a function of the cost of providing services to their customers, including prudently incurred operations and maintenance expenses, taxes, depreciation and amortization and a reasonable return on their investments. Both Northern Natural Gas' and Kern River's tariff rates have been developed under a rate design methodology whereby substantially all of their fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid by firm transportation and storage customers regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, costs. Kern River's reservation rates have historically been approved using a "levelized" cost-of-service methodology so that the rate remains constant over the levelization period. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense and return on equity amounts decrease. Both Northern Natural Gas' and Kern River's rates are subject to change in future general rate proceedings.

Interstate natural gas pipelines are also subject to regulations administered by the Office of Pipeline Safety within the Pipeline and Hazardous Materials Safety Administration, an agency within the United States Department of Transportation ("DOT"). Federal pipeline safety regulations are issued pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("NGPSA"), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas facilities, and requires an entity that owns or operates pipeline facilities to comply with such plans. Major amendments to the NGPSA include the Pipeline Safety Improvement Act of 2002 ("2002 Act"), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 ("2006 Act"), the Pipeline Safety, Regulatory Certainty, Job Creation Act of 2011 ("2011 Act") and the Protecting Our Infrastructure Of Pipelines And Enhancing Safety Act Of 2016 ("2016 Act").

The 2011 Act was a response to natural gas pipeline incidents, most notably the San Bruno natural gas pipeline explosion that occurred in September 2010 in California. The 2011 Act increased the maximum allowable civil penalties for violations, directs operator assistance for Federal authorities conducting investigations and authorized the DOT to hire additional inspection and enforcement personnel. The 2011 Act also directed the DOT to study several topics, including the definition of high-consequence areas, the use of automatic shutoff valves in high-consequence areas, expansion of integrity management requirements beyond high-consequence areas and cast iron pipe replacement. The studies are complete, and a number of notices of proposed rulemaking have been issued. The BHE Pipeline Group anticipates final rules on a number of areas sometime in 2018. The BHE Pipeline Group cannot currently assess the potential cost of compliance with new rules and regulations under the 2011 Act.

The DOT and related state agencies routinely audit and inspect the pipeline facilities for compliance with their regulations. The Pipeline Companies conduct internal audits of their facilities every four years with more frequent reviews of those deemed higher risk. The Pipeline Companies also conduct preliminary audits in advance of agency audits. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis. The Pipeline Companies believe their pipeline systems comply in all material respects with the NGPSA and with DOT regulations issued pursuant to the NGPSA.

Northern Powergrid Distribution Companies

the actual operating and capital costs of each of the licensees;

the operating and capital costs that each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the more efficient licensees;

the actual value of certain costs which are judged to be beyond the control of the licensees;

the taxes that each licensee is expected to pay;

the regulatory value ascribed to the expenditures that have been incurred in the past and the efficient expenditures that are to be incurred in the forthcoming regulatory period;

the rate of return to be allowed on expenditures that make up the regulatory asset value;

the financial ratios of each of the licensees and the license requirement for each licensee to maintain investment grade status;

an allowance in respect of the repair of the pension deficits in the defined benefit pension schemes sponsored by each of the licensees; and

any under- or over-recoveries of revenues, relative to allowed revenues, in the previous price control period.

A new price control can be implemented by GEMA without the consent of the DNOs, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's CMA, as can certain other parties. Any appeals must be notified within 20 working days of the license modification by GEMA. If the CMA determines that the appellant has relevant standing, then the statute requires that the CMA complete its process within six months, or in some exceptional circumstances seven months. The Northern Powergrid Distribution Companies appealed Ofgem's proposals for the resetting of the formula that commenced April 1, 2015, as did one other party, and the CMA subsequently revised GEMA's decision.

the period over which new regulatory assets are depreciated is being gradually lengthened, from 20 years to 45 years, with the change being phased over eight years;

allowed revenues will be adjusted during the price control period, rather than at the next price control review, to partially reflect cost variances relative to cost allowances;

the allowed cost of debt will be updated within the price control period by reference to a long-run trailing average based on external benchmarks of utility debt costs;

allowed revenues will be adjusted in relation to some new service standard incentives, principally relating to speed and service standards for new connections to the network; and

there is scope for a mid-period review and adjustment to revenues in the latter half of the period for any changes in the outputs required of licensees for certain specified reasons.

Under the price control, as revised by the CMA, and excluding the effects of incentive schemes and any deferred revenues from the prior price control, the base allowed revenue of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc decreased by approximately 1.0% and 0.5%, respectively, from 2015-16 to 2016-17, and then remains constant in all subsequent years within the price control period (RIIO-ED1) through 2022-23, before the addition of inflation. Nominal base allowed revenues will increase in line with inflation.

ALP Transmission

The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:

regulating and adjudicating issues related to the operation of electric utilities within Alberta;

approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;

reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;

adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and

collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.

Independent Power Projects

The Yuma, Cordova, Saranac, Power Resources, Topaz, Agua Caliente, Solar Star, Bishop Hill II, Jumbo Road, Marshall, Grande Prairie, Pinyon Pines, Alamo 6 and Pearl independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act, while the Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978. Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.

