Document

10-Q 1 bhe93017form10-q.htm 9.30.17 FORM 10-Q Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2017

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ______ to _______



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

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

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

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.



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

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.



Registrant	Large Accelerated Filer	Accelerated filer	Non-accelerated Filer	Smaller Reporting Company	Emerging Growth Company
BERKSHIRE HATHAWAY ENERGY COMPANY			X
PACIFICORP			X
MIDAMERICAN FUNDING, LLC			X
MIDAMERICAN ENERGY COMPANY			X
NEVADA POWER COMPANY			X
SIERRA PACIFIC POWER COMPANY			X

If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of October 31, 2017, 77,174,325 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of October 31, 2017, 357,060,915 shares of common stock, no par value, were outstanding.

All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of October 31, 2017.

All shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of October 31, 2017, 70,980,203 shares of common stock, no par value, were outstanding.

All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of October 31, 2017, 1,000 shares of common stock, $1.00 stated value, were outstanding.

All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. As of October 31, 2017, 1,000 shares of common stock, $3.75 par value, were outstanding.

This combined Form 10-Q is separately filed by Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.

TABLE OF CONTENTS

PART I



Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	151
Item 4.	Controls and Procedures	151

PART II



Item 1.	Legal Proceedings	152
Item 1A.	Risk Factors	152
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	152
Item 3.	Defaults Upon Senior Securities	152
Item 4.	Mine Safety Disclosures	152
Item 5.	Other Information	152
Item 6.	Exhibits	152
Signatures		153
Exhibit Index		154

Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 2 through 3, and Part II - Items 1 through 6, the following terms have the definitions indicated.



Berkshire Hathaway Energy Company and Related Entities
BHE		Berkshire Hathaway Energy Company
Berkshire Hathaway Energy or the Company		Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp		PacifiCorp and its subsidiaries
MidAmerican Funding		MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy		MidAmerican Energy Company
NV Energy		NV Energy, Inc. and its subsidiaries
Nevada Power		Nevada Power Company and its subsidiaries
Sierra Pacific		Sierra Pacific Power Company and its subsidiaries
Nevada Utilities		Nevada Power Company and Sierra Pacific Power Company
Registrants		Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, 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 U.S. Transmission		BHE U.S. Transmission, LLC
HomeServices		HomeServices of America, Inc. and its subsidiaries
BHE Pipeline Group or Pipeline Companies		Consists of Northern Natural Gas and Kern River
BHE Transmission		Consists of AltaLink and BHE U.S. Transmission
BHE Renewables		Consists of BHE Renewables, LLC and CalEnergy Philippines
Utilities		PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company
Berkshire Hathaway		Berkshire Hathaway Inc.

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



MWh		Megawatt Hours
OPUC		Oregon Public Utility Commission
PUCN		Public Utilities Commission of Nevada
REC		Renewable Energy Credit
RPS		Renewable Portfolio Standards
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
UPSC		Utah Public Service Commission
WPSC		Wyoming Public Service Commission
WUTC		Washington Utilities and Transportation Commission

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:


•	general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective Registrant's operations or related industries;


•	changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;


•	the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner;


•	changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;


•	performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions;

•

the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including storms, floods, fires, earthquakes, explosions, landslides, mining accidents, litigation, wars, terrorism, embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;


•	a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;


•	changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;


•	the financial condition and creditworthiness of the respective Registrant's significant customers and suppliers;


•	changes in business strategy or development plans;


•	availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates;


•	changes in the respective Registrant's credit ratings;


•	risks relating to nuclear generation, including unique operational, closure and decommissioning risks;

iii


•	hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;


•	the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;


•	the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;


•	fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;


•	increases in employee healthcare costs;


•	the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements;


•	changes in the residential real estate brokerage and mortgage industries and regulations that could affect brokerage and mortgage transactions;


•	unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;


•	the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;


•	the impact of new accounting guidance or changes in current accounting estimates and assumptions on the consolidated financial results of the respective Registrants;


•	the ability to successfully integrate future acquired operations into a Registrant's business; and


•	other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the SEC, including Part II, Item 1A and other discussions contained in this Form 10-Q. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.


Item 1.	Financial Statements



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		76
Balance Sheets		77
Statements of Operations		79
Statements of Changes in Equity		80
Statements of Cash Flows		81
Notes to Financial Statements		82
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		91
Consolidated Balance Sheets		92
Consolidated Statements of Operations		94
Consolidated Statements of Changes in Equity		95
Consolidated Statements of Cash Flows		96
Notes to Consolidated Financial Statements		97
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		111
Consolidated Balance Sheets		112
Consolidated Statements of Operations		113
Consolidated Statements of Changes in Shareholder's Equity		114
Consolidated Statements of Cash Flows		115
Notes to Consolidated Financial Statements		116
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		132
Consolidated Balance Sheets		133
Consolidated Statements of Operations		134
Consolidated Statements of Changes in Shareholder's Equity		135
Consolidated Statements of Cash Flows		136
Notes to Consolidated Financial Statements		137


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



Berkshire Hathaway Energy Company and its subsidiaries		30
PacifiCorp and its subsidiaries		68
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		100
Nevada Power Company and its subsidiaries		125
Sierra Pacific Power Company and its subsidiaries		145

Berkshire Hathaway Energy 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 Shareholders of

Berkshire Hathaway Energy Company

Des Moines, Iowa

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of September 30, 2017, and the related consolidated statements of operations and comprehensive income for the three-month and nine-month periods ended September 30, 2017 and 2016, and of changes in equity and cash flows for the nine-month periods ended September 30, 2017 and 2016. These interim financial statements are the responsibility of the Company'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 Berkshire Hathaway Energy Company and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 3, 2017

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	September 30,		December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	1,142	$	721
Trade receivables, net	1,994		1,751
Inventories	887		925
Mortgage loans held for sale	534		359
Other current assets	1,095		917
Total current assets	5,652		4,673

Property, plant and equipment, net	64,979		62,509
Goodwill	9,700		9,010
Regulatory assets	4,582		4,307
Investments and restricted cash and investments	4,987		3,945
Other assets	1,154		996

Total assets	$	91,054	$	85,440

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)



	As of
	September 30,			December 31,
	2017			2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,303		$	1,317
Accrued interest	523			454
Accrued property, income and other taxes	780			389
Accrued employee expenses	392			261
Short-term debt	2,493			1,869
Current portion of long-term debt	3,070			1,006
Other current liabilities	1,034			1,017
Total current liabilities	9,595			6,313

Regulatory liabilities	3,086			2,933
BHE senior debt	6,771			7,418
BHE junior subordinated debentures	100			944
Subsidiary debt	26,183			26,748
Deferred income taxes	14,832			13,879
Other long-term liabilities	2,883			2,742
Total liabilities	63,450			60,977

Commitments and contingencies (Note 11)

Equity:
BHE shareholders' equity:
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding	—			—
Additional paid-in capital	6,362			6,390
Retained earnings	21,534			19,448
Accumulated other comprehensive loss, net	(423		)	(1,511		)
Total BHE shareholders' equity	27,473			24,327
Noncontrolling interests	131			136
Total equity	27,604			24,463

Total liabilities and equity	$	91,054		$	85,440

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2017			2016
Operating revenue:
Energy	$	4,322		$	4,272		$	11,501		$	11,102
Real estate	961			820			2,502			2,152
Total operating revenue	5,283			5,092			14,003			13,254

Operating costs and expenses:
Energy:
Cost of sales	1,212			1,187			3,380			3,252
Operating expense	930			948			2,763			2,739
Depreciation and amortization	635			639			1,905			1,898
Real estate	882			733			2,311			1,973
Total operating costs and expenses	3,659			3,507			10,359			9,862

Operating income	1,624			1,585			3,644			3,392

Other income (expense):
Interest expense	(464		)	(460		)	(1,379		)	(1,401		)
Capitalized interest	14			14			34			128
Allowance for equity funds	24			17			59			147
Interest and dividend income	32			39			85			93
Other, net	2			15			24			26
Total other income (expense)	(392		)	(375		)	(1,177		)	(1,007		)

Income before income tax expense and equity income	1,232			1,210			2,467			2,385
Income tax expense	184			199			319			394
Equity income	30			36			80			96
Net income	1,078			1,047			2,228			2,087
Net income attributable to noncontrolling interests	10			11			30			25
Net income attributable to BHE shareholders	$	1,068		$	1,036		$	2,198		$	2,062

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)



	Three-Month Periods					Nine-Month Periods
	Ended September 30,					Ended September 30,
	2017		2016			2017			2016

Net income	$	1,078	$	1,047		$	2,228		$	2,087

Other comprehensive income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $1, $7, $(3), and $26	15		18			16			80
Foreign currency translation adjustment	227		(134		)	535			(339		)
Unrealized gains on available-for-sale securities, net of tax of $284, $53, $355 and $89	423		80			542			151
Unrealized gains (losses) on cash flow hedges, net of tax of $1, $(3), $(3) and $(1)	1		(3		)	(5		)	(2		)
Total other comprehensive income, net of tax	666		(39		)	1,088			(110		)

Comprehensive income	1,744		1,008			3,316			1,977
Comprehensive income attributable to noncontrolling interests	10		11			30			25
Comprehensive income attributable to BHE shareholders	$	1,734	$	997		$	3,286		$	1,952

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)



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

Balance, December 31, 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

Balance, December 31, 2016	77	$	—	$	6,390		$	19,448		$	(1,511	)	$	136		$	24,463
Net income	—	—		—			2,198			—			14			2,212
Other comprehensive income	—	—		—			—			1,088			—			1,088
Distributions	—	—		—			—			—			(16		)	(16		)
Common stock purchases	—	—		(1		)	(18		)	—			—			(19		)
Common stock exchange	—	—		(6		)	(94		)	—			—			(100		)
Other equity transactions	—	—		(21		)	—			—			(3		)	(24		)
Balance, September 30, 2017	77	$	—	$	6,362		$	21,534		$	(423	)	$	131		$	27,604

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2017			2016
Cash flows from operating activities:
Net income	$	2,228		$	2,087
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	1,943			1,922
Allowance for equity funds	(59		)	(147		)
Equity income, net of distributions	(14		)	(62		)
Changes in regulatory assets and liabilities	17			41
Deferred income taxes and amortization of investment tax credits	573			546
Other, net	13			(60		)
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(98		)	(348		)
Derivative collateral, net	(16		)	22
Pension and other postretirement benefit plans	(29		)	(73		)
Accrued property, income and other taxes	390			713
Accounts payable and other liabilities	170			183
Net cash flows from operating activities	5,118			4,824

Cash flows from investing activities:
Capital expenditures	(3,179		)	(3,521		)
Acquisitions, net of cash acquired	(1,102		)	(66		)
Increase in restricted cash and investments	(45		)	(48		)
Purchases of available-for-sale securities	(167		)	(98		)
Proceeds from sales of available-for-sale securities	186			125
Equity method investments	(54		)	(462		)
Other, net	(12		)	(47		)
Net cash flows from investing activities	(4,373		)	(4,117		)

Cash flows from financing activities:
Repayments of BHE senior debt and junior subordinated debentures	(1,344		)	(1,500		)
Common stock purchases	(19		)	—
Proceeds from subsidiary debt	1,562			1,484
Repayments of subsidiary debt	(834		)	(1,613		)
Net proceeds from short-term debt	365			887
Other, net	(60		)	(50		)
Net cash flows from financing activities	(330		)	(792		)

Effect of exchange rate changes	6			(5		)

Net change in cash and cash equivalents	421			(90		)
Cash and cash equivalents at beginning of period	721			1,108
Cash and cash equivalents at end of period	$	1,142		$	1,018

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	General

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

The Company is organized as eight business segments: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. ("NV Energy") (which primarily consists of Nevada Power Company ("Nevada Power") and Sierra Pacific Power Company ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("AltaLink") (which primarily consists of AltaLink, L.P. ("ALP")) and BHE U.S. Transmission, LLC), BHE Renewables (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). The Company, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, two interstate natural gas pipeline companies in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily 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, 2017 and for the three- and nine-month periods ended September 30, 2017 and 2016. The results of operations for the three- and nine-month periods ended September 30, 2017 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, 2016 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 ended September 30, 2017.

(2) New Accounting Pronouncements

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

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

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

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

In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. The material impacts currently identified include recording the unrealized gains and losses on available-for-sale securities in the Consolidated Statements of Operations as opposed to other comprehensive income ("OCI"). For the nine-month periods ended September 30, 2017 and 2016, these amounts, net of tax, were 542 million and 151 million, respectively.

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


(3)	Business Acquisitions

The Company completed various acquisitions totaling $1.1 billion, net of cash acquired, for the nine-month period ended September 30, 2017. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which primarily related to residential real estate brokerage businesses, development and construction costs for the 110-megawatt Alamo 6 solar project and the 50-megawatt Pearl solar project, and the remaining 25% interest in the Silverhawk natural gas-fueled generation facility at Nevada Power. As a result of the various acquisitions, the Company acquired assets of $1.1 billion, assumed liabilities of $476 million and recognized goodwill of $522 million.


(4)	Property, Plant and Equipment, Net

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



		As of
	Depreciable	September 30,			December 31,
	Life	2017			2016
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	73,138		$	71,536
Interstate natural gas pipeline assets	3-80 years	6,991			6,942
		80,129			78,478
Accumulated depreciation and amortization		(24,525		)	(23,603		)
Regulated assets, net		55,604			54,875

Nonregulated assets:
Independent power plants	5-30 years	5,911			5,594
Other assets	3-30 years	1,265			1,002
		7,176			6,596
Accumulated depreciation and amortization		(1,304		)	(1,060		)
Nonregulated assets, net		5,872			5,536

Net operating assets		61,476			60,411
Construction work-in-progress		3,503			2,098
Property, plant and equipment, net		$	64,979		$	62,509

Construction work-in-progress includes $3.1 billion as of September 30, 2017 and $1.8 billion as of December 31, 2016, related to the construction of regulated assets.

During the fourth quarter of 2016, MidAmerican Energy revised its electric and gas depreciation rates based on the results of a new depreciation study, the most significant impact of which was longer estimated useful lives for certain wind-powered generating facilities. The effect of this change was to reduce depreciation and amortization expense by $34 million annually, or $9 million and $26 million for the three- and nine-month periods ended September 30, 2017, based on depreciable plant balances at the time of the change.


