~~(1) Organization and Operations~~


(1)	General

Sierra Pacific Power Company, together with its subsidiaries (collectively, the "Company"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company ("Nevada Power") and certain other subsidiaries. The Company is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE")~~. BHE~~ is a holding company ~~based in Des Moines, Iowa~~ that owns subsidiaries principally engaged in energy ~~businesses.~~businesses (collectively with its subsidiaries, the "Company"). BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The Company's operations are organized and managed 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 (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). The Company, through these 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 selling power generated from solar, wind, geothermal and hydroelectric sources under long-term contracts, 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.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, ~~2015~~2016 and for the three- and nine-month periods ended September 30, ~~2015~~2016 and ~~2014.~~2015. The results of operations for the three- and nine-month periods ended September 30, ~~2015~~2016 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, ~~2014~~2015 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the nine-month period endedSeptember 30, ~~2015.~~2016.

~~(2)~~(2) New Accounting Pronouncements

In ~~April 2015,~~August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. ~~2015-03,~~2016-15, which amends FASB Accounting Standards Codification ("ASC") ~~Subtopic 835-30, "Interest - Imputation~~Topic 230, "Statement of ~~Interest.~~Cash Flows." The amendments in this guidance ~~require that debt issuance costs related to a recognized debt liability be presented~~address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in ~~the balance sheet as a direct deduction from the carrying amount of that debt liability instead of as an asset.~~practice. This guidance is effective for interim and annual reporting periods beginning after December 15, ~~2015,~~2017, with early adoption ~~permitted.~~permitted, and is required to be adopted retrospectively. The Company is currently evaluating the impact of adopting this guidance 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 ~~must be adopted retrospectively, wherein~~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 ~~each period presented should~~expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be ~~adjusted~~adopted using a modified retrospective approach. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to ~~reflect~~Consolidated Financial Statements.

In January 2016, the ~~new guidance.~~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 is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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, 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 is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.


(3)	Property, Plant and Equipment, Net

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



		As of
	Depreciable	September 30,			December 31,
	Life	2016			2015
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	70,316		$	69,248
Interstate natural gas pipeline assets	3-80 years	6,866			6,755
		77,182			76,003
Accumulated depreciation and amortization		(23,305		)	(22,682		)
Regulated assets, net		53,877			53,321

Nonregulated assets:
Independent power plants	5-30 years	5,073			4,751
Other assets	3-30 years	983			875
		6,056			5,626
Accumulated depreciation and amortization		(1,000		)	(805		)
Nonregulated assets, net		5,056			4,821

Net operating assets		58,933			58,142
Construction work-in-progress		3,175			2,627
Property, plant and equipment, net		$	62,108		$	60,769

Construction work-in-progress includes $2.6 billion as of September 30, 2016 and $2.3 billion as of December 31, 2015, related to the construction of regulated assets.


(4)	Regulatory Matters

In November 2014, ALP filed a general tariff application ("GTA") asking the Alberta Utilities Commission ("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 Alberta Electric System Operator. ALP amended the GTA in June 2015 to propose transmission tariff relief measures for customers and modifications to its capital structure. ALP also amended the GTA in October 2015. In May 2016, the AUC issued Decision 3524-D01-2016 pertaining to the 2015-2016 GTA. ALP filed its 2015-2016 GTA compliance filing in July 2016 in response to the AUC's decision. Following the AUC's assessment of whether the refiling complies with the decision, final transmission tariff rates for the 2015 and 2016 test years will be set, subject to further adjustment through the deferral account reconciliation process.

The compliance filing asks 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 compliance filing, as compared to the original 2015-2016 GTA filing in November 2014, were based on changes to several key components considered in Decision 3524-D01-2016. Among other things, the AUC approved 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.

In July 2016, ALP also submitted a separate transmission tariff application requesting approval from the AUC to reduce the 2016 interim refundable tariff from C$61 million per month to C$12 million per month for the period August 1, 2016 to December 31, 2016, in alignment with its compliance filing. The AUC approved the reduced 2016 monthly interim refundable tariff amount in August 2016.

Operating revenue for the nine-month period ended September 30, 2016, included a one-time reduction of $200 million from the 2015-2016 GTA decision received in May 2016 at ALP. The decision requires ALP to refund $200 million to customers by the end of 2016 through reduced monthly billings for the change from receiving cash during construction for the return on CWIP 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 higher capitalized interest and allowance for equity funds in the Consolidated Statements of Operations. In addition, the decision requires ALP to change to the flow through method of recognizing income tax expense effective January 1, 2016. This change reduced operating revenue by $11 million and $36 million, respectively, for the three- and nine-month periods ended September 30, 2016, with offsetting impacts to income tax expense in the Consolidated Statements of Operations.


(5)	Investments and Restricted Cash and Investments

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



	As of
	September 30,		December 31,
	2016		2015
Investments:
BYD Company Limited common stock	$	1,477	$	1,238
Rabbi trusts	398		380
Other	162		130
Total investments	2,037		1,748

Equity method investments:
Electric Transmission Texas, LLC	647		585
BHE Renewables tax equity investments	635		168
Bridger Coal Company	168		190
Other	157		160
Total equity method investments	1,607		1,103

Restricted cash and investments:
Quad Cities Station nuclear decommissioning trust funds	454		429
Solar Star and Topaz Projects	116		95
Other	161		129
Total restricted cash and investments	731		653

Total investments and restricted cash and investments	$	4,375	$	3,504

Reflected as:
Current assets	$	228	$	137
Noncurrent assets	4,147		3,367
Total investments and restricted cash and investments	$	4,375	$	3,504

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 accumulated other comprehensive income (loss) ("AOCI"). The fair value of BHE's investment in BYD Company Limited common stock reflects a pre-tax unrealized gain of $1.2 billion and $1.0 billion as of September 30, 2016 and December 31, 2015, respectively.


(6)	Recent Financing Transactions

Long-Term Debt

In September and March 2016, BHE repaid at par value a total of $1 billion, plus accrued interest, of its junior subordinated debentures due December 2043, and in June 2016, BHE repaid at par value $500 million, plus accrued interest, of its junior subordinated debentures due December 2044.

In June 2016, Marshall Wind Energy, LLC issued a $95 million Term Loan due June 2026 with principal payments beginning December 2016. The Term Loan has an underlying variable interest rate based on London Interbank Offered Rate ("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 May 2016, ALP issued C$350 million of its 2.747% Series 2016-1 Medium-Term Notes due May 2026. The net proceeds were used to repay short-term debt.

In May 2016, Sierra Pacific issued $205 million of its variable-rate tax-exempt Revenue Bonds due 2029-2036 and $139 million of its 1.25%-3.00% Revenue Bonds due 2029-2036. Sierra Pacific also purchased $125 million of the variable-rate tax-exempt Revenue Bonds due 2029-2036 on their date of issuance to hold for its own account and potential remarketing to the public at a future date. To provide collateral security for its obligations, Sierra Pacific issued its General and Refunding Securities, Series V, Nos. V-1, V-2 and V-3, in the collective amount of $344 million. The collective proceeds from the tax-exempt bond issuances were used in April and May 2016 to refund at par value, plus accrued interest, $349 million of tax-exempt Revenue Bonds due 2029-2036 previously issued on behalf of Sierra Pacific.

In April 2016, Sierra Pacific issued $400 million of its 2.60% General and Refunding Securities, Series U, due May 2026. The net proceeds were used, together with cash on hand, to pay at maturity the $450 million principal amount of 6.00% General and Refunding Securities, Series M, in May 2016.

Credit Facilities

In June 2016, BHE replaced its $1.4 billion and $600 million unsecured revolving credit facilities, which had been set to expire in June 2017, with a $2.0 billion unsecured credit facility with a stated maturity of June 2019 and two one-year extension options subject to bank consent. The credit facility, which is for general corporate purposes and also supports BHE's commercial paper program and provides for the issuance of letters of credit, has a variable interest rate based on the LIBOR or a base rate, at BHE's option, plus a spread that varies based on BHE's senior unsecured long-term debt credit ratings. The credit facility requires that BHE's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.70 to 1.0 as of the last day of each quarter.

In June 2016, PacifiCorp replaced its $600 million unsecured revolving credit facility, which had been set to expire in June 2017, with a $400 million unsecured credit facility with a stated maturity of June 2019 and two one-year extension options subject to bank consent. The credit facility, which supports PacifiCorp's commercial paper program, certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the LIBOR or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. The credit facility requires that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter. As of September 30, 2016, PacifiCorp had no borrowings outstanding or letters of credit issued under this credit facility.

In March 2016, Solar Star Funding, LLC amended its $320 million letter of credit facility reducing the amount available to $301 million and extending the maturity date to March 2026. As of September 30, 2016, Solar Star Funding, LLC had $284 million of letters of credit issued under this facility.


(7)	Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:



	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2016		2015		2016		2015

Federal statutory income tax rate	35	%	35	%	35	%	35	%
Income tax credits	(16	)	(9	)	(15	)	(11	)
State income tax, net of federal income tax benefit	—		—		—		1
Income tax effect of foreign income	(3	)	(1	)	(4	)	(4	)
Equity income	1		1		1		1
Other, net	(1	)	(2	)	—		(1	)
Effective income tax rate	16	%	24	%	17	%	21	%

Income tax credits relate primarily to production tax credits from wind-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

Income tax effect of foreign income includes, among other items, deferred income tax benefits of $16 million recognized in September 2016 upon the enactment of a reduction in the United Kingdom corporate income tax rate from 18% to 17% effective April 1, 2020.

Berkshire Hathaway includes the Company in its United States federal income tax return. For the nine-month periods ended September 30, 2016 and 2015, the Company received net cash payments for income taxes from Berkshire Hathaway totaling $860 million and $1.8 billion, respectively.


(8)	Employee Benefit Plans

Domestic Operations

Net periodic benefit cost for the domestic pension and other postretirement benefit plans included the following components (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015
Pension:
Service cost	$	7		$	8		$	22		$	24
Interest cost	31			30			94			91
Expected return on plan assets	(39		)	(42		)	(120		)	(127		)
Net amortization	12			13			36			41
Net periodic benefit cost	$	11		$	9		$	32		$	29
										��
Other postretirement:
Service cost	$	2		$	2		$	7		$	8
Interest cost	7			6			23			22
Expected return on plan assets	(10		)	(10		)	(31		)	(33		)
Net amortization	(2		)	(1		)	(9		)	(7		)
Net periodic benefit credit	$	(3	)	$	(3	)	$	(10	)	$	(10	)

Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $77 million and $1 million, respectively, during 2016. As of September 30, 2016, $73 million and $1 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

Net periodic benefit cost for the United Kingdom pension plan included the following components (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015

Service cost	$	5		$	6		$	16		$	18
Interest cost	17			20			55			60
Expected return on plan assets	(27		)	(29		)	(85		)	(87		)
Net amortization	11			17			34			49
Net periodic benefit cost	$	6		$	14		$	20		$	40

Employer contributions to the United Kingdom pension plan are expected to be £41 million during 2016. As of September 30, 2016, £31 million, or $44 million, of contributions had been made to the United Kingdom pension plan.

(9) Asset Retirement Obligation

MidAmerican Energy estimates its asset retirement obligation ("ARO") liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work. During the nine-month period ended September 30, 2016, MidAmerican Energy recorded an increase of $69 million to its ARO liability for the decommissioning of Quad Cities Generating Station Units 1 and 2 as a result of an updated decommissioning study reflecting changes in the estimated amount and timing of cash flow.


(10)	Risk Management and Hedging Activities

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 PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company (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 debt, future debt issuances and mortgage commitments. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain and Canada. The Company does not engage in a material amount of proprietary trading activities.

Each of the Company'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. 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 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.

There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Note 11 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of the Company's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):



	Other					Other			Other
	Current			Other		Current			Long-term
	Assets			Assets		Liabilities			Liabilities			Total
As of September 30, 2016
Not designated as hedging contracts:
Commodity assets⁽¹⁾	$	15		$	81	$	11		$	2		$	109
Commodity liabilities⁽¹⁾	(3		)	—		(66		)	(164		)	(233		)
Interest rate assets	12			—		—			—			12
Interest rate liabilities	—			—		(6		)	(14		)	(20		)
Total	24			81		(61		)	(176		)	(132		)

Designated as hedging contracts:
Commodity assets	—			—		1			1			2
Commodity liabilities	—			—		(21		)	(16		)	(37		)
Interest rate assets	—			—		—			—			—
Interest rate liabilities	—			—		(4		)	(7		)	(11		)
Total	—			—		(24		)	(22		)	(46		)

Total derivatives	24			81		(85		)	(198		)	(178		)
Cash collateral receivable	—			—		20			65			85
Total derivatives - net basis	$	24		$	81	$	(65	)	$	(133	)	$	(93	)



	Other					Other			Other
	Current			Other		Current			Long-term
	Assets			Assets		Liabilities			Liabilities			Total
As of December 31, 2015
Not designated as hedging contracts:
Commodity assets⁽¹⁾	$	25		$	72	$	7		$	2		$	106
Commodity liabilities⁽¹⁾	(4		)	—		(113		)	(175		)	(292		)
Interest rate assets	7			—		—			—			7
Interest rate liabilities	—			—		(3		)	(6		)	(9		)
Total	28			72		(109		)	(179		)	(188		)

Designated as hedging contracts:
Commodity assets	—			—		1			2			3
Commodity liabilities	—			—		(33		)	(17		)	(50		)
Interest rate assets	—			3		—			—			3
Interest rate liabilities	—			—		(4		)	(1		)	(5		)
Total	—			3		(36		)	(16		)	(49		)

Total derivatives	28			75		(145		)	(195		)	(237		)
Cash collateral receivable	—			—		40			63			103
Total derivatives - net basis	$	28		$	75	$	(105	)	$	(132	)	$	(134	)

(1)

The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of September 30, 2016 and December 31, 2015, a net regulatory asset of $195 million and $250 million, respectively, was recorded related to the net derivative liability of $124 million and $186 million, respectively. The difference between the net regulatory asset and the net derivative liability relates primarily to a power purchase agreement derivative at BHE Renewables.

Not Designated as Hedging Contracts

The following table reconciles the beginning and ending balances of the Company's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015

Beginning balance	$	185		$	233		$	250		$	223
Changes in fair value recognized in net regulatory assets	18			47			5			104
Net losses reclassified to operating revenue	(3		)	(11		)	(6		)	(4		)
Net losses reclassified to cost of sales	(5		)	(16		)	(54		)	(70		)
Ending balance	$	195		$	253		$	195		$	253

Designated as Hedging Contracts

The Company uses commodity derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions. Certain commodity derivative contracts have settled and the fair value at the date of settlement remains in AOCI and is recognized in earnings when the forecasted transactions impact earnings. The following table reconciles the beginning and ending balances of the Company's accumulated other comprehensive (income) loss (pre-tax) and summarizes pre-tax gains and losses on commodity derivative contracts designated and qualifying as cash flow hedges recognized in other comprehensive income ("OCI"), as well as amounts reclassified to earnings (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015

Beginning balance	$	26		$	38		$	46		$	32
Changes in fair value recognized in OCI	15			20			35			37
Net gains reclassified to operating revenue	1			1			1			4
Net losses reclassified to cost of sales	(7		)	(14		)	(47		)	(28		)
Ending balance	$	35		$	45		$	35		$	45

Realized gains and losses on hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales, operating expense or interest expense depending upon the nature of the item being hedged. For the three- and nine-month periods ended September 30, 2016 and 2015, hedge ineffectiveness was insignificant. As of September 30, 2016, the Company had cash flow hedges with expiration dates extending through June 2026 and $24 million of pre-tax unrealized losses are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):



	Unit of	September 30,		December 31,
	Measure	2016		2015
Electricity purchases	Megawatt hours	2		10
Natural gas purchases	Decatherms	321		317
Fuel purchases	Gallons	3		11
Interest rate swaps	US$	730		653
Mortgage sale commitments, net	US$	(375	)	(312	)

Credit Risk

The Utilities are exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent the Utilities' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Utilities analyze the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale 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 derivative contracts 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 September 30, 2016, the applicable credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $227 million and $288 million as of September 30, 2016 and December 31, 2015, respectively, for which the Company had posted collateral of $73 million and $75 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2016 and December 31, 2015, the Company would have been required to post $139 million and $198 million, respectively, 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.


(11)	Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 — Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

The following table presents the Company's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):



	Input Levels for Fair Value Measurements
	Level 1			Level 2			Level 3			Other⁽¹⁾			Total
As of September 30, 2016
Assets:
Commodity derivatives	$	1		$	22		$	88		$	(18	)	$	93
Interest rate derivatives	—			1			11			—			12
Mortgage loans held for sale	—			443			—			—			443
Money market mutual funds⁽²⁾	557			—			—			—			557
Debt securities:
United States government obligations	156			—			—			—			156
International government obligations	—			3			—			—			3
Corporate obligations	—			36			—			—			36
Municipal obligations	—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			2			—			—			2
Auction rate securities	—			—			18			—			18
Equity securities:
United States companies	249			—			—			—			249
International companies	1,483			—			—			—			1,483
Investment funds	174			—			—			—			174
	$	2,620		$	509		$	117		$	(18	)	$	3,228
Liabilities:
Commodity derivatives	$	(4	)	$	(234	)	$	(32	)	$	103		$	(167	)
Interest rate derivatives	(1		)	(30		)	—			—			(31		)
	$	(5	)	$	(264	)	$	(32	)	$	103		$	(198	)



As of December 31, 2015
Assets:
Commodity derivatives	$	—		$	16		$	93		$	(16	)	$	93
Interest rate derivatives	—			5			5			—			10
Mortgage loans held for sale	—			327			—			—			327
Money market mutual funds⁽²⁾	421			—			—			—			421
Debt securities:
United States government obligations	133			—			—			—			133
International government obligations	—			2			—			—			2
Corporate obligations	—			39			—			—			39
Municipal obligations	—			1			—			—			1
Agency, asset and mortgage-backed obligations	—			3			—			—			3
Auction rate securities	—			—			44			—			44
Equity securities:
United States companies	239			—			—			—			239
International companies	1,244			—			—			—			1,244
Investment funds	136			—			—			—			136
	$	2,173		$	393		$	142		$	(16	)	$	2,692
Liabilities:
Commodity derivatives	$	(13	)	$	(283	)	$	(46	)	$	119		$	(223	)
Interest rate derivatives	—			(13		)	(1		)	—			(14		)
	$	(13	)	$	(296	)	$	(47	)	$	119		$	(237	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $85 million and $103 million as of September 30, 2016 and December 31, 2015, respectively.


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

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. 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. Refer to Note 10 for further discussion regarding the Company's risk management and hedging activities.

The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.

The Company's investments in money market mutual funds and debt and equity securities are stated at fair value and are primarily accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics. The fair value of the Company's investments in auction rate securities, where there is no current liquid market, is determined using pricing models based on available observable market data and the Company's judgment about the assumptions, including liquidity and nonperformance risks, which market participants would use when pricing the asset.

The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):



	Three-Month Periods								Nine-Month Periods
	Ended September 30,								Ended September 30,
				Interest			Auction					Interest			Auction
	Commodity			Rate			Rate		Commodity			Rate			Rate
	Derivatives			Derivatives			Securities		Derivatives			Derivatives			Securities
2016:
Beginning balance	$	44		$	14		$	18	$	47		$	4		$	44
Changes included in earnings	9			49			—		8			103			—
Changes in fair value recognized in OCI	(2		)	—			—		(2		)	—			6
Changes in fair value recognized in net regulatory assets	(1		)	—			—		(12		)	—			—
Purchases	1			—			—		1			—			—
Redemptions	—			—			—		—			—			(32		)
Settlements	5			(52		)	—		14			(96		)	—
Ending balance	$	56		$	11		$	18	$	56		$	11		$	18



	Three-Month Periods									Nine-Month Periods
	Ended September 30,									Ended September 30,
				Interest			Auction						Interest			Auction
	Commodity			Rate			Rate			Commodity			Rate			Rate
	Derivatives			Derivatives			Securities			Derivatives			Derivatives			Securities
2015:
Beginning balance	$	34		$	5		$	45		$	51		$	—		$	45
Changes included in earnings	6			25			—			17			70			—
Changes in fair value recognized in OCI	(2		)	—			(1		)	(5		)	—			(1		)
Changes in fair value recognized in net regulatory assets	(4		)	—			—			(21		)	—			—
Purchases	—			—			—			1			—			—
Settlements	9			(23		)	—			—			(66		)	—
Transfers from Level 2	—			—			—			—			3			—
Ending balance	$	43		$	7		$	44		$	43		$	7		$	44

The Company's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):



	As of September 30, 2016				As of December 31, 2015
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	36,203	$	42,970	$	37,972	$	41,785


(12)	Commitments and Contingencies

Legal Matters

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company 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 and are described below.

USA Power

In October 2005, prior to BHE's ownership of PacifiCorp, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in the Third District Court of Salt Lake County, Utah ("Third District Court") by USA Power, LLC, USA Power Partners, LLC and Spring Canyon Energy, LLC (collectively, the "Plaintiff"). The Plaintiff's complaint alleged that PacifiCorp misappropriated confidential proprietary information in violation of Utah's Uniform Trade Secrets Act and accused PacifiCorp of breach of contract and related claims in regard to the Plaintiff's 2002 and 2003 proposals to build a natural gas-fueled generating facility in Juab County, Utah. In October 2007, the Third District Court granted PacifiCorp's motion for summary judgment on all counts and dismissed the Plaintiff's claims in their entirety. In a May 2010 ruling on the Plaintiff's petition for reconsideration, the Utah Supreme Court reversed summary judgment and remanded the case back to the Third District Court for further consideration. In May 2012, a jury awarded damages to the Plaintiff for breach of contract and misappropriation of a trade secret in the amounts of $18 million for actual damages and $113 million for unjust enrichment. After considering various motions filed by the parties to expand or limit damages, interest and attorney's fees, in May 2013, the court entered a final judgment against PacifiCorp in the amount of $115 million, which includes the $113 million of aggregate damages previously awarded and amounts awarded for the Plaintiff's attorneys' fees. The final judgment also ordered that postjudgment interest accrue beginning as of the date of the April 2013 initial judgment. In May 2013, PacifiCorp posted a surety bond issued by a subsidiary of Berkshire Hathaway to secure its estimated obligation. Both PacifiCorp and the Plaintiff filed appeals with the Utah Supreme Court. The Utah Supreme Court affirmed the district court's decision and denied the issues appealed by all parties. In May 2016, PacifiCorp paid $123 million for the final judgment and postjudgment interest.

Environmental Laws and Regulations

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

Hydroelectric Relicensing

PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with the Federal Energy Regulatory Commission ("FERC"). In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the state of California, the state of Oregon and various other governmental and non-governmental settlement parties signed the Klamath Hydroelectric Settlement Agreement ("KHSA"). Among other things, the KHSA provided that the United States Department of the Interior would conduct scientific and engineering studies to assess whether removal of the Klamath hydroelectric system's mainstem dams was in the public interest and would advance restoration of the Klamath Basin's salmonid fisheries. If it was determined that dam removal should proceed, dam removal would have begun no earlier than 2020.

Under the KHSA, PacifiCorp and its customers were protected from uncapped dam removal costs and liabilities. For dam removal to occur, federal legislation consistent with the KHSA was required to provide, among other things, protection for PacifiCorp from all liabilities associated with dam removal activities. As of December 31, 2015, no federal legislation had been enacted, and several parties to the KHSA initiated a dispute resolution process.

In February 2016, the principal parties to the KHSA (PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and Commerce) executed an agreement in principle committing to explore potential amendment of the KHSA to facilitate removal of the Klamath dams through a FERC process without the need for federal legislation. Since that time, PacifiCorp, the states of California and Oregon, and the United States Departments of the Interior and Commerce have negotiated an amendment to the KHSA that was signed on April 6, 2016. Consistent with the terms of the amended KHSA, on September 23, 2016, PacifiCorp and the Klamath River Renewal Corporation ("KRRC") jointly filed an application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilities from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with the FERC to surrender the license and decommission the facilities, but the application included a request for the FERC to refrain from acting on the surrender application until after the transfer of the license to the KRRC is effective.