The Yuma, Cordova, Saranac, Imperial Valley, Topaz, Agua Caliente, Solar Star, Bishop Hill II, Marshall, Grande Prairie and Pinyon Pines independent power projects have obtained authority from the FERC to sell their power using market-based rates. This authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the respective independent power projects are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. The Pinyon Pines, Solar Star, Topaz and Yuma independent power projects and power marketer CalEnergy, LLC file together for market power study purposes of the FERC-defined Southwest Region. The most recent triennial filing for the Southwest Region was made in June 2016 and an order accepting it was issued December 2016. The Cordova and Saranac independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2017 and an order accepting it was issued in January 2018. The Bishop Hill II independent power project and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2017 and is currently pending with the FERC.

The entire output of Jumbo Road, Alamo 6, Pearl and Power Resources is within the Electric Reliability Council of Texas ("ERCOT") and market-based authority is not required for such sales solely within ERCOT as the ERCOT market is not a FERC-jurisdictional market. Similarly, Wailuku sells its output solely to the Hawaii Electric Company within the Hawaii electric grid which is not a FERC-jurisdictional market and Wailuku therefore does not require market-based rate authority.

Residential Real Estate Brokerage Company

REGULATORY MATTERS

PacifiCorp

The 2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. PacifiCorp has agreed to defer the impact of the tax law change with each of its state rate regulatory bodies. PacifiCorp will be proposing to reduce customer rates for a portion of the lower annual income tax expense resulting from the decrease in federal tax rates, and deferring the remainder to offset other costs as approved by the regulatory bodies. PacifiCorp cannot predict the timing or ultimate outcome of regulatory actions on its proposals.

Utah Mine Disposition

In December 2014, PacifiCorp filed an advice letter with the CPUC to request approval to sell certain Utah mining assets and to establish memorandum accounts to track the costs associated with the Utah Mine Disposition for future recovery. In July 2015, the CPUC Energy Division issued a letter requiring PacifiCorp to file a formal application for approval of the sale of certain Utah mining assets. Accordingly, in September 2015, PacifiCorp filed an application with the CPUC. On February 6, 2017, a joint motion was filed with the CPUC seeking approval of a settlement agreement reached by PacifiCorp and all other parties. The agreement states, among other things, that the decision to sell certain Utah mining assets is in the public interest. Parties also reserve their rights to additional testimony, briefs and hearings to the extent the CPUC determines that additional California Environmental Quality Act proceedings are necessary. A CPUC decision on the joint motion and settlement agreement is expected in 2018.

For additional information related to the accounting impacts associated with the Utah Mine Disposition, refer to Notes 5 and 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.

Utah

In March 2017, PacifiCorp filed its annual 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 became effective on an interim basis May 1, 2017. In January 2018, the UPSC approved a stipulation that provides an additional $3 million reduction, which will be incorporated into the 2018 EBA filing to be made in March 2018.

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 RECs. The rate change 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 a proposed five-year pilot program with an annual budget of $10 million authorized under the legislation to address clean-coal technology programs, commercial line extension programs, an electric vehicle incentive program and associated residential time of use rate pilot and other programs authorized in legislation. The UPSC issued orders approving PacifiCorp's application in phases in December 2016, May 2017, June 2017 and October 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 regulatory rate review filed by various parties to the docket and denied the motions. On August 28, 2017, PacifiCorp filed a settlement stipulation in the net metering proceeding. The stipulation provides for the closure of the net metering program to new entrants on November 15, 2017, with a transition to a new program that provides a separate compensation rate for exported power. All net metering customers, including those with a submitted application, as of November 15, 2017, will be grandfathered into the current program until January 1, 2036. A new proceeding will be initiated to establish a methodology for the determination of the export credit for new customers. During this period, a transition program for new customers will commence November 15, 2017, for a limited number of customers. Beginning December 1, 2017, PacifiCorp began accepting applications for the new transition program for private generation customers. Residential and non-residential private generation customers in the transition program will be compensated for exported energy at 90% and 92.5% of the current average energy rates, respectively. The rates for the exported energy will be fixed through January 1, 2033 for these transition program customers. The new residential and non-residential transition program customers' compensation will be only available for the first 170 MW and 70 MW, respectively. The stipulation also includes an agreement to support a two-year extension on the state tax credit for residential solar installations. A hearing on the stipulation was held on September 18, 2017, and an order approving it was issued September 29, 2017.

Oregon

In March 2017, PacifiCorp submitted its filing for the annual 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. In October 2017, the OPUC issued an order approving PacifiCorp's request with some minor adjustments to the NPC modeling. PacifiCorp submitted the final update in November 2017 which reflected a rate increase of $2 million, or an average price increase of 0.2%, effective January 2018.

Wyoming

In April 2017, PacifiCorp filed its annual ECAM, REC and 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. In June 2017, the WPSC approved the ECAM, REC and RRA rates on an interim basis. In November 2017, a stipulation was filed resolving all issues in the proceeding. The stipulation results in an additional refund to customers of $1 million in 2017. The WPSC approved the stipulation at the hearing on November 28, 2017.