(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,
	2017		2016
Investments:
BYD Company Limited common stock	$	2,087	$	1,185
Rabbi trusts	431		403
Other	132		106
Total investments	2,650		1,694

Equity method investments:
BHE Renewables tax equity investments	804		741
Electric Transmission Texas, LLC	693		672
Bridger Coal Company	140		165
Other	158		142
Total equity method investments	1,795		1,720

Restricted cash and investments:
Quad Cities Station nuclear decommissioning trust funds	498		460
Other	317		282
Total restricted cash and investments	815		742

Total investments and restricted cash and investments	$	5,260	$	4,156

Reflected as:
Other current assets	$	273	$	211
Noncurrent assets	4,987		3,945
Total investments and restricted cash and investments	$	5,260	$	4,156

Investments

BHE's investment in BYD Company Limited common stock is accounted for as an available-for-sale security with changes in fair value recognized in 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 $1,855 million and $953 million as of September 30, 2017 and December 31, 2016, respectively.


(6)	Recent Financing Transactions

Long-Term Debt

In the first nine months of 2017, BHE repaid at par value a total of $944 million, plus accrued interest, of its junior subordinated debentures due December 2044.

In September 2017, HomeServices entered into a $250 million unsecured amortizing term loan due September 2022. The amortizing term loan has an underlying variable interest rate based on the London Interbank Offered Rate ("LIBOR") plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter. The net proceeds were used to fund the repayment or reimbursement of amounts provided by BHE for the costs related to acquisitions.

In July 2017, Northern Powergrid Metering Limited entered into a £200 million secured amortizing corporate facility with a stated maturity of June 2026. The amortizing facility has a variable interest rate based on the LIBOR plus a spread that varies based on an agreed-upon schedule. In July 2017, Northern Powergrid Metering Limited received proceeds of £120 million under the facility to repay amounts provided by Yorkshire Electricity Group plc which provides internal funds for the continuing smart meter deployment program of Northern Powergrid Metering Limited. Northern Powergrid Metering Limited has entered into interest rate swaps that fix the underlying interest rate on 85% of the outstanding debt.

In July 2017, Cordova Funding Corporation redeemed the remaining $89 million of its 8.48% to 9.07% Series A Senior Secured Bonds due December 2019, CE Generation, LLC redeemed the remaining $51 million of its 7.416% Senior Secured Bonds due December 2018, and Salton Sea Funding Corporation redeemed the remaining $20 million of its 7.475% Senior Secured Series F Bonds due November 2018, each at redemption prices determined in accordance with the terms of the respective indentures.

In June 2017, BHE issued $100 million of its 5.0% junior subordinated debentures due June 2057 in exchange for 181,819 shares of BHE no par value common stock held by a minority shareholder. The junior subordinated debentures are redeemable at BHE's option at any time from and after June 15, 2037, at par plus accrued and unpaid interest.

In May 2017, Alamo 6, LLC issued $232 million of its 4.17% Senior Secured Notes due March 2042. The principal of the notes amortizes beginning March 2018 with a final maturity in March 2042. The net proceeds were used to fund the repayment or reimbursement of amounts provided by BHE for the costs related to the development, construction and financing of a 110-megawatt solar project in Texas.

In April 2017, Kern River redeemed the remaining $175 million of its 4.893% Senior Notes due April 2018 at a redemption price determined in accordance with the terms of the indenture.

In February 2017, MidAmerican Energy issued $375 million of its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95% First Mortgage Bonds due August 2047. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds.

In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.

Credit Facilities

In September 2017, HomeServices terminated its $350 million unsecured credit facility expiring July 2018 and entered into a $600 million unsecured credit facility expiring September 2022. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the LIBOR or a base rate, at HomeServices' option, plus a spread that varies based on HomeServices' total net leverage ratio as of the last day of each quarter.

In June 2017, BHE extended, with lender consent, the maturity date to June 2020 for its $2.0 billion unsecured credit facility and PacifiCorp extended, with lender consent, the maturity date to June 2020 for its $400 million unsecured credit facility, each by exercising the first of two available one-year extensions.

In June 2017, PacifiCorp terminated its $600 million unsecured credit facility expiring March 2018 and entered into a $600 million unsecured credit facility expiring June 2020 with two one-year extension options subject to lender consent. The credit facility, which supports PacifiCorp's commercial paper program and 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 Eurodollar rate 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 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.

In June 2017, MidAmerican Energy terminated its $600 million unsecured credit facility expiring March 2018 and entered into a $900 million unsecured credit facility expiring June 2020 with two one-year extension options subject to lender consent. 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 the Eurodollar rate 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. The credit facility requires MidAmerican Energy'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.

In June 2017, Nevada Power amended its $400 million secured credit facility, extending the maturity date to June 2020 with two one-year extension options subject to lender consent. The amended credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Nevada Power's option, plus a spread that varies based on Nevada Power's credit ratings for its senior secured long-term debt securities. The amended credit facility requires Nevada Power's ratio of consolidated debt, including current maturities, to total capitalization not to exceed 0.65 to 1.0 as of the last day of each quarter.

In June 2017, Sierra Pacific amended its $250 million secured credit facility, extending the maturity date to June 2020 with two one-year extension options subject to lender consent. The amended credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at Sierra Pacific's option, plus a spread that varies based on Sierra Pacific's credit ratings for its senior secured long-term debt securities. The amended credit facility requires Sierra Pacific'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.

In May 2017, BHE entered into a $1.0 billion unsecured credit facility expiring May 2018. 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 Eurodollar rate or a base rate, at BHE's option, plus a spread that varies based on BHE's credit ratings for its senior unsecured long-term debt securities. The credit facility requires 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.


(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,
	2017		2016		2017		2016

Federal statutory income tax rate	35	%	35	%	35	%	35	%
Income tax credits	(19	)	(16	)	(18	)	(15	)
State income tax, net of federal income tax benefit	—		—		(1	)	—
Income tax effect of foreign income	(3	)	(3	)	(4	)	(4	)
Equity income	1		1		1		1
Other, net	1		(1	)	—		—
Effective income tax rate	15	%	16	%	13	%	17	%

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.

Berkshire Hathaway includes the Company in its United States federal income tax return. The Company's provision for income taxes has been computed on a stand-alone basis, and substantially all of its currently payable or receivable federal income taxes are remitted to or received from Berkshire Hathaway. For the nine-month periods ended September 30, 2017 and 2016, the Company received net cash payments for federal income taxes from Berkshire Hathaway totaling $659 million and $860 million, respectively.


(8)	Employee Benefit Plans

Domestic Operations

Net periodic benefit cost (credit) 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,
	2017			2016			2017			2016
Pension:
Service cost	$	6		$	7		$	18		$	22
Interest cost	29			31			87			94
Expected return on plan assets	(40		)	(39		)	(120		)	(120		)
Net amortization	7			12			22			36
Net periodic benefit cost	$	2		$	11		$	7		$	32

Other postretirement:
Service cost	$	3		$	2		$	7		$	7
Interest cost	7			7			21			23
Expected return on plan assets	(9		)	(10		)	(30		)	(31		)
Net amortization	(3		)	(2		)	(10		)	(9		)
Net periodic benefit credit	$	(2	)	$	(3	)	$	(12	)	$	(10	)

Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $15 million and $5 million, respectively, during 2017. As of September 30, 2017, $9 million and $5 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,
	2017			2016			2017			2016

Service cost	$	6		$	5		$	19		$	16
Interest cost	15			17			44			55
Expected return on plan assets	(25		)	(27		)	(74		)	(85		)
Settlement	18			—			18			—
Net amortization	17			11			50			34
Net periodic benefit cost	$	31		$	6		$	57		$	20

Employer contributions to the United Kingdom pension plan are expected to be £45 million during 2017. As of September 30, 2017, £34 million, or $43 million, of contributions had been made to the United Kingdom pension plan.


(9)	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, Nevada Power and Sierra Pacific (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, 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 10 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, 2017
Not designated as hedging contracts:
Commodity assets⁽¹⁾	$	16		$	93	$	7		$	3		$	119
Commodity liabilities⁽¹⁾	(1		)	—		(60		)	(135		)	(196		)
Interest rate assets	22			—		—			—			22
Interest rate liabilities	—			—		(3		)	(7		)	(10		)
Total	37			93		(56		)	(139		)	(65		)

Designated as hedging contracts:
Commodity assets	—			—		2			6			8
Commodity liabilities	—			—		(11		)	(17		)	(28		)
Interest rate assets	—			6		—			—			6
Interest rate liabilities	—			—		(1		)	—			(1		)
Total	—			6		(10		)	(11		)	(15		)

Total derivatives	37			99		(66		)	(150		)	(80		)
Cash collateral receivable	—			—		21			64			85
Total derivatives - net basis	$	37		$	99	$	(45	)	$	(86	)	$	5



	Other					Other			Other
	Current			Other		Current			Long-term
	Assets			Assets		Liabilities			Liabilities			Total
As of December 31, 2016
Not designated as hedging contracts:
Commodity assets⁽¹⁾	$	42		$	86	$	5		$	2		$	135
Commodity liabilities⁽¹⁾	(10		)	—		(46		)	(150		)	(206		)
Interest rate assets	15			—		—			—			15
Interest rate liabilities	—			—		(4		)	(6		)	(10		)
Total	47			86		(45		)	(154		)	(66		)

Designated as hedging contracts:
Commodity assets	1			—		2			3			6
Commodity liabilities	—			—		(14		)	(8		)	(22		)
Interest rate assets	—			8		—			—			8
Interest rate liabilities	—			—		(3		)	—			(3		)
Total	1			8		(15		)	(5		)	(11		)

Total derivatives	48			94		(60		)	(159		)	(77		)
Cash collateral receivable	—			—		13			61			74
Total derivatives - net basis	$	48		$	94	$	(47	)	$	(98	)	$	(3	)

(1)

The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of September 30, 2017 and December 31, 2016, a net regulatory asset of $162 million and $148 million, respectively, was recorded related to the net derivative liability of $77 million and $71 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,
	2017			2016			2017			2016

Beginning balance	$	162		$	185		$	148		$	250
Changes in fair value recognized in net regulatory assets	10			18			43			5
Net (losses) gains reclassified to operating revenue	(5		)	(3		)	9			(6		)
Net losses reclassified to cost of sales	(5		)	(5		)	(38		)	(54		)
Ending balance	$	162		$	195		$	162		$	195

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 OCI, as well as amounts reclassified to earnings (in millions):



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2017			2016

Beginning balance	$	21		$	26		$	16		$	46
Changes in fair value recognized in OCI	5			15			28			35
Net gains reclassified to operating revenue	—			1			—			1
Net losses reclassified to cost of sales	(7		)	(7		)	(25		)	(47		)
Ending balance	$	19		$	35		$	19		$	35

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, 2017 and 2016, hedge ineffectiveness was insignificant. As of September 30, 2017, the Company had cash flow hedges with expiration dates extending through June 2026 and $10 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	2017		2016

Electricity purchases	Megawatt hours	9		5
Natural gas purchases	Decatherms	339		271
Fuel purchases	Gallons	2		11
Interest rate swaps	US$	694		714
Interest rate swaps	£	102		—
Mortgage sale commitments, net	US$	(442	)	(309	)

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, 2017, 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 $190 million and $190 million as of September 30, 2017 and December 31, 2016, respectively, for which the Company had posted collateral of $73 million and $69 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, 2017 and December 31, 2016, the Company would have been required to post $105 million and $110 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.


(10)	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 financial 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, 2017
Assets:
Commodity derivatives	$	1		$	24		$	102		$	(19	)	$	108
Interest rate derivatives	—			14			14			—			28
Mortgage loans held for sale	—			534			—			—			534
Money market mutual funds⁽²⁾	855			—			—			—			855
Debt securities:
United States government obligations	168			—			—			—			168
International government obligations	—			5			—			—			5
Corporate obligations	—			37			—			—			37
Municipal obligations	—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			1			—			—			1
Equity securities:
United States companies	270			—			—			—			270
International companies	2,094			—			—			—			2,094
Investment funds	182			—			—			—			182
	$	3,570		$	617		$	116		$	(19	)	$	4,284
Liabilities:
Commodity derivatives	$	(1	)	$	(207	)	$	(16	)	$	104		$	(120	)
Interest rate derivatives	—			(10		)	(1		)	—			(11		)
	$	(1	)	$	(217	)	$	(17	)	$	104		$	(131	)



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


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $85 million and $74 million as of September 30, 2017 and December 31, 2016, respectively.


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

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 9 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 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
2017:
Beginning balance	$	81		$	8		$	—	$	60		$	6		$	—
Changes included in earnings	7			34			—		19			100			—
Changes in fair value recognized in OCI	(1		)	—			—		(3		)	—			—
Changes in fair value recognized in net regulatory assets	(3		)	—			—		(5		)	—			—
Purchases	—			8			—		1			6			—
Settlements	2			(37		)	—		14			(99		)	—
Ending balance	$	86		$	13		$	—	$	86		$	13		$	—



	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

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

Long-term debt	$	36,124	$	41,197	$	36,116	$	40,718


(11)	Commitments and Contingencies

Fuel, Capacity and Transmission Contract Commitments

During the nine-month period ended September 30, 2017, MidAmerican Energy amended certain of its natural gas supply and transportation contracts increasing minimum payments by $247 million through 2021 and $70 million for 2022 through 2037.

Construction Commitments

During the nine-month period ended September 30, 2017, MidAmerican Energy entered into contracts totaling $675 million for the construction of wind-powered generating facilities in 2017 through 2019, with remaining payments totaling $84 million for the fourth quarter of 2017, $340 million in 2018 and $8 million in 2019.

Operating Leases and Easements

During the nine-month period ended September 30, 2017, MidAmerican Energy entered into non-cancelable easements with minimum payments totaling $114 million through 2057 for land in Iowa on which some of its wind-powered generating facilities will be located.

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.

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 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").