Under the amended KHSA, the KRRC must indemnify PacifiCorp from liabilities associated with dam removal. The amended KHSA also limits PacifiCorp's contribution to facilities removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measure in November 2014 from which the state of California's contribution toward facilities removal costs will be drawn. In accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the California state budget in 2016, with the funding effective for at least five years. If facilities removal costs exceed the combined funding that will be available from PacifiCorp's Oregon and California customers and the state of California, sufficient funds would need to be provided by the KRRC or an entity other than PacifiCorp in order for facilities removal to proceed.

If certain conditions in the amended KHSA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.

Guarantees

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


(13)	Components of Other Comprehensive Income (Loss), Net

The following table shows the change in AOCI attributable to BHE shareholders by each component of OCI, net of applicable income taxes (in millions):



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

Balance, December 31, 2014	$	(490	)	$	(412	)	$	390	$	18		$	(494	)
Other comprehensive income (loss)	10			(479		)	179		(13		)	(303		)
Balance, September 30, 2015	$	(480	)	$	(891	)	$	569	$	5		$	(797	)

Balance, December 31, 2015	$	(438	)	$	(1,092	)	$	615	$	7		$	(908	)
Other comprehensive income (loss)	80			(339		)	151		(2		)	(110		)
Balance, September 30, 2016	$	(358	)	$	(1,431	)	$	766	$	5		$	(1,018	)

Reclassifications from AOCI to net income for the periods ended September 30, 2016 and 2015 were insignificant. For information regarding cash flow hedge reclassifications from AOCI to net income in their entirety, refer to Note 10. Additionally, refer to the "Foreign Operations" discussion in Note 8 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.


(14)	Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Effective January 1, 2016, MidAmerican Energy transferred the assets and liabilities of its unregulated retail services business to MidAmerican Energy Services, LLC, a subsidiary of BHE. Prior period amounts have been changed to reflect this activity in BHE and Other. Information related to the Company's reportable segments is shown below (in millions):



	Three-Month Periods					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2016		2015			2016		2015
Operating revenue:
PacifiCorp	$	1,434	$	1,423		$	3,919	$	3,942
MidAmerican Funding	797		681			2,008		1,984
NV Energy	987		1,124			2,309		2,665
Northern Powergrid	220		265			748		852
BHE Pipeline Group	201		196			704		736
BHE Transmission⁽¹⁾	169		153			309		428
BHE Renewables	273		269			582		583
HomeServices	820		745			2,152		1,951
BHE and Other⁽²⁾	191		213			523		597
Total operating revenue	$	5,092	$	5,069		$	13,254	$	13,738

Depreciation and amortization:
PacifiCorp	$	193	$	194		$	589	$	584
MidAmerican Funding	118		101			338		300
NV Energy	106		103			315		307
Northern Powergrid	49		50			149		148
BHE Pipeline Group	53		51			160		151
BHE Transmission	61		56			177		147
BHE Renewables	57		55			169		160
HomeServices	9		8			24		20
BHE and Other⁽²⁾	2		(1		)	1		(3		)
Total depreciation and amortization	$	648	$	617		$	1,922	$	1,814



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015
Operating income:
PacifiCorp	$	445		$	437		$	1,108		$	1,037
MidAmerican Funding	284			209			524			422
NV Energy	394			398			656			697
Northern Powergrid	90			129			373			452
BHE Pipeline Group	68			66			320			322
BHE Transmission⁽¹⁾	81			62			35			166
BHE Renewables	157			153			233			225
HomeServices	87			78			179			161
BHE and Other⁽²⁾	(21		)	4			(36		)	(9		)
Total operating income	1,585			1,536			3,392			3,473
Interest expense	(460		)	(475		)	(1,401		)	(1,423		)
Capitalized interest⁽¹⁾	14			18			128			69
Allowance for equity funds⁽¹⁾	17			23			147			84
Interest and dividend income	39			27			93			79
Other, net	15			(9		)	26			27
Total income before income tax expense and equity income	$	1,210		$	1,120		$	2,385		$	2,309



Interest expense:
PacifiCorp	$	95	$	97	$	286	$	287
MidAmerican Funding	55		50		164		150
NV Energy	60		67		190		195
Northern Powergrid	33		37		105		108
BHE Pipeline Group	13		16		39		51
BHE Transmission	40		37		114		110
BHE Renewables	51		49		148		144
HomeServices	1		1		2		3
BHE and Other⁽²⁾	112		121		353		375
Total interest expense	$	460	$	475	$	1,401	$	1,423



Operating revenue by country:
United States	$	4,697	$	4,643	$	12,185	$	12,444
United Kingdom	220		265		748		852
Canada⁽¹⁾	170		154		313		434
Philippines and other	5		7		8		8
Total operating revenue by country	$	5,092	$	5,069	$	13,254	$	13,738



Income before income tax expense and equity income by country:
United States	$	1,089	$	962	$	1,945	$	1,785
United Kingdom	74		98		284		364
Canada	43		41		114		119
Philippines and other	4		19		42		41
Total income before income tax expense and equity income by country	$	1,210	$	1,120	$	2,385	$	2,309



	As of
	September 30,		December 31,
	2016		2015
Total assets:
PacifiCorp	$	23,557	$	23,550
MidAmerican Funding	17,199		16,315
NV Energy	14,424		14,656
Northern Powergrid	6,727		7,317
BHE Pipeline Group	5,115		4,953
BHE Transmission	8,493		7,553
BHE Renewables	6,775		5,892
HomeServices	1,947		1,705
BHE and Other⁽²⁾	1,651		1,677
Total assets	$	85,888	$	83,618


(1)	Refer to Note 4 for information regarding certain regulatory matters impacting AltaLink's financial results for the three- and nine-month periods ended September 30, 2016.


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

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2016 (in millions):



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

December 31, 2015	$	1,129	$	2,102	$	2,369	$	1,056		$	101		$	1,428	$	95	$	794	$	2		$	9,076
Acquisitions	—		—		—		—			—			4		—		41		1			46
Foreign currency translation	—		—		—		(92		)	—			77		—		—		(3		)	(18		)
Other	—		—		—		—			(19		)	—		—		—		—			(19		)
September 30, 2016	$	1,129	$	2,102	$	2,369	$	964		$	82		$	1,509	$	95	$	835	$	—		$	9,085


Item 2.	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 the Company's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.

The Company's operations are organized and managed as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of Northern Natural Gas and Kern River), BHE Transmission (which consists of AltaLink and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these 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 selling power generated from solar, wind, geothermal and hydroelectric sources under long-term contracts, 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. 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 and Other, relate principally to other entities, corporate functions and intersegment eliminations. Effective January 1, 2016, MidAmerican Energy transferred the assets and liabilities of its unregulated retail services business to MidAmerican Energy Services, LLC, a subsidiary of BHE. Prior period amounts have been changed to reflect this activity in BHE and Other.

Results of Operations for the Third Quarter and First Nine Months of 2016 and 2015

Overview

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



	Third Quarter											First Nine Months
	2016			2015			Change					2016			2015			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	254		$	245		$	9		4	%	$	596		$	551		$	45		8	%
MidAmerican Funding	318			230			88			38		518			449			69			15
NV Energy	222			219			3			1		319			341			(22		)	(6	)
Northern Powergrid	60			77			(17		)	(22	)	228			281			(53		)	(19	)
BHE Pipeline Group	36			32			4			13		175			168			7			4
BHE Transmission	57			46			11			24		173			137			36			26
BHE Renewables	98			74			24			32		142			109			33			30
HomeServices	49			44			5			11		105			91			14			15
BHE and Other	(58		)	(93		)	35			38		(194		)	(226		)	32			14
Total net income attributable to BHE shareholders	$	1,036		$	874		$	162		19		$	2,062		$	1,901		$	161		8

Net income attributable to BHE shareholders increased $162 million for the third quarter of 2016 compared to 2015 due to the following:

PacifiCorp's net income increased $9 million primarily due to higher margins of $24 million, partially offset by higher operations and maintenance expense of $12 million. Margins increased primarily due to lower purchased electricity costs, higher retail revenue and lower average cost of natural gas, partially offset by higher coal costs and lower wholesale electricity revenue. Retail customer load increased by 1.0% due to an increase in the average number of residential and commercial customers primarily in Utah, the impacts of weather on residential customer load and increased usage from irrigation customers, partially offset by lower commercial and residential customer usage.

MidAmerican Funding's net income increased $88 million due to higher electric margins of $102 million and higher recognized production tax credits of $39 million, partially offset by higher depreciation and amortization of $17 million due to plant placed in-service and an accrual related to an Iowa regulatory revenue sharing arrangement, higher interest expense of $5 million primarily due to the issuance of first mortgage bonds in October 2015 and higher income taxes on higher pre-tax income. Electric margins reflect higher retail sales volumes, higher recoveries through bill riders, higher wholesale revenue, higher retail rates in Iowa and higher transmission revenue, partially offset by higher energy costs.

NV Energy's net income increased $3 million due to lower interest expense of $7 million, higher other income of $3 million and higher electric margins of $1 million, partially offset by higher operating expense of $3 million and higher depreciation and amortization of $3 million due to higher plant in-service. Electric margins increased due to customer growth, partially offset by the impacts of weather.

Northern Powergrid's net income decreased $17 million largely due to net asset provisions at the CE Gas business of $16 million, the stronger United States dollar of $11 million, and higher depreciation of $7 million from additional assets placed in-service, partially offset by lower income tax expense of $17 million from deferred income tax benefits due to a 1% reduction in the United Kingdom corporate income tax rate. Higher tariff rates were more than offset by the recovery in 2015 of the December 2013 customer rebate, unfavorable movements in regulatory provisions and lower units distributed.

BHE Pipeline Group's net income increased $4 million due to higher transportation revenues from expansion projects and lower interest expense due to the early redemption in December 2015 of the 6.676% Senior Notes at Kern River, partially offset by higher depreciation expense.

BHE Transmission's net income increased $11 million from higher earnings at AltaLink of $10 million primarily due to additional assets placed in-service and a favorable regulatory decision and from higher earnings at BHE U.S. Transmission of $1 million primarily due to higher equity earnings at Electric Transmission Texas, LLC from continued investment and additional plant placed in-service.

BHE Renewables' net income increased $24 million primarily due to three tax equity investments reaching commercial operations, favorable changes in the valuations of a power purchase agreement derivative and interest rate swaps and higher production at wind projects, partially offset by lower revenue at Imperial Valley and the Solar Star projects.

HomeServices' net income increased $5 million due to higher earnings at mortgage businesses from improved revenues.

BHE and Other net loss improved $35 million due primarily to an increase in federal income tax credits recognized on a consolidated basis, higher investment returns and lower interest expense, partially offset by higher other operating costs.

Net income attributable to BHE shareholders increased $161 million for the first nine months of 2016 compared to 2015 due to the following:

PacifiCorp's net income increased $45 million due to higher margins of $86 million, partially offset by lower AFUDC of $7 million and higher depreciation and amortization of $5 million. Margins increased primarily due to higher retail revenue, lower coal-fueled generation, lower purchased electricity costs and lower natural gas costs, partially offset by lower wholesale electricity revenue and higher coal costs. Retail customer load decreased by 0.4% due to lower commercial and industrial customer usage, partially offset by an increase in the average number of residential and commercial customers and higher residential customer usage, including the impacts of weather.

MidAmerican Funding's net income increased $69 million due to higher electric margins of $139 million, higher recognized production tax credits of $33 million, lower fossil-fueled generation maintenance of $11 million and lower electric distribution costs of $4 million, partially offset by higher depreciation and amortization of $38 million from wind-powered generation and other plant placed in-service and an accrual related to an Iowa regulatory revenue sharing arrangement, higher interest expense of $14 million primarily due to the issuance of first mortgage bonds in October 2015, a pre-tax gain of $13 million in 2015 on the sale of a generating facility lease and higher income taxes on higher pre-tax income. Electric margins reflect higher retail sales volumes, lower energy costs, higher retail rates in Iowa and higher transmission revenue, partially offset by lower wholesale revenue.

NV Energy's net income decreased $22 million due to higher operating expense of $40 million and higher depreciation and amortization of $8 million due to higher plant in-service, partially offset by higher electric margins of $8 million and lower interest expense of $5 million. Operating expense increased due to benefits from changes in contingent liabilities in 2015, higher planned maintenance and other generating costs and higher property and other taxes. Electric margins increased primarily due to the impacts of weather and customer growth.

Northern Powergrid's net income decreased $53 million due to lower distribution revenues mainly reflecting the impact of the new price control period effective April 1, 2015, the stronger United States dollar of $21 million, net asset provisions at the CE Gas business of $16 million, and higher depreciation of $16 million from additional assets placed in-service, partially offset by lower pension costs.

BHE Pipeline Group's net income increased $7 million due to lower operating expenses from the timing of overhauls and pipeline integrity projects and lower interest expense due to the early redemption in December 2015 of the 6.676% Senior Notes at Kern River, partially offset by lower transportation revenues from lower volumes and rates due to mild winter temperatures and higher depreciation expense.

BHE Transmission's net income increased $36 million from higher earnings at AltaLink of $29 million primarily due to additional assets placed in-service and favorable regulatory decisions, partially offset by the stronger United States dollar of $6 million, and from higher earnings at BHE U.S. Transmission of $7 million primarily due to higher equity earnings at Electric Transmission Texas, LLC from continued investment and additional plant placed in-service.

BHE Renewables' net income increased $33 million due to three tax equity investments reaching commercial operations, higher production at wind projects and lower project acquisition costs, partially offset by lower revenues at the Solar Star project and unfavorable changes in the valuations of the interest rate swaps and a power purchase agreement derivative.

HomeServices' net income increased $14 million due to higher earnings at mortgage businesses from improved revenues.

BHE and Other net loss improved $32 million due to income taxes as an increase in federal income tax credits and deferred state income tax benefits recognized on a consolidated basis were partially offset by favorable United States income taxes on foreign earnings in 2015. Also contributing to the improved results were lower interest expense and higher investment returns.

Reportable Segment Results

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



	Third Quarter									First Nine Months
	2016		2015		Change					2016		2015		Change
Operating revenue:
PacifiCorp	$	1,434	$	1,423	$	11		1	%	$	3,919	$	3,942	$	(23	)	(1	)%
MidAmerican Funding	797		681		116			17		2,008		1,984		24			1
NV Energy	987		1,124		(137		)	(12	)	2,309		2,665		(356		)	(13	)
Northern Powergrid	220		265		(45		)	(17	)	748		852		(104		)	(12	)
BHE Pipeline Group	201		196		5			3		704		736		(32		)	(4	)
BHE Transmission	169		153		16			10		309		428		(119		)	(28	)
BHE Renewables	273		269		4			1		582		583		(1		)	—
HomeServices	820		745		75			10		2,152		1,951		201			10
BHE and Other	191		213		(22		)	(10	)	523		597		(74		)	(12	)
Total operating revenue	$	5,092	$	5,069	$	23		—		$	13,254	$	13,738	$	(484	)	(4	)



Operating income:
PacifiCorp	$	445		$	437	$	8		2	%	$	1,108		$	1,037		$	71		7	%
MidAmerican Funding	284			209		75			36		524			422			102			24
NV Energy	394			398		(4		)	(1	)	656			697			(41		)	(6	)
Northern Powergrid	90			129		(39		)	(30	)	373			452			(79		)	(17	)
BHE Pipeline Group	68			66		2			3		320			322			(2		)	(1	)
BHE Transmission	81			62		19			31		35			166			(131		)	(79	)
BHE Renewables	157			153		4			3		233			225			8			4
HomeServices	87			78		9			12		179			161			18			11
BHE and Other	(21		)	4		(25		)	*		(36		)	(9		)	(27		)	*
Total operating income	$	1,585		$	1,536	$	49		3		$	3,392		$	3,473		$	(81	)	(2	)

* Not meaningful

PacifiCorp

Operating revenue increased $11 million for the third quarter of 2016 compared to 2015 due to higher retail revenue of $28 million, partially offset by lower wholesale and other revenue of $17 million. The increase in retail revenue was due to higher retail customer load of $17 million and higher retail rates of $11 million. Retail customer load increased by 1.0% due to an increase in the average number of residential and commercial customers primarily in Utah, the impacts of weather on residential customer load and increased usage from irrigation customers, partially offset by lower commercial and residential customer usage. Wholesale and other revenue decreased primarily due to lower wholesale prices and volumes.

Operating income increased $8 million for the third quarter of 2016 compared to 2015 primarily due to higher margins of $24 million, partially offset by higher operations and maintenance expense of $12 million. Margins increased due to lower energy costs of $13 million and higher operating revenue of $11 million. Energy costs decreased due to lower purchased electricity costs and lower average cost of natural gas, partially offset by higher coal costs.

Operating revenue decreased $23 million for the first nine months of 2016 compared to 2015 due to lower wholesale and other revenue of $79 million, partially offset by higher retail revenue of $56 million. Wholesale and other revenue decreased primarily due to lower wholesale volumes and lower average wholesale prices. The increase in retail revenue was due to higher rates of $42 million and higher customer load of $14 million. Retail customer load decreased by 0.4% due to lower commercial and industrial customer usage, partially offset by an increase in the average number of residential and commercial customers and higher residential customer usage, including the impacts of weather.

Operating income increased $71 million for the first nine months of 2016 compared to 2015 due to higher margins of $86 million, partially offset by higher depreciation and amortization of $5 million. Margins increased due to lower energy costs of $109 million, partially offset by lower operating revenue of $23 million. Energy costs decreased due to lower coal-fueled generation, lower purchased electricity prices and lower natural gas costs, partially offset by higher purchased electricity volumes and higher coal costs.

MidAmerican Funding

Operating revenue increased $116 million for the third quarter of 2016 compared to 2015 due to higher electric operating revenue of $107 million and higher natural gas operating revenue of $8 million. Electric operating revenue increased due to higher retail revenue of $81 million and higher wholesale and other revenue of $26 million. Retail revenue increased $29 million from higher recoveries through bill riders, which are substantially offset by cost of sales, operating expense and production tax credits, $23 million from non-weather usage factors, including higher industrial sales volumes, $15 million from the impact of warmer temperatures in 2016 and $14 million from higher electric rates in Iowa effective January 1, 2016. Electric retail customer load increased 3.6% from the favorable impact of temperatures and industrial growth. Electric wholesale and other revenue increased due to higher wholesale prices of $13 million, higher wholesale volumes of $7 million and higher transmission revenue of $6 million related to Multi-Value Projects, which are expected to increase as projects are constructed. Natural gas operating revenue increased primarily due to 15.4% higher wholesale volumes and 1.1% higher retail sales volumes.

Operating income increased $75 million for the third quarter of 2016 compared to 2015 due to higher electric operating income. Electric operating income increased primarily due to the higher operating revenue, partially offset by higher depreciation and amortization of $17 million due to wind generation and other plant placed in-service and an accrual related to an Iowa regulatory revenue sharing arrangement, higher operating expense recovered through bill riders of $7 million and higher energy costs of $5 million from higher purchased power costs and higher natural gas-fueled generation, net of lower coal-fueled generation and greater wind-powered generation.

Operating revenue increased $24 million for the first nine months of 2016 compared to 2015 due to higher electric operating revenue of $100 million, partially offset by lower natural gas operating revenue of $69 million and lower other operating revenue of $7 million. Electric operating revenue increased due to higher retail revenue of $96 million and higher wholesale and other revenue of $4 million. Retail revenue increased $35 million from higher electric rates in Iowa effective January 1, 2016, $33 million from non-weather usage factors, including higher industrial sales volumes, $27 million from warmer cooling season temperatures, net of warmer winter temperatures, in 2016, and $1 million from higher recoveries through bill riders. Electric retail customer load increased 2.9% from the favorable impact of temperatures and industrial growth. Electric wholesale and other revenue increased primarily due to higher wholesale prices of $16 million and higher transmission revenue of $13 million related to Multi-Value Projects, which are expected to increase as projects are constructed, partially offset by lower wholesale volumes of $26 million. Natural gas operating revenue decreased due to a lower average per-unit cost of gas sold of $61 million, which is offset in cost of sales, and 6.3% lower retail sales volumes, primarily from warmer winter temperatures in 2016, partially offset by 5.6% higher wholesale volumes. Other operating revenue decreased primarily due to the completion of major projects of a nonregulated utility construction subsidiary in 2015.

Operating income increased $102 million for the first nine months of 2016 compared to 2015 due to higher electric operating income of $105 million, partially offset by lower natural gas operating income of $3 million. Electric operating income increased due to the higher operating revenue, lower energy costs of $39 million reflecting lower coal-fueled generation in part due to greater wind-powered generation, higher purchased power volumes and higher natural gas-fueled generation, lower fossil-fueled generation maintenance of $11 million from planned outages in 2015 and lower electric distribution costs of $4 million, partially offset by higher depreciation and amortization of $38 million due to wind generation and other plant placed in-service and an accrual related to an Iowa regulatory revenue sharing arrangement and higher operating expense recovered through bill riders of $9 million. Natural gas operating income decreased due to the lower retail sales volumes in the first quarter of 2016.

NV Energy

Operating revenue decreased $137 million for the third quarter of 2016 compared to 2015 due to lower electric operating revenue of $132 million and lower natural gas operating revenue of $4 million primarily due to lower energy rates. Electric operating revenue decreased due to lower retail revenue of $127 million and lower wholesale, transmission and other revenue of $5 million. Retail revenue was lower due to $142 million from lower retail rates primarily from lower energy costs which are passed on to customers through deferred energy adjustment mechanisms and $7 million lower customer usage primarily due to the impacts of weather, partially offset by $17 million from higher customer growth and $4 million from higher energy efficiency rate revenue, which is offset in operating expense. Electric retail customer load increased 1.5% compared to 2015.

Operating income decreased $4 million for the third quarter of 2016 compared to 2015 due to higher operating expense of $3 million, due to energy efficiency program costs, and higher depreciation and amortization of $3 million, due to higher plant in-service. The decrease in operating income is offset by higher electric margins of $1 million due to lower electric operating revenue offset by lower energy costs of $133 million. Energy costs decreased due to lower net deferred power costs of $145 million and a lower average cost of fuel for generation of $14 million, partially offset by higher purchased power costs of $26 million.

Operating revenue decreased $356 million for the first nine months of 2016 compared to 2015 due to lower electric operating revenue of $339 million and lower natural gas operating revenue of $14 million primarily due to lower energy rates, partially offset by higher customer usage. Electric operating revenue decreased due to lower retail revenue of $319 million and lower wholesale, transmission and other revenue of $20 million. Retail revenue decreased primarily due to $361 million from lower retail rates primarily from lower energy costs which are passed on to customers through deferred energy adjustment mechanisms, partially offset by $33 million from higher customer growth and $11 million of higher energy efficiency rate revenue, which is offset in operating expense. Electric retail customer load increased 1.4% compared to 2015.

Operating income decreased $41 million for the first nine months of 2016 compared to 2015 due to higher operating expense of $40 million, primarily due to benefits from changes in contingent liabilities in 2015, higher energy efficiency program costs, which is offset in operating revenue, higher planned maintenance and other generating costs, and higher property and other taxes, and higher depreciation and amortization of $8 million, due to higher plant in-service. The decrease in operating income is offset by higher electric margins of $8 million from lower electric operating revenue offset by lower energy costs of $347 million. Energy costs decreased due to lower net deferred power costs of $319 million and a lower average cost of fuel for generation of $82 million, partially offset by higher purchased power costs of $54 million.

Northern Powergrid

Operating revenue decreased $45 million for the third quarter of 2016 compared to 2015 due to the stronger United States dollar of $40 million, lower distribution revenue of $5 million and lower contracting revenue of $5 million, partially offset by higher smart meter revenue of $5 million. Distribution revenue decreased due to the recovery in 2015 of the December 2013 customer rebate of $12 million, unfavorable movements in regulatory provisions of $6 million and lower units distributed of $6 million, partially offset by higher tariff rates of $19 million. Operating income decreased $39 million for the third quarter of 2016 compared to 2015 due to the stronger United States dollar of $16 million, net asset provisions at the CE Gas business of $16 million and higher depreciation expense of $7 million from additional distribution and smart meter assets placed in-service, partially offset by lower pension costs of $4 million.