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 included rates based on the $8 million, or 2.3%, increase ordered by the WUTC in September 2016. The compliance filing was approved by the WUTC on September 14, 2017, with rates effective September 15, 2017. On December 1, 2017, PacifiCorp submitted a tariff filing to implement the first price change for the decoupling mechanism approved in PacifiCorp's 2015 regulatory rate review. WUTC staff disputed PacifiCorp's interpretation of the WUTC's order for the decoupling mechanism and PacifiCorp's subsequent calculations requesting additional funds be booked for return to customers. In February 2018, the WUTC granted the staff's motions and rejected PacifiCorp's tariff revision and required that PacifiCorp re-file price changes for its decoupling mechanism.

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. The IPUC approved the ECAM application with rates 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. 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. The CPUC issued an order in February 2018 approving this request.

In August 2017, PacifiCorp filed for a rate decrease of $1 million, or 1.1%, through its annual ECAC. The CPUC issued an order approving PacifiCorp's request in December 2017, the rate decrease was effective January 2018.

MidAmerican Energy

In July 2014, the IUB issued an order approving increases in MidAmerican Energy's Iowa retail electric base rates over approximately three years with equal annualized increases in revenues of $45 million, effective August 2013 and again on January 1, 2015 and 2016, for a total annualized increase of $135 million when fully implemented. In addition to an increase in base rates, the order approved, among other items, a revenue sharing mechanism that shares with MidAmerican Energy's customers 80% of revenues related to equity returns above 11% and 100% of revenues related to equity returns above 14%, with the customer portion of any sharing reducing rate base. MidAmerican Energy recorded a regulatory liability for revenue sharing totaling $26 million in 2017 and $30 million in 2016, which reduced rate base in the respective following January. In August 2016, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's construction of up to 2,000 MW (nominal ratings) of additional wind-powered generating facilities. The ratemaking principles modified the revenue sharing mechanism, effective in 2018, such that sharing will be triggered each year by MidAmerican Energy's actual equity returns above a threshold calculated annually in accordance with the order. The threshold is the weighted average of equity returns for rate base as authorized via ratemaking principles proceedings and for remaining rate base, interest rates on 30-year single A-rated utility bond yields plus 400 basis points, with a minimum return of 9.5%. Pursuant to the change in revenue sharing, MidAmerican Energy will share with customers 100% of the revenue in excess of this trigger. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases.

The 2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. MidAmerican Energy has made filings or has been in discussions with each of its state rate regulatory bodies proposing either a reduction in retail rates or rate base for all or a portion of the net benefits of the 2017 Tax Reform for 2018 and beyond. MidAmerican Energy has proposed in Iowa, its largest jurisdiction, to reduce customer revenue via a rider mechanism for 50% of the lower annual income tax expense resulting from the decrease in federal tax rates, updated annually. Results for the Iowa electric jurisdiction will be subject to Iowa revenue sharing provisions. If MidAmerican Energy's filings in each of its rate jurisdictions are approved as proposed, it is estimated that 2018 revenue will be reduced by approximately $72 million, subject to change depending upon actual results of operations. MidAmerican Energy cannot predict the timing or ultimate outcome of regulatory actions on its proposals.

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 supported an annual revenue increase of $29 million, or 2%, but requested no incremental annual revenue relief. In December 2017, the PUCN issued an order which reduced Nevada Power's revenue requirement by $26 million and requires Nevada Power to share 50% of revenues related to equity returns above 9.7%. As a result of the order, Nevada Power recorded expense of $28 million primarily due to the reduction of a regulatory asset to return to customers revenue collected for costs not incurred. In January 2018, Nevada Power filed a petition for clarification of certain findings and directives in the order. The new rates were effective in February 2018.

The 2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. 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 the 2017 Tax Reform for 2018 and beyond. The filings support an annual rate reduction of $59 million and $25 million for Nevada Power and Sierra Pacific, respectively. The Nevada Utilities cannot predict the timing or ultimate outcome of regulatory actions on its proposals.

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 MW of net metering at the grandfathered rates. Sierra Pacific believes the effects of the PUCN decision results 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.

EEPR and EEIR

EEPR was established to allow the Nevada Utilities to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by the Nevada Utilities and approved by the PUCN in integrated resource plan proceedings. To the extent the Nevada Utilities' earned rate of return exceeds the rate of return used to set base general rates, the Nevada Utilities' are required to refund to customers EEIR revenue previously collected for that year. In March 2017, the Nevada Utilities each filed an application to reset the EEIR and EEPR and refund the EEIR revenue received in 2016, including carrying charges. In September 2017, the PUCN issued an order accepting a stipulation requiring Nevada Power to refund the 2016 revenue and reset the rates as filed effective October 1, 2017. The current EEIR liability for Nevada Power and Sierra Pacific is $10 million and $1 million, respectively, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2017.