Congress failed to pass legislation needed to implement the original KHSA. On April 6, 2016, PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and Commerce and other stakeholders executed an amendment to the KHSA. 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. The KRRC's license surrender 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, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. 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 towards facilities removal costs are being 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 for 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.


(12)	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-		Gains (Losses)			Attributable
	Retirement			Translation			For-Sale		on Cash			To BHE
	Benefits			Adjustment			Securities		Flow Hedges			Shareholders, Net

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	)

Balance, December 31, 2016	$	(447	)	$	(1,675	)	$	585	$	26		$	(1,511	)
Other comprehensive income (loss)	16			535			542		(5		)	1,088
Balance, September 30, 2017	$	(431	)	$	(1,140	)	$	1,127	$	21		$	(423	)

Reclassifications from AOCI to net income for the periods ended September 30, 2017 and 2016 were insignificant. For information regarding cash flow hedge reclassifications from AOCI to net income in their entirety, refer to Note 9. 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.


(13)	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. 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,
	2017		2016		2017			2016
Operating revenue:
PacifiCorp	$	1,430	$	1,434	$	3,956		$	3,919
MidAmerican Funding	815		797		2,170			2,008
NV Energy	1,047		987		2,384			2,309
Northern Powergrid	221		220		685			748
BHE Pipeline Group	193		201		700			704
BHE Transmission	182		169		506			309
BHE Renewables	283		273		647			582
HomeServices	961		820		2,502			2,152
BHE and Other⁽¹⁾	151		191		453			523
Total operating revenue	$	5,283	$	5,092	$	14,003		$	13,254

Depreciation and amortization:
PacifiCorp	$	200	$	193	$	598		$	589
MidAmerican Funding	112		118		370			338
NV Energy	105		106		315			315
Northern Powergrid	55		49		156			149
BHE Pipeline Group	42		53		115			160
BHE Transmission	58		61		165			177
BHE Renewables	63		57		187			169
HomeServices	16		9		38			24
BHE and Other⁽¹⁾	—		2		(1		)	1
Total depreciation and amortization	$	651	$	648	$	1,943		$	1,922



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2017			2016
Operating income:
PacifiCorp	$	467		$	445		$	1,150		$	1,108
MidAmerican Funding	288			284			531			524
NV Energy	393			394			682			656
Northern Powergrid	81			90			308			373
BHE Pipeline Group	65			68			328			320
BHE Transmission	86			81			236			35
BHE Renewables	157			157			256			233
HomeServices	79			87			191			179
BHE and Other⁽¹⁾	8			(21		)	(38		)	(36		)
Total operating income	1,624			1,585			3,644			3,392
Interest expense	(464		)	(460		)	(1,379		)	(1,401		)
Capitalized interest	14			14			34			128
Allowance for equity funds	24			17			59			147
Interest and dividend income	32			39			85			93
Other, net	2			15			24			26
Total income before income tax expense and equity income	$	1,232		$	1,210		$	2,467		$	2,385



Interest expense:
PacifiCorp	$	95	$	95	$	285	$	286
MidAmerican Funding	59		55		177		164
NV Energy	57		60		173		190
Northern Powergrid	34		33		98		105
BHE Pipeline Group	11		13		33		39
BHE Transmission	45		40		125		114
BHE Renewables	51		51		153		148
HomeServices	1		1		3		2
BHE and Other⁽¹⁾	111		112		332		353
Total interest expense	$	464	$	460	$	1,379	$	1,401



Operating revenue by country:
United States	$	4,869	$	4,697	$	12,793	$	12,185
United Kingdom	221		220		685		748
Canada	182		170		506		313
Philippines and other	11		5		19		8
Total operating revenue by country	$	5,283	$	5,092	$	14,003	$	13,254



Income before income tax expense and equity income by country:
United States	$	1,113	$	1,089	$	2,065	$	1,945
United Kingdom	49		74		213		284
Canada	47		43		127		114
Philippines and other	23		4		62		42
Total income before income tax expense and equity income by country	$	1,232	$	1,210	$	2,467	$	2,385



	As of
	September 30,		December 31,
	2017		2016
Assets:
PacifiCorp	$	23,578	$	23,563
MidAmerican Funding	19,019		17,571
NV Energy	14,344		14,320
Northern Powergrid	7,280		6,433
BHE Pipeline Group	4,958		5,144
BHE Transmission	9,182		8,378
BHE Renewables	7,492		7,010
HomeServices	2,834		1,776
BHE and Other⁽¹⁾	2,367		1,245
Total assets	$	91,054	$	85,440


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

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2017 (in millions):



									BHE Pipeline Group
			MidAmerican Funding		NV Energy		Northern Powergrid					BHE Transmission		BHE Renewables		HomeServices
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid					BHE Transmission		BHE Renewables		HomeServices		Total

December 31, 2016	$	1,129	$	2,102	$	2,369	$	930	$	75		$	1,470	$	95	$	840	$	9,010
Acquisitions	—		—		—		—		—			—		—		522		522
Foreign currency translation	—		—		—		56		—			114		—		—		170
Other	—		—		—		—		(2		)	—		—		—		(2		)
September 30, 2017	$	1,129	$	2,102	$	2,369	$	986	$	73		$	1,584	$	95	$	1,362	$	9,700


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 is organized 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 locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, two interstate natural gas pipeline companies in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily 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.

Results of Operations for the Third Quarter and First Nine Months of 2017 and 2016

Overview

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



	Third Quarter											First Nine Months
	2017			2016			Change					2017			2016			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	263		$	254		$	9		4	%	$	618		$	596		$	22		4	%
MidAmerican Funding	383			318			65			20		616			518			98			19
NV Energy	223			222			1			—		347			319			28			9
Northern Powergrid	39			60			(21		)	(35	)	174			228			(54		)	(24	)
BHE Pipeline Group	35			36			(1		)	(3	)	183			175			8			5
BHE Transmission	58			57			1			2		171			173			(2		)	(1	)
BHE Renewables	89			98			(9		)	(9	)	194			142			52			37
HomeServices	45			49			(4		)	(8	)	107			105			2			2
BHE and Other	(67		)	(58		)	(9		)	(16	)	(212		)	(194		)	(18		)	(9	)
Total net income attributable to BHE shareholders	$	1,068		$	1,036		$	32		3		$	2,198		$	2,062		$	136		7

Net income attributable to BHE shareholders increased $32 million for the third quarter of 2017 compared to 2016 due to the following:

•

PacifiCorp's net income increased $9 million primarily due to higher gross margins of $30 million, excluding the impact of demand side management program revenue (offset in operating expense), partially offset by higher depreciation and amortization of $7 million, primarily from additional plant placed in-service. Gross margins increased due to higher retail customer volumes, lower coal costs, lower natural gas-fueled generation, and higher wheeling revenue, partially offset by higher purchased electricity costs, lower average retail rates and lower wholesale revenue from lower volumes. Retail customer volumes increased 2.1% due to impacts of weather on residential customers primarily in Utah and Oregon, higher commercial usage primarily in Oregon and Utah and an increase in the average number of residential and commercial customers in Utah, partially offset by lower irrigation usage in Idaho and Oregon and lower industrial usage in Utah and Oregon.

•

MidAmerican Funding's net income increased $65 million primarily due to higher recognized production tax credits of $45 million due to higher generation from wind-powered facilities placed in-service in the second half of 2016, higher electric gross margins of $7 million, excluding the impact of demand side management program revenue (offset in operating expense), and lower depreciation and amortization of $7 million substantially from changes in accruals for Iowa regulatory arrangements. Electric gross margins increased due to higher recoveries through bill riders and higher transmission revenue, partially offset by lower wholesale revenue from lower sales volumes and prices.

•

Northern Powergrid's net income decreased $21 million largely due to $17 million of deferred income tax benefits reflected in the third quarter of 2016 due to a 1% reduction in the United Kingdom corporate income tax rate, higher pension expense of $13 million and lower distribution revenue of $7 million, partially offset by $19 million of asset provisions recognized in the third quarter of 2016 at the CE Gas business. Distribution revenue decreased mainly due to lower tariff rates and units distributed.


•	BHE Renewables' net income decreased $9 million mainly due to make-whole payments associated with the early redemptions of certain project debt.


•	HomeServices' net income decreased $4 million primarily due to lower earnings from brokerage and mortgage businesses.


•	BHE and Other net loss increased $9 million primarily due to lower federal income tax credits recognized on a consolidated basis, higher consolidated deferred state income tax expense due to an increase in the Illinois enacted tax rate and unfavorable results of $8 million at MidAmerican Energy Services, LLC, partially offset by lower other operating costs.

Net income attributable to BHE shareholders increased $136 million for the first nine months of 2017 compared to 2016 due to the following:

•

PacifiCorp's net income increased $22 million primarily due to higher gross margins of $71 million, excluding the impact of demand side management program revenue (offset in operating expense), partially offset by higher depreciation and amortization of $22 million from additional plant placed in-service and higher property and other taxes. Gross margins increased due to higher retail customer volumes, lower natural gas-fueled generation, higher wholesale revenue from higher short-term market prices and volumes and higher wheeling revenue, partially offset by higher purchased electricity costs and lower average retail rates. Retail customer volumes increased 2.4% due to impacts of weather primarily on residential customers in Oregon, Washington and Utah, higher commercial usage primarily in Utah and Oregon, an increase in the average number of residential and commercial customers primarily in Utah and Oregon and higher industrial usage in the eastern service territory, partially offset by lower residential usage across the service territory, lower industrial usage in Oregon and lower irrigation usage primarily in Oregon and Idaho.

•

MidAmerican Funding's net income increased $98 million primarily due to higher recognized production tax credits of $71 million due to higher generation from wind-powered facilities placed in-service in the second half of 2016 and higher electric gross margins of $60 million, excluding the impact of demand side management program revenue (offset in operating expense), partially offset by higher depreciation and amortization of $31 million, primarily due to accruals for Iowa regulatory arrangements and the increase in wind-powered generating facilities, and higher operating expenses. Electric gross margins increased due to higher wholesale revenue from higher sales volumes and prices, higher recoveries through bill riders, higher retail customer volumes and higher transmission revenue, partially offset by higher coal-fueled generation and purchased power costs. Retail customer volumes increased 1.5% due to industrial growth net of lower residential and commercial volumes from milder temperatures.

•

NV Energy's net income increased $28 million for the first nine months of 2017 compared to 2016 primarily due to higher electric gross margins of $25 million, excluding the impact of energy efficiency program revenue (offset in operating expense), and lower interest expense of $17 million on lower deferred charges and from lower rates on outstanding debt balances. Electric gross margins increased due to higher customer usage from the impacts of weather, an increase in the average number of customers, customer usage patterns and an increase in transmission revenues.

•

Northern Powergrid's net income decreased $54 million largely due to the stronger United States dollar of $19 million, higher pension expense of $21 million, lower distribution revenue of $17 million and $17 million of deferred income tax benefits reflected in the third quarter of 2016 due to a 1% reduction in the United Kingdom corporate income tax rate, partially offset by $19 million of asset provisions recognized in the third quarter of 2016 at the CE Gas business. Distribution revenue decreased due to lower units distributed, the recovery in 2016 of the December 2013 customer rebate and unfavorable movements in regulatory provisions, partially offset by higher tariff rates.


•	BHE Pipeline Group’s net income increased $8 million due to a reduction in expenses and regulatory liabilities related to the impact of an alternative rate structure approved by the FERC at Kern River and higher transportation revenues at Northern Natural Gas, partially offset by lower transportation revenues at Kern River and higher operating expenses at Northern Natural Gas.

•

BHE Transmission's net income decreased $2 million from lower earnings at BHE U.S. Transmission of $4 million from lower equity earnings at Electric Transmission Texas, LLC due to the impacts of new rates effective in March 2017, partially offset by higher earnings at AltaLink of $2 million primarily due to the impacts of additional assets placed in-service partially offset by lower recoveries and decreases in contingent liabilities.

•

BHE Renewables' net income increased $52 million mainly due to favorable earnings from tax equity investments reaching commercial operation, additional wind and solar capacity placed in-service, higher generation at the Solar Star projects due to transformer related forced outages in 2016 and higher production at the Casecnan project due to higher rainfall, partially offset by make-whole payments associated with the early redemptions of certain project debt.


•	HomeServices' net income increased $2 million primarily due to higher earnings at franchise businesses, partially offset by lower earnings at brokerage and mortgage businesses.

•

BHE and Other net loss increased $18 million primarily due to lower federal income tax credits recognized on a consolidated basis, higher consolidated deferred state income tax expense due to an increase in the Illinois enacted tax rate and unfavorable results of $8 million at MidAmerican Energy Services, LLC, partially offset by lower interest expense due to redemptions of junior subordinated debentures and lower consolidated deferred state income tax expense due to changes in the tax status of certain subsidiaries.

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
	2017		2016		Change					2017		2016		Change
Operating revenue:
PacifiCorp	$	1,430	$	1,434	$	(4	)	—	%	$	3,956	$	3,919	$	37		1	%
MidAmerican Funding	815		797		18			2		2,170		2,008		162			8
NV Energy	1,047		987		60			6		2,384		2,309		75			3
Northern Powergrid	221		220		1			—		685		748		(63		)	(8	)
BHE Pipeline Group	193		201		(8		)	(4	)	700		704		(4		)	(1	)
BHE Transmission	182		169		13			8		506		309		197			64
BHE Renewables	283		273		10			4		647		582		65			11
HomeServices	961		820		141			17		2,502		2,152		350			16
BHE and Other	151		191		(40		)	(21	)	453		523		(70		)	(13	)
Total operating revenue	$	5,283	$	5,092	$	191		4		$	14,003	$	13,254	$	749		6



Operating income:
PacifiCorp	$	467	$	445		$	22		5	%	$	1,150		$	1,108		$	42		4	%
MidAmerican Funding	288		284			4			1		531			524			7			1
NV Energy	393		394			(1		)	—		682			656			26			4
Northern Powergrid	81		90			(9		)	(10	)	308			373			(65		)	(17	)
BHE Pipeline Group	65		68			(3		)	(4	)	328			320			8			3
BHE Transmission	86		81			5			6		236			35			201			*
BHE Renewables	157		157			—			—		256			233			23			10
HomeServices	79		87			(8		)	(9	)	191			179			12			7
BHE and Other	8		(21		)	29			*		(38		)	(36		)	(2		)	(6	)
Total operating income	$	1,624	$	1,585		$	39		2		$	3,644		$	3,392		$	252		7

* Not meaningful

PacifiCorp

Operating revenue decreased $4 million for the third quarter of 2017 compared to 2016 due to lower retail revenue of $8 million, partially offset by higher wholesale and other revenue of $4 million. Retail revenue decreased due to lower average rates and lower demand side management program revenue (offset in operating expense), primarily driven by the establishment of the Utah Sustainable Transportation and Energy Plan program, partially offset by higher customer volumes. Retail customer volumes increased 2.1% due to impacts of weather on residential customers, primarily in Utah and Oregon, higher commercial usage primarily in Oregon and Utah, and an increase in the average number of residential and commercial customers in Utah, partially offset by lower irrigation usage in Idaho and Oregon, and lower industrial usage in Utah and Oregon. Wholesale and other revenue increased due to higher wheeling and REC revenues, partially offset by lower wholesale sales volumes.