Operating revenue decreased $104 million for the first nine months of 2016 compared to 2015 due to the stronger United States dollar of $72 million, lower distribution revenues of $37 million and lower contracting revenue of $7 million, partially offset by higher smart meter revenue of $12 million. Distribution revenue decreased due to lower units distributed of $12 million, the recovery in 2015 of the December 2013 customer rebate of $11 million, lower tariff rates of $10 million, mainly reflecting the impact of the new price control period effective April 1, 2015, and unfavorable movements in regulatory provisions of $4 million. Operating income decreased $79 million for the first nine months of 2016 compared to 2015 due to the lower distribution revenue, the stronger United States dollar of $34 million, net asset provisions at the CE Gas business of $16 million and higher depreciation expense of $16 million from additional distribution and smart meter assets in-service, partially offset by the higher smart meter revenue and lower pension costs of $12 million.

BHE Pipeline Group

Operating revenue increased $5 million for the third quarter of 2016 compared to 2015 due higher transportation revenues from expansion projects. Operating income increased $2 million for the third quarter of 2016 compared to 2015 due to the higher transportation revenues, partially offset by higher depreciation expense.

Operating revenue decreased $32 million for the first nine months of 2016 compared to 2015 due to lower gas sales of $24 million at Northern Natural Gas related to system balancing activities, which is largely offset in cost of sales, and lower transportation revenues from lower volumes and rates due to mild temperatures, partially offset by higher storage revenue at Northern Natural Gas due to higher rates. Operating income decreased $2 million for the first nine months of 2016 compared to 2015 due to the lower transportation revenues and higher depreciation, partially offset by the higher storage revenue and lower operating expenses due to the timing of overhauls and pipeline integrity projects.

BHE Transmission

Operating revenue increased $16 million for the third quarter of 2016 compared to 2015 due to $24 million from additional assets placed in-service and recovery of higher costs and $3 million from a regulatory decision at AltaLink that increased its common equity ratio to 37% from 36%, partially offset by AltaLink's change to the flow through method of recognizing income tax expense, effective January 1, 2016, of $11 million, which is offset in income tax expense. Operating income increased $19 million for the third quarter of 2016 compared to 2015 due to the higher operating revenues and lower operating expenses at AltaLink.

Operating revenue decreased $119 million for the first nine months of 2016 compared to 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 $36 million, which is offset in income tax expense, and the stronger United States dollar of $19 million, partially offset by $133 million from additional assets placed in-service and recovery of higher costs and $3 million from a regulatory decision at AltaLink that increased its common equity ratio to 37% from 36%. Operating income decreased $131 million for the first nine months of 2016 compared to 2015 due to the lower operating revenues at AltaLink and the stronger United States dollar of $6 million. The 2015-2016 GTA decision requires AltaLink to refund $200 million to customers by the end of 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 higher capitalized interest and allowance for equity funds.

BHE Renewables

Operating revenue increased $4 million for the third quarter of 2016 compared to 2015 due to higher wind generation at the Pinyon Pines and Jumbo Road projects of $5 million, a favorable change in the valuation of a power purchase agreement derivative of $4 million and additional wind capacity placed in-service of $2 million, partially offset by lower solar generation of $4 million at the Solar Star Project and lower geothermal generation of $2 million. Operating income increased $4 million for the third quarter of 2016 compared to 2015 due to the increase in operating revenue.

Operating revenue decreased $1 million for the first nine months of 2016 compared to 2015 due to lower geothermal generation of $15 million and lower solar generation of $9 million primarily from transformer related forced outages at Solar Star, partially offset by higher wind generation at the Pinyon Pines and Jumbo Road projects of $20 million and additional wind capacity placed in-service of $4 million. Operating income increased $8 million for the first nine months of 2016 compared to 2015 due to lower operating expense of $17 million, partially offset by higher depreciation and amortization of $9 million from additional solar and wind capacity placed in-service. Operating expense decreased due to the scope and timing of maintenance at certain geothermal plants and lower project acquisition costs, partially offset by additional solar and wind capacity placed in-service.

HomeServices

Operating revenue increased $75 million for the third quarter 2016 compared to 2015 due to a 7.2% increase in closed brokerage units and a 1.6% increase in average home sales prices. The increase in operating revenue was due to an increase from existing businesses totaling $15 million and an increase in acquired businesses totaling $60 million. The increase in existing businesses reflects a 0.7% increase in average home sales prices and $12 million of higher mortgage revenue, partially offset by a 0.4% decrease in closed brokerage units. Operating income increased $9 million for the third quarter of 2016 compared to 2015 due to the higher mortgage revenue and from acquired brokerage businesses, partially offset by lower net revenues at existing brokerage businesses.

Operating revenue increased $201 million for the first nine months of 2016 compared to 2015 due to a 9.3% increase in closed brokerage units and a 1.5% increase in average home sales prices. The increase in operating revenue was due to an increase from existing businesses totaling $63 million and an increase in acquired businesses totaling $138 million. The increase in existing businesses reflects a 1.1% increase in closed brokerage units, a 1.9% increase in average home sales prices and $25 million of higher mortgage revenue. Operating income increased $18 million for the first nine months of 2016 compared to 2015 due to the higher mortgage revenue and from acquired brokerage businesses, partially offset by lower net revenues at existing brokerage businesses.

BHE and Other

Operating revenue decreased $22 million for the third quarter of 2016 compared to 2015 due to lower electricity and natural gas volumes and prices at MidAmerican Energy Services, LLC. Operating loss increased $25 million for the third quarter of 2016 compared to 2015 due to higher other operating costs, partially offset by higher margins of $10 million at MidAmerican Energy Services, LLC.

Operating revenue decreased $74 million for the first nine months of 2016 compared to 2015 due to lower electricity volumes and natural gas prices and volumes, partially offset by higher electricity prices, at MidAmerican Energy Services, LLC. Operating loss increased $27 million for the first nine months of 2016 compared to 2015 due to higher other operating costs, partially offset by higher margins of $3 million at MidAmerican Energy Services, LLC.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):



	Third Quarter									First Nine Months
	2016		2015		Change					2016		2015		Change

Subsidiary debt	$	345	$	351	$	(6	)	(2	)%	$	1,042	$	1,038	$	4		—	%
BHE senior debt and other	101		100		1			1		305		304		1			—
BHE junior subordinated debentures	14		24		(10		)	(42	)	54		81		(27		)	(33	)
Total interest expense	$	460	$	475	$	(15	)	(3	)	$	1,401	$	1,423	$	(22	)	(2	)

Interest expense on subsidiary debt decreased $6 million for the third quarter of 2016 compared to 2015 and increased $4 million for the first nine months of 2016 compared to 2015. Net movements in interest expense on subsidiary debt were due to debt issuances at MidAmerican Funding, NV Energy, Northern Powergrid, AltaLink and BHE Renewables, scheduled maturities and principal payments and by the impact of foreign currency exchange rate movements of $6 million and $16 million, respectively.

Interest expense on BHE junior subordinated debentures decreased $10 million for the third quarter of 2016 compared to 2015 and $27 million for the first nine months of 2016 compared to 2015 due to repayments totaling $500 million in each of September 2016, June 2016 and March 2016 as well as $250 million in December 2015 and $600 million in June 2015.

Capitalized Interest

Capitalized interest decreased $4 million for the third quarter of 2016 compared to 2015 due to lower construction work-in-progress balances at AltaLink.

Capitalized interest increased $59 million for the first nine months of 2016 compared to 2015 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 AltaLink, PacifiCorp and BHE Renewables.

Allowance for Equity Funds

Allowance for equity funds decreased $6 million for the third quarter of 2016 compared to 2015 due to lower construction work-in-progress balances at AltaLink.

Allowance for equity funds increased $63 million for the first nine months of 2016 compared to 2015 due to $104 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 PacifiCorp, AltaLink and MidAmerican Energy.

Interest and Dividend Income

Interest and dividend income increased $12 million for the third quarter of 2016 compared to 2015 and $14 million for the first nine months of 2016 compared to 2015 primarily due to a dividend from BYD Company Limited.

Other, net

Other, net increased $24 million for the third quarter of 2016 compared to 2015 primarily due to higher investment returns and favorable movements in the Pinyon Pines interest rate swaps of $6 million.

Other, net decreased $1 million for the first nine months of 2016 compared to 2015 primarily due to a $13 million gain at MidAmerican Funding on the sale of a generating facility lease in 2015 and unfavorable movements in the Pinyon Pines interest rate swaps of $5 million, partially offset by higher investment returns.

Income Tax Expense

Income tax expense decreased $70 million for the third quarter of 2016 compared to 2015 and the effective tax rate was 16% for 2016 and 24% for 2015. The effective tax rate decreased due to higher production tax credits recognized of $93 million, deferred income tax benefits of $16 million due to a 1% reduction in the United Kingdom corporate income tax rate and favorable impacts of rate making, partially offset by higher income tax expense on higher pre-tax income.

Income tax expense decreased $80 million for the first nine months of 2016 compared to 2015 and the effective tax rate was 17% for 2016 and 21% for 2015. The effective tax rate decreased due to higher production tax credits recognized of $101 million, favorable deferred state income tax benefits of $29 million, deferred income tax benefits of $16 million due to a 1% reduction in the United Kingdom corporate income tax rate and favorable impacts of rate making of $16 million, partially offset by favorable United States income taxes on foreign earnings in 2015.

Equity Income

Equity income increased $3 million for the third quarter of 2016 compared to 2015 due to higher equity earnings of $2 million at Electric Transmission Texas, LLC from continued investment and additional plant placed in-service.

Equity income increased $7 million for the first nine months of 2016 compared to 2015 due to higher equity earnings of $11 million at Electric Transmission Texas, LLC from continued investment and additional plant placed in-service, partially offset by a loss of $7 million from tax equity investments at BHE Renewables.

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. Refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2015 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums.

As of September 30, 2016, the Company's total net liquidity was as follows (in millions):



							MidAmerican			NV			Northern
	BHE			PacifiCorp			Funding			Energy			Powergrid			AltaLink			Other			Total

Cash and cash equivalents	$	73		$	198		$	51		$	357		$	4		$	16		$	319		$	1,018

Credit facilities⁽¹⁾	2,000			1,000			609			650			204			857			1,013			6,333
Less:
Short-term debt	(1,010		)	—			—			—			(10		)	(374		)	(492		)	(1,886		)
Tax-exempt bond support and letters of credit	(7		)	(150		)	(190		)	(80		)	—			(7		)	—			(434		)
Net credit facilities	983			850			419			570			194			476			521			4,013

Total net liquidity	$	1,056		$	1,048		$	470		$	927		$	198		$	492		$	840		$	5,031
Credit facilities:
Maturity dates	2019			2018, 2019			2017, 2018			2018			2020			2017, 2020			2016, 2017, 2018


(1)	Includes the drawn uncommitted credit facilities totaling $10 million at Northern Powergrid.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2016 and 2015 were $4.8 billion and $5.9 billion, respectively. The change was primarily due to lower income tax receipts of $878 million and payment for the USA Power final judgment and postjudgment interest of $123 million.

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 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 in 2017, at 60% of value in 2018, and 40% of value 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 Company's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019, production tax credits through 2029 and investment tax credits earned on qualifying wind and solar projects through 2021, respectively.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2016 and 2015 were $(4.1) billion and $(4.4) billion, respectively. The change was primarily due to lower capital expenditures of $730 million, partially offset by $474 million of tax equity investments in 2016.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2016 was $(792) million. Uses of cash totaled $3.2 billion and consisted mainly of repayments of subsidiary debt totaling $1.6 billion and repayments of BHE junior subordinated debentures of $1.5 billion. Sources of cash totaled $2.4 billion from $1.5 billion of proceeds from subsidiary debt issuances and $887 million of net proceeds from short-term debt.

For a discussion of recent financing transactions, refer to Note 6 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the nine-month period ended September 30, 2015 was $(428) million. Uses of cash totaled $1.9 billion and consisted mainly of repayments of subsidiary debt totaling $712 million, repayment of BHE junior subordinated debentures of $600 million, net repayments of short-term debt of $473 million and repurchases of common stock totaling $36 million. Sources of cash totaled $1.5 billion related to proceeds from subsidiary debt issuances.

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 are as follows (in millions):



	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2015		2016		2016
Capital expenditures by business:
PacifiCorp	$	640	$	586	$	772
MidAmerican Funding	880		1,129		1,588
NV Energy	367		386		597
Northern Powergrid	535		435		546
BHE Pipeline Group	155		150		257
BHE Transmission	735		386		469
BHE Renewables	923		430		622
HomeServices	8		13		19
BHE and Other	8		6		14
Total	$	4,251	$	3,521	$	4,884



Capital expenditures by type:
Wind generation	$	804	$	1,110	$	1,388
Solar generation	729		15		105
Electric transmission	725		339		568
Environmental	97		52		86
Other development projects	44		26		127
Other operating	1,852		1,979		2,610
Total	$	4,251	$	3,521	$	4,884

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

•Wind generation includes the following:

◦

Construction of wind-powered generating facilities at MidAmerican Energy totaling $732 million and $601 million for the nine-month periods ended September 30, 2016 and 2015, respectively. MidAmerican Energy anticipates costs for wind-powered generating facilities will total an additional $200 million for 2016. MidAmerican Energy is constructing 599 MW (nominal ratings) that are expected to be placed in-service in 2016, of which 171 MW (nominal ratings) had been placed in-service as of September 30, 2016, and 2,000 MW (nominal ratings) of wind-powered generating facilities expected to be placed in-service in 2017 through 2019, as discussed below. Each of these projects is expected to qualify for 100% of production tax credits currently available.

◦

Construction of wind-powered generating facilities at BHE Renewables totaling $378 million and $201 million for the nine-month periods ended September 30, 2016 and 2015, respectively. The Marshall Wind Project with a total capacity of 72 MW achieved commercial operation in April 2016 and the Jumbo Road Project with a total capacity of 300 MW achieved commercial operation in April 2015. BHE Renewables anticipates costs for wind-powered generating facilities will total an additional $54 million for 2016. BHE Renewables is developing and constructing up to 400 MW of wind-powered generating facilities in the state of Nebraska.

Solar generation includes the following:


◦	Construction of the Topaz Project totaling $- million and $49 million for the nine-month periods ended September 30, 2016 and 2015, respectively. 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 $9 million and $641 million for the nine-month periods ended September 30, 2016 and 2015, respectively. 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.

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 miles of 345 kV transmission line located in Iowa and Illinois.

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.

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

MidAmerican Energy Wind

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 expected to be placed in service in 2017 through 2019. The ratemaking principles establish a cost cap of $3.6 billion, including AFUDC, and a fixed rate of return on equity of 11.0% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding. 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 if they are above the 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.

Other Renewable Investments

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 $170 million in 2015, $474 million through September 30, 2016 and expects to contribute $195 million in 2017 and $136 million in 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 into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits generated by the project.

Contractual Obligations

As of September 30, 2016, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2015 other than the 2016 debt issuances and the renewable tax equity investments previously discussed.

Quad Cities Station Operating Status

Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018, as a result of Illinois not passing adequate legislation and Quad Cities Station not clearing the 2019-2020 PJM Interconnection, L.L.C. capacity auction. MidAmerican Energy has expressed to Exelon Generation its desire for the continued operation of the facility through the end of its operating license in 2032 and continues to work with Exelon Generation for solutions to that end. An early shutdown of Quad Cities Station before the end of its operating license would require an evaluation of MidAmerican Energy's legal rights pursuant to the Quad Cities Station agreements with Exelon Generation. In addition, the carrying value and classification of assets and liabilities related to Quad Cities Station on MidAmerican Energy's balance sheets would need to be evaluated, and a determination made of the sufficiency of the nuclear decommissioning trust fund to fund decommissioning costs at an earlier retirement date. If the trust fund is determined to be deficient, MidAmerican Energy may be required to contribute additional assets to the trust fund or directly pay certain decommissioning costs.

Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2015, and new regulatory matters occurring in 2016.

Wholesale Electricity and Capacity

The FERC regulates the Utilities' rates charged to wholesale customers for electricity and transmission capacity and related services. Most of the Utilities' wholesale electricity sales and purchases occur under market-based pricing allowed by the FERC and are therefore subject to market volatility.

The Utilities' and BHE Renewables' authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the Utilities and BHE Renewables 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. In June 2016, BHE Renewables submitted a triennial filing to the FERC for the southwest region and PacifiCorp and NV Energy submitted a triennial filing for the northwest region. These filings are pending at 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. In June 2016, the FERC issued an order for all BHE subsidiaries, including the Utilities, with market-based rates to amend their respective market-based rate tariffs to preclude them from selling in the PacifiCorp East, PacifiCorp West, Idaho Power Company and NorthWestern Corporation balancing authority areas (the "Mitigated BAAs") at market-based rates. These tariff amendments have been filed. Sales may be made in the Mitigated BAAs at cost-based rates. In addition, the specified BHE subsidiaries were ordered to issue refunds for market-based wholesale electricity sales in the Mitigated BAAs for the period from January 2015 through April 2016, to the extent such sales were priced above cost-based rates. Such refunds, totaling less than $1 million, were made by PacifiCorp, Nevada Power and Sierra Pacific in July 2016. MidAmerican Energy and BHE Renewables do not transact in the Mitigated BAAs. In July 2016, the specified BHE subsidiaries affected in the order filed with the FERC a request for rehearing and clarification. The specified BHE subsidiaries affected in the order do not believe the order will have a material impact on their respective consolidated financial statements.

PacifiCorp

Utah

In March 2016, PacifiCorp filed its annual Energy Balancing Account ("EBA") with the UPSC requesting recovery of $19 million in deferred net power costs for the period January 1, 2015 through December 31, 2015. A settlement was reached with all parties and filed with the UPSC for approval. In October 2016, the UPSC approved the settlement, authorizing recovery of the stipulated amount of $15 million. New rates will be effective November 2016.

In March 2016, PacifiCorp filed its annual REC balancing account application with the UPSC requesting recovery of $7 million for the period January 1, 2015 through December 31, 2015. The UPSC approved interim rates effective June 2016, and final rates August 2016.

The Utah Sustainable Transportation and Energy Plan was signed into law in March 2016. The legislation establishes a five-year pilot program to provide up to $10 million annually of mandated funding for electric vehicle infrastructure and clean coal research, and authorizes funding at the commission's discretion for solar development, utility-scale battery storage, and other innovative technology, economic development and air quality initiatives. The legislation allows PacifiCorp to change its regulatory accounting for energy efficiency services and programs from expense to capital, to be amortized over a ten-year period. The difference between amounts collected in rates for energy efficiency services and programs and the annual amount of cost amortization will result in a regulatory liability that may be used for depreciation of its coal-fired plants, as determined by the commission. Beginning June 1, 2016, the legislation mandates full recovery of Utah's share of incremental fuel, purchased power and other variable supply costs through the EBA that are not fully in base rates rather than the prior recovery of 70%. The legislation also allows for the approval by the UPSC of a renewable energy tariff that would allow qualifying customers to receive 100% renewable energy from PacifiCorp. A renewable energy tariff was filed with the UPSC in June 2016, which the UPSC approved in August 2016. In September 2016, PacifiCorp filed an application seeking approval of its proposed five-year pilot program with an annual budget of $10 million.

Oregon

In April 2016, PacifiCorp submitted its initial filing for the annual Transition Adjustment Mechanism filing in Oregon requesting an annual increase of $20 million, or an average price increase of 2%, based on forecasted net power costs and loads for calendar year 2017. Consistent with the passage of Oregon Senate Bill 1547-B ("SB 1547-B"), the filing includes the impact of expiring production tax credits, which account for $5 million of the requested increase. In October 2016, the OPUC issued a preliminary order approving PacifiCorp's filing subject to updates to be filed in November 2016 to account for changes in contracts and market conditions. Final rates become effective in January 2017.

Wyoming

In March 2016, PacifiCorp filed its annual Energy Cost Adjustment Mechanism ("ECAM") and REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") applications with the WPSC. The ECAM filing requests approval to recover $12 million in deferred net power costs for the period January 1, 2015 through December 31, 2015, and the RRA application requests approval to refund $1 million to customers. In May 2016, the WPSC approved ECAM and RRA rates on an interim basis. In September 2016, a settlement was reached with all parties in the case, reducing the requested recovery of the ECAM to $11 million. In October 2016, the WPSC approved a stipulation in which the parties agreed to allow interim rates for the RRA that were effective in May 2016 to become final and the net decrease in rates for the ECAM to become effective in November 2016.

Washington

In December 2013, the WUTC approved an annual increase of $17 million, or an average price increase of 6%, effective December 2013 related to a general rate case filed in January 2013 requesting $37 million, or an average price increase of 12%. In January 2014, PacifiCorp filed a petition for judicial review of certain findings of the WUTC's December 2013 order. In April 2016, the Washington Court of Appeals issued its order in the appeal of the general rate case. The two issues before the court were the WUTC's decisions to: (1) re-price power purchase agreements with California and Oregon qualifying facilities at market prices; and (2) the cost of capital, including use of a hypothetical capital structure. The court affirmed the WUTC, deferring to the WUTC's discretion in ratemaking and concluding that it did not abuse that discretion.

In September 2016, the WUTC issued final orders in PacifiCorp's November 2015 rate filing, two-year rate plan and decoupling mechanism proceeding. The WUTC approved a rate increase of $6 million, or 1.7%, effective October 2016 and a second step rate increase of $8 million, or 2.3%, effective September 2017. The WUTC also approved a revenue decoupling mechanism and accelerated depreciation for coal-fueled generation facilities included in Washington rates. As part of the proposed rate plan, PacifiCorp agreed to not file a general rate case in Washington with rates effective earlier than mid-2018.

Idaho

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. In March 2016, the IPUC approved recovery of $17 million effective April 2016.

In September 2016, a compliance filing was made with the IPUC to update net power costs in base rates effective January 2017. If approved, the filing will result in a decrease in rates of 0.4%.

California

In March 2016, the CPUC approved PacifiCorp's application to recover a $1 million revenue requirement associated with drought-related fire hazard mitigation costs recorded in its catastrophic events memorandum account in 2014. In October 2016, PacifiCorp filed its post test year adjustment mechanism attrition factor for 2017, requesting an overall increase of $1 million, or 1%. If approved by the CPUC, new rates will be effective January 2017.

NV Energy (Nevada Power and Sierra Pacific)

Chapter 704B Applications

In November 2014, one Nevada Power retail electric customer filed an application with the PUCN to purchase energy from a provider of a new electric resource and become a distribution only service customer, as allowed by Chapter 704B of the Nevada Revised Statutes. Chapter 704B 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 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 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 customers, including MGM Resorts International ("MGM") and Wynn Las Vegas, LLC ("Wynn"), filed applications to purchase energy from a provider of a new electric resource and become distribution only service customers. 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. The costs associated with the impact fee and on-going charges were assessed to reimburse Nevada Power for the customers' share of previously committed investments and long-term renewable contracts. The impact fee is set at a level designed such that the remaining customers are not subjected to increased costs. In December 2015, the customers 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 June 2016, MGM and Wynn made the required compliance filings and the PUCN issued orders allowing the customers to acquire electric energy and ancillary services from another energy supplier and become distribution only service customers of Nevada Power. The third customer did not make its compliance filing before the required deadline. In September 2016, MGM and Wynn paid impact fees totaling $97 million. In October 2016, MGM and Wynn became distribution only service customers and started procuring energy from another energy supplier. There are no applications pursuant to Chapter 704B pending before the PUCN in Nevada Power's respective service territory.

In July 2016, one Sierra Pacific retail electric customer filed an application with the PUCN to acquire electric energy and ancillary services from another energy supplier and become a distribution only service customer. In September 2016, that customer withdrew its application; however, another retail electric customer filed a similar application with the PUCN.

Net Metering

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

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

In January 2016, the PUCN denied requests to stay the order issued December 23, 2015. The PUCN also voted to reopen the evidentiary proceeding to address the application of new net metering rules for customers who applied for net metering service before the issuance of the final order. In February 2016, the PUCN affirmed most of the provisions of the December 23, 2015 order and adopted a twelve-year transition plan for changing rates for net metering customers to cost-based rates for utility services and value-based pricing for excess energy. Subsequently, two solar industry interest groups filed petitions for judicial review of the PUCN order issued in February 2016. The petitions request that the court either modify the PUCN order or direct the PUCN to modify its decision in a manner that would maintain rates and rules of service applicable to net metering as existed prior to the December 23, 2015 order of the PUCN. Two of the three petitions filed by the solar industry interest groups have been dismissed. In September 2016, the state district court issued an order in the third petition. The court concluded that the PUCN failed to provide existing net metering customers adequate legal notice of the proceeding. The court affirmed the PUCN's decision to establish new net energy metering rates and apply those to new net metering customers. In addition, a referendum has been filed in Nevada to modify the statutes applicable to net metering. This referendum was challenged in Nevada state district court and the court determined the referendum was not consistent with the Nevada Constitution. The Nevada state district court decision was appealed to the Nevada Supreme Court. In August 2016, the Nevada Supreme Court upheld the Nevada state district court decision.