Chapter 704B Applications

In May 2015, MGM Resorts International ("MGM") and Wynn Las Vegas, LLC ("Wynn"), filed applications with the PUCN to purchase energy from alternative providers of a new electric resource and become distribution only service customers of Nevada

Power. In December 2015, the PUCN granted the 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, the applicants filed 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 of $82 million and $15 million, respectively. In October 2016, MGM and Wynn became distribution only service 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. This request is still pending. In May 2017, a stipulation reached between MGM, Regulatory Operations Staff and the Bureau of Consumer Protection was filed requiring Nevada Power to reduce the original $82 million impact fee by $16 million and apply the credit against MGM's remaining on-going charge obligation. 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 May 2017, Switch paid impact fees of $27 million and, in June 2017, Switch became a distribution only service customer and started procuring energy from another energy supplier.

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 private, 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 established separate rate classes for customers who install private, 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. Additionally, the PUCN established a separate value for compensating customers who produce and deliver excess energy to the Nevada Utilities. The valuation considered 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, which was settled and dismissed in August 2017.

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 private, 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. As mentioned above, Sierra Pacific filed a petition for reconsideration relating to the additional six MWs of net metering, which was denied in June 2017.

Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The legislation, among other things, established net metering crediting rates for private generation customers with installed net metering systems less than 25 kilowatts. Under AB 405, private generation 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 private generation 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, which has not yet been set for procedural review. In September 2017, the PUCN issued an order directing the Nevada Utilities to place all new private generation customers who have submitted applications after June 15, 2017 into a new rate class with rates equal to the rate class they would be in if they were not private generation customers. Private generation customers with installed net metering systems less than 25-kilowatts prior to June 15, 2017 may elect to migrate to the new rate class created under AB 405 or stay in their otherwise-applicable rate class. The new AB 405 rates became effective December 1, 2017.

Emissions Reduction and Capacity Replacement Plan

IRP

In July 2016, Sierra Pacific filed its statutorily required IRP. In August 2016, Nevada Power filed an amendment to its related IRP. As a part of the filings, the Nevada Utilities sought PUCN authorization to acquire the South Point Energy Center, a 504-MW combined-cycle generating facility located in Arizona. In December 2016, the PUCN denied the acquisition of this facility. In January 2017, Nevada Power filed a petition for reconsideration relating to the acquisition of South Point Energy Center. In February 2017, the PUCN affirmed the denial of the acquisition of South Point Energy Center. The Nevada Utilities amended their respective IRPs in November 2017, requesting approval of three long-term renewable purchase power contracts. Nevada law was modified in 2017 under Senate Bill 146 and for future filings requires Nevada Power and Sierra Pacific to file jointly.

Kern River

ALP

General Tariff Applications

In November 2014, ALP filed a general tariff application ("GTA") requesting the AUC to 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 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 approximately C$415 million tariff relief in 2015 and 2016 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.

In August 2017, the AUC issued a decision with respect to ALP's second compliance filing amendment filed in April 2017. The AUC denied ALP's proposal to remove C$7 million of recapitalized AFUDC associated with canceled projects on the basis that the amount would more appropriately be recovered through ALP's deferral account reconciliation process. The AUC also directed the recalculation of the amount of related income taxes using typical direct assigned project schedules filed in the general tariff applications, and to adjust its funded future income tax liability only for the change in timing differences.

In September 2017, ALP filed its third compliance filing with the AUC which proposed a one-time payment to the AESO of C$7 million to settle the 2015-2016 final transmission tariffs of C$485 million for 2016 and C$723 million for 2015. In December 2017, the AUC approved ALP's third compliance filing as filed.

ALP filed its 2017-2018 GTA in February 2016. The AUC held this application in abeyance pending the release of the 2015-2016 GTA Decision. ALP subsequently 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. The 2017-2018 GTA reflected an additional C$185 million of tariff relief related to items approved in the 2015-2016 GTA decision. In December 2016, the AUC approved ALP's request to enter into a negotiated settlement process.

In January 2017, ALP successfully reached a negotiated settlement with all parties regarding 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.

In November 2017, ALP filed and received AUC approval regarding its compliance filing, which includes revenue requirements of C$864 million and C$888 million for 2017 and 2018, respectively.

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.

In October 2017, ALP's evidence was submitted recommending a range of 9% to 10.75% return on equity, on a recommended equity ratio of 40%. ALP also filed evidence outlining increased uncertainties in the Alberta utility regulatory environment. In January 2018, the Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the City of Calgary filed intervenor evidence. The return on equity recommended by the intervenors ranges from 6.3% to 7.75%. The equity ratio recommended by the intervenors for ALP ranges from 35% to 37%.

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 decision may relate.

In December 2017, ALP 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.

BHE U.S. Transmission

A significant portion of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base regulatory rate review. In December 2017, the most recent interim rate change filing was approved which set total annual revenue requirements at $332 million and a rate base of $2.5 billion. In January 2017, the PUCT approved ETT's request to suspend the base regulatory rate review filing scheduled for February 2017 and set ETT's annual revenue requirement to $327 million, effective March 2017. Results of a base regulatory rate review would be prospective except for any deemed disallowance by the PUCT of the transmission investment since the initial base regulatory rate review in 2007.

ENVIRONMENTAL LAWS AND REGULATIONS

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air and water quality, RPS, 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 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. Refer to "Liquidity and Capital Resources" of each respective Registrant in Item 7 of this Form 10-K for discussion of each Registrant's forecast environmental-related capital expenditures.