Operating income increased $22 million for the third quarter of 2017 compared to 2016 due to lower operating expenses of $23 million, higher gross margins of $9 million, partially offset by higher depreciation and amortization of $7 million from additional plant placed in-service. Operating expenses decreased due to a decrease in demand side management program expense (offset in operating revenue) of $21 million and lower pension expense. Gross margins increased due to higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower coal costs and lower natural gas-fueled generation, partially offset by higher purchased electricity costs from higher prices and volumes.

Operating revenue increased $37 million for the first nine months of 2017 compared to 2016 due to higher wholesale and other revenue of $31 million and higher retail revenue of $6 million. Wholesale and other revenue increased due to higher wholesale revenue from higher short-term market prices and sales volumes and higher wheeling and REC revenues. Retail revenue increased due to higher customer volumes, partially offset by lower average rates and lower demand side management program revenue (offset in operating expense), primarily driven by the establishment of the Utah Sustainable Transportation and Energy Plan program. Retail customer volumes increased 2.4% due to impacts of weather, primarily on residential customers in Oregon, Washington and Utah, higher commercial usage primarily in Utah and Oregon, an increase in the average number of residential and commercial customers, primarily in Utah and Oregon, and higher industrial usage in the eastern service territory, partially offset by lower residential usage across the service territory, lower industrial usage in Oregon and lower irrigation usage primarily in Oregon and Idaho.

Operating income increased $42 million for the first nine months of 2017 compared to 2016 due to lower operating expenses of $45 million and higher gross margins of $26 million, partially offset by higher depreciation and amortization of $22 million from additional plant placed in-service and higher property taxes. Operating expenses decreased due to a decrease in demand side management program expense (offset in operating revenue) of $44 million and lower pension expense, partially offset by higher injury and damage expenses, primarily due to a prior year accrual for insurance proceeds and current year settlements, and higher labor costs related to storm damage restoration. Gross margins were higher due to the increase in operating revenue, higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower natural gas-fueled generation and lower coal costs, partially offset by higher purchased electricity costs from higher volumes and prices.

MidAmerican Funding

Operating revenue increased $18 million for the third quarter of 2017 compared to 2016 primarily due to higher electric operating revenue of $15 million from higher retail revenue of $29 million and lower wholesale and other revenue of $14 million. Electric retail revenue increased $38 million from higher recoveries through bill riders (substantially offset in cost of sales, operating expense and income tax expense) and $5 million from non-weather usage and rate factors, including higher industrial sales volumes, partially offset by $14 million from the impact of milder temperatures in 2017. Electric retail customer volumes increased 0.4% from industrial growth, partially offset by the unfavorable impact of temperatures. Electric wholesale and other revenue decreased due to lower wholesale volumes of $14 million and lower wholesale prices of $6 million, partially offset by higher transmission revenue of $6 million.

Operating income increased $4 million for the third quarter of 2017 compared to 2016 due to higher electric gross margins of $15 million due to the increase in operating revenue and lower depreciation and amortization of $7 million, partially offset by higher operating expenses. The decrease in depreciation and amortization reflects lower accruals for Iowa regulatory arrangements and a reduction of $9 million from lower depreciation rates implemented in December 2016, partially offset by wind generation and other plant placed in-service. Operating expenses increased primarily due to higher demand side management program expense (offset in operating revenue) of $8 million and higher generation maintenance costs.

Operating revenue increased $162 million for the first nine months of 2017 compared to 2016 due to higher electric operating revenue of $105 million and higher natural gas operating revenue of $55 million. Electric operating revenue increased due to higher wholesale and other revenue of $53 million and higher retail revenue of $52 million. Electric wholesale and other revenue increased due primarily to higher wholesale volumes of $34 million, higher transmission revenue of $11 million and higher wholesale prices of $6 million. Electric retail revenue increased $47 million from higher recoveries through bill riders (substantially offset in cost of sales, operating expense and income tax expense) and $33 million from non-weather usage and rate factors, including higher industrial sales volumes, partially offset by $28 million from the impact of milder temperatures in 2017. Electric retail customer volumes increased 1.5% from industrial growth, partially offset by the unfavorable impact of temperatures. Natural gas operating revenue increased due to a higher average per-unit cost of gas sold of $59 million (offset in cost of sales), higher demand side management program revenue (offset in operating expense) of $3 million and 1.7% higher wholesale sales volumes, partially offset by 6.2% lower retail sales volumes.

Operating income increased $7 million for the first nine months of 2017 compared to 2016 due to higher electric gross margins of $75 million and higher natural gas gross margins of $3 million, partially offset by higher depreciation and amortization of $31 million, higher property and other taxes of $6 million and higher operating expenses. Electric gross margins were higher due to the increase in operating revenue, partially offset by higher coal-fueled generation and higher purchased power costs. The increase in depreciation and amortization reflects wind generation and other plant placed in-service and higher accruals for Iowa regulatory arrangements, partially offset by a reduction of $26 million from lower depreciation rates implemented in December 2016. Operating expenses increased primarily due to higher demand side management program expense (offset in operating revenue) of $17 million and higher generation maintenance costs.

NV Energy

Operating revenue increased $60 million for the third quarter of 2017 compared to 2016 due to higher electric operating revenue primarily due to higher retail revenue of $58 million and higher transmission revenue of $4 million. Electric retail revenue increased due to $115 million from higher rates primarily from energy costs (offset in cost of sales), $25 million from higher distribution only service revenue and impact fees received due to customers purchasing energy from alternative providers and becoming distribution only service customers, $5 million from an increase in the average number of customers and $4 million higher customer usage mainly from the impacts of weather, partially offset by $73 million from lower commercial and industrial revenue, mainly from customers purchasing energy from alternative providers, $10 million of lower energy efficiency program revenue (offset in operating expense) and $9 million from a refinement of the unbilled revenue estimate. Electric retail customer volumes, including distribution only service customers, increased 3.8% compared to 2016.

Operating income decreased $1 million for the third quarter of 2017 compared to 2016 due to lower electric gross margins of $9 million offset by lower operating expenses of $8 million primarily due to lower energy efficiency program expense (offset in electric operating revenue). Electric gross margins were lower due to higher energy costs of $69 million primarily due to lower net deferred power costs, partially offset by the increase in electric operating revenue.

Operating revenue increased $75 million for the first nine months of 2017 compared to 2016 due to higher electric operating revenue of $89 million, partially offset by lower natural gas operating revenue of $15 million. Electric operating revenue increased due to higher retail revenue of $81 million and higher transmission revenue of $9 million. Electric retail revenue increased due to $130 million from higher rates primarily from energy costs (offset in cost of sales), $36 million from higher distribution only service revenue and impact fees received due to customers purchasing energy from alternative providers and becoming distribution only service customers, $18 million from an increase in the average number customers and $11 million higher customer usage mainly from the impacts of weather, partially offset by $93 million from lower commercial and industrial revenue, mainly from customers purchasing energy from alternative providers, and $23 million of lower energy efficiency program revenue (offset in operating expense). Electric retail customer volumes, including distribution only service customers, increased 2.4% compared to 2016. Natural gas operating revenue decreased due to lower energy rates, partially offset by higher customer usage.

Operating income increased $26 million for the first nine months of 2017 compared to 2016 due to lower operating expenses of $23 million primarily due to lower energy efficiency program expense (offset in electric operating revenue) and higher electric gross margins of $2 million. Electric gross margins were higher due to the increase in electric operating revenue, partially offset by higher energy costs of $87 million. Energy costs increased due to a higher average cost of fuel for generation of $62 million, lower net deferred power costs of $23 million and higher purchased power costs of $3 million.

Northern Powergrid

Operating revenue increased $1 million for the third quarter of 2017 compared to 2016 due to lower distribution revenue of $7 million, partially offset by higher smart metering revenue of $6 million. Distribution revenue decreased mainly due to lower tariff rates of $4 million and lower units distributed of $2 million. Operating income decreased $9 million for the third quarter of 2017 compared to 2016 due to higher pension expense of $13 million, mainly due to a settlement loss recognized in the third quarter as a result of the level of lump sum plan withdrawals, higher depreciation of $7 million from additional assets placed in-service and higher distribution costs of $4 million, partially offset by $19 million of asset provisions recognized in the third quarter of 2016 at the CE Gas business.

Operating revenue decreased $63 million for the first nine months of 2017 compared to 2016 due to the stronger United States dollar of $66 million and lower distribution revenue of $17 million, partially offset by higher smart metering revenue of $18 million. Distribution revenue decreased due to lower units distributed of $14 million, the recovery in 2016 of the December 2013 customer rebate of $11 million and unfavorable movements in regulatory provisions of $5 million, partially offset by higher tariff rates of $11 million. Operating income decreased $65 million for the first nine months of 2017 compared to 2016 due to the stronger United States dollar of $33 million, higher pension expense of $23 million, mainly due to the 2017 settlement loss recognized, higher depreciation of $21 million from additional assets placed in service and higher distribution costs of $7 million, partially offset by $19 million of asset provisions recognized in the third quarter of 2016 at the CE Gas business.

BHE Pipeline Group

Operating revenue decreased $8 million for the third quarter of 2017 compared to 2016 due to lower transportation revenues at Kern River, partially offset by higher transportation revenues at Northern Natural Gas. Operating income decreased $3 million for the third quarter of 2017 compared to 2016 primarily due to lower transportation revenues at Kern River and higher operating expenses at Northern Natural Gas, partially offset by lower depreciation expense and higher transportation revenues at Northern Natural Gas.

Operating revenue decreased $4 million for the first nine months of 2017 compared to 2016 due lower transportation revenues at Kern River, partially offset by higher gas sales of $15 million related to system balancing activities (largely offset in cost of sales) and higher transportation revenues at Northern Natural Gas. Operating income increased $8 million for the first nine months of 2017 compared to 2016 primarily due to a reduction in expenses and regulatory liabilities related to the impact of an alternative rate structure approved by the FERC at Kern River and higher transportation revenues at Northern Natural Gas, partially offset by higher operating expenses at Northern Natural Gas and lower transportation revenues at Kern River.

BHE Transmission

Operating revenue increased $13 million for the third quarter of 2017 compared to 2016 primarily due to the weaker United States dollar of $7 million and higher costs recovered in operating revenue. Operating income increased $5 million for the third quarter of 2017 compared to 2016 primarily due to the weaker United States dollar of $4 million.

Operating revenue increased $197 million for the first nine months of 2017 compared to 2016 primarily due to a one-time reduction of $200 million from the 2015-2016 GTA decision received in May 2016 at AltaLink, $10 million from additional assets placed in service and the weaker United States dollar of $9 million, partially offset by lower costs recovered in operating revenue. Operating income increased $201 million for the first nine months of 2017 compared to 2016 primarily due to the higher operating revenue from the 2015-2016 GTA decision that required AltaLink to refund $200 million to customers in 2016 through reduced monthly billings for the change from receiving cash during construction for the return on construction work-in-progress in rate base to recording allowance for borrowed and equity funds used during construction related to construction expenditures during the 2011 to 2014 time period. The refund was offset with higher capitalized interest and allowance for equity funds. Operating income was also favorably impacted $6 million by the weaker United States dollar.

BHE Renewables

Operating revenue increased $10 million for the third quarter of 2017 compared to 2016 due to additional wind and solar capacity placed in-service of $17 million, partially offset by lower geothermal revenues of $6 million due to unfavorable pricing and lower capacity revenues. Operating income was unchanged for the third quarter of 2017 compared to 2016 as higher costs associated with the additional capacity placed in-service offset the increased revenues.

Operating revenue increased $65 million for the first nine months of 2017 compared to 2016 due to additional wind and solar capacity placed in-service of $45 million, higher generation at the Solar Star projects of $29 million due to transformer related forced outages in 2016 and higher production at the Casecnan project of $10 million due to higher rainfall, partially offset by lower generation at the Topaz project of $11 million mainly due to a scheduled maintenance outage and lower generation of $7 million at the existing wind projects due to a lower wind resource. Operating income increased $23 million for the first nine months of 2017 compared to 2016 due to the increase in operating revenue, partially offset by higher operating expense of $24 million and higher depreciation and amortization of $17 million, each primarily due to the additional wind and solar capacity placed in-service. Operating expense also increased from the scope and timing of maintenance at certain geothermal plants. The change in depreciation and amortization reflects a reduction of $6 million from the extension of the useful life of certain wind-generating facilities from 25 years to 30 years effective January 2017.

HomeServices

Operating revenue increased $141 million for the third quarter of 2017 compared to 2016 due to an increase from acquired businesses totaling $139 million. Operating income decreased $8 million for the third quarter of 2017 compared to 2016 primarily due to lower earnings from brokerage businesses, mainly due to higher operating expenses, and lower mortgage revenue.

Operating revenue increased $350 million for the first nine months of 2017 compared to 2016 primarily due to an increase from acquired businesses totaling $279 million and a 3.8% increase in average home sales prices for existing businesses. Operating income increased $12 million for the first nine months of 2017 compared to 2016 primarily due to higher earnings from franchise businesses, mainly due to a favorable settlement and a gain on the collection of notes receivable, partially offset by lower earnings from brokerage businesses, mainly due to higher operating expenses, and lower mortgage revenue.