In July 2016, the Nevada Utilities filed applications with the PUCN to revert back to the original net metering rates for a period of twenty years for customers who installed or had an active application for distributed, renewable generating facilities as of December 31, 2015. In September 2016, the PUCN accepted a stipulation and approved the applications as modified by the stipulation.

General Rate Cases

In June 2016, Sierra Pacific filed an electric general rate case with the PUCN. The filing requests 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. If approved by the PUCN, the settlement agreement would reduce Sierra Pacific’s electric revenue requirement by $3 million. Hearings on the remaining issues are scheduled for November 2016. An order is expected by the end of 2016 and, if approved, would be effective January 1, 2017.

In June 2016, Sierra Pacific filed a gas general rate case with the PUCN. The filing requests 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. If approved by the PUCN, the settlement agreement would reduce Sierra Pacific’s gas revenue requirement by $2 million. An order is expected by the end of 2016 and, if approved, would be effective January 1, 2017.

ALP

General Tariff Applications

In November 2014, ALP filed a GTA asking 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 to propose transmission tariff relief measures for customers and modifications to its capital structure. ALP also amended the GTA in October 2015. In May 2016, the AUC issued Decision 3524-D01-2016 pertaining to the 2015-2016 GTA. ALP filed its 2015-2016 GTA compliance filing in July 2016 in response to the AUC's decision pertaining to the 2015-2016 GTA. Following the AUC's assessment of whether the refiling complies with the decision, final transmission tariff rates for the 2015 and 2016 test years will be set, subject to further adjustment through the deferral account reconciliation process.

Approved 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 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;

Denied ALP's request for increases in its common equity ratio of 3% in 2015; and

Approved ALP's depreciation rates as filed, but reduced most of ALP's salvage rates to 2014 levels, which resulted in a reduction of revenue of about C$87 million over two years.

In October 2016, ALP updated its 2015-2016 GTA compliance filing to reflect the impacts of the generic cost of capital decision issued in October 2016. The update asks the AUC to approve ALP's revenue requirement of C$688 million for 2016.

In Decision 3524-D01-2016, the AUC also approved the capital forecasts substantially as filed, but directed ALP to use as part of its refiling the actual amount of capital additions for direct assign projects brought into service in 2015, and ALP's revised capital additions forecast for 2016, which were approximately C$2.9 billion and C$697 million, respectively.

ALP updated and refiled its 2017-2018 GTA in August 2016 to reflect the findings and conclusions of the AUC presented in the 2015-2016 GTA decision issued in May 2016. In October 2016, AltaLink 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 asks the AUC to approve ALP's revenue requirement of C$891 million for 2017 and C$919 million for 2018. In November 2016, ALP filed its 2017 interim tariff application requesting an interim refundable transmission tariff to be effective January 1, 2017 of $74 million per month.

The total tariff relief proposed in the 2015-2016 GTA and the 2017-2018 GTA for ALP's customers is approximately C$600 million over the 2015-2018 period.

2016 Generic Cost of Capital Proceeding

In April 2015, the AUC opened a new generic cost of capital proceeding to set the deemed capital structure and generic return on equity for 2016 and 2017. ALP filed evidence in January 2016. ALP's external rate of return expert evidence proposes 9% to 10.5% return on equity, on a recommended equity component 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. In March 2016, intervenors filed their expert evidence proposing a range of 7% to 7.5% return on equity, on a recommended equity component of 35%, for ALP. The oral hearing took place during May and June 2016.

In October 2016, the AUC released Decision 20622-D01-2016 with respect to its generic cost of capital proceeding to set the deemed capital structure and generic return on equity for 2016 and 2017. The AUC set the return on equity at 8.3% for 2016 and 8.5% for 2017. ALP's equity ratio was set at 37% for 2016 and 2017. The AUC set deemed common equity ratios for each regulated utility that are consistent with credit ratings in the A category on a stand-alone basis and determined that company specific adjustments were not required for ALP's large capital build program. The AUC also concluded that there was a directional increase in generic business risk, mainly due to concerns with the principles reflected in the Utility Asset Disposition ("UAD") decision.

Appeals of Recent AUC Decisions

In March 2015, the AUC issued its decision regarding cost of 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 return on equity applicable to all utilities to 8.30% from the previously approved placeholder rate of 8.75% and decreased ALP's equity ratio from 37% to 36% for the years 2013, 2014 and 2015. ALP and other utilities had applied to the Alberta Court of Appeal for leave to appeal this decision; however, a decision not to proceed was made in the first quarter of 2016.

In November 2013, the AUC issued its 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. The Supreme Court of Canada dismissed the appeal in April 2016.

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. ALP requested approval of the capital project expenditures, including the new competitively bid EPCM rates, in its 2012-2013 direct assigned capital deferral account filing. The AUC approved the EPCM rates applied for as part of that filing as prudent in June 2016.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Refer to "Liquidity and Capital Resources" of each respective Registrant in Part I, Item 2 of this Form 10-Q for discussion of each Registrant's forecast environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrants' Annual Report on Form 10-K for the year ended December 31, 2015.

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 State Implementation Plans ("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.

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.

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 to the EPA. The EPA issued final sulfur dioxide area designations in the first phase on June 30, 2016; none of the areas in which the Registrants own or operate facilities were designated as being in non-attainment.

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 Mercury and Air Toxics Standards ("MATS") became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015 with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.

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

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. The EPA took final action on the Utah regional haze SIP with an effective date of 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 filed an administrative and judicial appeal of EPA's final rule in September 2016.

The state of Arizona issued a regional haze SIP requiring, among other things, the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions requiring SCR controls on Cholla Unit 4. PacifiCorp filed an appeal in the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it relates to their interests. The Ninth Circuit issued an order in February 2015, holding the matter in abeyance relating to PacifiCorp and Arizona Public Service Company as they work with state and federal agencies on an alternate compliance approach for Cholla Unit 4. In January 2015, permit applications and studies were submitted to amend the Cholla Title V permit, and subsequently the Arizona SIP to convert Cholla Unit 4 to a natural gas-fueled unit in 2025. The Arizona Department of Environmental Quality prepared a draft permit and a revision to the Arizona regional haze SIP, held two public hearings in July 2015 and, after considering the comments received during the public comment period that closed on July 14, 2015, submitted the final proposals to the EPA for review, public comment and final action. The EPA issued its proposed action to approve amendments to the Arizona regional haze SIP, which were published in the Federal Register in July 2016. The public comment period closed September 2, 2016. The EPA’s final action is expected by late 2016.

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 submitted 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. As part of an agreement to revise Colorado's regional haze SIP, the owners of the Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups to retire Unit 1 by December 31, 2025, or alternatively to remove the unit from coal-fueled service in 2021 and implement a natural gas conversion by 2023. The terms of the agreement are being incorporated into an amended SIP and will be considered by the Colorado Air Quality Board for approval in December 2016. The EPA's review and approval process for the amended SIP will follow thereafter.

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. The cornerstone of the United States' commitment is the Clean Power Plan which was finalized by the EPA in 2015 but is currently stayed by the U.S. Supreme Court pending the outcome of litigation on the rule. The Paris Agreement was signed by more than 170 countries in April 2016, and will become effective once 55 countries representing 55% of the world’s greenhouse gas emissions ratify the agreement. On October 4, 2016, the requisite number of countries representing more than 55% of the world's greenhouse gas emissions ratified the Paris Agreement; as a result, the Paris Agreement became effective November 4, 2016. Under the terms of the Paris Agreement, ratifying countries are bound for a three-year period and must provide one-year's notice of their intent to withdraw. The earliest date the U.S. could withdraw from the Paris Agreement is November 4, 2020.

Clean Power Plan

In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The EPA also changed the compliance period to begin in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh and 1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. The EPA also released in August 2015, a draft federal plan as an option or backstop for states to utilize in the event they do not submit approvable state plans. The public comment period on the draft federal plan and proposed model trading rules closed January 21, 2016. States were required to submit their initial implementation plans by September 2016 but could request an extension to September 2018. However, on February 9, 2016, the United States Supreme Court ordered that the EPA's emission guidelines for existing sources be stayed pending the disposition of the challenges to the rule in the D.C. Circuit Court of Appeals and any action on a writ of certiorari before the United States Supreme Court. Oral argument was heard before the full D.C. Circuit (with the exception of Chief Judge Merrick Garland) on September 27, 2016. A decision by the court is unlikely to be issued until early 2017. The full impacts of the final rule or the federal plan on the Registrants cannot be determined until the outcome of the pending litigation and subsequent appeals, the development and implementation of state plans, and finalization of the federal plan. PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

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:

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 greenhouse gas 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 will establish a greenhouse gas emissions reduction pathway 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.

Renewable Portfolio Standards

In March 2016, Oregon Senate Bill 1547-B, the Clean Electricity and Coal Transition Plan, was signed into law. SB 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. SB 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.

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2015. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2015.

PacifiCorp and its subsidiaries

Consolidated Financial Section

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Portland, Oregon

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2016, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2016 and 2015, and of changes in shareholders' equity and cash flows for the nine-month periods ended September 30, 2016 and 2015. These interim financial statements are the responsibility of PacifiCorp's management.

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

Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 2015, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2016, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2015 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Portland, Oregon

November 4, 2016

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	September 30,		December 31,
	2016		2015
ASSETS

Current assets:
Cash and cash equivalents	$	198	$	12
Accounts receivable, net	702		740
Income taxes receivable	—		17
Inventories:
Materials and supplies	229		233
Fuel	225		192
Regulatory assets	65		102
Other current assets	56		81
Total current assets	1,475		1,377

Property, plant and equipment, net	19,047		19,026
Regulatory assets	1,456		1,583
Other assets	411		381

Total assets	$	22,389	$	22,367

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)



	As of
	September 30,			December 31,
	2016			2015
LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	410		$	473
Income taxes payable	116			—
Accrued employee expenses	93			70
Accrued interest	106			115
Accrued property and other taxes	129			62
Short-term debt	—			20
Current portion of long-term debt and capital lease obligations	67			68
Regulatory liabilities	45			34
Other current liabilities	189			229
Total current liabilities	1,155			1,071

Regulatory liabilities	963			938
Long-term debt and capital lease obligations	7,026			7,078
Deferred income taxes	4,816			4,750
Other long-term liabilities	882			1,027
Total liabilities	14,842			14,864

Commitments and contingencies (Note 8)

Shareholders' equity:
Preferred stock	2			2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—			—
Additional paid-in capital	4,479			4,479
Retained earnings	3,077			3,033
Accumulated other comprehensive loss, net	(11		)	(11		)
Total shareholders' equity	7,547			7,503

Total liabilities and shareholders' equity	$	22,389		$	22,367

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015

Operating revenue	$	1,434		$	1,423		$	3,919		$	3,942

Operating costs and expenses:
Energy costs	478			491			1,295			1,404
Operations and maintenance	272			260			800			800
Depreciation and amortization	193			188			576			567
Taxes, other than income taxes	47			48			141			138
Total operating costs and expenses	990			987			2,812			2,909

Operating income	444			436			1,107			1,033

Other income (expense):
Interest expense	(95		)	(95		)	(285		)	(283		)
Allowance for borrowed funds	4			4			12			14
Allowance for equity funds	7			7			21			26
Other, net	3			2			9			7
Total other income (expense)	(81		)	(82		)	(243		)	(236		)

Income before income tax expense	363			354			864			797
Income tax expense	110			109			270			247
Net income	$	253		$	245		$	594		$	550

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)

(Amounts in millions)



										Accumulated
					Additional					Other			Total
	Preferred		Common		Paid-in		Retained			Comprehensive			Shareholders'
	Stock		Stock		Capital		Earnings			Loss, Net			Equity

Balance, December 31, 2014	$	2	$	—	$	4,479	$	3,288		$	(13	)	$	7,756
Net income	—		—		—		550			—			550
Common stock dividends declared	—		—		—		(950		)	—			(950		)
Balance, September 30, 2015	$	2	$	—	$	4,479	$	2,888		$	(13	)	$	7,356

Balance, December 31, 2015	$	2	$	—	$	4,479	$	3,033		$	(11	)	$	7,503
Net income	—		—		—		594			—			594
Common stock dividends declared	—		—		—		(550		)	—			(550		)
Balance, September 30, 2016	$	2	$	—	$	4,479	$	3,077		$	(11	)	$	7,547

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2016			2015

Cash flows from operating activities:
Net income	$	594		$	550
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	576			567
Allowance for equity funds	(21		)	(26		)
Deferred income taxes and amortization of investment tax credits	76			32
Changes in regulatory assets and liabilities	85			41
Other, net	6			7
Changes in other operating assets and liabilities:
Accounts receivable and other assets	19			14
Derivative collateral, net	2			(42		)
Inventories	(32		)	(3		)
Income taxes	133			250
Accounts payable and other liabilities	(66		)	121
Net cash flows from operating activities	1,372			1,511

Cash flows from investing activities:
Capital expenditures	(586		)	(640		)
Other, net	26			(8		)
Net cash flows from investing activities	(560		)	(648		)

Cash flows from financing activities:
Proceeds from long-term debt	—			250
Repayments of long-term debt and capital lease obligations	(56		)	(116		)
Net repayments of short-term debt	(20		)	(20		)
Common stock dividends	(550		)	(950		)
Other, net	—			(3		)
Net cash flows from financing activities	(626		)	(839		)

Net change in cash and cash equivalents	186			24
Cash and cash equivalents at beginning of period	12			23
Cash and cash equivalents at end of period	$	198		$	47

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

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2016 and for the three- and nine-month periods ended September 30, 2016 and 2015. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2016 and 2015. The results of operations for the three- and nine-month periods ended September 30, 2016 and 2015 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2015 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2016.

(2) New Accounting Pronouncements

In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, which amends FASB Accounting Standards Codification ("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. PacifiCorp is currently evaluating the impact of adopting this guidance 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. 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. PacifiCorp is currently evaluating the impact of adopting this guidance 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. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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, 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. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3) Property, Plant and Equipment, Net

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



		As of
		September 30,			December 31,
	Depreciable Life	2016			2015

Property, plant and equipment in-service	5-75 years	$	27,051		$	26,757
Accumulated depreciation and amortization		(8,658		)	(8,360		)
Net property, plant and equipment in-service		18,393			18,397
Construction work-in-progress		654			629
Total property, plant and equipment, net		$	19,047		$	19,026

(4)Recent Financing Transactions

In June 2016, PacifiCorp replaced its $600 million unsecured revolving credit facility, which had been set to expire in June 2017, with a $400 million unsecured credit facility with a stated maturity of June 2019 and two one-year extension options subject to bank consent. The credit facility, which supports PacifiCorp's commercial paper program, certain series of its tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the London Interbank Offered Rate ("LIBOR") or a base rate, at PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities. The credit facility requires that PacifiCorp's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter. As of September 30, 2016, PacifiCorp had no borrowings outstanding or letters of credit issued under this credit facility.

(5) Employee Benefit Plans

Net periodic benefit cost for the pension and other postretirement benefit plans included the following components (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015
Pension:
Service cost	$	1		$	1		$	3		$	3
Interest cost	14			13			41			40
Expected return on plan assets	(18		)	(19		)	(56		)	(58		)
Net amortization	8			10			25			31
Net periodic benefit cost	$	5		$	5		$	13		$	16

Other postretirement:
Service cost	$	1		$	—		$	2		$	2
Interest cost	3			4			11			12
Expected return on plan assets	(5		)	(5		)	(16		)	(17		)
Net amortization	(1		)	(1		)	(4		)	(3		)
Net periodic benefit credit	$	(2	)	$	(2	)	$	(7	)	$	(6	)

Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $- million, respectively, during 2016. As of September 30, 2016, $3 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(6) Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated service territories. PacifiCorp's 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 and wholesale electricity that is purchased and sold. 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 debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp 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. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp 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, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):



	Other					Other			Other
	Current			Other		Current			Long-term
	Assets			Assets		Liabilities			Liabilities			Total

As of September 30, 2016
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	5		$	2	$	4		$	—		$	11
Commodity liabilities	(2		)	—		(27		)	(87		)	(116		)
Total	3			2		(23		)	(87		)	(105		)

Total derivatives	3			2		(23		)	(87		)	(105		)
Cash collateral receivable	—			—		14			59			73
Total derivatives - net basis	$	3		$	2	$	(9	)	$	(28	)	$	(32	)

As of December 31, 2015
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	10		$	—	$	2		$	—		$	12
Commodity liabilities	(1		)	—		(58		)	(89		)	(148		)
Total	9			—		(56		)	(89		)	(136		)

Total derivatives	9			—		(56		)	(89		)	(136		)
Cash collateral receivable	—			—		18			57			75
Total derivatives - net basis	$	9		$	—	$	(38	)	$	(32	)	$	(61	)


(1)	PacifiCorp's commodity derivatives are generally included in rates and as of September 30, 2016 and December 31, 2015, a regulatory asset of $102 million and $133 million, respectively, was recorded related to the net derivative liability of $105 million and $136 million, respectively.

Not Designated as Hedging Contracts

The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015

Beginning balance	$	89		$	99		$	133		$	85
Changes in fair value recognized in net regulatory assets	15			38			(4		)	65
Net (losses) gains reclassified to operating revenue	(2		)	1			8			29
Net losses reclassified to energy costs	—			(10		)	(35		)	(51		)
Ending balance	$	102		$	128		$	102		$	128

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):



	Unit of	September 30,		December 31,
	Measure	2016		2015
Electricity (sales) purchases	Megawatt hours	(6	)	1
Natural gas purchases	Decatherms	92		111
Fuel oil purchases	Gallons	3		11

Credit Risk

PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp 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, PacifiCorp 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, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale 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 derivative contracts 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 PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2016, PacifiCorp's credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $109 million and $142 million as of September 30, 2016 and December 31, 2015, respectively, for which PacifiCorp had posted collateral of $73 million and $75 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2016 and December 31, 2015, PacifiCorp would have been required to post $28 million and $64 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

(7) Fair Value Measurements

The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.

Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.

The following table presents PacifiCorp's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):



	Input Levels for Fair Value Measurements
	Level 1		Level 2			Level 3		Other⁽¹⁾			Total
As of September 30, 2016
Assets:
Commodity derivatives	$	—	$	11		$	—	$	(6	)	$	5
Money market mutual funds⁽²⁾	199		—			—		—			199
Investment funds	16		—			—		—			16
	$	215	$	11		$	—	$	(6	)	$	220

Liabilities - Commodity derivatives	$	—	$	(116	)	$	—	$	79		$	(37	)

As of December 31, 2015
Assets:
Commodity derivatives	$	—	$	9		$	3	$	(3	)	$	9
Money market mutual funds⁽²⁾	13		—			—		—			13
Investment funds	15		—			—		—			15
	$	28	$	9		$	3	$	(3	)	$	37

Liabilities - Commodity derivatives	$	—	$	(148	)	$	—	$	78		$	(70	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $73 million and $75 million as of September 30, 2016 and December 31, 2015, respectively.


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

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 PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp 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 energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first six years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first six years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp 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. Refer to Note 6 for further discussion regarding PacifiCorp's risk management and hedging activities.

PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value and are primarily accounted for as available-for-sale securities. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):



	As of September 30, 2016				As of December 31, 2015
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	7,063	$	8,690	$	7,114	$	8,210

(8) Commitments and Contingencies

Legal Matters

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

USA Power

Sanpete County, Utah Rangeland Fire

In June 2012, a major rangeland fire occurred in Sanpete County, Utah. Certain parties allege that contact between two of PacifiCorp's transmission lines may have triggered a ground fault that led to the fire. PacifiCorp has engaged experts to review the cause and origin of the fire, as well as to assess the damages. PacifiCorp has accrued its best estimate of the potential loss and expected insurance recovery. PacifiCorp believes it is reasonably possible it may incur additional loss beyond the amount accrued, but does not believe the potential additional loss will have a material impact on its consolidated financial results.

Environmental Laws and Regulations

Hydroelectric Relicensing

In February 2016, the principal parties to the KHSA (PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and Commerce) executed an agreement in principle committing to explore potential amendment of the KHSA to facilitate removal of the Klamath dams through a FERC process without the need for federal legislation. Since that time, PacifiCorp, the states of California and Oregon, and the United States Departments of the Interior and Commerce have negotiated an amendment to the KHSA that was signed on April 6, 2016. Consistent with the terms of the amended KHSA, on September 23, 2016, PacifiCorp and the Klamath River Renewal Corporation ("KRRC")" jointly filed an application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilities from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with the FERC to surrender the license and decommission the facilities, but the application included a request for the FERC to refrain from acting on the surrender application until after the transfer of the license to the KRRC is effective.

If certain conditions in the amended KHSA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.

Guarantees

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

(9) Related Party Transactions

Berkshire Hathaway includes BHE and its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income taxes are remitted to or received from BHE. For the nine-month period ended September 30, 2016, PacifiCorp made net cash payments for federal and state income taxes to BHE totaling $61 million. For the nine-month period ended September 30, 2015, PacifiCorp received net cash payments for federal and state income taxes from BHE totaling $35 million.


Item 2.	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 PacifiCorp 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 PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2016 and 2015

Overview

Net income for the third quarter of 2016 was $253 million, an increase of $8 million, or 3%, compared to 2015. Net income increased primarily due to higher margins of $24 million, partially offset by higher operations and maintenance of $12 million and depreciation and amortization of $5 million. Margins increased primarily due to lower purchased electricity costs, higher retail revenue and lower natural gas costs, partially offset by higher coal costs and lower wholesale electricity revenue. Retail customer load increased by 1.0% due to an increase in the average number of residential and commercial customers, the impacts of weather on residential customer load and increased usage from irrigation customers, partially offset by lower commercial customer usage primarily in Utah. Energy generated remained relatively flat for the third quarter of 2016 compared to 2015 due to lower natural gas-fueled and coal-fueled generation, partially offset by higher hydroelectric and wind-powered generation. Purchased electricity volumes decreased 15% and wholesale electricity sales volumes decreased 27%.

Net income for the first nine months of 2016 was $594 million, an increase of $44 million, or 8%, compared to 2015. Net income increased due to higher margins of $86 million, partially offset by higher depreciation and amortization of $9 million and lower AFUDC of $7 million. Margins increased primarily due to higher retail revenue, lower coal costs, lower purchased electricity costs and lower natural gas costs, partially offset by lower wholesale electricity revenue. Retail customer load decreased by 0.4% due to lower commercial and industrial customer usage, partially offset by an increase in the average number of residential and commercial customers and higher residential customer usage, including the impacts of weather. Energy generated decreased 7% for the first nine months of 2016 compared to 2015 due to lower coal-fueled generation, partially offset by higher hydroelectric, wind-powered and natural gas-fueled generation. Purchased electricity volumes increased 7% and wholesale electricity sales volumes decreased 29%.

Operating revenue and energy costs are the key drivers of PacifiCorp's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. PacifiCorp believes that a discussion of gross margin, representing operating revenue less energy costs, is therefore meaningful.