Clean Air Act Regulations

National Ambient Air Quality Standards

In October 2015, the EPA revised the national ambient air quality standard for ground level ozone, strengthening the standard from 75 parts per billion to 70 parts per billion. It is anticipated that the EPA will make attainment/nonattainment designations for the revised standards by late 2017. Nonattainment areas will have until 2020 to late 2037 to meet the standard. Given the level at which the standard was set in conjunction with retirements and the installation of controls, the new standard is not expected to have a significant impact on the relevant Registrant. The EPA designated the entire state of Iowa as attainment/unclassifiable on November 16, 2017.

Until the 2015 standard is fully implemented, the EPA continues to implement the 2008 ozone standards. The Upper Green River Basin Area in Wyoming, including all of Sublette and portions of Lincoln and Sweetwater Counties, were proposed to be designated as nonattainment for the 2008 ozone standard. When the final designations were released in April 2012, portions of Lincoln and Sweetwater Counties and Sublette County were determined to be in marginal nonattainment. While PacifiCorp's Jim Bridger plant is located in Sweetwater County, it is not in the portion of the designated nonattainment area and has not been impacted by the 2012 designation. In December 2017, EPA Region 9 notified Nevada of its intent to designate a portion of Clark County as nonattainment under the 2015 standard and will modify the state's recommendation for this area. The EPA also intends to designate all other areas in the state not previously designated as attainment/unclassifiable. This redesignation to nonattainment could potentially impact Nevada Power's Clark, Sun Peak, Las Vegas, Lenzie, Silverhawk, Harry Allen, Higgins, and Goodsprings generating facilities. However, until such time as the 2015 standard is implemented for Clark County in a final action, any potential impacts cannot be determined. In order for the EPA to consider more current air quality data in the final designation, Nevada must submit certified quality-assured air quality monitoring data for the time period 2015-2017 to the EPA by February 28, 2018. After considering any additional information received, the EPA plans to promulgate final ozone designations in spring of 2018.

On December 20, 2017, the EPA responded to the state of Arizona's recommendation that a section of Yuma County, in which the Yuma independent power project is located, be designated as nonattainment with respect to the 2015 National Ambient Air Quality Standards for ozone, indicating its acceptance of the state's designations for areas in attainment, and requesting additional data to finalize designations of nonattainment areas by February 28, 2018. The Yuma independent power project could be impacted by the requirements of the final rule. Until such time as the designations are final, any potential impacts cannot be determined.

The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour sulfur dioxide standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 sulfur dioxide standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of sulfur dioxide in 2012 or emitted more than 2,600 tons of sulfur dioxide and had an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of sulfur dioxide and having an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 sulfur dioxide standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment.

Mercury and Air Toxics Standards

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.

Cross-State Air Pollution Rule

The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce nitrogen oxides emissions in 2017. The final rule was published in the Federal Register in October 2016. The rule requires additional reductions in nitrogen oxides emissions beginning in May 2017. On December 23, 2016, a lawsuit was filed against the EPA in the D.C. Circuit over the final CSAPR "update" rule, which is still pending.

MidAmerican Energy has installed emissions controls at its coal-fueled generating facilities to comply with the CSAPR and may purchase emissions allowances to meet a portion of its compliance obligations. The cost of these allowances is subject to market conditions at the time of purchase and historically has not been material. MidAmerican Energy believes that the controls installed to date are consistent with the reductions to be achieved from implementation of the rule and does not anticipate that any impacts of the CSAPR update will be significant.

Regional Haze

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. 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 decision issuing the FIP. 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.

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 November 28, 2017.

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.

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-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the 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. Until such time as the EPA undertakes further action to reconsider the new source performance standards 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 U.S. Supreme Court. Oral argument was heard before the D.C. Circuit on September 27, 2016. The court has not yet issued its decision. On October 10, 2017, the EPA issued a proposal to repeal the Clean Power Plan and the EPA will take comments on the proposed repeal until April 26, 2018. In addition, the EPA published in the Federal Register an Advance Notice of Proposed Rulemaking on December 28, 2017, seeking public input on, without committing to, a potential replacement rule. The public comment period for the Advance Notice of Proposed Rulemaking is currently scheduled to conclude February 26, 2018. The full impacts of the EPA's recent efforts to repeal the Clean Power Plan are not expected to have a material impact on the Registrants. 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.

Notwithstanding the absence of comprehensive climate legislation or regulation, the Registrants have continued to invest in lower- and non-carbon generating resources and to operate in an environmentally responsible manner. In July 2015, BHE signed the American Business Act on Climate pledge, in which BHE pledged to build on the Company's combined investment of more than $15 billion in renewable energy generation under construction and in operation through 2014 by investing up to an additional $15 billion. Components of BHE's pledge, which continue to be implemented, include:

Pursue the construction of an additional 552 MW of new wind-powered generation in Iowa, increasing MidAmerican Energy's generating portfolio to more than 4,000 MW of wind, which was equivalent to an estimated 51 percent of its Iowa customers' annual retail usage in 2017. MidAmerican Energy surpassed its Climate Pledge commitments in 2016 and 2017 and is currently continuing with the construction of an additional 2,000 MW of wind-powered generation in Iowa, of which 334 MW was placed in-service in 2017. The 2,000-MW wind project is expected to be fully complete in late 2019, and by year-end 2020, MidAmerican Energy's annual renewable energy generation is expected to reach a level that is equivalent to more than 90% of its Iowa customers' annual retail usage. MidAmerican Energy owns the largest portfolio of wind-powered generating capacity in the United States among rate-regulated utilities.