BHE and Other

Operating revenue decreased $40 million for the third quarter of 2017 compared to 2016 due to lower electricity and natural gas volumes and rates at MidAmerican Energy Services, LLC. Operating income improved $29 million for the third quarter of 2017 compared to 2016 due to lower operating expenses, partially offset by lower margins of $8 million at MidAmerican Energy Services, LLC.

Operating revenue decreased $70 million for the first nine months of 2017 compared to 2016 due to lower electricity and natural gas volumes and rates at MidAmerican Energy Services, LLC. Operating loss increased $2 million for the first nine months of 2017 compared to 2016 due to lower margins of $9 million at MidAmerican Energy Services, LLC, partially offset by lower operating expenses.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense is summarized as follows (in millions):



	Third Quarter									First Nine Months
	2017		2016		Change					2017		2016		Change

Subsidiary debt	$	354	$	345	$	9		3	%	$	1,045	$	1,042	$	3		—	%
BHE senior debt and other	106		101		5			5		317		305		12			4
BHE junior subordinated debentures	4		14		(10		)	(71	)	17		54		(37		)	(69	)
Total interest expense	$	464	$	460	$	4		1		$	1,379	$	1,401	$	(22	)	(2	)

Interest expense increased $4 million for the third quarter of 2017 compared to 2016 and decreased $22 million for the first nine months of 2017 compared to 2016 due to repayments of BHE junior subordinated debentures of $944 million in 2017 and $2.0 billion in 2016, scheduled maturities and principal payments, early redemptions and the impact of foreign currency exchange rate movements of $8 million in the first nine months, partially offset by debt issuances at MidAmerican Funding, Northern Powergrid, AltaLink and BHE Renewables.

Capitalized Interest

Capitalized interest decreased $94 million for the first nine months of 2017 compared to 2016 primarily due to $96 million recorded in the second quarter of 2016 from the 2015-2016 GTA decision received in May 2016 at AltaLink, which was offset in operating revenue, partially offset by higher construction work-in-progress balances at MidAmerican Energy.

Allowance for Equity Funds

Allowance for equity funds increased $7 million for the third quarter of 2017 compared to 2016 and decreased $88 million for the first nine months of 2017 compared to 2016 primarily due to $104 million recorded in the second quarter of 2016 from the 2015-2016 GTA decision received in May 2016 at AltaLink, which was offset in operating revenue, partially offset by higher construction work-in-progress balances at MidAmerican Energy.

Interest and Dividend Income

Interest and dividend income decreased $7 million for the third quarter of 2017 compared to 2016 and $8 million for the first nine months of 2017 compared to 2016 primarily due to lower dividends received from BYD Company Limited.

Other, net

Other, net decreased $13 million for the third quarter of 2017 compared to 2016 primarily due to costs associated with the early redemption of subsidiary long-term debt in 2017.

Other, net decreased $2 million for the first nine months of 2017 compared to 2016 mainly due to costs associated with the early redemption of subsidiary long-term debt in 2017 and an impairment of certain energy management assets at MidAmerican Energy Services, LLC, partially offset by higher investment returns and favorable changes in the valuations of interest rate swap derivatives.

Income Tax Expense

Income tax expense decreased $15 million for the third quarter of 2017 compared to 2016 and the effective tax rate was 15% for 2017 and 16% for 2016. The effective tax rate decreased due to higher production tax credits recognized of $34 million and the favorable impacts of rate making of $10 million, partially offset by deferred income tax benefits of $16 million reflected in the third quarter of 2016 due to a 1% reduction in the United Kingdom corporate income tax rate.

Income tax expense decreased $75 million for the first nine months of 2017 compared to 2016 and the effective tax rate was 13% for 2017 and 17% for 2016. The effective tax rate decreased due to higher production tax credits recognized of $96 million and the favorable impacts of rate making of $14 million, partially offset by higher income tax expense on higher pre-tax income and deferred income tax benefits of $16 million reflected in the third quarter of 2016 due to a 1% reduction in the United Kingdom corporate income tax rate.

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 based on a per-kilowatt rate pursuant to the applicable federal income tax law and are eligible for the credit for 10 years from the date the qualifying generating facilities are placed in-service. Production tax credits recognized in 2017 were $432 million, or $96 million higher than 2016, while production tax credits earned in 2017 were $346 million, or $79 million higher than 2016. The difference between production tax credits recognized and earned of $86 million as of September 30, 2017, primarily at MidAmerican Energy, will be reflected in earnings over the remainder of 2017.

Equity Income

Equity income decreased $6 million for the third quarter of 2017 compared to 2016 and $16 million for the first nine months of 2017 compared to 2016 due to lower pre-tax equity earnings from tax equity investments at BHE Renewables and lower equity earnings at Electric Transmission Texas, LLC, primarily due to the impacts of new rates effective in March 2017.

Net Income Attributable to Noncontrolling Interests

Net income attributable to noncontrolling interests increased $5 million for the first nine months of 2017 compared to 2016 due to higher earnings at HomeServices' franchise business.

Liquidity and Capital Resources

Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt 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. 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, 2016 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of September 30, 2017, 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	$	75		$	104		$	512		$	109		$	62	$	9		$	271		$	1,142

Credit facilities	3,000			1,000			909			650			201		1,062			1,660			8,482
Less:
Short-term debt	(1,405		)	—			—			—			—		(286		)	(802		)	(2,493		)
Tax-exempt bond support and letters of credit	(7		)	(130		)	(220		)	(80		)	—		(7		)	—			(444		)
Net credit facilities	1,588			870			689			570			201		769			858			5,545

Total net liquidity	$	1,663		$	974		$	1,201		$	679		$	263	$	778		$	1,129		$	6,687
Credit facilities:
Maturity dates	2018, 2020			2020			2018, 2020			2020			2020		2017, 2018, 2021			2017, 2018, 2022

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2017 and 2016 were $5.1 billion and $4.8 billion, respectively. The change was primarily due to improved operating results, changes in working capital and the payment for USA Power final judgment and post-judgment interest in the prior year, partially offset by a reduction in income tax receipts and higher cash payments for interest.

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.

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

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2017 and 2016 were $(4.4) billion and $(4.1) billion, respectively. The change was primarily due to higher cash paid for acquisitions of $1.0 billion, partially offset by lower capital expenditures of $342 million and lower funding of tax equity investments.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2017 was $(330) million. Uses of cash totaled $2.3 billion and consisted mainly of repayments of BHE senior debt and junior subordinated debentures totaling $1.3 billion and repayments of subsidiary debt totaling $834 million. Sources of cash totaled $1.9 billion and consisted of $1.6 billion of proceeds from subsidiary debt issuances and $365 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, 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 and consisted of $1.5 billion of proceeds from subsidiary debt issuances and $887 million net proceeds from short-term debt.

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

Future Uses of Cash

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

Capital Expenditures

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

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



	Nine-Month Periods				Annual
	Ended September 30,				Forecast
	2016		2017		2017
Capital expenditures by business:
PacifiCorp	$	586	$	553	$	798
MidAmerican Funding	1,129		1,165		2,006
NV Energy	386		333		433
Northern Powergrid	435		434		616
BHE Pipeline Group	150		174		309
BHE Transmission	386		255		343
BHE Renewables	430		239		315
HomeServices	13		18		34
BHE and Other	6		8		13
Total	$	3,521	$	3,179	$	4,867



Capital expenditures by type:
Wind generation	$	1,110	$	804	$	1,292
Solar generation	15		95		125
Electric transmission	339		267		330
Environmental	52		56		111
Other growth	302		400		560
Operating	1,703		1,557		2,449
Total	$	3,521	$	3,179	$	4,867

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 $455 million and $732 million for the nine-month periods ended September 30, 2017 and 2016, respectively. MidAmerican Energy anticipates costs for wind-powered generating facilities will total an additional $254 million for 2017. 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 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. Each of these projects is expected to qualify for 100% of production tax credits currently available.

◦

Repowering certain existing wind-powered generating facilities at PacifiCorp and MidAmerican Energy and the construction of new wind-powered generating facilities at PacifiCorp totaling $280 million for the nine-month period ended September 30, 2017. PacifiCorp and MidAmerican Energy anticipate costs for these activities will total an additional $221 million for 2017. The repowering projects entail the replacement of significant components of older turbines. The energy production from the repowered and the new facilities is expected to qualify for 100% of the federal renewable electricity production tax credits available for ten years once the equipment is placed in-service.

◦

Construction of wind-powered generating facilities at BHE Renewables totaling $69 million and $378 million for the nine-month periods ended September 30, 2017 and 2016, respectively. BHE Renewables anticipates costs for wind-powered generating facilities will total an additional $11 million in 2017 and $263 million in 2018. BHE Renewables is developing and constructing up to 212 MW of wind-powered generating facilities in the state of Illinois.


•	Solar generation includes the construction of the community solar gardens project in Minnesota at BHE Renewables totaling $92 million for the nine-month period ended September 30, 2017. BHE Renewables anticipates costs for the community solar gardens project will total an additional $27 million in 2017 and $26 million in 2018.

•

Electric transmission includes PacifiCorp's costs associated with main grid reinforcement and the Energy Gateway Transmission Expansion Program, MidAmerican Energy's Multi-Value Projects approved by the Midcontinent Independent System Operator, Inc. for the construction of approximately 250 miles of 345 kV transmission line located in Iowa and Illinois and AltaLink's directly assigned projects from the AESO.

•

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


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


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

Acquisitions

The Company completed various acquisitions totaling $1.1 billion for the nine-month period ended September 30, 2017. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related primarily to residential real estate brokerage businesses, development and construction costs for the 110-megawatt Alamo 6 solar project and the 50-megawatt Pearl solar project, and the remaining 25% interest in the Silverhawk natural gas-fueled generation facility at Nevada Power. As a result of the acquisitions, the Company acquired assets of $1.1 billion, assumed liabilities of $476 million and recognized goodwill of $522 million.

Integrated Resource Plan

In April 2017, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP") with its state commissions. The IRP includes investments in renewable energy resources, upgrades to the existing wind fleet, and energy efficiency measures to meet future customer needs. Implementation of wind upgrades, new transmission, and new wind renewable resources will require an estimated $3 billion in capital investment from 2017 through 2020. PacifiCorp's forecast capital expenditures for 2018 through 2019 increased $723 million from the forecast included in BHE's 2016 Annual Report on Form 10-K as a result of its 2017 IRP.

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 $170 million in 2015, $584 million in 2016 and $85 million through September 30, 2017, and expects to contribute $317 million for the remainder of 2017 and $254 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 enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.

Contractual Obligations

As of September 30, 2017, 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, 2016 other than the recent financing transactions and the renewable tax equity investments previously discussed.

Quad Cities Generating Station Operating Status

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

On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of Illinois ("Northern District of Illinois") against the Illinois Power Agency alleging that the state’s zero emission credit program violates certain provisions of the U.S. Constitution. Both complaints argue that the Illinois zero emission credit program will distort the FERC’s energy and capacity market auction system of setting wholesale prices. As majority owner and operator of Quad Cities Station, Exelon Generation intervened in both suits and filed motions to dismiss in both matters. On July 14, 2017, the Northern District of Illinois granted the motions to dismiss. On July 17, 2017, the plaintiffs filed appeals with the United States Court of Appeals for the Seventh Circuit. The procedural schedule has been established for the appeals. MidAmerican Energy cannot predict the outcome of these lawsuits.

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

Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2016, and new regulatory matters occurring in 2017.

PacifiCorp

In June 2017, PacifiCorp filed two applications each with the UPSC, IPUC and the WPSC for the Energy Vision 2020 project. The first application seeks approvals to construct or procure four new Wyoming wind resources with a total capacity of 860 MWs identified as benchmark resources and certain transmission facilities. A request for proposals was issued in September 2017 seeking up to 1,270 MWs to compete against PacifiCorp's benchmark resources in the final resource selection process for the project. PacifiCorp estimates the combined wind and transmission projects will cost approximately $2 billion. The WPSC, UPSC, and IPUC have set procedural schedules with hearings to occur in the first quarter of 2018. The second application seeks approval of PacifiCorp's resource decision to upgrade or "repower" existing wind resources, as prudent and in the public interest. PacifiCorp estimates the wind repowering project will cost approximately $1 billion. The hearings on repowering in Utah, Idaho and Wyoming will occur in November 2017, December 2017, and January 2018, respectively. Applications filed in Utah, Idaho and Wyoming seek approval for the proposed ratemaking treatment associated with the projects.

Utah

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

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

As a result of the Utah Sustainable Transportation and Energy Plan legislation that was signed into law in March 2016, PacifiCorp filed an application in September 2016 seeking approval of a proposed five-year pilot program with an annual budget of $10 million authorized under the legislation to address clean-coal technology programs, commercial line extension programs, an electric vehicle incentive program and associated residential time of use rate pilot and other programs authorized in legislation. The UPSC issued orders approving PacifiCorp's application in phases in December 2016, May 2017 and June 2017.

In November 2016, PacifiCorp filed cost of service analyses, as ordered by the UPSC, to quantify the cost shifting due to net metering. The UPSC ordered the analyses to comply with a 2014 law requiring the examination of whether the costs of net metering exceed the benefits to PacifiCorp and other customers. The filing includes a proposal for a new rate schedule for residential customer generators with a three-part rate based on the cost of serving this class of customer, which will mitigate future cost shifting. PacifiCorp proposed that the new rate schedule only apply to new net metering customers that submit applications after December 9, 2016. On December 9, 2016, PacifiCorp requested that the effective date for the start of a transitional tariff be suspended while it works with stakeholders on a collaborative process to resolve net metering rate design issues. The filing also requests an increase in the application fees for net metering. In February 2017, the UPSC ruled on motions to dismiss and requests for a show cause order for a regulatory rate review filed by various parties to the docket and denied the motions. On August 28, 2017, PacifiCorp filed a settlement stipulation in the net metering proceeding. The stipulation provides for the closure of the net metering program to new entrants on November 15, 2017, with a transition to a new program that provides a separate compensation rate for exported power. All net metering customers, including those with a submitted application, as of November 15, 2017, will be grandfathered into the current program until January 1, 2036. A new proceeding will be initiated to establish a methodology for the determination of the export credit for new customers. During this period, a transition program for new customers will commence November 15, 2017, for a limited number of customers. Beginning December 1, 2017, PacifiCorp will start accepting applications for the new transition program for private generation customers. Residential and non-residential private generation customers will be compensated for exported energy at 90% and 92.5% of the current average energy rates, respectively. The rates for the exported energy will be fixed through January 1, 2033 for these transition program customers. The new residential and non-residential transition program customers’ compensation will be only available for the first 170 MW and 70 MW, respectively. The stipulation also includes an agreement to support a two-year extension on the state tax credit for residential solar installations. A hearing on the stipulation was held on September 18, 2017, and an order approving it was issued September 29, 2017.