A comparison of PacifiCorp's key operating results is as follows:



	Third Quarter									First Nine Months
	2016		2015		Change					2016		2015		Change

Gross margin (in millions):
Operating revenue	$	1,434	$	1,423	$	11		1	%	$	3,919	$	3,942	$	(23	)	(1	)%
Energy costs	478		491		(13		)	(3	)	1,295		1,404		(109		)	(8	)
Gross margin	$	956	$	932	$	24		3		$	2,624	$	2,538	$	86		3

Sales (GWh):
Residential	4,147		4,022		125			3	%	11,909		11,409		500			4	%
Commercial	4,443		4,641		(198		)	(4	)	12,597		12,924		(327		)	(3	)
Industrial and irrigation	5,804		5,622		182			3		15,897		16,293		(396		)	(2	)
Other	136		102		34			33		373		311		62			20
Total retail	14,530		14,387		143			1		40,776		40,937		(161		)	—
Wholesale	1,513		2,069		(556		)	(27	)	4,493		6,337		(1,844		)	(29	)
Total sales	16,043		16,456		(413		)	(3	)	45,269		47,274		(2,005		)	(4	)

Average number of retail customers
(in thousands)	1,842		1,816		26			1	%	1,837		1,809		28			2	%

Average revenue per MWh:
Retail	$	93.10	$	92.04	$	1.06		1	%	$	90.44	$	88.71	$	1.73		2	%
Wholesale	$	28.32	$	28.72	$	(0.40	)	(1	)%	$	25.41	$	30.83	$	(5.42	)	(18	)%

Sources of energy (GWh)⁽¹⁾:
Coal	10,775		10,820		(45		)	—	%	26,637		31,496		(4,859		)	(15	)%
Natural gas	2,743		2,842		(99		)	(3	)	7,642		6,696		946			14
Hydroelectric⁽²⁾	488		407		81			20		2,719		2,088		631			30
Wind and other⁽²⁾	647		618		29			5		2,337		2,001		336			17
Total energy generated	14,653		14,687		(34		)	—		39,335		42,281		(2,946		)	(7	)
Energy purchased	2,542		2,976		(434		)	(15	)	9,031		8,429		602			7
Total	17,195		17,663		(468		)	(3	)	48,366		50,710		(2,344		)	(5	)

Average cost of energy per MWh:
Energy generated⁽³⁾	$	20.86	$	20.02	$	0.84		4	%	$	19.36	$	19.77	$	(0.41	)	(2	)%
Energy purchased	$	49.68	$	52.57	$	(2.89	)	(5	)%	$	43.02	$	51.58	$	(8.56	)	(17	)%


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


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


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

Gross margin increased $24 million, or 3%, for the third quarter of 2016 compared to 2015 primarily due to:

$30 million of lower purchased electricity costs due to lower average market prices and lower volumes;

$28 million of higher retail revenues primarily due to higher retail rates and a 1.0% increase in retail customer load due to a 0.7% increase in the average number of residential and commercial customers and a 0.7% increase due to the impacts of warmer summer temperatures primarily in Utah, partially offset by 0.4% decrease in commercial and residential customer usage; and

$12 million of lower natural gas costs primarily due to lower average unit costs.

The increases above were partially offset by:

$24 million of higher coal costs primarily due to charges related to damaged longwall mining equipment; and

$17 million of lower wholesale electricity revenue due to lower prices and volumes.

Operations and maintenance increased $12 million, or 5%, for the third quarter of 2016 compared to 2015 primarily due to a Washington rate case decision disallowing returns on recent selective catalytic reduction projects.

Depreciation and amortization increased $5 million, or 3%, for the third quarter of 2016 compared to 2015 primarily due to higher plant-in-service.

Gross margin increased $86 million, or 3%, for the first nine months of 2016 compared to 2015 primarily due to:

$56 million of higher retail revenues primarily due to higher retail rates, a 0.8% increase in the average number of residential and commercial customers and a 0.3% increase due to the impacts of warmer summer temperatures primarily in Utah, partially offset by a 1.5% decrease in commercial and industrial customer usage;

$54 million of lower coal costs due to decreased generation, partially offset by higher average unit costs and charges related to damaged longwall mining equipment;

$46 million of lower purchased electricity costs due to $89 million of lower average market prices, partially offset by $43 million of higher volumes; and

$18 million of lower natural gas costs due to $67 million of lower market prices, partially offset by $49 million of increased generation.

The increases above were partially offset by:

$81 million of lower wholesale electricity revenue due to lower volumes and prices.

Operations and maintenance remained relatively unchanged for the first nine months of 2016 compared to 2015 primarily due to a Washington rate case decision disallowing returns on recent selective catalytic reduction projects, partially offset by insurance recoveries expected from a prior period claim.

Depreciation and amortization increased $9 million, or 2%, for the first nine months of 2016 compared to 2015 primarily due to higher plant-in-service.

Taxes, other than income taxes increased $3 million, or 2% for the first nine months of 2016 compared to 2015 due to higher property taxes primarily from higher assessed property values.

Allowance for borrowed and equity funds decreased $7 million, or 18%, for the first nine months of 2016 compared to 2015 primarily due lower qualified construction work-in-progress balances.

Income tax expense increased $23 million, or 9%, for the first nine months of 2016 compared to 2015 and the effective tax rate was 31% for the first nine months of 2016 and 2015. The increase in income tax expense was primarily due to higher pre-tax book income.

Liquidity and Capital Resources

As of September 30, 2016, PacifiCorp's total net liquidity was as follows (in millions):



Cash and cash equivalents	$	198

Credit facilities	1,000
Less:
Short-term debt	—
Tax-exempt bond support and letters of credit	(150		)
Net credit facilities	850

Total net liquidity	$	1,048

Credit facilities:
Maturity dates	2018, 2019

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2016 and 2015 were $1.4 billion and $1.5 billion, respectively. The change was primarily due to payment for USA Power final judgment and postjudgment interest, lower receipts from wholesale electricity sales and cash paid for income taxes in the current year compared to cash received for income taxes in the prior year, partially offset by lower purchased electricity payments, lower fuel payments, higher receipts from retail customers and lower cash collateral posted for derivative contracts.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2016 and 2015 were $(560) million and $(648) million, respectively. The change primarily reflects lower capital expenditures of $54 million in 2016, a 2015 service territory acquisition of $23 million and current year net distributions from an affiliate of $20 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2016 was $(626) million. Uses of cash consisted substantially of $550 million for common stock dividends paid to PPW Holdings LLC, $54 million for the repayment of long-term debt and $20 million for the repayment of short-term debt.

Net cash flows from financing activities for the nine-month period ended September 30, 2015 was $(839) million. Uses of cash consisted substantially of $950 million for common stock dividends paid to PPW Holdings LLC, $115 million for the repayment of long-term debt and $20 million for the repayment of short-term debt. Sources of cash consisted of proceeds from the issuance of long-term debt of $250 million.

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of September 30, 2016, PacifiCorp had no short-term debt outstanding. As of December 31, 2015, PacifiCorp had $20 million of short-term debt outstanding at a weighted average interest rate of 0.65%.

Long-term Debt

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1.3 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance.

Future Uses of Cash

PacifiCorp 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, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

PacifiCorp 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.

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):



	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2015		2016		2016

Transmission system investment	$	105	$	68	$	92
Environmental	83		42		63
Operating and other	452		476		617
Total	$	640	$	586	$	772

PacifiCorp's historical and forecast capital expenditures include the following:

Transmission system investment includes main grid reinforcement costs, construction costs for the 170-mile single-circuit 345-kV Sigurd-Red Butte transmission line that was placed in-service in May 2015 and initial development costs for several other long-term projects.

Environmental includes the installation of new or the replacement of existing emissions control equipment at certain generating facilities, 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.

Remaining investments relate to operating projects that consist of routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand.

Integrated Resource Plan

In March 2015, PacifiCorp filed its 2015 Integrated Resource Plan ("IRP") with the state commissions. In 2015 the WPSC accepted the 2015 IRP into its files and the UPSC, IPUC and WUTC acknowledged the 2015 IRP. In February 2016, the OPUC acknowledged the 2015 IRP with one exception. In March 2016, PacifiCorp filed its update to the 2015 IRP with the state commissions.

Request for Proposals

PacifiCorp issues individual Request for Proposals ("RFP"), each of which typically focuses on a specific category of generation resources consistent with the IRP or other customer-driven demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load requirements and/or to meet renewable portfolio standard requirements. Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.

PacifiCorp issued renewable resource and renewable energy credit RFPs to the market on April 11, 2016. The RFPs were issued to seek cost-effective renewable resources and RECs that can take full advantage of federal income tax incentives and that can be used to meet renewable portfolio standard requirements in Oregon, Washington, and California. PacifiCorp executed REC purchase agreements from one wind project offering prior-year vintage RECs and from six solar projects offering RECs that will be generated over the period 2016 through 2036. The solar projects are located in Oregon and Utah and have an aggregate capacity of 168.5 MW.

Contractual Obligations

As of September 30, 2016, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2015.

Regulatory Matters

PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.

Environmental Laws and Regulations

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

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

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, pension and other postretirement benefits, income taxes and revenue recognition-unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2015. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2015.

MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

Des Moines, Iowa

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of September 30, 2016, and the related statements of operations and comprehensive income for the three-month and nine-month periods ended September 30, 2016 and 2015, and of changes in equity and cash flows for the nine-month periods ended September 30, 2016 and 2015. These interim financial statements are the responsibility of MidAmerican Energy's management.

Based on our reviews, we are not aware of any material modifications that should be made to such interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheet of MidAmerican Energy Company as of December 31, 2015, and the related statements of operations, comprehensive income, changes in equity and cash flows for the year then ended (not presented herein) prior to reclassification for the discontinued operations described in Note 3 to the accompanying financial information; and in our report dated February 26, 2016, we expressed an unqualified opinion on those financial statements. We also audited the adjustments described in Note 3 to reclassify the December 31, 2015 balance sheet of MidAmerican Energy Company for discontinued operations. In our opinion, such adjustments are appropriate and have been properly applied to the previously issued financial statements in deriving the accompanying retrospectively adjusted financial information as of December 31, 2015.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 4, 2016

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	September 30,		December 31,
	2016		2015

ASSETS
Current assets:
Cash and cash equivalents	$	50	$	103
Receivables, net	292		342
Income taxes receivable	—		104
Inventories	264		238
Other current assets	19		58
Total current assets	625		845

Property, plant and equipment, net	12,453		11,723
Regulatory assets	1,171		1,044
Investments and restricted cash and investments	663		634
Other assets	171		139

Total assets	$	15,083	$	14,385

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

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)



	As of
	September 30,			December 31,
	2016			2015

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	309		$	426
Accrued interest	46			46
Accrued property, income and other taxes	183			125
Current portion of long-term debt	250			34
Other current liabilities	167			166
Total current liabilities	955			797

Long-term debt	4,018			4,237
Deferred income taxes	3,330			3,061
Regulatory liabilities	806			831
Asset retirement obligations	554			488
Other long-term liabilities	277			266
Total liabilities	9,940			9,680

Commitments and contingencies (Note 11)

Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—			—
Additional paid-in capital	561			561
Retained earnings	4,583			4,174
Accumulated other comprehensive loss, net	(1		)	(30		)
Total shareholder's equity	5,143			4,705

Total liabilities and shareholder's equity	$	15,083		$	14,385

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015
Operating revenue:
Regulated electric	$	692		$	585		$	1,572		$	1,472
Regulated gas and other	103			95			432			502
Total operating revenue	795			680			2,004			1,974

Operating costs and expenses:
Cost of fuel, energy and capacity	130			125			312			351
Cost of gas sold and other	55			48			237			304
Operations and maintenance	180			172			510			516
Depreciation and amortization	118			101			338			300
Property and other taxes	28			26			84			83
Total operating costs and expenses	511			472			1,481			1,554

Operating income	284			208			523			420

Other income and (expense):
Interest expense	(50		)	(44		)	(147		)	(133		)
Allowance for borrowed funds	3			2			6			6
Allowance for equity funds	6			5			14			16
Other, net	3			(3		)	8			2
Total other income and (expense)	(38		)	(40		)	(119		)	(109		)

Income before income tax benefit	246			168			404			311
Income tax benefit	(74		)	(65		)	(123		)	(138		)

Income from continuing operations	320			233			527			449

Discontinued operations (Note 3):
Income from discontinued operations	—			2			—			18
Income tax expense	—			1			—			8
Income on discontinued operations	—			1			—			10

Net income	$	320		$	234		$	527		$	459

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)



	Three-Month Periods					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2016		2015			2016		2015

Net income	$	320	$	234		$	527	$	459

Other comprehensive (loss) income, net of tax:
Unrealized (losses) gains on available-for-sale securities, net of tax of $-, $-, $1 and $-	—		(1		)	2		—
Unrealized losses on cash flow hedges, net of tax of $-, $(4), $- and $(5)	—		(3		)	—		(7		)
Total other comprehensive (loss) income, net of tax	—		(4		)	2		(7		)

Comprehensive income	$	320	$	230		$	529	$	452

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)



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

Balance, December 31, 2014	$	561	$	3,712		$	(23	)	$	4,250
Net income	—		459			—			459
Other comprehensive loss	—		—			(7		)	(7		)
Balance, September 30, 2015	$	561	$	4,171		$	(30	)	$	4,702

Balance, December 31, 2015	$	561	$	4,174		$	(30	)	$	4,705
Net income	—		527			—			527
Other comprehensive income	—		—			2			2
Dividend (Note 3)	—		(117		)	27			(90		)
Other equity transactions	—		(1		)	—			(1		)
Balance, September 30, 2016	$	561	$	4,583		$	(1	)	$	5,143

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2016			2015
Cash flows from operating activities:
Net income	$	527		$	459
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	338			300
Deferred income taxes and amortization of investment tax credits	113			24
Changes in other assets and liabilities	34			36
Other, net	(42		)	(7		)
Changes in other operating assets and liabilities:
Receivables, net	(67		)	49
Inventories	(26		)	(33		)
Derivative collateral, net	4			49
Contributions to pension and other postretirement benefit plans, net	(5		)	(6		)
Accounts payable	14			(78		)
Accrued property, income and other taxes, net	160			341
Other current assets and liabilities	30			16
Net cash flows from operating activities	1,080			1,150

Cash flows from investing activities:
Utility construction expenditures	(1,129		)	(880		)
Purchases of available-for-sale securities	(96		)	(91		)
Proceeds from sales of available-for-sale securities	92			83
Other, net	5			4
Net cash flows from investing activities	(1,128		)	(884		)

Cash flows from financing activities:
Proceeds from long-term debt	33			—
Repayments of long-term debt	(38		)	—
Net repayments of short-term debt	—			(50		)
Net cash flows from financing activities	(5		)	(50		)

Net change in cash and cash equivalents	(53		)	216
Cash and cash equivalents at beginning of period	103			29
Cash and cash equivalents at end of period	$	50		$	245

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

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)


(1)	General

MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries and related corporate services. MHC's nonregulated subsidiaries include Midwest Capital Group, Inc. and MEC Construction Services Co. MHC is the direct, wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2016, and for the three- and nine-month periods ended September 30, 2016 and 2015. Certain amounts in the prior period Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income or retained earnings. The results of operations for the three- and nine-month periods ended September 30, 2016, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2015, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2016.


(2)	New Accounting Pronouncements

In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, which amends FASB Accounting Standards Codification ("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. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its 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. 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. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to 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. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.

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, 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. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.


(3)	Discontinued Operations

On January 1, 2016, MidAmerican Energy transferred the assets and liabilities of its unregulated retail services business to a subsidiary of BHE. The transfer was made at MidAmerican Energy’s carrying value of the assets and liabilities as of December 31, 2015, and was recorded by MidAmerican Energy as a noncash dividend as summarized in the table below. Financial results of the unregulated retail services business for the three- and nine-month periods ended September 30, 2015, have been reclassified to discontinued operations in the Statements of Operations. Operating revenue and cost of sales of the unregulated retail services business for the three-month period ended September 30, 2015, totaled $240 million and $232 million, respectively. Operating revenue and cost of sales of the unregulated retail services business for the nine-month period ended September 30, 2015, totaled $685 million and $648 million, respectively. Cash flows from operating activities of the unregulated retail services business totaled $13 million for the nine-month period ended September 30, 2015, and are reflected in the Statement of Cash Flows. Assets, liabilities and equity of the unregulated retail services business reflected in the Balance Sheet as of December 31, 2015, are as follows (in millions):



Receivables	$	115
Derivative assets	41
Deferred income taxes	21
Accounts payable	(49		)
Derivative liabilities	(42		)
Other assets and liabilities, net	4
Dividend, excluding accumulated other comprehensive loss, net	90
Accumulated other comprehensive loss, net	27
Dividend, including accumulated other comprehensive loss, net	$	117


(4)	Property, Plant and Equipment, Net

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



		As of
		September 30,			December 31,
	Depreciable Life	2016			2015
Utility plant in service, net:
Generation	20-70 years	$	10,601		$	10,404
Transmission	52-70 years	1,479			1,305
Electric distribution	20-70 years	3,138			3,059
Gas distribution	28-70 years	1,542			1,507
Utility plant in service		16,760			16,275
Accumulated depreciation and amortization		(5,357		)	(5,229		)
Utility plant in service, net		11,403			11,046
Nonregulated property, net:
Nonregulated property gross	5-45 years	7			15
Accumulated depreciation and amortization		(1		)	(5		)
Nonregulated property, net		6			10
		11,409			11,056
Construction work in progress		1,044			667
Property, plant and equipment, net		$	12,453		$	11,723

(5) Recent Financing Transactions

In September 2016, the Iowa Finance Authority issued $33 million of variable-rate tax-exempt Pollution Control Facilities Refunding Revenue Bonds due September 2036, the proceeds of which were loaned to MidAmerican Energy to refinance, in September 2016, variable-rate tax-exempt pollution control refunding revenue bonds totaling $29 million due September 2016 and $4 million due March 2017, which were optionally redeemed in full. The interest rate on the new bonds will initially be reset on a weekly basis through remarketing of the bonds in the short-term tax-exempt market. MidAmerican Energy is contractually responsible for the timely payment of principal and interest on the bonds.


(6)	Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit from continuing operations is as follows:



	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2016		2015		2016		2015

Federal statutory income tax rate	35	%	35	%	35	%	35	%
Income tax credits	(58	)	(62	)	(58	)	(65	)
State income tax, net of federal income tax benefit	(6	)	(10	)	(4	)	(7	)
Effects of ratemaking	(1	)	(2	)	(3	)	(7	)
Other, net	—		—		—		—
Effective income tax rate	(30	)%	(39	)%	(30	)%	(44	)%

Income tax credits relate primarily to production tax credits from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in service.

Berkshire Hathaway includes BHE and subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, MidAmerican Energy's provision for income taxes has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income taxes are remitted to or received from BHE. MidAmerican Energy received net cash payments for income taxes from BHE totaling $416 million and $513 million for the nine-month periods ended September 30, 2016 and 2015, respectively.


(7)	Employee Benefit Plans

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.

Net periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015
Pension:
Service cost	$	3		$	3		$	8		$	9
Interest cost	8			8			25			24
Expected return on plan assets	(11		)	(11		)	(33		)	(34		)
Net amortization	—			—			1			1
Net periodic benefit cost	$	—		$	—		$	1		$	—

Other postretirement:
Service cost	$	1		$	2		$	4		$	5
Interest cost	2			1			7			6
Expected return on plan assets	(3		)	(4		)	(10		)	(11		)
Net amortization	(1		)	—			(3		)	(2		)
Net periodic benefit credit	$	(1	)	$	(1	)	$	(2	)	$	(2	)

Employer contributions to the pension and other postretirement benefit plans are expected to be $8 million and $1 million, respectively, during 2016. As of September 30, 2016, $5 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.


(8)	Asset Retirement Obligations


(9)	Risk Management and Hedging Activities

MidAmerican Energy is exposed to the impact of market fluctuations in commodity prices and interest rates. MidAmerican Energy is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated service territory. Prior to January 1, 2016, MidAmerican Energy also provided nonregulated retail electricity and natural gas services in competitive markets, which created contractual obligations to provide electric and natural gas services. MidAmerican Energy's 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 debt and future debt issuances. MidAmerican Energy does not engage in a material amount of proprietary trading activities.

MidAmerican Energy 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. To mitigate a portion of its commodity price risk, MidAmerican Energy 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. MidAmerican Energy 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, MidAmerican Energy may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate its exposure to interest rate risk. MidAmerican Energy does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in MidAmerican Energy's accounting policies related to derivatives. Refer to Note 10 for additional information on derivative contracts and to Note 3 for a discussion of discontinued operations.

The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of MidAmerican Energy's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Balance Sheets (in millions):



	Other Current Assets		Other Assets		Other Current Liabilities			Other Long-term Liabilities			Total
As of September 30, 2016:
Not designated as hedging contracts⁽¹⁾⁽²⁾:
Commodity assets	$	2	$	—	$	3		$	—		$	5
Commodity liabilities	—		—		(7		)	(2		)	(9		)
Total	2		—		(4		)	(2		)	(4		)

Designated as hedging contracts⁽²⁾:
Commodity assets	—		—		—			—			—
Commodity liabilities	—		—		—			—			—
Total	—		—		—			—			—

Total derivatives	2		—		(4		)	(2		)	(4		)
Cash collateral receivable	—		—		1			—			1
Total derivatives - net basis	$	2	$	—	$	(3	)	$	(2	)	$	(3	)



	Other Current Assets			Other Assets		Other Current Liabilities			Other Long- Term Liabilities			Total
As of December 31, 2015:
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	12		$	4	$	5		$	2		$	23
Commodity liabilities	(3		)	—		(36		)	(10		)	(49		)
Total	9			4		(31		)	(8		)	(26		)

Designated as hedging contracts:
Commodity assets	—			—		1			2			3
Commodity liabilities	—			—		(32		)	(17		)	(49		)
Total	—			—		(31		)	(15		)	(46		)

Total derivatives	9			4		(62		)	(23		)	(72		)
Cash collateral receivable	—			—		22			6			28
Total derivatives - net basis	$	9		$	4	$	(40	)	$	(17	)	$	(44	)


(1)	MidAmerican Energy's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of September 30, 2016 and December 31, 2015, a net regulatory asset of $5 million and $20 million, respectively, was recorded related to the net derivative liability of $4 million and $26 million, respectively.


(2)	The changes in derivative values from December 31, 2015, are substantially due to the transfer of MidAmerican Energy's unregulated retail services business to a subsidiary of BHE.

Not Designated as Hedging Contracts

The following table reconciles the beginning and ending balances of MidAmerican Energy's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015

Beginning balance	$	3		$	28		$	20		$	38
Changes in fair value recognized in net regulatory assets	5			10			8			29
Net losses reclassified to operating revenue	(1		)	(12		)	(14		)	(34		)
Net losses reclassified to cost of gas sold	(2		)	(3		)	(9		)	(10		)
Ending balance	$	5		$	23		$	5		$	23

Designated as Hedging Contracts

MidAmerican Energy used commodity derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices related to its unregulated retail services business, which was transferred to a subsidiary of BHE. The following table reconciles the beginning and ending balances of MidAmerican Energy's accumulated other comprehensive loss (pre-tax) and summarizes pre-tax gains and losses on commodity derivative contracts designated and qualifying as cash flow hedges recognized in other comprehensive income ("OCI"), as well as amounts reclassified to earnings (in millions):



	Three-Month Periods					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2016		2015			2016			2015

Beginning balance	$	—	$	39		$	45		$	34
Transfer to affiliate	—		—			(45		)	—
Changes in fair value recognized in OCI	—		21			—			40
Net gains reclassified to nonregulated cost of sales	—		(14		)	—			(28		)
Ending balance	$	—	$	46		$	—		$	46

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):



	Unit of	September 30,	December 31,
	Measure	2016	2015

Electricity purchases	Megawatt hours	—	15
Natural gas purchases	Decatherms	17	17

Credit Risk

MidAmerican Energy is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent MidAmerican Energy's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, MidAmerican Energy 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, MidAmerican Energy 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, MidAmerican Energy exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base MidAmerican Energy's collateral requirements on its credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts 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 MidAmerican Energy's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2016, MidAmerican Energy's credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of MidAmerican Energy's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $7 million and $66 million as of September 30, 2016 and December 31, 2015, respectively, for which MidAmerican Energy had posted collateral of $- million at each date. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2016 and December 31, 2015, MidAmerican Energy would have been required to post $3 million and $55 million, respectively, of additional collateral. MidAmerican Energy's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors. MidAmerican Energy's exposure to contingent features declined significantly as a result of the transfer of its unregulated retail services business to a subsidiary of BHE.


(10)	Fair Value Measurements

The carrying value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.

Level 3 — Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.