Add more than 1,000 MW of incremental solar and wind capacity through long-term power purchase agreements to PacifiCorp's owned 1,030 MW of wind-powered generating capacity. PacifiCorp owns the second largest portfolio of wind-powered generating capacity in the United States among rate-regulated utilities. PacifiCorp's Climate Pledge commitments were met December 2016. As of December 31, 2017, PacifiCorp's non-carbon generating capacity, owned and contracted, totaled 4,573 MW, which is capable of generating energy equivalent to 24 percent of its retail sales in 2017. In 2017, PacifiCorp announced Energy Vision 2020, which will significantly expand the amount of wind power serving customers by 2020 through a $3 billion investment in repowering its existing wind fleet with larger blades and newer technology; adding at least 1,311 megawatts of new wind resources by the end of 2020; and building transmission in Wyoming to enable additional wind generation.

Invest in transmission infrastructure in the West and Midwest to support the integration of renewable energy onto the grid.

Support and advance the development of markets in the West to optimize the electric grid, lower costs, enhance reliability and more effectively integrate renewable sources.

Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;

Additional costs may be incurred to purchase and deploy new generating technologies;

Operating costs may be higher and generating unit outputs may be lower;

Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and

The relevant Registrant's natural gas pipeline operations, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.

Regional and State Activities

In June 2013, Nevada SB 123 was signed into law. Among other things, SB 123 and regulations thereunder require Nevada Power to file with the PUCN an emission reduction and capacity replacement plan by May 1, 2014. In May 2014, Nevada Power filed its emissions reduction capacity replacement plan. The plan provided for the retirement or elimination of 300 MW of coal generating capacity by December 31, 2014, another 250 MW of coal generating capacity by December 31, 2017, and another 250 MW of coal generating capacity by December 31, 2019, along with replacement of such capacity with a mixture of constructed, acquired or contracted renewable and non-technology specific generating units. The plan also sets forth the expected timeline and costs associated with decommissioning coal-fired generating units that will be retired or eliminated pursuant to the plan. The PUCN has the authority to approve or modify the emission reduction and capacity replacement plan filed by Nevada Power. Given the PUCN may recommend and/or approve variations to Nevada Power's resource plans relative to requirements under SB 123, the specific impacts of SB 123 on Nevada Power cannot be determined.

Under the authority of California's Global Warming Solutions Act, which includes a series of policies aimed at returning California greenhouse gas emissions to 1990 levels by 2020, the California Air Resources Board adopted a GHG cap-and-trade program with an effective date of January 1, 2012; compliance obligations were imposed on entities beginning in 2013. PacifiCorp is subject to the cap-and-trade program as a retail service provider in California and an importer of wholesale energy into California. In 2015, Governor Jerry Brown issued an executive order to reduce emissions to 40% below 1990 levels by 2030 and 80% by 2050. In September 2016, California Senate Bill 32 was signed into law establishing greenhouse gas emissions reduction targets of 40% below 1990 levels by 2030.

In September 2016, the Washington State Department of Ecology issued a final rule regulating GHG emissions from sources in Washington. The rule regulates greenhouse gases including carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride beginning in 2017 with three-year compliance periods thereafter (i.e., 2017-2019, 2020-2022, etc.). Under the rule, the Washington State Department of Ecology established GHG emissions reduction pathways for all covered entities. Covered entities may use emission reduction units, which may be traded with other covered entities, to meet their compliance requirements. PacifiCorp's resources that are covered under the rule include the Chehalis generating facility, which is a natural gas combined-cycle plant located in Washington state. PacifiCorp received its baseline emission order on December 17, 2017, which specified the emission reduction requirements for the Chehalis generating facility every three years beginning in 2017. The reduction requirements average 1.7% per year. However, the Washington State Department of Ecology suspended the compliance obligations of the Clean Air Rule after a Thurston County Superior Court judge ruled the state lacks authority to mandate reductions from indirect emitters. Pending further interpretation of the court’s decision by the Washington State Department of Ecology, entities subject to the rule are required to continue reporting emissions.

The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to reduce GHG emissions in ten Northeastern and Mid-Atlantic states, required, beginning in 2009, the reduction of carbon dioxide emissions from the power sector of 10% by 2018. In May 2011, New Jersey withdrew from participation in the Regional Greenhouse Gas Initiative. Following a program review in 2012, the nine Regional Greenhouse Gas Initiative states implemented a new 2014 cap which was approximately 45% lower than the 2012-2013 cap. The cap is reduced each year by 2.5% from 2015 to 2020. As called for in the 2012 program review, a program review was initiated for 2016 and continues through 2017 with the expectation that states will implement program changes in the fourth control period from 2018 to 2020. In December 2017, an updated model rule was released by the Regional Greenhouse Gas Initiative states which includes an additional 30% regional cap reduction between 2020 and 2030.