Oregon

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

Wyoming

In April 2017, PacifiCorp filed its annual Energy Cost Adjustment Mechanism ("ECAM") and REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") applications with the WPSC. The ECAM filing requests approval to refund to customers $5 million in deferred net power costs for the period January 1, 2016 through December 31, 2016, and the RRA application requests approval to refund to customers $1 million. In June 2017, the WPSC approved the ECAM and RRA rates on an interim basis until a final order is issued by the WPSC, which is expected in the first quarter of 2018.

Washington

In August 2017, PacifiCorp submitted a compliance filing to implement the second-year rate increase approved as part of the two-year rate plan in the 2015 regulatory rate review. The compliance filing included rates based on the $8 million, or 2.3%, increase ordered by the WUTC in September 2016. The compliance filing was approved by the WUTC on September 14, 2017, with rates effective September 15, 2017.

Idaho

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

In March 2017, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $8 million for deferred costs in 2016. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, recovery of Deer Creek longwall mine investment and changes in production tax credits and renewable energy credits. The IPUC approved the ECAM application with rates effective June 1, 2017.

California

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

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

NV Energy (Nevada Power and Sierra Pacific)

Regulatory Rate Reviews

In June 2017, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $29 million, or 2%, but requested no incremental annual revenue relief. The hearings are scheduled in the last quarter of 2017. The PUCN is expected to complete the hearings by the end of 2017, but the PUCN has not indicated when they will issue a final order or when that order would become effective.

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

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

Chapter 704B Applications

Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one MW or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs.

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

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

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

In May 2017, Peppermill Resort Spa Casino ("Peppermill"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific. In August 2017, the PUCN approved a stipulation allowing Peppermill to purchase energy from alternative providers subject to conditions, including paying an impact fee. In September 2017, Peppermill provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.

Net Metering

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

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

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

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

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

Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The legislation, among other things, established net metering crediting rates for private generation customers with installed net metering systems less than 25 kilowatts. Under AB 405, private generation customers will be compensated at 95% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the first 80 MWs of cumulative installed capacity of all net metering systems in Nevada, 88% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the next 80 MWs of cumulative installed capacity in Nevada, 81% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the next 80 MWs of cumulative installed capacity in Nevada and 75% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for any additional private generation capacity. In July 2017, the Nevada Utilities filed with the PUCN proposed amendments to their tariffs necessary to comply with the provisions of AB 405. The filing in July 2017 also included a proposed optional time of use rate tariff for both Nevada Power and Sierra Pacific, which has not yet been set for procedural review. In September 2017, the PUCN issued an order directing the Nevada Utilities to place all new private generation customers who have submitted applications after June 15, 2017, into a new rate class with rates equal to the rate class they would be in if they were not private generation customers. Private generation customers with installed net metering systems less than 25 kilowatts prior to June 15, 2017, may elect to migrate to the new rate class created under AB 405 or stay in their otherwise-applicable rate class.

Energy Choice Initiative

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

ALP

General Tariff Applications

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

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

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

During the second quarter 2017, ALP responded to information requests from the AUC with respect to its second compliance filing amendment filed in April 2017. In August 2017, the AUC issued a decision with respect to ALP's second compliance filing amendment filed in April 2017. The AUC denied ALP's proposal to remove C$7 million of recapitalized AFUDC associated with canceled projects on the basis that the amount would more appropriately be recovered through ALP's deferral account reconciliation process. In addition, the AUC reaffirmed ALP's 2016 refund of C$267 million of previously collected CWIP-in-rate base, along with C$45 million of cumulative return thereon. The AUC also directed the recalculation of the amount of related income taxes using typical direct assigned project schedules filed in the general tariff applications, and to adjust its funded future income tax liability only for the change in timing differences.

In September 2017, ALP filed with the AUC its third compliance filing, which proposes a one-time payment to the AESO of C$7 million to settle the 2015-2016 final transmission tariffs. Further direction or a final decision from the AUC is expected in the fourth quarter 2017. Once the AUC approves ALP’s third compliance filing, final transmission tariff rates for the 2015 and 2016 test years will be set, subject to further adjustment through the deferral account reconciliation process.

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

During the second quarter 2017, ALP responded to information requests from the AUC with respect to its 2017-2018 negotiated settlement agreement application filed in February 2017. In August 2017, the AUC issued a decision approving ALP's negotiated settlement agreement for the 2017-2018 GTA, as filed. Also, the AUC approved a C$31 million refund of accumulated depreciation surplus as opposed to the C$130 million refund proposed in the original application. In November 2017, ALP filed a compliance filing with the AUC to reflect the reduction of the accumulated depreciation surplus refund and related adjustments.

2018 Generic Cost of Capital Proceeding

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

Deferral Account Reconciliation Application

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

In June 2017, the AUC also suspended the process in order to address a conflict of interest issue related to the provision of confidential documents.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Refer to "Liquidity and Capital Resources" of each respective Registrant in Part I, Item 2 of this Form 10-Q for discussion of each Registrant's forecast environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2016, and new environmental matters occurring in 2017.

Clean Air Act Regulations

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

Regional Haze

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

The state of Utah issued a regional haze SIP requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides and particulate matter portions. Certain groups appealed the EPA's approval of the sulfur dioxide portion and oral argument was heard before the United States Court of Appeals for the Tenth Circuit ("Tenth Circuit") in March 2014. In October 2014, the Tenth Circuit upheld the EPA's approval of the sulfur dioxide portion of the SIP. The state of Utah and PacifiCorp filed petitions for administrative and judicial review of the EPA's final rule on the BART determinations for the nitrogen oxides and particulate matter portions of Utah's regional haze SIP in March 2013. In May 2014, the Tenth Circuit dismissed the petition on jurisdictional grounds. In addition, and separate from the EPA's approval process and related litigation, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. The alternative BART analysis and revised regional haze SIP were submitted in June 2015 to the EPA for review and proposed action after a public comment period. The revised regional haze SIP included a state-enforceable requirement to cease operation of the Carbon Facility by August 15, 2015. PacifiCorp retired the Carbon Facility in December 2015. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to nitrogen oxides controls and require the installation of selective catalytic reduction ("SCR") controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties have filed requests with the EPA to reconsider and stay that decision, and have also filed motions for stay and petitions for review with the Tenth Circuit asking the court to overturn the EPA’s actions. In June 2017, the state of Utah and PacifiCorp issued requests to the EPA to reconsider its decision in issuing the FIP. By letter dated July 14, 2017, from Administrator Scott Pruitt, the EPA indicated that based on existing and new evidence potentially relevant to the EPA’s evaluation of Utah’s 2015 SIP, the agency would reconsider its final rule and prepare a notice of proposed rulemaking and take public comment on its proposed action. On July 18, 2017, the EPA filed with the Tenth Circuit a motion to hold the pending appeals in abeyance pending agency reconsideration of the final rule. The Tenth Circuit initially requested that all parties file a response setting forth their opposition or nonopposition to the EPA’s motion to hold the cases in abeyance by July 28, 2017. However, on July 18, 2017, PacifiCorp asked the Tenth Circuit to take judicial notice of the EPA’s request to hold the appeals in abeyance and reaffirmed its request to stay the FIP. The Tenth Circuit ordered all parties to respond to both the EPA's motion for abeyance and the motions by PacifiCorp and others to take judicial notice of EPA's reconsideration by August 4, 2017. On September 11, 2017, the Tenth Circuit issued an order granting both the motion to hold the case in abeyance and the motions for stay. The stay tolls the compliance requirements of the federal implementation plan for the number of days the stay is in effect while the EPA reconsiders the basis for the issuance of the federal plan.

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. 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; after notice and comment, the Arizona Department of Environmental Quality submitted the amended Arizona SIP to the EPA, which approved the amendments to the Arizona regional haze SIP with an effective date of April 26, 2017.

The Navajo Generating Station, in which Nevada Power is a joint owner with an 11.3% ownership share, is also a source that is subject to the regional haze BART requirements. In January 2013, the EPA announced a proposed FIP addressing BART and an alternative for the Navajo Generating Station that includes a flexible timeline for reducing nitrogen oxides emissions. Nevada Power, along with the other owners of the facility, have been reviewing the EPA's proposal to determine its impact on the viability of the facility's future operations. The land lease for the Navajo Generating Station is subject to renewal in 2019. In the spring 2017, the owners of the Navajo Generating Station voted to shut down and demolish the plant on or before December 23, 2019; however, the owners agreed to continue operating the plant through 2019 with demolition to follow if the tribe approved a new lease by July 1, 2017. Subsequently, the Navajo Council approved the requested lease extension June 26, 2017, and on July 1, 2017, the Navajo Nation signed the replacement lease with the utility owners of the Navajo Generating Station. Two remaining owners, the U.S. Bureau of Reclamation and the City of Los Angeles, must approve the lease by December 1, 2017, to enable continued operations through 2019. The Navajo Nation, along with the U.S. Bureau of Reclamation and Peabody Energy have further indicated a desire to keep the plant and coal mine operating through at least 2030, which would require a new ownership structure for the facility. The utility owners have specified that a new ownership proposal must be put forward by October 1, 2017, in order to complete the transition prior to December 23, 2019. Nevada Power filed the Emissions Reduction and Capacity Replacement Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019, which was approved by the PUCN. Bids to sell the facility were due to Salt River Project on October 1, 2017; however, none were tendered by that date. The owners were subsequently informed that several interested parties are preparing bids which are expected for submittal and review in late October. Any potential new owner, along with the Navajo Nation has until November 1, 2017, to reach an agreement in principle and one year from that date to reach a new ownership agreement and lease. In light of the tight time frames involved, it is expected that any bid received at this time will be highly conditioned.

Climate Change

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

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards have been appealed to the D.C. Circuit and oral argument was scheduled to be heard April 17, 2017; however, the court canceled the oral arguments March 30, 2017, and, on April 28, 2017, ordered that the cases be held in abeyance for 60 days, with supplemental briefs required to be filed May 15, 2017, regarding whether the cases should be remanded to the EPA rather than held in abeyance. On August 10, 2017, the court placed the case in abeyance pending further order of the court. Until such time as the court renders a final determination regarding the validity of the standards or the EPA rescinds the standards, any new fossil-fueled generating facilities constructed by the relevant Registrants will be required to meet the GHG new source performance standards.

Clean Power Plan

In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The EPA also changed the compliance period to begin in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh and 1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. On February 9, 2016, the United States Supreme Court ordered that the EPA's emission guidelines for existing sources be stayed pending the disposition of the challenges to the rule in the D.C. Circuit and any action on a writ of certiorari before the U.S. Supreme Court. Oral argument was heard before the full D.C. Circuit (with the exception of Chief Judge Merrick Garland) on September 27, 2016, and the court has not yet issued its decision. The case has been held in abeyance pending underlying action by the EPA. On October 10, 2017, the EPA issued a proposal to repeal the Clean Power Plan and the public comment period closes on the proposal December 15, 2017. EPA has not determined whether it will issue a replacement rule. Until such time as the EPA takes final action on the repeal and determines whether there will be a replacement rule, the impact of EPA’s actions on the Registrants cannot be determined. PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

Water Quality Standards

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

In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions has changed the effluent discharged from coal- and natural gas-fueled generating facilities. Under the guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal; the new limits were to have been met as soon as possible, beginning November 1, 2018 and implemented by December 31, 2023. On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with the EPA. The EPA granted the request for reconsideration on April 12, 2017, imposed an immediate administrative stay of compliance dates in the rule that had not passed judicial review, and requested that the court stay the pending litigation over the rule until September 12, 2017. On June 6, 2017, the EPA proposed to extend many of the compliance deadlines that would otherwise occur in 2018. On September 18, 2017, the EPA issued a final rule extending certain compliance dates for flue gas desulfurization wastewater and bottom ash transport water limits until November 1, 2020. While most of the issues raised by this rule are already being addressed through the coal combustion residuals rule and are not expected to impose significant additional requirements on the facilities, the impact of the rule cannot be fully determined until the reconsideration action is complete and any judicial review is concluded.

In April 2014, the EPA and the United States Army Corps of Engineers issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but is currently under appeal in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the U.S. Supreme Court granted a petition to address jurisdictional challenges to the rule. On June 27, 2017, the EPA initiated the repeal of the "waters of the United States" rule. The EPA plans to undertake a two-step process, with the first step to repeal the 2015 rule and the second step to carry out a notice-and-comment rulemaking in which a substantive re-evaluation of the definition of the "waters of the United States" will be undertaken. The proposed repeal of the rule has not yet been published in the Federal Register. Depending on the outcome of the appeal(s) and intended rulemaking, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits would have been required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. On February 28, 2017, President Trump signed an Executive Order directing the EPA to review and rescind or revise the rule. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule. Until the outcome of the pending actions and any litigation is known, the Registrants cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs or increased requirements for compensatory mitigation.

Coal Combustion Byproduct Disposal

In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts, presenting two alternatives to regulation under the RCRA. The public comment period closed in November 2010. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and became effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of coal combustion residuals. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. On August 10, 2017, the EPA issued proposed permitting guidance on how states’ coal combustion residuals permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. The public comment period on the permitting guidance closed on September 14, 2017. Also, on September 14, 2017, the EPA granted reconsideration on aspects of the final rule. On September 18, 2017, the EPA filed a motion to hold the pending litigation on the final rule in abeyance; however, the D.C. Circuit has not made a final ruling on the motion. The D.C. Circuit requested additional briefing on the abeyance motion and directed the EPA to identify, by November 15, 2017, which issues it intends to reconsider and the timeframe for completion of the reconsideration process. Oral argument on the motion for abeyance is scheduled for November 20, 2017.