The following table presents MidAmerican Energy's assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):



	Input Levels for Fair Value Measurements
	Level 1			Level 2			Level 3			Other⁽¹⁾			Total
As of September 30, 2016:
Assets:
Commodity derivatives	$	—		$	3		$	2		$	(3	)	$	2
Money market mutual funds⁽²⁾	51			—			—			—			51
Debt securities:
United States government obligations	156			—			—			—			156
International government obligations	—			3			—			—			3
Corporate obligations	—			36			—			—			36
Municipal obligations	—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			2			—			—			2
Auction rate securities	—			—			18			—			18
Equity securities:
United States companies	249			—			—			—			249
International companies	6			—			—			—			6
Investment funds	9			—			—			—			9
	$	471		$	46		$	20		$	(3	)	$	534

Liabilities - commodity derivatives	$	(1	)	$	(4	)	$	(4	)	$	4		$	(5	)



	Input Levels for Fair Value Measurements
	Level 1			Level 2			Level 3			Other⁽¹⁾			Total
As of December 31, 2015:
Assets:
Commodity derivatives	$	—		$	8		$	18		$	(13	)	$	13
Money market mutual funds⁽²⁾	56			—			—			—			56
Debt securities:
United States government obligations	133			—			—			—			133
International government obligations	—			2			—			—			2
Corporate obligations	—			39			—			—			39
Municipal obligations	—			1			—			—			1
Agency, asset and mortgage-backed obligations	—			3			—			—			3
Auction rate securities	—			—			26			—			26
Equity securities:
United States companies	239			—			—			—			239
International companies	6			—			—			—			6
Investment funds	4			—			—			—			4
	$	438		$	53		$	44		$	(13	)	$	522

Liabilities - commodity derivatives	$	(13	)	$	(61	)	$	(24	)	$	41		$	(57	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $1 million and $28 million as of September 30, 2016 and December 31, 2015, respectively.


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

Derivative contracts are recorded on the 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 MidAmerican Energy transacts. When quoted prices for identical contracts are not available, MidAmerican Energy uses forward price curves. Forward price curves represent MidAmerican Energy's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. MidAmerican Energy 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 MidAmerican Energy. Market price quotations are generally readily obtainable for the applicable term of MidAmerican Energy's outstanding derivative contracts; therefore, MidAmerican Energy's forward price curves reflect 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, MidAmerican Energy 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, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 9 for further discussion regarding MidAmerican Energy's risk management and hedging activities.

MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value and are primarily accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics. The fair value of MidAmerican Energy's investments in auction rate securities, where there is no current liquid market, is determined using pricing models based on available observable market data and MidAmerican Energy's judgment about the assumptions, including liquidity and nonperformance risks, which market participants would use when pricing the asset.

The following table reconciles the beginning and ending balances of MidAmerican Energy's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	Commodity Derivatives			Auction Rate Securities			Commodity Derivatives			Auction Rate Securities
2016:
Beginning balance	$	(2	)	$	18		$	(6	)	$	26
Transfer to affiliate	—			—			(4		)	—
Changes in fair value recognized in OCI	—			—			—			3
Changes in fair value recognized in net regulatory assets	(1		)	—			(5		)	—
Redemptions	—			—			—			(11		)
Settlements	1			—			13			—
Ending balance	$	(2	)	$	18		$	(2	)	$	18

2015:
Beginning balance	$	(7	)	$	27		$	12		$	26
Changes included in earnings	2			—			6			—
Changes in fair value recognized in OCI	(2		)	(1		)	(5		)	—
Changes in fair value recognized in net regulatory assets	(5		)	—			(20		)	—
Purchases	—			—			1			—
Settlements	5			—			(1		)	—
Ending balance	$	(7	)	$	26		$	(7	)	$	26

MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):



	As of September 30, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	4,268	$	5,000	$	4,271	$	4,636


(11)	Commitments and Contingencies

Legal Matters

MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.

Environmental Laws and Regulations

Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using FERC-approved formula rates subject to true-up for actual cost of service. Prior to September 2016, the rates in effect were based on a 12.38% return on equity ("ROE"). In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the 12.38% ROE no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the base ROE effective January 2015. In September 2016, the FERC issued an order for the first complaint, which reduces the base ROE to 10.32% and requires refunds, plus interest, for the period from November 2013 through February 2015. The FERC is expected to rule on the second complaint by the second quarter of 2017, covering the period from February 2015 through May 2016. MidAmerican Energy believes it is probable that the FERC will order a base ROE lower than 12.38% in the second complaint and has accrued an $11 million liability for refunds under both complaints of amounts collected under the higher ROE from November 2013 through September 30, 2016.


(12)	Components of Accumulated Other Comprehensive Income (Loss), Net

The following table shows the change in accumulated other comprehensive income (loss), net ("AOCI") by each component of other comprehensive income, net of applicable income taxes (in millions):



	Unrealized			Unrealized			Accumulated
	Losses on			Losses			Other
	Available-For-Sale			on Cash Flow			Comprehensive
	Securities			Hedges			Loss, Net

Balance, December 31, 2014	$	(3	)	$	(20	)	$	(23	)
Other comprehensive loss	—			(7		)	(7		)
Balance at September 30, 2015	$	(3	)	$	(27	)	$	(30	)

Balance, December 31, 2015	$	(3	)	$	(27	)	$	(30	)
Other comprehensive income	2			—			2
Dividend (Note 3)	—			27			27
Balance, September 30, 2016	$	(1	)	$	—		$	(1	)

For information regarding cash flow hedge reclassifications from AOCI to net income in their entirety, refer to Note 9.


(13)	Segment Information

MidAmerican Energy has identified two reportable segments: regulated electric and regulated gas. The previously reported nonregulated energy segment consisted substantially of MidAmerican Energy's unregulated retail services business, which was transferred to a subsidiary of BHE and is excluded from the information presented below. Refer to Note 3 for further discussion. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting gas owned by others through its distribution system. Pricing for regulated electric and regulated gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the financial results and assets of remaining nonregulated operations.

The following tables provide information on a reportable segment basis (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016		2015
Operating revenue:
Regulated electric	$	692		$	585		$	1,572	$	1,472
Regulated gas	102			94			430		499
Other	1			1			2		3
Total operating revenue	$	795		$	680		$	2,004	$	1,974

Depreciation and amortization:
Regulated electric	$	107		$	91		$	306	$	270
Regulated gas	11			10			32		30
Total depreciation and amortization	$	118		$	101		$	338	$	300

Operating income:
Regulated electric	$	289		$	215		$	481	$	376
Regulated gas	(5		)	(6		)	42		45
Other	—			(1		)	—		(1		)
Total operating income	$	284		$	208		$	523	$	420



	As of
	September 30, 2016		December 31, 2015
Total assets:
Regulated electric	$	13,842	$	12,970
Regulated gas	1,240		1,251
Other⁽¹⁾	1		164
Total assets	$	15,083	$	14,385


(1)	Other total assets for December 31, 2015, includes amounts for MidAmerican Energy's unregulated retail services business transferred to a subsidiary of BHE.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

Des Moines, Iowa

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of September 30, 2016, and the related consolidated statements of operations and comprehensive income for the three-month and nine-month periods ended September 30, 2016 and 2015, and of changes in equity and cash flows for the nine-month periods ended September 30, 2016 and 2015. These interim financial statements are the responsibility of MidAmerican Funding's management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries as of December 31, 2015, and the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for the year then ended (not presented herein) prior to reclassification for the discontinued operations described in Note 3 to the accompanying financial information; and in our report dated February 26, 2016, we expressed an unqualified opinion on those consolidated financial statements. We also audited the adjustments described in Note 3 to reclassify the December 31, 2015 balance sheet of MidAmerican Funding, LLC and subsidiaries for discontinued operations. In our opinion, such adjustments are appropriate and have been properly applied to the previously issued financial statements in deriving the accompanying retrospectively adjusted financial information as of December 31, 2015.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 4, 2016

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	September 30,		December 31,
	2016		2015

ASSETS
Current assets:
Cash and cash equivalents	$	51	$	103
Receivables, net	295		346
Income taxes receivable	—		104
Inventories	264		238
Other current assets	18		58
Total current assets	628		849

Property, plant and equipment, net	12,466		11,737
Goodwill	1,270		1,270
Regulatory assets	1,171		1,044
Investments and restricted cash and investments	665		636
Other assets	172		138

Total assets	$	16,372	$	15,674

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)



	As of
	September 30,			December 31,
	2016			2015

LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	309		$	427
Accrued interest	49			53
Accrued property, income and other taxes	183			125
Note payable to affiliate	38			139
Current portion of long-term debt	250			34
Other current liabilities	167			166
Total current liabilities	996			944

Long-term debt	4,343			4,563
Deferred income taxes	3,325			3,056
Regulatory liabilities	806			831
Asset retirement obligations	554			488
Other long-term liabilities	277			267
Total liabilities	10,301			10,149

Commitments and contingencies (Note 11)

Member's equity:
Paid-in capital	1,679			1,679
Retained earnings	4,393			3,876
Accumulated other comprehensive loss, net	(1		)	(30		)
Total member's equity	6,071			5,525

Total liabilities and member's equity	$	16,372		$	15,674

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015
Operating revenue:
Regulated electric	$	692		$	585		$	1,572		$	1,472
Regulated gas and other	105			96			436			512
Total operating revenue	797			681			2,008			1,984

Operating costs and expenses:
Cost of fuel, energy and capacity	130			125			312			351
Cost of gas sold and other	56			48			239			311
Operations and maintenance	181			172			511			517
Depreciation and amortization	118			101			338			300
Property and other taxes	28			26			84			83
Total operating costs and expenses	513			472			1,484			1,562

Operating income	284			209			524			422

Other income and (expense):
Interest expense	(55		)	(50		)	(164		)	(150		)
Allowance for borrowed funds	3			2			6			6
Allowance for equity funds	6			5			14			16
Other, net	3			(3		)	9			16
Total other income and (expense)	(43		)	(46		)	(135		)	(112		)

Income before income tax benefit	241			163			389			310
Income tax benefit	(77		)	(67		)	(129		)	(139		)

Income from continuing operations	318			230			518			449

Discontinued operations (Note 3):
Income from discontinued operations	—			2			—			18
Income tax expense	—			1			—			8
Income on discontinued operations	—			1			—			10

Net income	$	318		$	231		$	518		$	459

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)



	Three-Month Periods					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2016		2015			2016		2015

Net income	$	318	$	231		$	518	$	459

Other comprehensive (loss) income, net of tax:
Unrealized (losses) gains on available-for-sale securities, net of tax of $-, $-, $1 and $-	—		(1		)	2		—
Unrealized losses on cash flow hedges, net of tax of $-, $(4), $- and $(5)	—		(3		)	—		(7		)
Total other comprehensive (loss) income, net of tax	—		(4		)	2		(7		)

Comprehensive income	$	318	$	227		$	520	$	452

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)



	Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Loss, Net			Total Equity

Balance, December 31, 2014	$	1,679	$	3,417		$	(23	)	$	5,073
Net income	—		459			—			459
Other comprehensive loss	—		—			(7		)	(7		)
Balance, September 30, 2015	$	1,679	$	3,876		$	(30	)	$	5,525

Balance, December 31, 2015	$	1,679	$	3,876		$	(30	)	$	5,525
Net income	—		518			—			518
Other comprehensive income	—		—			2			2
Transfer to affiliate (Note 3)	—		—			27			27
Other equity transactions	—		(1		)	—			(1		)
Balance, September 30, 2016	$	1,679	$	4,393		$	(1	)	$	6,071

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2016			2015
Cash flows from operating activities:
Net income	$	518		$	459
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	338			300
Deferred income taxes and amortization of investment tax credits	113			25
Changes in other assets and liabilities	34			36
Other, net	(42		)	(20		)
Changes in other operating assets and liabilities:
Receivables, net	(67		)	50
Inventories	(26		)	(33		)
Derivative collateral, net	4			49
Contributions to pension and other postretirement benefit plans, net	(5		)	(6		)
Accounts payable	14			(78		)
Accrued property, income and other taxes, net	160			341
Other current assets and liabilities	24			11
Net cash flows from operating activities	1,065			1,134

Cash flows from investing activities:
Utility construction expenditures	(1,129		)	(880		)
Purchases of available-for-sale securities	(96		)	(91		)
Proceeds from sales of available-for-sale securities	92			83
Proceeds from sale of investment	—			13
Other, net	5			4
Net cash flows from investing activities	(1,128		)	(871		)

Cash flows from financing activities:
Proceeds from long-term debt	33
Repayments of long-term debt	(38		)	—
Net change in note payable to affiliate	16			3
Net repayments of short-term debt	—			(50		)
Net cash flows from financing activities	11			(47		)

Net change in cash and cash equivalents	(52		)	216
Cash and cash equivalents at beginning of period	103			30
Cash and cash equivalents at end of period	$	51		$	246

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	General

MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct, wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries and related corporate services. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations. Direct, wholly owned nonregulated subsidiaries of MHC are Midwest Capital Group, Inc. and MEC Construction Services Co.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2016, and for the three- and nine-month periods ended September 30, 2016 and 2015. Certain amounts in the prior period Consolidated Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income or retained earnings. The results of operations for the three- and nine-month periods ended September 30, 2016, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2015, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2016.


(2)	New Accounting Pronouncements

Refer to Note 2 of MidAmerican Energy's Notes to Financial Statements.


(3)	Discontinued Operations

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. The transfer of MidAmerican Energy's unregulated retail services business to a subsidiary of BHE repaid a portion of MHC's note payable to BHE.


(4)	Property, Plant and Equipment, Net

Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had nonregulated property gross of $22 million as of September 30, 2016 and December 31, 2015, and related accumulated depreciation and amortization of $9 million and $8 million as of September 30, 2016 and December 31, 2015, respectively, which consisted primarily of a corporate aircraft owned by MHC.

(5) Recent Financing Transactions

Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.


(6)	Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit from continuing operations is as follows:



	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2016		2015		2016		2015

Federal statutory income tax rate	35	%	35	%	35	%	35	%
Income tax credits	(60	)	(64	)	(61	)	(66	)
State income tax, net of federal income tax benefit	(7	)	(11	)	(4	)	(7	)
Effects of ratemaking	—		(2	)	(3	)	(7	)
Other, net	—		1		—		—
Effective income tax rate	(32	)%	(41	)%	(33	)%	(45	)%

Berkshire Hathaway includes BHE and subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income taxes have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income taxes are remitted to or received from BHE. MidAmerican Funding received net cash payments for income taxes from BHE totaling $422 million and $515 million for the nine-month periods ended September 30, 2016 and 2015, respectively.


(7)	Employee Benefit Plans

Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements.


(8)	Asset Retirement Obligations

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.


(9)	Risk Management and Hedging Activities

Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.


(10)	Fair Value Measurements

Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):



	As of September 30, 2016				As of December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	4,593	$	5,458	$	4,597	$	5,051

(11) Commitments and Contingencies

MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements.


(12)	Components of Accumulated Other Comprehensive Income (Loss), Net

Refer to Note 12 of MidAmerican Energy's Notes to Financial Statements.

(13) Segment Information

MidAmerican Funding has identified two reportable segments: regulated electric and regulated gas. The previously reported nonregulated energy segment consisted substantially of MidAmerican Energy's unregulated retail services business, which was transferred to a subsidiary of BHE and is excluded from the information presented below. Refer to Note 3 for further discussion. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting gas owned by others through its distribution system. Pricing for regulated electric and regulated gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the financial results and assets of nonregulated operations, MHC and MidAmerican Funding.

The following tables provide information on a reportable segment basis (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016		2015
Operating revenue:
Regulated electric	$	692		$	585		$	1,572	$	1,472
Regulated gas	102			94			430		499
Other	3			2			6		13
Total operating revenue	$	797		$	681		$	2,008	$	1,984

Depreciation and amortization:
Regulated electric	$	107		$	91		$	306	$	270
Regulated gas	11			10			32		30
Total depreciation and amortization	$	118		$	101		$	338	$	300

Operating income:
Regulated electric	$	289		$	215		$	481	$	376
Regulated gas	(5		)	(6		)	42		45
Other	—			—			1		1
Total operating income	$	284		$	209		$	524	$	422



	As of
	September 30, 2016		December 31, 2015
Total assets⁽¹⁾:
Regulated electric	$	15,033	$	14,161
Regulated gas	1,319		1,330
Other	20		183
Total assets	$	16,372	$	15,674



(1)	Total assets by reportable segment reflect the assignment of goodwill to applicable reporting units. Other total assets for December 31, 2015, includes amounts for MidAmerican Energy's unregulated retail services business transferred to a subsidiary of BHE.


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

MidAmerican Funding is an Iowa limited liability company whose sole member is BHE. MidAmerican Funding owns all of the outstanding common stock of MHC Inc., which owns all of the common stock of MidAmerican Energy, Midwest Capital Group, Inc. and MEC Construction Services Co. MidAmerican Energy is a public utility company headquartered in Des Moines, Iowa. MHC Inc., MidAmerican Funding and BHE are also headquartered in Des Moines, Iowa.

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy as presented in this joint filing. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with the historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. Refer to Note 3 of those Notes to Financial Statements for a discussion of the transfer of MidAmerican Energy's unregulated retail services business to a subsidiary of BHE on January 1, 2016. MidAmerican Energy's and MidAmerican Funding's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2016 and 2015

Overview

MidAmerican Energy -

MidAmerican Energy's income from continuing operations for the third quarter of 2016 was $320 million, an increase of $87 million, or 37%, compared to 2015 due to higher electric margins of $102 million, higher recognized production tax credits of $39 million and lower generation operations and maintenance of $4 million, partially offset by higher income taxes on higher pre-tax income, higher depreciation and amortization of $17 million due to plant placed in service and an accrual related to an Iowa revenue sharing arrangement, higher operations costs recovered through bill riders of $9 million and higher interest expense of $6 million primarily due to the issuance of first mortgage bonds in October 2015. Electric margins reflect higher retail sales volumes, higher recoveries through bill riders, higher wholesale revenue, higher retail rates in Iowa and higher transmission revenue, partially offset by higher energy costs.

MidAmerican Energy's income from continuing operations for the first nine months of 2016 was $527 million, an increase of $78 million, or 17%, compared to 2015 due to higher electric margins of $139 million, higher recognized production tax credits of $33 million, lower generation operations and maintenance of $12 million and lower electric and gas distribution costs of $8 million, partially offset by higher income taxes on higher pre-tax income and the effects of ratemaking, higher depreciation and amortization of $38 million from wind-powered generation and other plant placed in service and an accrual related to an Iowa revenue sharing arrangement, higher operations costs recovered through bill riders of $14 million and higher interest expense of $14 million primarily due to the issuance of first mortgage bonds in October 2015. Electric margins reflect higher retail sales volumes, lower energy costs, higher retail rates in Iowa and higher transmission revenue, partially offset by lower wholesale revenue.

MidAmerican Funding -

MidAmerican Funding's income from continuing operations for the third quarter of 2016 was $318 million, an increase of $88 million, or 38%, compared to 2015 and, for the first nine months of 2016, was $518 million, an increase of $69 million, or 15%, compared to 2015. In addition to the changes in MidAmerican Energy's earnings discussed above, MidAmerican Funding recognized an $8 million after-tax gain on the sale of an investment in a generating facility lease in the first quarter of 2015.

Regulated Electric Gross Margin

A comparison of key operating results related to regulated electric gross margin is as follows:



	Third Quarter									First Nine Months
	2016		2015		Change					2016		2015		Change
Gross margin (in millions):
Operating revenue	$	692	$	585	$	107		18	%	$	1,572	$	1,472	$	100		7	%
Cost of fuel, energy and capacity	130		125		5			4		312		351		(39		)	(11	)
Gross margin	$	562	$	460	$	102		22		$	1,260	$	1,121	$	139		12

Electricity Sales (GWh):
Residential	1,969		1,896		73			4	%	5,018		4,862		156			3	%
Small general service	1,023		1,046		(23		)	(2	)	2,859		2,914		(55		)	(2	)
Large general service	3,106		2,932		174			6		8,999		8,605		394			5
Other	427		425		2			—		1,213		1,207		6			—
Total retail	6,525		6,299		226			4		18,089		17,588		501			3
Wholesale	2,037		1,751		286			16		5,620		6,772		(1,152		)	(17	)
Total sales	8,562		8,050		512			6		23,709		24,360		(651		)	(3	)

Average number of retail customers (in thousands)	761		753		8			1	%	759		751		8			1	%

Average revenue per MWh:
Retail	$	94.02	$	84.53	$	9.49		11	%	$	76.75	$	73.42	$	3.33		5	%
Wholesale	$	28.13	$	21.91	$	6.22		28	%	$	22.84	$	20.56	$	2.28		11	%

Heating degree days	27		48		(21		)	(44	)%	3,388		3,845		(457		)	(12	)%
Cooling degree days	855		758		97			13	%	1,284		1,052		232			22	%

Sources of energy (GWh)⁽¹⁾:
Coal	4,618		4,674		(56		)	(1	)%	9,907		13,051		(3,144		)	(24	)%
Nuclear	1,003		994		9			1		2,887		2,858		29			1
Natural gas	307		182		125			69		515		182		333			183
Wind and other⁽²⁾	1,950		1,670		280			17		7,981		6,495		1,486			23
Total energy generated	7,878		7,520		358			5		21,290		22,586		(1,296		)	(6	)
Energy purchased	916		768		148			19		3,030		2,205		825			37
Total	8,794		8,288		506			6		24,320		24,791		(471		)	(2	)


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


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

Regulated electric gross margin increased $102 million for the third quarter of 2016 compared to 2015 primarily due to:


(1)	Higher retail gross margin of $81 million due to -

an increase of $29 million from higher recoveries through bill riders;

an increase of $22 million primarily from non-weather-related usage factors, including higher industrial sales volumes;

an increase of $14 million from higher electric rates in Iowa effective January 1, 2016;

an increase of $13 million from the impact of warmer temperatures; and

an increase of $3 million from lower retail energy costs primarily due to a lower average cost of fuel for generation;


(2)	Higher wholesale gross margin of $15 million primarily due to higher margins per unit on higher sales volumes enabled by greater availability of lower cost generation; and


(3)	Higher Multi-Value Projects ("MVPs") transmission revenue of $6 million, which is expected to increase as projects are constructed.

Regulated electric gross margin increased $139 million for the first nine months of 2016 compared to 2015 primarily due to:


(1)	Higher retail gross margin of $109 million due to -

an increase of $35 million from higher electric rates in Iowa effective January 1, 2016;

an increase of $31 million primarily from non-weather-related usage factors, including higher industrial sales volumes;

an increase of $24 million from the impact of temperatures;

an increase of $18 million from lower retail energy costs primarily due to a lower average cost of fuel for generation; and

an increase of $1 million from higher recoveries through bill riders;


(2)	Higher wholesale gross margin of $17 million due to higher margins per unit from greater availability of lower cost generation for wholesale purposes, partially offset by lower sales volumes attributable to lower coal-fueled generation; and


(3)	Higher MVPs transmission revenue of $13 million, which is expected to increase as projects are constructed.

Regulated Gas Gross Margin

A comparison of key operating results related to regulated gas gross margin is as follows:



	Third Quarter									First Nine Months
	2016		2015		Change					2016		2015		Change
Gross margin (in millions):
Operating revenue	$	102	$	94	$	8		9	%	$	430	$	499	$	(69	)	(14)	%
Cost of gas sold	54		48		6			13		236		304		(68		)	(22	)
Gross margin	$	48	$	46	$	2		4		$	194	$	195	$	(1	)	(1	)

Natural gas throughput (000's Dth):
Residential	2,820		2,753		67			2	%	31,121		33,401		(2,280		)	(7)	%
Small general service	1,840		1,844		(4		)	—		15,729		16,914		(1,185		)	(7	)
Large general service	922		923		(1		)	—		3,574		3,514		60			2
Other	1		2		(1		)	(50	)	26		29		(3		)	(10	)
Total retail sales	5,583		5,522		61			1		50,450		53,858		(3,408		)	(6	)
Wholesale sales	8,568		7,422		1,146			15		28,615		27,105		1,510			6
Total sales	14,151		12,944		1,207			9		79,065		80,963		(1,898		)	(2	)
Gas transportation service	18,087		17,268		819			5		60,117		59,016		1,101			2
Total gas throughput	32,238		30,212		2,026			7		139,182		139,979		(797		)	(1	)

Average number of retail customers (in thousands)	738		731		7			1	%	738		731		7			1	%
Average revenue per retail Dth sold	$	12.77	$	12.25	$	0.52		4	%	$	6.80	$	7.37	$	(0.57	)	(8)	%
Average cost of natural gas per retail Dth sold	$	5.49	$	5.12	$	0.37		7	%	$	3.45	$	4.19	$	(0.74	)	(18)	%

Combined retail and wholesale average cost of natural gas per Dth sold	$	3.82	$	3.75	$	0.07		2	%	$	2.99	$	3.76	$	(0.77	)	(20)	%

Heating degree days	27		52		(25		)	(48)	%	3,572		4,003		(431		)	(11)	%

Regulated gas revenue includes purchased gas adjustment clauses through which MidAmerican Energy is allowed to recover the cost of gas sold from its retail gas utility customers. Consequently, fluctuations in the cost of gas sold do not directly affect gross margin or net income because regulated gas revenue reflects comparable fluctuations through the purchased gas adjustment clauses. For the third quarter of 2016, MidAmerican Energy's combined retail and wholesale average per-unit cost of gas sold increased 2%, resulting in an increase of $1 million in gas revenue and cost of gas sold compared to 2015. For the first nine months of 2016, MidAmerican Energy's combined retail and wholesale average per-unit cost of gas sold decreased 20%, resulting in a decrease of $61 million in gas revenue and cost of gas sold compared to 2015.