GHG Litigation

Each Registrant closely monitors ongoing environmental litigation applicable to its respective operations. Numerous lawsuits have been unsuccessfully pursued against the industry that attempt to link GHG emissions to public or private harm. The lower courts initially refrained from adjudicating the cases under the "political question" doctrine, because of their inherently political nature. These cases have typically been appealed to federal appellate courts and, in certain circumstances, to the United States Supreme Court. In the U.S. Supreme Court's 2011 decision in the case of American Electric Power Co., Inc., et al. v. Connecticut et al., the court addressed the question of whether federal common law nuisance claims could be maintained against certain electric power companies' for their GHG emissions and require the setting of an emissions cap for the emitters. The court held that the Clean Air Act and the EPA actions it authorizes displace any federal common law right to seek abatement of carbon dioxide emissions from fossil-fuel-fired power plants. Recent efforts by the EPA to repeal the Clean Power Plan could increase the filing of common law nuisance lawsuits against emitters of GHG. Adverse rulings in GHG-related cases could result in increased or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities.

The GHG rules, changes to those rules, and the Registrants' compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.

Renewable Portfolio Standards

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. 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 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 U.S. 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 U.S. 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. Depending on the outcome of final action by the EPA and additional legal action, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits will be required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. However, 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 will be posted to the respective Registrant's coal combustion rule compliance data and information websites by March 2, 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 Form 10-K and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for discussion of the impacts on asset retirement obligations as a result of the final rule.

Other

Other laws, regulations and agencies to which the relevant Registrants are subject include, but are not limited to:

The Nuclear Waste Policy Act of 1982, under which the United States Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 13 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 12 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's nuclear decommissioning obligations.

Item 1A. Risk Factors

Corporate and Financial Structure Risks

BHE is a holding company and depends on distributions from subsidiaries, including joint ventures, to meet its obligations.

their respective earnings, capital requirements, and required debt and preferred stock payments;

the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and

regulatory restrictions that limit the ability of BHE's regulated utility subsidiaries to distribute profits.

A significant portion of BHE's capital structure is comprised of debt, and BHE expects to incur additional debt in the future to fund items such as, among others, acquisitions, capital investments and the development and construction of new or expanded facilities. As of December 31, 2017, BHE had the following outstanding obligations:

senior unsecured debt of $6.5 billion;

junior subordinated debentures of $100 million;

short-term borrowings of $3.3 billion;

guarantees and letters of credit in respect of subsidiary and equity method investments aggregating $332 million; and

commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling $265 million.

BHE's consolidated subsidiaries also have significant amounts of outstanding debt, which totaled $29.8 billion as of December 31, 2017. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) BHE's share of the outstanding debt of its own or its subsidiaries' equity method investments.

Because BHE is a holding company, the claims of its senior debt holders are structurally subordinated with respect to the assets and earnings of its subsidiaries. Therefore, the rights of its creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders, if any. In addition, pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties, the equity interest of MidAmerican Funding's subsidiary and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects, are directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of BHE's debt.

BHE's majority shareholder, Berkshire Hathaway, could exercise control over BHE in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors and BHE could exercise control over the Subsidiary Registrants in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors and PacifiCorp's preferred stockholders.

BHE indirectly owns all of the common stock of PacifiCorp, Nevada Power and Sierra Pacific and is the sole member of MidAmerican Funding and, accordingly, indirectly owns all of MidAmerican Energy's common stock. As a result, BHE has control over all decisions requiring shareholder approval, including the election of directors. In circumstances involving a conflict of interest between BHE and the creditors of the Subsidiary Registrants, BHE could exercise its control in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors.

Business Risks

Much of BHE's growth has been achieved through acquisitions, and any such acquisition may not be successful.

Any acquisition entails numerous risks, including, among others:

the failure of the combined business to realize the expected benefits;

the risk of unexpected or unidentified issues not discovered in the diligence process; and

the need for substantial additional capital and financial investments.

The operation of complex utility systems or interstate natural gas pipeline and storage systems that are spread over large geographic areas involves many operating uncertainties and events beyond each respective Registrant's control. These potential events include the breakdown or failure of the Registrants' thermal, nuclear, hydroelectric, solar, wind and other electricity generating facilities and related equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, which could lead to catastrophic events; unscheduled outages; strikes, lockouts or other labor-related actions; shortages of qualified labor; transmission and distribution system constraints; failure to obtain, renew or maintain rights-of-way, easements and leases on United States federal, Native American, First Nations or tribal lands; terrorist activities or military or other actions, including cyber attacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; third party excavation errors; unexpected degradation of pipeline systems; design, construction or manufacturing defects; and catastrophic events such as severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism and embargoes. A catastrophic event might result in injury or loss of life, extensive property damage or environmental or natural resource damages. For example, in the event of an uncontrolled release of water at one of PacifiCorp's high hazard potential hydroelectric dams, it is probable that loss of human life, disruption of lifeline facilities and property damage could occur in the downstream population and civil or other penalties could be imposed by the FERC. Any of these events or other operational events could significantly reduce or eliminate the relevant Registrant's revenue or significantly increase its expenses, thereby reducing the availability of distributions to BHE. For example, if the relevant Registrant cannot operate its electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event, its revenue could decrease and its expenses could increase due to the need to obtain energy from more expensive sources. Further, the Registrants self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs. The scope, cost and availability of each Registrant's insurance coverage may change, including the portion that is self-insured. Any reduction of each Registrant's revenue or increase in its expenses resulting from the risks described above, could adversely affect the relevant Registrant's consolidated financial results.