At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. These six impoundments are subject to closure on or before April 2018. At the time the rule was published in April 2015, the Nevada Utilities operated ten evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts and are subject to final closure on or before April 2018, and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule. Refer to Note 13 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2016 and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2016 for discussion of the impacts on asset retirement obligations as a result of the final rule.

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2016. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2016.

PacifiCorp and its subsidiaries

Consolidated Financial Section

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Portland, Oregon

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2017, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2017 and 2016, and of changes in shareholders' equity and cash flows for the nine-month periods ended September 30, 2017 and 2016. These interim financial statements are the responsibility of PacifiCorp'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 PacifiCorp and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Portland, Oregon

November 3, 2017

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	September 30,		December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	104	$	17
Accounts receivable, net	722		728
Income taxes receivable	—		17
Inventories:
Materials and supplies	237		228
Fuel	207		215
Regulatory assets	30		53
Other current assets	72		96
Total current assets	1,372		1,354

Property, plant and equipment, net	19,135		19,162
Regulatory assets	1,518		1,490
Other assets	388		388

Total assets	$	22,413	$	22,394

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)



	As of
	September 30,			December 31,
	2017			2016
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	398		$	408
Income taxes payable	64			—
Accrued employee expenses	115			67
Accrued interest	106			115
Accrued property and other taxes	136			63
Short-term debt	—			270
Current portion of long-term debt and capital lease obligations	591			58
Regulatory liabilities	67			54
Other current liabilities	164			164
Total current liabilities	1,641			1,199

Regulatory liabilities	1,032			978
Long-term debt and capital lease obligations	6,436			7,021
Deferred income taxes	4,884			4,880
Other long-term liabilities	913			926
Total liabilities	14,906			15,004

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	3,038			2,921
Accumulated other comprehensive loss, net	(12		)	(12		)
Total shareholders' equity	7,507			7,390

Total liabilities and shareholders' equity	$	22,413		$	22,394

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,
	2017			2016			2017			2016

Operating revenue	$	1,430		$	1,434		$	3,956		$	3,919

Operating costs and expenses:
Energy costs	465			478			1,305			1,295
Operations and maintenance	248			272			754			800
Depreciation and amortization	200			193			598			576
Taxes, other than income taxes	50			47			149			141
Total operating costs and expenses	963			990			2,806			2,812

Operating income	467			444			1,150			1,107

Other income (expense):
Interest expense	(95		)	(95		)	(285		)	(285		)
Allowance for borrowed funds	4			4			12			12
Allowance for equity funds	7			7			21			21
Other, net	6			3			13			9
Total other income (expense)	(78		)	(81		)	(239		)	(243		)

Income before income tax expense	389			363			911			864
Income tax expense	126			110			294			270
Net income	$	263		$	253		$	617		$	594

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, 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

Balance, December 31, 2016	$	2	$	—	$	4,479	$	2,921		$	(12	)	$	7,390
Net income	—		—		—		617			—			617
Common stock dividends declared	—		—		—		(500		)	—			(500		)
Balance, September 30, 2017	$	2	$	—	$	4,479	$	3,038		$	(12	)	$	7,507

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,
	2017			2016
Cash flows from operating activities:
Net income	$	617		$	594
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	598			576
Allowance for equity funds	(21		)	(21		)
Deferred income taxes and amortization of investment tax credits	14			76
Changes in regulatory assets and liabilities	21			85
Other, net	1			6
Changes in other operating assets and liabilities:
Accounts receivable and other assets	25			19
Derivative collateral, net	(4		)	2
Inventories	(1		)	(32		)
Income taxes	75			133
Accounts payable and other liabilities	110			(66		)
Net cash flows from operating activities	1,435			1,372

Cash flows from investing activities:
Capital expenditures	(553		)	(586		)
Other, net	32			26
Net cash flows from investing activities	(521		)	(560		)

Cash flows from financing activities:
Repayments of long-term debt and capital lease obligations	(54		)	(56		)
Net repayments of short-term debt	(270		)	(20		)
Common stock dividends	(500		)	(550		)
Other, net	(3		)	—
Net cash flows from financing activities	(827		)	(626		)

Net change in cash and cash equivalents	87			186
Cash and cash equivalents at beginning of period	17			12
Cash and cash equivalents at end of period	$	104		$	198

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 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, 2017 and for the three- and nine-month periods ended September 30, 2017 and 2016. 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, 2017 and 2016. The results of operations for the three- and nine-month periods ended September 30, 2017 and 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 PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2016 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, 2017.

(2) New Accounting Pronouncements

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

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

In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. 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 plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. PacifiCorp does not believe this will have a material impact 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 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. PacifiCorp plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. PacifiCorp currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp’s performance to date. PacifiCorp plans to quantitatively disaggregate revenue in the required financial statement footnote by customer class.

(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	2017			2016

Property, plant and equipment in-service	5-75 years	$	27,599		$	27,298
Accumulated depreciation and amortization		(9,222		)	(8,793		)
Net property, plant and equipment in-service		18,377			18,505
Construction work-in-progress		758			657
Total property, plant and equipment, net		$	19,135		$	19,162

(4) Recent Financing Transactions

In June 2017, PacifiCorp extended, with lender consent, the maturity date to June 2020 for its $400 million unsecured credit facility by exercising the first of two available one-year extensions.

These credit facilities, which support PacifiCorp's commercial paper program and certain series of its tax-exempt bond obligations and provide for the issuance of letters of credit, have a variable interest rate based on the Eurodollar rate 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. These credit facilities require 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.

(5) Employee Benefit Plans

Net periodic benefit (credit) 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,
	2017			2016			2017			2016
Pension:
Service cost	$	—		$	1		$	—		$	3
Interest cost	12			14			37			41
Expected return on plan assets	(18		)	(18		)	(54		)	(56		)
Net amortization	3			8			10			25
Net periodic benefit (credit) cost	$	(3	)	$	5		$	(7	)	$	13

Other postretirement:
Service cost	$	1		$	1		$	2		$	2
Interest cost	3			3			10			11
Expected return on plan assets	(5		)	(5		)	(16		)	(16		)
Net amortization	(1		)	(1		)	(4		)	(4		)
Net periodic benefit credit	$	(2	)	$	(2	)	$	(8	)	$	(7	)

Employer contributions to the pension and other postretirement benefit plans are expected to be $5 million and $- million, respectively, during 2017. As of September 30, 2017, $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, 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, 2017
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	4		$	1	$	2		$	—		$	7
Commodity liabilities	(1		)	—		(24		)	(82		)	(107		)
Total	3			1		(22		)	(82		)	(100		)

Total derivatives	3			1		(22		)	(82		)	(100		)
Cash collateral receivable	—			—		16			57			73
Total derivatives - net basis	$	3		$	1	$	(6	)	$	(25	)	$	(27	)

As of December 31, 2016
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	24		$	2	$	1		$	—		$	27
Commodity liabilities	(6		)	—		(14		)	(84		)	(104		)
Total	18			2		(13		)	(84		)	(77		)

Total derivatives	18			2		(13		)	(84		)	(77		)
Cash collateral receivable	—			—		10			59			69
Total derivatives - net basis	$	18		$	2	$	(3	)	$	(25	)	$	(8	)


(1)	PacifiCorp's commodity derivatives are generally included in rates and as of September 30, 2017 and December 31, 2016, a regulatory asset of $97 million and $73 million, respectively, was recorded related to the net derivative liability of $100 million and $77 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,
	2017			2016			2017			2016

Beginning balance	$	95		$	89		$	73		$	133
Changes in fair value recognized in net regulatory assets	6			15			36			(4		)
Net (losses) gains reclassified to operating revenue	(5		)	(2		)	8			8
Net gains (losses) reclassified to energy costs	1			—			(20		)	(35		)
Ending balance	$	97		$	102		$	97		$	102

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	2017		2016

Electricity sales	Megawatt hours	(3	)	(3	)
Natural gas purchases	Decatherms	97		84
Fuel oil purchases	Gallons	2		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, 2017, 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 $102 million and $97 million as of September 30, 2017 and December 31, 2016, respectively, for which PacifiCorp had posted collateral of $73 million and $69 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, 2017 and December 31, 2016, PacifiCorp would have been required to post $26 million and $22 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 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 financial 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, 2017
Assets:
Commodity derivatives	$	—	$	7		$	—	$	(3	)	$	4
Money market mutual funds⁽²⁾	100		—			—		—			100
Investment funds	20		—			—		—			20
	$	120	$	7		$	—	$	(3	)	$	124

Liabilities - Commodity derivatives	$	—	$	(107	)	$	—	$	76		$	(31	)

As of December 31, 2016
Assets:
Commodity derivatives	$	—	$	27		$	—	$	(7	)	$	20
Money market mutual funds⁽²⁾	13		—			—		—			13
Investment funds	17		—			—		—			17
	$	30	$	27		$	—	$	(7	)	$	50

Liabilities - Commodity derivatives	$	—	$	(104	)	$	—	$	76		$	(28	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $73 million and $69 million as of September 30, 2017 and December 31, 2016, 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 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, 2017				As of December 31, 2016
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	7,005	$	8,277	$	7,052	$	8,204

(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.

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. PacifiCorp 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").

Congress failed to pass legislation needed to implement the original KHSA. On April 6, 2016, PacifiCorp, the states of California and Oregon, and the United States Departments of the Interior and Commerce and other stakeholders executed an amendment to the KHSA. 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. The KRRC's license surrender 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, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. 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 are being 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 for 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

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 periods ended September 30, 2017 and 2016, PacifiCorp made net cash payments for federal and state income taxes to BHE totaling $205 million and $61 million, respectively.


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 2017 and 2016

Overview

Net income for the third quarter of 2017 was $263 million, an increase of $10 million, or 4%, compared to 2016. Net income increased primarily due to higher gross margins of $30 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense) of $21 million, partially offset by higher depreciation and amortization of $7 million, primarily from additional plant placed in-service. Gross margins increased due to higher retail customer volumes, lower coal costs, lower natural gas-fueled generation, and higher wheeling revenue, partially offset by higher purchased electricity costs, lower average retail rates and lower wholesale revenue, primarily due to lower volumes. Retail customer volumes increased 2.1% due to impacts of weather on residential customers, primarily in Utah and Oregon, higher commercial usage primarily in Oregon and Utah, and an increase in the average number of residential and commercial customers in Utah, partially offset by lower irrigation usage in Idaho and Oregon, and lower industrial usage in Utah and Oregon. Energy generated decreased 2% for the third quarter of 2017 compared to 2016 primarily due to lower natural gas-fueled and wind-powered generation, partially offset by higher hydroelectric generation. Wholesale electricity sales volumes decreased 11% and purchased electricity volumes increased 19%.

Net income for the first nine months of 2017 was $617 million, an increase of $23 million, or 4%, compared to 2016. Net income increased primarily due to higher gross margins of $71 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense) of $44 million, partially offset by higher depreciation and amortization of $22 million from additional plant placed in-service and higher property taxes of $6 million. Gross margins increased due to higher retail customer volumes, lower natural gas-fueled generation, higher wholesale revenue from higher short-term market prices and volumes, and higher wheeling revenue, partially offset by higher purchased electricity costs from higher volumes and prices, and lower average retail rates. Retail customer volumes increased 2.4% due to impacts of weather, primarily on residential customers in Oregon, Washington and Utah, higher commercial usage primarily in Oregon, an increase in the average number of residential and commercial customers, primarily in Utah and Oregon, and higher industrial usage in the eastern service territory, partially offset by lower residential usage across the service territory, lower industrial usage in Oregon and lower irrigation usage primarily in Oregon and Idaho. Energy generated decreased 2% for the first nine months of 2017 compared to 2016 primarily due to lower natural gas-fueled and wind-powered generation, partially offset by higher hydroelectric and coal generation. Wholesale electricity sales volumes decreased 3% and purchased electricity volumes increased 20%.

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
	2017		2016		Change					2017		2016		Change
Gross margin (in millions):
Operating revenue	$	1,430	$	1,434	$	(4	)	—	%	$	3,956	$	3,919	$	37		1	%
Energy costs	465		478		(13		)	(3	)%	1,305		1,295		10			1	%
Gross margin	$	965	$	956	$	9		1	%	$	2,651	$	2,624	$	27		1	%

Sales (GWh):
Residential	4,372		4,147		225			5	%	12,410		11,909		501			4	%
Commercial⁽¹⁾	4,783		4,544		239			5	%	13,303		12,863		440			3	%
Industrial, irrigation and other⁽¹⁾	5,683		5,839		(156		)	(3	)%	16,061		16,004		57			—	%
Total retail	14,838		14,530		308			2	%	41,774		40,776		998			2	%
Wholesale	1,350		1,513		(163		)	(11	)%	4,362		4,493		(131		)	(3	)%
Total sales	16,188		16,043		145			1	%	46,136		45,269		867			2	%

Average number of retail customers
(in thousands)	1,868		1,842		26			1	%	1,863		1,837		26			1	%

Average revenue per MWh:
Retail	$	90.58	$	93.10	$	(2.52	)	(3	)%	$	88.41	$	90.44	$	(2.03	)	(2	)%
Wholesale	$	28.74	$	28.32	$	0.42		1	%	$	29.55	$	25.41	$	4.14		16	%

Heating degree days	304		236		68			29	%	6,472		5,726		746			13	%
Cooling degree days	1,804		1,494		310			21	%	2,342		2,051		291			14	%

Sources of energy (GWh)⁽²⁾:
Coal	10,764		10,775		(11		)	—	%	27,120		26,637		483			2	%
Natural gas	2,486		2,743		(257		)	(9	)%	5,647		7,642		(1,995		)	(26	)%
Hydroelectric⁽³⁾	641		488		153			31	%	3,598		2,719		879			32	%
Wind and other⁽³⁾	460		647		(187		)	(29	)%	2,030		2,337		(307		)	(13	)%
Total energy generated	14,351		14,653		(302		)	(2	)%	38,395		39,335		(940		)	(2	)%
Energy purchased	3,023		2,542		481			19	%	10,845		9,031		1,814			20	%
Total	17,374		17,195		179			1	%	49,240		48,366		874			2	%

Average cost of energy per MWh:
Energy generated⁽⁴⁾	$	19.89	$	20.86	$	(0.97	)	(5	)%	$	19.21	$	19.36	$	(0.15	)	(1	)%
Energy purchased	$	53.34	$	49.68	$	3.66		7	%	$	42.20	$	43.02	$	(0.82	)	(2	)%


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


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


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


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

Gross margin increased $9 million, or 1%, for the third quarter of 2017 compared to 2016 primarily due to:


•	$38 million of higher retail revenues due to increased volumes of 2.1% due to impacts of weather and higher usage, primarily in Utah and Oregon;


•	$28 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms;


•	$22 million of lower coal costs due to prior year charges related to damaged longwall mining equipment, and current quarter lower volumes; and


•	$7 million of lower natural gas costs primarily due to lower gas-fueled generation as gas prices were higher in 2017.