Regulated gas gross margin increased $2 million for the third quarter of 2016 compared to 2015 due to higher demand-side management ("DSM") recoveries.

Regulated gas gross margin decreased $1 million for the first nine months of 2016 compared to 2015 due to:


(1)	Lower retail sales volumes of $6 million reflecting warmer winter temperatures in 2016; partially offset by


(2)	Higher DSM recoveries of $5 million.

Operating Costs and Expenses

MidAmerican Energy -

Operations and maintenance increased $8 million for the third quarter of 2016 compared to 2015 due to higher demand-side management ("DSM") program costs of $6 million and higher transmission operations costs from the Midcontinent Independent System Operator, Inc. ("MISO") of $3 million, both of which are recovered through bill riders, as well as higher health care costs and higher wind-powered generation maintenance, partially offset by lower fossil-fueled generation maintenance and lower generation operations.

Operations and maintenance decreased $6 million for the first nine months of 2016 compared to 2015 due to lower fossil-fueled generation maintenance of $11 million, lower generation operations of $7 million and lower electric and gas distribution costs of $8 million, partially offset by higher DSM program costs and transmission operations costs from MISO recoverable in bill riders of $14 million and higher wind-powered generation maintenance of $6 million.

Depreciation and amortization increased $17 million and $38 million for the third quarter and first nine months of 2016, respectively, compared to 2015 due to utility plant additions, including wind-powered generating facilities placed in service in the second half of 2015, and an accrual related to an Iowa revenue sharing arrangement.

Other Income and (Expense)

MidAmerican Energy -

Interest expense increased $6 million and $14 million for the third quarter and first nine months of 2016, respectively, compared to 2015 due to higher interest expense from the issuance of $650 million of first mortgage bonds in October 2015, partially offset by the payment of a $426 million turbine purchase obligation in December 2015.

Allowance for borrowed and equity funds increased $2 million for the third quarter of 2016 compared to 2015 primarily due to higher construction work-in-progress balances related to wind-powered generation and decreased $2 million for the first nine months of 2016 compared to 2015 primarily due to lower construction work-in-progress balances related to wind-powered generation.

Other, net increased $6 million for the third quarter and first nine months of 2016 compared to 2015 due to higher returns on corporate-owned life insurance policies.

MidAmerican Funding -

In addition to the fluctuations discussed above for MidAmerican Energy, MidAmerican Funding's other, net for the first nine months of 2015 reflects a $13 million pre-tax gain on the sale of an investment in a generating facility lease in 2015.

Income Tax Benefit

MidAmerican Energy -

MidAmerican Energy's income tax benefit on continuing operations increased $9 million for the third quarter of 2016 compared to 2015, and the effective tax rate was (30)% for 2016 and (39)% for 2015. The change in the effective tax rate for the third quarter of 2016 was substantially due to a higher pre-tax income, partially offset by an increase in recognized production tax credits.

MidAmerican Energy's income tax benefit on continuing operations decreased $15 million for the first nine months of 2016 compared to 2015, and the effective tax rate was (30)% for 2016 and (44)% for 2015. The change in the effective tax rate for the first nine months of 2016 was substantially due to a higher pre-tax income and the effects of ratemaking, partially offset by an increase in recognized production tax credits.

Production tax credits are recognized in earnings for interim periods based on the application of an estimated annual effective tax rate to pretax earnings. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities were placed in service. Production tax credits recognized in the third quarter of 2016 were $143 million, or $39 million higher than the third quarter of 2015, while production tax credits earned in the third quarter of 2016 were $41 million, or $5 million higher than the third quarter of 2015 primarily due to wind-powered generation placed in service in late 2015. Production tax credits recognized in the first nine months of 2016 were $235 million, or $33 million higher than the first nine months of 2015, while production tax credits earned in the first nine months of 2016 were $171 million, or $28 million higher than the first nine months of 2015 primarily due to wind-powered generation placed in service in late 2015. The difference between production tax credits recognized and earned of $64 million as of September 30, 2016, will be reflected in earnings over the remainder of 2016.

MidAmerican Funding -

MidAmerican Funding's income tax benefit on continuing operations increased $10 million for the third quarter of 2016 compared to 2015, and the effective tax rate was (32)% for 2016 and (41)% for 2015. MidAmerican Funding's income tax benefit on continuing operations decreased $10 million for the first nine months of 2016 compared to 2015, and the effective tax rate was (33)% for 2016 and (45)% for 2015. The change in the effective tax rate was principally due to the factors discussed for MidAmerican Energy. Additionally, income taxes for the first nine months of 2015 reflect taxes on a $13 million gain on the sale of an investment in a generating facility lease in the first quarter of 2015.

Liquidity and Capital Resources

As of September 30, 2016, MidAmerican Energy's total net liquidity was $465 million consisting of $50 million of cash and cash equivalents and $605 million of credit facilities reduced by $190 million of the credit facilities reserved to support MidAmerican Energy's variable-rate tax-exempt bond obligations. As of September 30, 2016, MidAmerican Funding's total net liquidity was $470 million, including $1 million of additional cash and cash equivalents and MHC Inc.'s $4 million credit facility.

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2016 and 2015, were $1.08 billion and $1.15 billion, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2016 and 2015, were $1.07 billion and $1.13 billion, respectively. Cash flows from operating activities declined due to the timing of MidAmerican Energy's income tax cash flows with BHE, lower reimbursements of collateral related to derivative positions, the timing of DSM expenditures and recoveries and payments for the settlement of asset retirement obligations, partially offset by higher gross margins for MidAmerican Energy's regulated electric business and the timing of other working capital. MidAmerican Energy's income tax cash flows with BHE totaled net cash payments from BHE of $416 million and $513 million for the first nine months of 2016 and 2015, respectively. Income tax cash flows for 2016 reflect the receipt of $106 million of income tax benefits generated in 2015 and for 2015 reflect the receipt of $255 million of income tax benefits generated in 2014. The timing of MidAmerican Energy'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 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 50% for 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 the following levels for construction projects whose construction begins before the end of the respective year as follows: at full value for 2016, at 80% of present value for 2017, at 60% of present value for 2018, and 40% of present value for 2019. As a result of PATH, MidAmerican Energy's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in service through 2019 and production tax credits earned on qualifying wind projects through 2029.

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the nine-month periods ended September 30, 2016 and 2015, were $(1.13) billion and $(884) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2016 and 2015, were $(1.13) billion and $(871) million, respectively. Net cash flows from investing activities consist almost entirely of utility construction expenditures, which increased for the first nine months of 2016 compared to 2015 due to higher expenditures for wind-powered generation construction. Purchases and proceeds related to available-for-sale securities primarily consist of activity within the Quad Cities Generating Station nuclear decommissioning trust. MidAmerican Funding received $13 million in 2015 related to the sale of an investment in a generating facility lease.

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the nine-month periods ended September 30, 2016 and 2015 were $(5) million and $(50) million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2016 and 2015, were $11 million and $(47) million, respectively. In September 2016, the Iowa Finance Authority issued $33 million of variable-rate tax-exempt Pollution Control Facilities Refunding Revenue Bonds due September 2036, the proceeds of which were loaned to MidAmerican Energy to refinance, in September 2016, variable-rate tax-exempt pollution control refunding revenue bonds totaling $29 million due September 2016 and $4 million due March 2017, which were optionally redeemed in full. Additionally, in January 2016, MidAmerican Energy repaid $4 million of variable-rate tax-exempt pollution control refunding revenue bonds due January 2016. MidAmerican Energy repaid $50 million of commercial paper in 2015. MidAmerican Funding received $16 million in 2016 and made payments of $3 million in 2015 through its note payable with BHE.

Debt Authorizations and Related Matters

MidAmerican Energy has authority from the FERC to issue through June 30, 2018, commercial paper and bank notes aggregating $605 million at interest rates not to exceed the applicable London Interbank Offered Rate ("LIBOR") plus a spread of up to 400 basis points. MidAmerican Energy has a $600 million unsecured credit facility expiring in March 2018. MidAmerican Energy may request that the banks extend the credit facility up to two years. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on LIBOR or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.

MidAmerican Energy currently has an effective registration statement with the United States Securities and Exchange Commission to issue an indeterminate amount of long-term debt securities through September 16, 2018. Additionally, MidAmerican Energy has authorization from the FERC to issue through March 31, 2017, long-term securities totaling up to $1.05 billion at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points and from the Illinois Commerce Commission to issue up to an aggregate of $900 million of additional long-term debt securities, of which $150 million expires December 9, 2016, and $750 million expires September 22, 2018.

In conjunction with the March 1999 merger, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy's equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy. If MidAmerican Energy's common equity level were to drop below the required thresholds, MidAmerican Energy's ability to issue debt could be restricted. As of September 30, 2016, MidAmerican Energy's common equity ratio was 53% computed on a basis consistent with its commitment.

Future Uses of Cash

MidAmerican Energy and MidAmerican Funding have 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, and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Utility Construction Expenditures

MidAmerican Energy's primary need for capital is utility construction expenditures. 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.

MidAmerican Energy's forecast utility construction expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, are approximately $1.6 billion for 2016 and include:

$932 million primarily for the construction of 599 MW (nominal ratings) of wind-powered generating facilities expected to be placed in service in 2016, of which 171 MW (nominal ratings) had been placed in service as of September 30, 2016, and for the construction of 2,000 MW (nominal ratings) of wind-powered generating facilities expected to be placed in service in 2017 through 2019, as discussed below. Each of these projects is expected to qualify for 100% of production tax credits currently available.

$118 million for transmission MVP investments. MidAmerican Energy has approval from the Midcontinent Independent System Operator, Inc. for the construction of four MVPs located in Iowa and Illinois, which will add approximately 245 miles of 345 kV transmission line to MidAmerican Energy's transmission system.

Remaining costs primarily relate to routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand.

MidAmerican Energy Wind

Contractual Obligations

As of September 30, 2016, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's contractual obligations from the information provided in Item 7 of their Annual Report on Form 10‑K for the year ended December 31, 2015.

Regulatory Matters

MidAmerican Energy is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.

Quad Cities Station Operating Status

The following significant assets and liabilities associated with Quad Cities Station were included on MidAmerican Energy's balance sheet as of September 30, 2016 (in millions):



Assets:
Net plant in service, including nuclear fuel	$	333
Construction work in progress	6
Inventory	18
Regulatory assets	4

Liabilities:
Asset retirement obligation⁽¹⁾	369


(1)	The Quad Cities Station asset retirement obligation assumes a 2032 closure. MidAmerican Energy’s nuclear decommissioning trust fund established for the settlement of the Quad Cities Station asset retirement obligation totaled $455 million and an associated regulatory liability for the excess of the trust fund over the asset retirement obligation totaled $86 million as of September 30, 2016.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding air and water quality, 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 state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of MidAmerican Energy's forecast environmental-related capital expenditures.

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

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2015. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2015.

Nevada Power Company and its subsidiaries

Consolidated Financial Section

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Las Vegas, Nevada

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of September 30, 2016, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2016 and 2015, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 2016 and 2015. These interim financial statements are the responsibility of Nevada Power's management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Nevada Power Company and subsidiaries as of December 31, 2015, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2016, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2015 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 4, 2016

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	September 30,			December 31,
	2016			2015
ASSETS

Current assets:
Cash and cash equivalents	$	302		$	536
Accounts receivable, net	359			265
Inventories	72			80
Other current assets	51			46
Total current assets	784			927

Property, plant and equipment, net	6,971			6,996
Regulatory assets	1,018			1,057
Other assets	38			37

Total assets	$	8,811		$	9,017

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	208		$	214
Accrued interest	27			54
Accrued property, income and other taxes	128			30
Regulatory liabilities	88			173
Current portion of long-term debt and financial and capital lease obligations	15			225
Customer deposits	64			58
Other current liabilities	55			28
Total current liabilities	585			782

Long-term debt and financial and capital lease obligations	3,050			3,060
Regulatory liabilities	411			304
Deferred income taxes	1,449			1,405
Other long-term liabilities	262			303
Total liabilities	5,757			5,854

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—			—
Other paid-in capital	2,308			2,308
Retained earnings	749			858
Accumulated other comprehensive loss, net	(3		)	(3		)
Total shareholder's equity	3,054			3,163

Total liabilities and shareholder's equity	$	8,811		$	9,017

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

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015

Operating revenue	$	766		$	878		$	1,690		$	1,944

Operating costs and expenses:
Cost of fuel, energy and capacity	251			362			618			879
Operating and maintenance	105			104			304			279
Depreciation and amortization	76			74			227			222
Property and other taxes	10			9			30			25
Total operating costs and expenses	442			549			1,179			1,405

Operating income	324			329			511			539

Other income (expense):
Interest expense	(45		)	(48		)	(140		)	(141		)
Allowance for borrowed funds	—			1			2			2
Allowance for equity funds	—			1			3			3
Other, net	7			4			17			15
Total other income (expense)	(38		)	(42		)	(118		)	(121		)

Income before income tax expense	286			287			393			418
Income tax expense	98			100			136			147
Net income	$	188		$	187		$	257		$	271

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

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)



									Accumulated
				Other					Other			Total
	Common Stock			Paid-in		Retained			Comprehensive			Shareholder's
	Shares	Amount		Capital		Earnings			Loss, Net			Equity
Balance, December 31, 2014	1,000	$	—	$	2,308	$	583		$	(3	)	$	2,888
Net income	—	—		—		271			—			271
Dividends declared	—	—		—		(13		)	—			(13		)
Other equity transactions	—	—		—		(1		)	—			(1		)
Balance, September 30, 2015	1,000	$	—	$	2,308	$	840		$	(3	)	$	3,145

Balance, December 31, 2015	1,000	$	—	$	2,308	$	858		$	(3	)	$	3,163
Net income	—	—		—		257			—			257
Dividends declared	—	—		—		(365		)	—			(365		)
Other equity transaction	—	—		—		(1		)	—			(1		)
Balance, September 30, 2016	1,000	$	—	$	2,308	$	749		$	(3	)	$	3,054

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

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2016			2015

Cash flows from operating activities:
Net income	$	257		$	271
Adjustments to reconcile net income to net cash flows from operating activities:
Gain on nonrecurring items	—			(3		)
Depreciation and amortization	227			222
Deferred income taxes and amortization of investment tax credits	52			123
Allowance for equity funds	(3		)	(3		)
Changes in regulatory assets and liabilities	139			(8		)
Deferred energy	(3		)	133
Amortization of deferred energy	(87		)	40
Other, net	3			(3		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(96		)	(204		)
Inventories	7			10
Accrued property, income and other taxes	98			36
Accounts payable and other liabilities	7			8
Net cash flows from operating activities	601			622

Cash flows from investing activities:
Capital expenditures	(249		)	(214		)
Proceeds from sale of assets	—			9
Other, net	—			10
Net cash flows from investing activities	(249		)	(195		)

Cash flows from financing activities:
Repayments of long-term debt and financial and capital lease obligations	(221		)	(260		)
Dividends paid	(365		)	(13		)
Net cash flows from financing activities	(586		)	(273		)

Net change in cash and cash equivalents	(234		)	154
Cash and cash equivalents at beginning of period	536			220
Cash and cash equivalents at end of period	$	302		$	374

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

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Organization and Operations

Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers, primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2016 and for the three- and nine-month periods ended September 30, 2016 and 2015. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2016 and 2015. Certain amounts in the prior period Consolidated Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income or retained earnings. The results of operations for the three- and nine-month periods ended September 30, 2016 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Nevada Power's Item 8 Notes to Consolidated Financial Statements included in BHE's Annual Report on Form 10-K for the year ended December 31, 2015 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2016.

(2) New Accounting Pronouncements

In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, which amends FASB Accounting Standards Codification ("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. Nevada Power is currently evaluating the impact of adopting this guidance 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. 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. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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, 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. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3) Property, Plant and Equipment, Net

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



		As of
	Depreciable Life	September 30,			December 31,
	Depreciable Life	2016			2015
Utility plant:
Generation	30 - 55 years	$	4,222		$	4,212
Distribution	20 - 65 years	3,208			3,118
Transmission	45 - 65 years	1,838			1,788
General and intangible plant	5 - 65 years	738			694
Utility plant		10,006			9,812
Accumulated depreciation and amortization		(3,144		)	(2,971		)
Utility plant, net		6,862			6,841
Other non-regulated, net of accumulated depreciation and amortization	5 - 65 years	2			2
Plant, net		6,864			6,843
Construction work-in-progress		107			153
Property, plant and equipment, net		$	6,971		$	6,996

(4) Regulatory Matters

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the Public Utilities Commission of Nevada ("PUCN").

Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

Chapter 704B Applications

costs. In December 2015, the customers 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 June 2016, MGM and Wynn made the required compliance filings and the PUCN issued orders allowing the customers to acquire electric energy and ancillary services from another energy supplier and become distribution only service customers of Nevada Power. The third customer did not make its compliance filing before the required deadline. In September 2016, MGM and Wynn paid impact fees totaling $97 million. In October 2016, MGM and Wynn became distribution only service customers and started procuring energy from another energy supplier.

Nevada Power has deferred recognition of $92 million of the impact fee which is included in noncurrent regulatory liabilities on the Consolidated Balance Sheet as of September 30, 2016. The majority of the deferred impact fee will be amortized over six years as ordered by the PUCN. The remaining $5 million will be remitted to the government for assessed fees or applied to an existing regulatory asset.

(5) Employee Benefit Plans

Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Nevada Power contributed $36 million to the Qualified Pension Plan for the nine-months ended September 30, 2016. Nevada Power did not make any contributions to the Qualified Pension Plan for the nine-months ended September 30, 2015. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts payable to NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):



	As of
	September 30,			December 31,
	2016			2015
Qualified Pension Plan -
Other long-term liabilities	$	(7	)	$	(38	)

Non-Qualified Pension Plans:
Other current liabilities	(1		)	(1		)
Other long-term liabilities	(9		)	(9		)

Other Postretirement Plans -
Other long-term liabilities	(5		)	(5		)

(6) Risk Management and Hedging Activities

Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's 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 and wholesale electricity that is purchased and sold. 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 actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.

Nevada Power 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. To mitigate a portion of its commodity price risk, Nevada Power 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. Nevada Power 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, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.

The following table, which excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):



	Other			Other
	Current			Long-term
	Liabilities			Liabilities			Total
As of September 30, 2016
Commodity liabilities⁽¹⁾	$	(9	)	$	(10	)	$	(19	)

As of December 31, 2015
Commodity liabilities⁽¹⁾	$	(8	)	$	(14	)	$	(22	)


(1)	Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates and as of September 30, 2016 and December 31, 2015, a regulatory asset of $19 million and $22 million, respectively, was recorded related to the derivative liability of $19 million and $22 million, respectively.

Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding derivative contracts with indexed and fixed price terms that comprise the mark-to-market values as of (in millions):



	Unit of	September 30,		December 31,
	Measure	2016		2015
Electricity sales	Megawatt hours	(2	)	(2	)
Natural gas purchases	Decatherms	143		126

Credit Risk

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

Collateral and Contingent Features

In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts may either specifically provide rights to demand cash or other security in the event of a credit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2016, credit ratings from the three recognized credit rating agencies were investment grade.

The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features was $3 million as of September 30, 2016 and December 31, 2015, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.


(7)	Fair Value Measurements

The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.

Level 3 - Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.

The following table presents Nevada Power's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):



	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3			Total
As of September 30, 2016
Assets - investment funds	$	6	$	—	$	—		$	6

Liabilities - commodity derivatives	$	—	$	—	$	(19	)	$	(19	)

As of December 31, 2015
Assets - investment funds	$	5	$	—	$	—		$	5

Liabilities - commodity derivatives	$	—	$	—	$	(22	)	$	(22	)

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 Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Interest rate swaps are valued using a financial model which utilizes observable inputs for similar instruments based primarily on market price curves. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of September 30, 2016 and December 31, 2015, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs. Refer to Note 6 for further discussion regarding Nevada Power's risk management and hedging activities.

Nevada Power's investment funds are accounted for as trading securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

The following table reconciles the beginning and ending balances of Nevada Power's commodity derivative liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015
Beginning balance	$	(22	)	$	(33	)	$	(22	)	$	(30	)
Changes in fair value recognized in regulatory assets	(1		)	2			(6		)	(3		)
Settlements	4			6			9			8
Ending balance	$	(19	)	$	(25	)	$	(19	)	$	(25	)

Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long‑term debt (in millions):



	As of September 30, 2016				As of December 31, 2015
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	2,580	$	3,176	$	2,788	$	3,240


(8)	Commitments and Contingencies

Environmental Laws and Regulations

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

Senate Bill 123

In June 2013, the Nevada State Legislature passed Senate Bill No. 123 ("SB 123"), which included the retirement of coal plants and replacing the capacity with renewable and other generating facilities. In May 2014, Nevada Power filed its Emissions Reduction Capacity Replacement Plan ("ERCR Plan") in compliance with SB 123. In July 2015, Nevada Power filed an amendment to its ERCR Plan with the PUCN which was approved in September 2015. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123.

Consistent with direction provided by the PUCN, Nevada Power acquired a 272-megawatt ("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 143 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, which is pending PUCN approval. These transactions are related to Nevada Power's final steps to comply with SB 123, resulting in the retirement of 812 MW of coal-fueled generation by 2019.

Legal Matters

Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Nevada Power 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 and are described below.

Switch, Ltd.

In July 2016, Switch, Ltd. filed a complaint in the United States District Court for the District of Nevada against various parties, including Nevada Power. In September 2016, Switch filed an amended complaint. The amended complaint alleges that actions by the former general counsel of the PUCN, as well as the PUCN and the PUCN Staff, violated state and federal laws and as a result of those actions Switch was prevented from being able to utilize an alternative energy provider. Switch also alleges that Nevada Power was aware of the wrong doing and either participated in the activities or failed to take action to stop the wrong doing, and as a result Nevada Power has been improperly enriched by these activities. In addition, Switch asserted antitrust claims against Nevada Power. Switch is seeking monetary damages and to invalidate the settlement agreement between Switch and Nevada Power relating to Switch utilizing an alternative energy provider. Nevada Power intends to vigorously defend against these claims. Nevada Power cannot assess or predict the outcome of the case at this time.

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

General

Nevada Power's revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. Nevada Power is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short- and long-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of Nevada Power. Additionally, the timely recovery of purchased power, fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of Nevada Power.

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power 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 Nevada Power's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2016 and 2015

Net income for the third quarter of 2016 was $188 million, an increase of $1 million, or 1%, compared to 2015 due to higher customer growth, the redemption of $210 million Series M, 5.950% General and Refunding Mortgage Notes in May 2016 and higher income on investments, offset by lower margins from changes in usage patterns with commercial and industrial customers, lower customer usage primarily due to the impacts of weather and higher depreciation and amortization primarily due to higher plant placed in-service.

Net income for the first nine months of 2016 was $257 million, a decrease of $14 million, or 5%, compared to 2015 due to benefits from changes in contingent liabilities in 2015, lower margins from changes in usage patterns with commercial and industrial customers, higher depreciation and amortization primarily due to higher plant placed in-service, increased taxes due to a new state commerce tax and increases in property and franchise taxes, higher planned maintenance and other generating costs, expenses related to uncollectible accounts, a gain on the sale of an equity investment in 2015 and lower transmission demand. The decrease in net income is partially offset by higher customer growth, the redemption of $210 million Series M, 5.950% General and Refunding Mortgage Notes in May 2016 and higher income on investments.