Each Registrant is required to comply with numerous federal, state, local and foreign laws and regulations as described in "General Regulation" and "Environmental Laws and Regulations" in Item 1 of this Form 10-K that have broad application to each Registrant and limits the respective Registrant's ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring or disposing of operating assets; operating and maintaining generating facilities and transmission and distribution system assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; transacting between subsidiaries and affiliates; and paying dividends or similar distributions. These laws and regulations, which are followed in developing the Registrants' safety and compliance programs and procedures, are implemented and enforced by federal, state and local regulatory agencies, such as the Occupational Safety and Health Administration, the FERC, the EPA, the DOT, the NRC, the Federal Mine Safety and Health Administration and various state regulatory commissions in the United States, and foreign regulatory agencies, such as GEMA, which discharges certain of its powers through its staff within Ofgem, in Great Britain and the AUC in Alberta, Canada.

Compliance with applicable laws and regulations generally requires each Registrant to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs and damages arising out of contaminated properties. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, each Registrant could be required to shut down some facilities or materially alter its operations. Further, each Registrant may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for its operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay each Registrant from operating its facilities, developing or favorably locating new facilities or expanding existing facilities. If any Registrant fails to comply with any environmental or other regulatory requirements, such Registrant may be subject to penalties and fines or other sanctions, including changes to the way its electricity generating facilities are operated that may adversely impact generation or how the Pipeline Companies are permitted to operate their systems that may adversely impact throughput. The costs of complying with laws and regulations could adversely affect each Registrant's consolidated financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require such Registrant to increase its purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect such Registrant's consolidated financial results.

Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition and decreased revenues within each Registrant's service territories, such as the Nevada Energy Choice Initiative; new environmental requirements, including the implementation of or changes to the Clean Power Plan, RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to each Registrant's service territories as a result of condemnation or takeover by municipalities or other governmental entities, particularly where it lacks the exclusive right to serve its customers; the inability of each Registrant to recover its costs on a timely basis, if at all; new pipeline safety requirements; or a negative impact on each Registrant's current transportation and cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on each Registrant.

State Regulatory Rate Review Proceedings

States set retail rates based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state or other jurisdiction. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense, investment and capital structure that it deems are just and reasonable in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standard. Additionally, each state regulatory commission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital. While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that each Registrant will be able to realize the allowed rate of return.

Energy cost increases above the level assumed in establishing base rates may be subject to customer sharing. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on the Utilities, despite efforts to minimize this impact through the use of hedging contracts and sharing mechanisms or through future general regulatory rate reviews. Any of these consequences could adversely affect each Registrant's consolidated financial results.

FERC Jurisdiction

The FERC authorizes cost-based rates associated with transmission services provided by the Utilities' transmission facilities. Under the Federal Power Act, the Utilities, or MISO as it relates to MidAmerican Energy, may voluntarily file, or may be obligated to file, for changes, including general rate changes, to their system-wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity at wholesale, has jurisdiction over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect each Registrant's consolidated financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. As a transmission owning member of MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. As participants in EIM, PacifiCorp, Nevada Power and Sierra Pacific are also subject to applicable California ISO rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.

The NERC has standards in place to ensure the reliability of the electric generation system and transmission grid. The Utilities are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.

Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the maximum tariff rate for that service or the pipeline may agree to provide a discounted rate, which would be a rate between the maximum and minimum tariff rates. In a rate proceeding, rates in these contracts are generally not subject to adjustment. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the cost used in the determination of the negotiated or discounted rates, which could result either in losses or lower rates of return for providing such services. Under certain circumstances, FERC policy allows interstate natural gas pipelines to design new maximum tariff rates to recover such costs in regulatory rate reviews. However, with respect to discounts granted to affiliates, the interstate natural gas pipeline must demonstrate that the discounted rate was necessary in order to meet competition.

GEMA Jurisdiction

The Northern Powergrid Distribution Companies, as Distribution Network Operators ("DNOs") and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year to year, but is a control on revenue that operates independently of a significant portion of the DNO's actual costs. A resetting of the formula does not require the consent of the DNO, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's Competition and Markets Authority. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of any price control, additional costs have a direct impact on the financial results of the Northern Powergrid Distribution Companies.

AUC Jurisdiction

regulating and adjudicating issues related to the operation of electric utilities within Alberta;

processing and approving general tariff applications relating to revenue requirements and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable and approval of the transmission tariff rates of regulated transmission providers by the AESO, which is the independent transmission system operator in Alberta that controls the operation of AltaLink's transmission system;