Operating revenue and cost of fuel, energy and capacity are key drivers of Nevada Power's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. Nevada Power believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity, is therefore meaningful. A comparison of Nevada Power's key operating results is as follows:



	Third Quarter										First Nine Months
	2016		2015		Change						2016		2015		Change
Gross margin (in millions):
Operating revenue	$	766	$	878	$	(112	)	(13	)	%	$	1,690	$	1,944	$	(254	)	(13	)	%
Cost of fuel, energy and capacity	251		362		(111		)	(31	)		618		879		(261		)	(30	)
Gross margin	$	515	$	516	$	(1	)	—			$	1,072	$	1,065	$	7		1

GWh sold:
Residential	3,814		3,772		42			1		%	7,802		7,586		216			3		%
Commercial	1,440		1,429		11			1			3,600		3,560		40			1
Industrial	2,149		2,153		(4		)	—			5,772		5,790		(18		)	—
Other	59		55		4			7			155		153		2			1
Total retail	7,462		7,409		53			1			17,329		17,089		240			1
Wholesale	76		104		(28		)	(27	)		177		292		(115		)	(39	)
Total GWh sold	7,538		7,513		25			—			17,506		17,381		125			1

Average number of retail customers (in thousands):
Residential	799		786		13			2		%	795		781		14			2		%
Commercial	105		104		1			1			105		104		1			1
Industrial	2		2		—			—			2		2		—			—
Total	906		892		14			2			902		887		15			2

Average retail revenue per MWh	$	101.22	$	116.78	$	(15.56	)	(13	)	%	$	95.69	$	111.46	$	(15.77	)	(14	)	%

Heating degree days	—		—		—			—		%	829		624		205			33		%
Cooling degree days	2,295		2,350		(55		)	(2	)	%	3,674		3,767		(93		)	(2	)	%

Sources of energy (GWh)⁽¹⁾:
Coal	599		623		(24		)	(4	)	%	1,140		1,229		(89		)	(7	)	%
Natural gas	4,657		5,198		(541		)	(10	)		11,569		11,304		265			2
Renewables	26		—		26			*			47		—		47			*
Total energy generated	5,282		5,821		(539		)	(9	)		12,756		12,533		223			2
Energy purchased	2,471		2,428		43			2			5,410		5,203		207			4
Total	7,753		8,249		(496		)	(6	)		18,166		17,736		430			2

* Not meaningful


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

Gross margin decreased $1 million, for the third quarter of 2016 compared to 2015 due to:

$5 million in usage patterns for commercial and industrial customers and

$3 million due to lower customer usage primarily due to the impacts of weather.

The decrease in gross margin was offset by:

$7 million due to higher customer growth.

Depreciation and amortization increased $2 million, or 3%, for the third quarter of 2016 compared to 2015 primarily due to higher plant placed in-service.

Other income (expense) is favorable $4 million, or 10%, for the third quarter of 2016 compared to 2015 due to the redemption of $210 million Series M, 5.950% General and Refunding Mortgage Notes in May 2016 and higher income on investments.

Income tax expense decreased $2 million, or 2%, for the third quarter of 2016 compared to 2015. The effective tax rate was 34% for 2016 and 35% for 2015.

Gross margin increased $7 million, or 1%, for the first nine months of 2016 compared to 2015 due to:

$12 million due to higher customer growth and

$6 million in higher energy efficiency program rate revenue, which is offset in operating and maintenance expense.

The increase in gross margin was offset by:

$8 million in usage patterns for commercial and industrial customers and

$3 million in lower transmission demand.

Operating and maintenance increased $25 million, or 9%, for the first nine months of 2016 compared to 2015 due to benefits from changes in contingent liabilities in 2015, higher energy efficiency program costs, which are fully recovered in operating revenue, higher planned maintenance and other generating costs and expenses related to uncollectible accounts. These increases are partially offset by lower compensation costs.

Depreciation and amortization increased $5 million, or 2%, for the first nine months of 2016 compared to 2015 primarily due to higher plant placed in-service.

Property and other taxes increased $5 million, or 20%, for the first nine months of 2016 compared to 2015 due to increases in property and franchise taxes and a new state commerce tax.

Other income (expense) is favorable $3 million, or 2%, for the first nine months of 2016 compared to 2015 due to the redemption of $210 million Series M, 5.950% General and Refunding Mortgage Notes in May 2016 and higher income on investments, partially offset by a gain on the sale of an equity investment in 2015 and higher interest on deferred charges.

Income tax expense decreased $11 million, or 7%, for the first nine months of 2016 compared to 2015. The effective tax rate was 35% for 2016 and 2015.

Liquidity and Capital Resources

As of September 30, 2016, Nevada Power's total net liquidity was $702 million consisting of $302 million in cash and cash equivalents and $400 million of revolving credit facility availability.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2016 and 2015 were $601 million and $622 million, respectively. The change was due to decreased collections from customers due to lower retail rates as a result of deferred energy adjustment mechanisms and lower customer advances, a 2016 contribution to the pension plan and increased operating costs. The decrease was offset by the receipt of impact fees from MGM Resorts International and Wynn Las Vegas, lower payments for fuel costs, settlement payments of contingent liabilities in 2015 and higher collections from customers for renewable energy programs.

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 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. 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, Nevada Power's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019 and investment tax credits (once the net operating loss is fully utilized) earned on qualifying projects through 2021.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2016 and 2015 were $(249) million and $(195) million, respectively. The change was due to increased capital maintenance expenditures and cash received for the sale of securities and an equity investment in 2015.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2016 and 2015 were $(586) million and $(273) million, respectively. The change was due to higher dividends paid to NV Energy, Inc. in 2016, partially offset by lower repayments of long-term debt.

Ability to Issue Debt

Nevada Power's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2016, Nevada Power has financing authority from the PUCN consisting of the ability to: (1) issue new long-term debt securities of up to $1.3 billion; (2) refinance up to $1.3 billion of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion. Nevada Power's revolving credit facility contains a financial maintenance covenant which Nevada Power was in compliance with as of September 30, 2016. In addition, certain financing agreements contain covenants which are currently suspended as Nevada Power's senior secured debt is rated investment grade. However, if Nevada Power's senior secured debt ratings fall below investment grade by either Moody's Investors Service or S&P Global Ratings, Nevada Power would be subject to limitations under these covenants.

Future Uses of Cash

Nevada Power 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 use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

Nevada Power 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.

Nevada Power's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):



	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2015		2016		2016

Generation development	$	38	$	1	$	90
Distribution	123		110		137
Transmission system investment	2		29		27
Other	51		109		145
Total	$	214	$	249	$	399

In April 2016, Nevada Power executed an agreement to purchase a 504-MW natural gas facility. The sale is subject to certain conditions including federal and state regulatory approval. The transaction is expected to close in the fourth quarter of 2016.

Contractual Obligations

As of September 30, 2016, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2015.

Regulatory Matters

Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Nevada Power's current regulatory matters.

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local 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 Nevada Power's current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Nevada Power believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of Nevada Power's forecasted environmental-related capital expenditures.

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

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2015. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2015.

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Las Vegas, Nevada

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of September 30, 2016, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2016 and 2015, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 2016 and 2015. These interim financial statements are the responsibility of Sierra Pacific's management.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Sierra Pacific Power Company and subsidiaries as of December 31, 2015, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2016, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2015 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 4, 2016

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	September 30,			December 31,
	2016			2015
ASSETS

Current assets:
Cash and cash equivalents	$	67		$	106
Accounts receivable, net	107			124
Inventories	39			39
Other current assets	17			13
Total current assets	230			282

Property, plant and equipment, net	2,801			2,766
Regulatory assets	434			432
Other assets	7			7

Total assets	$	3,472		$	3,487

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	116		$	127
Accrued interest	11			15
Accrued property, income and other taxes	11			13
Regulatory liabilities	94			78
Current portion of long-term debt and financial and capital lease obligations	2			453
Customer deposits	17			17
Other current liabilities	19			11
Total current liabilities	270			714

Long-term debt and financial and capital lease obligations	1,153			749
Regulatory liabilities	225			230
Deferred income taxes	606			570
Other long-term liabilities	123			148
Total liabilities	2,377			2,411

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	—			—
Other paid-in capital	1,111			1,111
Accumulated deficit	(15		)	(35		)
Accumulated other comprehensive loss, net	(1		)	—
Total shareholder's equity	1,095			1,076

Total liabilities and shareholder's equity	$	3,472		$	3,487

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2016			2015			2016			2015

Operating revenue:
Electric	$	207		$	228		$	539		$	625
Natural gas	15			18			81			94
Total operating revenue	222			246			620			719

Operating costs and expenses:
Cost of fuel, energy and capacity	73			96			208			294
Natural gas purchased for resale	5			7			42			57
Operating and maintenance	40			42			126			119
Depreciation and amortization	30			28			88			84
Property and other taxes	5			7			18			19
Total operating costs and expenses	153			180			482			573

Operating income	69			66			138			146

Other income (expense):
Interest expense	(12		)	(16		)	(42		)	(46		)
Allowance for borrowed funds	—			—			1			1
Allowance for equity funds	1			1			2			2
Other, net	2			1			3			3
Total other income (expense)	(9		)	(14		)	(36		)	(40		)

Income before income tax expense	60			52			102			106
Income tax expense	22			19			37			38
Net income	$	38		$	33		$	65		$	68

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)



									Accumulated
				Other					Other			Total
	Common Stock			Paid-in		Accumulated			Comprehensive			Shareholder's
	Shares	Amount		Capital		Deficit			Loss, Net			Equity

Balance, December 31, 2014	1,000	$	—	$	1,111	$	(111	)	$	(2	)	$	998
Net income	—	—		—		68			—			68
Dividends declared	—	—		—		(7		)	—			(7		)
Balance, September 30, 2015	1,000	$	—	$	1,111	$	(50	)	$	(2	)	$	1,059

Balance, December 31, 2015	1,000	$	—	$	1,111	$	(35	)	$	—		$	1,076
Net income	—	—		—		65			—			65
Dividends declared	—	—		—		(45		)	—			(45		)
Other equity transactions	—	—		—		—			(1		)	(1		)
Balance, September 30, 2016	1,000	$	—	$	1,111	$	(15	)	$	(1	)	$	1,095

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2016			2015

Cash flows from operating activities:
Net income	$	65		$	68
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	88			84
Allowance for equity funds	(2		)	(2		)
Deferred income taxes and amortization of investment tax credits	37			38
Changes in regulatory assets and liabilities	(14		)	(19		)
Deferred energy	55			68
Amortization of deferred energy	(35		)	20
Other, net	(1		)	2
Changes in other operating assets and liabilities:
Accounts receivable and other assets	12			11
Inventories	1			—
Accrued property, income and other taxes	—			(1		)
Accounts payable and other liabilities	(15		)	22
Net cash flows from operating activities	191			291

Cash flows from investing activities:
Capital expenditures	(137		)	(153		)
Other, net	—			2
Net cash flows from investing activities	(137		)	(151		)

Cash flows from financing activities:
Proceeds from issuance of long-term debt	1,089			—
Repayments of long-term debt and financial and capital lease obligations	(1,137		)	(1		)
Dividends paid	(45		)	(7		)
Net cash flows from financing activities	(93		)	(8		)

Net change in cash and cash equivalents	(39		)	132
Cash and cash equivalents at beginning of period	106			22
Cash and cash equivalents at end of period	$	67		$	154

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Organization and Operations

Sierra Pacific Power Company, together with its subsidiaries ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2016 and for the three- and nine-month periods ended September 30, 2016 and 2015. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2016 and 2015. Certain amounts in the prior period Consolidated Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income or retained earnings. The results of operations for the three- and nine-month periods ended September 30, 2016 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Sierra Pacific's Item 8 Notes to Consolidated Financial Statements included in BHE's Annual Report on Form 10-K for the year ended December 31, 2015 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Sierra Pacific's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2016.

(2) New Accounting Pronouncements

In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, which amends FASB Accounting Standards Codification ("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. Sierra Pacific is currently evaluating the impact of adopting this guidance 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. 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. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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, 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. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3) Property, Plant and Equipment, Net

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


		As of							As of
	Depreciable Life	September 30,			December 31,			Depreciable Life	September 30,			December 31,
		2015			2014				2016			2015
Utility plant in-service:
Utility plant:
Electric generation	40 - 125 years	$	1,104		$	1,036		30 - 60 years	$	1,137		$	1,134
Electric distribution	20 - 70 years	1,369			1,321			20 - 70 years	1,411			1,382
Electric transmission	50 - 70 years	728			719			50 - 70 years	757			739
Electric general and intangible plant	5 - 65 years	134			123			5 - 65 years	164			139
Natural gas distribution	40 - 70 years	371			366			40 - 70 years	378			374
Natural gas general and intangible plant	8 - 10 years	13			13			8 - 10 years	15			13
Common general	5 - 65 years	245			234			5 - 65 years	267			265
Utility plant in-service		3,964			3,812
Utility plant									4,129			4,046
Accumulated depreciation and amortization		(1,364		)	(1,300		)		(1,419		)	(1,368		)
Utility plant in-service, net		2,600			2,512
Utility plant, net									2,710			2,678
Other non-regulated, net of accumulated depreciation and amortization								5 - 65 years	6			—
Plant, net									2,716			2,678
Construction work-in-progress		89			128				85			88
Property, plant and equipment, net		$	2,689		$	2,640			$	2,801		$	2,766



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

001-05152	PACIFICORP	93-0246090
	(An Oregon Corporation)
	825 N.E. Multnomah Street
	Portland, Oregon 97232
	503-813-5645

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

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

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

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

	~~Securities registered pursuant to Section 12(b) of the Act: None~~N/A
	~~Securities registered pursuant to Section 12(g) of the Act:~~
	~~Common Stock, $3.75 par value~~(Former name or former address, if changed from last report)



~~PART I~~

Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	132
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21154
Item 4.	Controls and Procedures	21154


~~PART II~~

Item 1.	Legal Proceedings	22155
Item 1A.	Risk Factors	22155
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22155
Item 3.	Defaults Upon Senior Securities	22155
Item 4.	Mine Safety Disclosures	22155
Item 5.	Other Information	22155
Item 6.	Exhibits	22155
Signatures		23156
Exhibit Index		24157



~~Sierra Pacific Power~~Berkshire Hathaway Energy Company and Related Entities
BHE		Berkshire Hathaway Energy Company
Berkshire Hathaway Energy or the Company		Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp		PacifiCorp and its subsidiaries
MidAmerican Funding		MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy		MidAmerican Energy Company
NV Energy		NV Energy, Inc. and its subsidiaries
Nevada Power		Nevada Power Company and its subsidiaries
Sierra Pacific		Sierra Pacific Power Company and its subsidiaries
~~BHE~~Nevada Utilities		Nevada Power Company and Sierra Pacific Power Company
Registrants		Berkshire Hathaway Energy, PacifiCorp, MidAmerican Funding, MidAmerican Energy, Nevada Power and Sierra Pacific
Subsidiary Registrants		PacifiCorp, MidAmerican Funding, MidAmerican Energy, Nevada Power and Sierra Pacific
Northern Powergrid		Northern Powergrid Holdings Company
Northern Natural Gas		Northern Natural Gas Company
Kern River		Kern River Gas Transmission Company
AltaLink		BHE Canada Holdings Corporation
ALP		AltaLink, L.P.
BHE ~~Merger~~U.S. Transmission		~~On December 19, 2013, NV Energy, Inc. became an indirect wholly owned subsidiary of~~ BHE U.S. Transmission, LLC
~~NV Energy~~HomeServices		NVHomeServices of America, Inc. and its subsidiaries
BHE Pipeline Group or Pipeline Companies		Consists of Northern Natural Gas and Kern River
BHE Transmission		Consists of AltaLink and BHE U.S. Transmission
BHE Renewables		Consists of BHE Renewables, LLC and CalEnergy Philippines
Utilities		PacifiCorp, MidAmerican Energy ~~Inc.~~Company, Nevada Power Company and Sierra Pacific Power Company
Berkshire Hathaway		Berkshire Hathaway Inc.
~~Nevada Power~~Topaz		~~Nevada Power Company, an electric utility wholly owned by NV Energy~~Topaz Solar Farms LLC
~~Clark Mountain Generating Station~~Topaz Project		~~132-megawatt~~550-megawatt solar project in California
Jumbo Road		Jumbo Road Holdings, LLC
Jumbo Road Project		300-megawatt wind-powered generating facility in ~~Nevada~~Texas
~~Ft. Churchill Generating Station~~Solar Star Funding		~~226-megawatt generating facility in Nevada~~Solar Star Funding, LLC
~~ON Line~~Solar Star Projects		~~500-kilovolt transmission line connecting the Company and Nevada Power~~
~~Tracy Generating Station~~		~~753-megawatt generating facility~~A combined 586-megawatt solar project in ~~Nevada~~
~~Valmy Generating Station~~		~~522-megawatt generating facility in Nevada~~California

Certain Industry Terms

AESO		Alberta Electric System Operator
AFUDC		Allowance for Funds Used During Construction
~~California ISO~~AUC		Alberta Utilities Commission
CPUC		California ~~Independent System Operator Corporation~~Public Utilities Commission
~~Dth~~GTA		~~Decatherms~~
~~EEIR~~		~~Energy Efficiency Implementation Rate~~
~~EEPR~~		~~Energy Efficiency Program Rate~~
~~EIM~~		~~Energy Imbalance Market~~General Tariff Application
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GHG		Greenhouse Gases



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



Registrant	Large ~~accelerated filer~~ oAccelerated Filer	Accelerated filero	Non-accelerated ~~filer~~ x Filer	Smaller ~~reporting company~~ o Reporting Company
BERKSHIRE HATHAWAY ENERGY COMPANY			X
PACIFICORP			X
MIDAMERICAN FUNDING, LLC			X
MIDAMERICAN ENERGY COMPANY			X
NEVADA POWER COMPANY			X
SIERRA PACIFIC POWER COMPANY			X



GWh		Gigawatt Hours
IPUC		Idaho Public Utilities Commission
IUB		Iowa Utilities Board
kV		Kilovolt
MW		Megawatts
MWh		Megawatt Hours
OPUC		Oregon Public Utility Commission
PUCN		Public Utilities Commission of Nevada
REC		Renewable Energy Credit
RPS		Renewable Portfolio Standards
SEC		United States Securities and Exchange Commission
UPSC		Utah Public Service Commission
WPSC		Wyoming Public Service Commission
WUTC		Washington Utilities and Transportation Commission



Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		4
Consolidated Balance Sheets		5
Consolidated Statements of Operations		7
Consolidated Statements of Comprehensive Income		8
Consolidated Statements of Changes in Equity		9
Consolidated Statements of Cash Flows		10
Notes to Consolidated Financial Statements		11
PacifiCorp and its subsidiaries
Report of Independent Registered Public Accounting Firm		54
Consolidated Balance Sheets		55
Consolidated Statements of Operations		57
Consolidated Statements of Changes in Shareholders' Equity		58
Consolidated Statements of Cash Flows		59
Notes to Consolidated Financial Statements		60
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		77
Balance Sheets		78
Statements of Operations		80
Statements of Comprehensive Income		81
Statements of Changes in Equity		82
Statements of Cash Flows		83
Notes to Financial Statements		84
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		96
Consolidated Balance Sheets		97
Consolidated Statements of Operations		99
Consolidated Statements of Comprehensive Income		100
Consolidated Statements of Changes in Equity		101
Consolidated Statements of Cash Flows		102
Notes to Consolidated Financial Statements		103
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		118
Consolidated Balance Sheets		119
Consolidated Statements of Operations		120
Consolidated Statements of Changes in Shareholder's Equity		121
Consolidated Statements of Cash Flows		122
Notes to Consolidated Financial Statements		123
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		136
Consolidated Balance Sheets		137
Consolidated Statements of Operations		138
Consolidated Statements of Changes in Shareholder's Equity		139
Consolidated Statements of Cash Flows		140
Notes to Consolidated Financial Statements		141


									Accumulated						BHE Shareholders' Equity
				Other					Other			Total												Accumulated
	Common Stock			Paid-in		Accumulated			Comprehensive			Shareholder's						Additional						Other
	Shares	Amount		Capital		Deficit			Loss, Net			Equity			Common			Paid-in			Retained			Comprehensive			Noncontrolling			Total
															Shares	Stock		Capital			Earnings			Loss, Net			Interests			Equity
Balance, December 31, 2013	1,000	$	—	$	1,111	$	(93	)	$	(2	)	$	1,016
Net income	—	—		—		67			—			67
Balance, September 30, 2014	1,000	$	—	$	1,111	$	(26	)	$	(2	)	$	1,083

Balance, December 31, 2014	1,000	$	—	$	1,111	$	(111	)	$	(2	)	$	998		77	$	—	$	6,423		$	14,513		$	(494	)	$	131		$	20,573
Adoption of ASC 853															—	—		—			56			—			11			67
Net income	—	—		—		68			—			68			—	—		—			1,901			—			13			1,914
Dividends declared	—	—		—		(7		)	—			(7		)
Other comprehensive loss															—	—		—			—			(303		)	—			(303		)
Distributions															—	—		—			—			—			(15		)	(15		)
Common stock purchases															—	—		(3		)	(33		)	—			—			(36		)
Other equity transactions															—	—		(8		)	—			—			(4		)	(12		)
Balance, September 30, 2015	1,000	$	—	$	1,111	$	(50	)	$	(2	)	$	1,059		77	$	—	$	6,412		$	16,437		$	(797	)	$	136		$	22,188

The accompanying notes are an integral part of these consolidated financial statements.
Balance, December 31, 2015															77	$	—	$	6,403		$	16,906		$	(908	)	$	134		$	22,535
Net income															—	—		—			2,062			—			14			2,076
Other comprehensive loss															—	—		—			—			(110		)	—			(110		)
Distributions															—	—		—			—			—			(14		)	(14		)
Other equity transactions															—	—		1			—			—			8			9
Balance, September 30, 2016															77	$	—	$	6,404		$	18,968		$	(1,018	)	$	142		$	24,496



	As of September 30, 2015				As of December 31, 2014
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,173	$	1,266	$	1,174	$	1,301


(1)	Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.



	BERKSHIRE HATHAWAY ENERGY COMPANY

~~SIERRA PACIFIC~~Date: November 4, 2016	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Executive Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	PACIFICORP

Date: November 4, 2016	/s/ Nikki L. Kobliha
	Nikki L. Kobliha
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	MIDAMERICAN FUNDING, LLC
	MIDAMERICAN ENERGY COMPANY

Date: November 4, 2016	/s/ Thomas B. Specketer
	Thomas B. Specketer
	Vice President and Controller
	of MidAmerican Funding, LLC
	and Vice President, Chief Financial Officer and Director
	of MidAmerican Energy Company
	(principal financial and accounting officer)

	NEVADA POWER COMPANY
		~~(Registrant)~~



Date:	November ~~6, 2015~~4, 2016	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Senior Vice President, Chief Financial Officer and Director
	(principal financial and accounting officer)

	SIERRA PACIFIC POWER COMPANY

Date: November 4, 2016	/s/ E. Kevin Bethel
	E. Kevin Bethel
	Senior Vice President, Chief Financial Officer and Director
	(principal financial and accounting officer)


154.1	£120,000,000 Finance Contract, dated December 2, 2015, by and between Northern Powergrid (Northeast) Ltd and the European Investment Bank (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).


4.2	Guarantee and Indemnity Agreement, dated December 8, 2015, by and between Northern Powergrid Holdings Company and the European Investment Bank (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).


4.3	£130,000,000 Finance Contract, dated December 2, 2015, by and between Northern Powergrid (Yorkshire) plc and the European Investment Bank (incorporated by reference to Exhibit 4.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).


4.5	Deed of Amendment and Consent, dated March 1, 2016, by and between Northern Powergrid Holdings Company, Northern Powergrid (Yorkshire) plc and the European Investment Bank (incorporated by reference to Exhibit 4.5 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).


10.3	Amended and Restated Credit Agreement, dated as of July 30, 2015, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, The Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).


10.7	Third Amended and Restated Credit Agreement, dated as of December 17, 2015, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.7 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).


10.8	Fourth Amended and Restated Credit Agreement, dated as of December 17, 2015, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.8 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).


15.1	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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


15.2	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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


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


15.3	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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