The increases above were partially offset by:


•	$35 million of higher purchased electricity costs due to higher prices and volumes;


•	$22 million of lower average retail rates;


•	$21 million of lower demand side management program revenue (offset in operations and maintenance expense), primarily driven by the recently implemented Utah Sustainable Transportation and Energy Plan ("STEP") program; and


•	$9 million of higher coal prices.

Operations and maintenance decreased $24 million, or 9%, for the third quarter of 2017 compared to 2016 primarily due to a decrease in demand side management program expense (offset in operating revenue) driven by the establishment of the Utah STEP program and a decrease in pension expense primarily due to a current year plan change.

Depreciation and amortization increased $7 million, or 4%, for the third quarter of 2017 compared to 2016 primarily due to higher plant-in-service.

Income tax expense increased $16 million, or 15%, for the third quarter of 2017 compared to 2016. The effective tax rate was 32% for 2017 and 30% for 2016. The effective tax rate increased primarily due to lower production tax credits associated with PacifiCorp's wind-powered generating facilities as a result of the expiration of the 10-year production tax credit period for certain wind-powered generating facilities.

Gross margin increased $27 million, or 1%, for the first nine months of 2017 compared to 2016 primarily due to:

•

$102 million of higher retail revenues due to increased customer volumes of 2.4% due to impacts of weather, primarily on residential customers in Oregon, Washington and Utah, higher commercial usage primarily in Oregon, an increase in the average number of residential and commercial customers, primarily in Utah and Oregon, and higher industrial usage in the eastern service territory, partially offset by lower residential usage across the service territory, lower industrial usage in Oregon and lower irrigation usage primarily in Oregon and Idaho;


•	$36 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms;


•	$28 million of lower natural gas costs primarily due to lower gas-fueled generation due to higher gas prices in 2017;


•	$20 million of lower coal costs due to prior year charges related to damaged longwall mining equipment;


•	$15 million of higher wholesale revenue due to higher short-term market prices and higher volumes; and


•	$13 million due to higher wheeling revenue, primarily due to higher volumes and short-term prices.

The increases above were partially offset by:


•	$69 million of higher purchased electricity costs due to volumes and prices;


•	$49 million of lower average retail rates;


•	$44 million of lower demand side management program revenue (offset in operations and maintenance expense), primarily driven by the recently implemented Utah STEP program; and


•	$24 million of higher coal costs due to higher prices and volumes.

Operations and maintenance decreased $46 million, or 6%, for the first nine months of 2017 compared to 2016 primarily due to a decrease in demand side management program expense (offset in operating revenue) driven by the establishment of the Utah STEP program, and a decrease in pension expense primarily due to a current year plan change. These decreases were partially offset by higher injury and damage expenses, primarily due to a prior year accrual for insurance proceeds, and higher labor costs related to storm damage restoration.

Depreciation and amortization increased $22 million, or 4%, for the first nine months of 2017 compared to 2016 primarily due to higher plant-in-service.

Taxes, other than income taxes increased $8 million, or 6% for the first nine months of 2017 compared to 2016 due to higher assessed property values.

Income tax expense increased $24 million, or 9%, for the first nine months of 2017 compared to 2016 and the effective tax rate was 32% and 31% for 2017 and 2016, respectively. The effective tax rate increased primarily due to lower production tax credits associated with PacifiCorp's wind-powered generating facilities as a result of the expiration of the 10-year production tax credit period for certain wind-powered generating facilities.

Liquidity and Capital Resources

As of September 30, 2017, PacifiCorp's total net liquidity was as follows (in millions):



Cash and cash equivalents	$	104

Credit facilities	1,000
Less:
Short-term debt	—
Tax-exempt bond support	(130		)
Net credit facilities	870

Total net liquidity	$	974

Credit facilities:
Maturity dates	2020

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2017 and 2016 were $1,435 million and $1,372 million, respectively. The change was primarily due to the payment for USA Power final judgment and post-judgment interest in the prior year, higher receipts from wholesale and retail customers and lower fuel payments, partially offset by current year higher cash payments for income taxes and purchased power.

The timing of PacifiCorp'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.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2017 and 2016 were $(521) million and $(560) million, respectively. The change mainly reflects a current year decrease in capital expenditures of $33 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, 2017 was $(827) million. Uses of cash consisted substantially of $500 million for common stock dividends paid to PPW Holdings LLC, $270 million for the repayment of short-term debt and $50 million for the repayment of long-term debt.

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.

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of September 30, 2017, PacifiCorp had no short-term debt outstanding. As of December 31, 2016, PacifiCorp had $270 million of short-term debt outstanding at a weighted average interest rate of 0.96%.

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.

As of September 30, 2017, PacifiCorp had $216 million of letters of credit providing credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling $213 million plus interest. These letters of credit were fully available as of September 30, 2017 and expire periodically through March 2019.

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
	2016		2017		2017

Transmission system investment	$	68	$	75	$	118
Environmental	42		18		28
Wind investment	—		8		8
Operating and other	476		452		644
Total	$	586	$	553	$	798

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


•	Transmission system investment primarily reflects main grid reinforcement costs and initial costs for the 140-mile 500 kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp’s Energy Gateway Transmission expansion program expected to be placed in-service in 2020. Planned spending for the Aeolus-Bridger/Anticline line totals $16 million in 2017.

•

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, including upgrades to customer meters in Oregon, California and Idaho.

Integrated Resource Plan

In April 2017, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP") with its state commissions. The IRP includes investments in renewable energy resources, upgrades to the existing wind fleet, and energy efficiency measures to meet future customer needs. Implementation of wind upgrades, new transmission and new wind renewable resources will require an estimated $3 billion in capital investment from 2017 through 2020. PacifiCorp's forecast capital expenditures for 2018 through 2019 increased $723 million from the forecast included in PacifiCorp's 2016 Annual Report on Form 10-K as a result of its 2017 IRP.

Request for Proposals

As required by applicable laws and regulations, PacifiCorp filed its draft 2017R Request for Proposals ("RFP") with the UPSC in June 2017 and with the OPUC in August 2017. The UPSC and the OPUC approved PacifiCorp’s 2017R RFP in September 2017. The 2017R RFP was subsequently released to the market on September 27, 2017. The 2017R RFP is seeking up to 1,270 MW of new wind resources that can interconnect to PacifiCorp’s transmission system in Wyoming once a proposed high-voltage transmission line is constructed. The 2017R RFP is also seeking proposals for wind resources located outside of Wyoming capable of delivering all-in economic benefits for PacifiCorp's customers. The proposed high-voltage transmission line and new wind resources must be placed in service by December 31, 2020, to maximize potential federal production tax credit benefits for PacifiCorp's customers. Bids were due in October 2017.

Contractual Obligations

As of September 30, 2017, 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, 2016.

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, local and foreign laws and regulations regarding air and water quality, RPS, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp'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. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. 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 financial results. 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, 2016. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2016.

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, 2017, and the related statements of operations for the three-month and nine-month periods ended September 30, 2017 and 2016, and of changes in equity and cash flows for the nine-month periods ended September 30, 2017 and 2016. 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, 2016, and the related statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 3, 2017

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	September 30,		December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	512	$	14
Receivables, net	312		285
Income taxes receivable	—		9
Inventories	235		264
Other current assets	21		35
Total current assets	1,080		607

Property, plant and equipment, net	13,587		12,821
Regulatory assets	1,335		1,161
Investments and restricted cash and investments	707		653
Other assets	193		217

Total assets	$	16,902	$	15,459

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,
	2017		2016
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	256	$	303
Accrued interest	52		45
Accrued property, income and other taxes	228		137
Short-term debt	—		99
Current portion of long-term debt	350		250
Other current liabilities	158		159
Total current liabilities	1,044		993

Long-term debt	4,544		4,051
Deferred income taxes	3,781		3,572
Regulatory liabilities	927		883
Asset retirement obligations	515		510
Other long-term liabilities	307		290
Total liabilities	11,118		10,299

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—		—
Additional paid-in capital	561		561
Retained earnings	5,223		4,599
Total shareholder's equity	5,784		5,160

Total liabilities and shareholder's equity	$	16,902	$	15,459

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,
	2017			2016			2017			2016
Operating revenue:
Regulated electric	$	707		$	692		$	1,677		$	1,572
Regulated gas and other	106			103			489			432
Total operating revenue	813			795			2,166			2,004

Operating costs and expenses:
Cost of fuel, energy and capacity	130			130			342			312
Cost of gas sold and other	54			55			288			237
Operations and maintenance	200			180			547			510
Depreciation and amortization	111			118			369			338
Property and other taxes	30			28			90			84
Total operating costs and expenses	525			511			1,636			1,481

Operating income	288			284			530			523

Other income (expense):
Interest expense	(54		)	(50		)	(160		)	(147		)
Allowance for borrowed funds	4			3			9			6
Allowance for equity funds	11			6			25			14
Other, net	5			3			13			8
Total other income (expense)	(34		)	(38		)	(113		)	(119		)

Income before income tax benefit	254			246			417			404
Income tax benefit	(131		)	(74		)	(207		)	(123		)

Net income	$	385		$	320		$	624		$	527

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

Balance, December 31, 2016	$	561	$	4,599		$	—		$	5,160
Net income	—		624			—			624
Balance, September 30, 2017	$	561	$	5,223		$	—		$	5,784

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,
	2017			2016
Cash flows from operating activities:
Net income	$	624		$	527
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	369			338
Deferred income taxes and amortization of investment tax credits	64			113
Changes in other assets and liabilities	28			34
Other, net	(23		)	(42		)
Changes in other operating assets and liabilities:
Receivables, net	(28		)	(67		)
Inventories	29			(26		)
Derivative collateral, net	3			4
Contributions to pension and other postretirement benefit plans, net	(8		)	(5		)
Accounts payable	(5		)	14
Accrued property, income and other taxes, net	98			160
Other current assets and liabilities	20			30
Net cash flows from operating activities	1,171			1,080

Cash flows from investing activities:
Utility construction expenditures	(1,162		)	(1,129		)
Purchases of available-for-sale securities	(126		)	(96		)
Proceeds from sales of available-for-sale securities	127			92
Other, net	—			5
Net cash flows from investing activities	(1,161		)	(1,128		)

Cash flows from financing activities:
Proceeds from long-term debt	842			33
Repayments of long-term debt	(255		)	(38		)
Net repayments of short-term debt	(99		)	—
Net cash flows from financing activities	488			(5		)

Net change in cash and cash equivalents	498			(53		)
Cash and cash equivalents at beginning of period	14			103
Cash and cash equivalents at end of period	$	512		$	50

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, 2017, and for the three- and nine-month periods ended September 30, 2017 and 2016. The results of operations for the three- and nine-month periods ended September 30, 2017, 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, 2016, 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, 2017.


(2)	New Accounting Pronouncements

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

In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents must be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy plans to adopt this guidance effective January 1, 2018, and does not believe the adoption of this guidance will have a material impact on its Financial Statements and disclosures included within Notes to Financial Statements. In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy plans to adopt this guidance effective January 1, 2018, and does not believe the adoption of this guidance will have a material impact 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 plans to adopt this guidance effective January 1, 2019, and is currently evaluating the impact 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. MidAmerican Energy does not believe this guidance will have a material impact 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 and 2017, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. MidAmerican Energy plans to adopt this guidance effective January 1, 2018 under the modified retrospective method and is currently evaluating the impact on its Financial Statements and disclosures included within Notes to Financial Statements. MidAmerican Energy currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when MidAmerican Energy has the right to invoice as it corresponds directly with the value to the customer of MidAmerican Energy’s performance to date. MidAmerican Energy's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by jurisdiction for each segment.


(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	2017			2016
Utility plant in service, net:
Generation	20-70 years	$	11,339		$	11,282
Transmission	52-75 years	1,802			1,726
Electric distribution	20-75 years	3,297			3,197
Gas distribution	29-75 years	1,606			1,565
Utility plant in service		18,044			17,770
Accumulated depreciation and amortization		(5,765		)	(5,448		)
Utility plant in service, net		12,279			12,322
Nonregulated property, net:
Nonregulated property gross	20-50 years	7			7
Accumulated depreciation and amortization		(1		)	(1		)
Nonregulated property, net		6			6
		12,285			12,328
Construction work-in-progress		1,302			493
Property, plant and equipment, net		$	13,587		$	12,821

(4) Recent Financing Transactions

Long-Term Debt

In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.

Credit Facilities

(5) 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 is as follows:



	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2017		2016		2017		2016

Federal statutory income tax rate	35	%	35	%	35	%	35	%
Income tax credits	(74	)	(58	)	(74	)	(58	)
State income tax, net of federal income tax benefit	(10	)	(6	)	(7	)	(4	)
Effects of ratemaking	(2	)	(1	)	(4	)	(3	)
Other, net	(1	)	—		—		—
Effective income tax rate	(52	)%	(30	)%	(50	)%	(30	)%

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 $381 million and $416 million for the nine-month periods ended September 30, 2017 and 2016, respectively.


(6)	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 (credit) cost 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,
	2017			2016			2017			2016
Pension:
Service cost	$	2		$	3		$	7		$	8
Interest cost	8			8			23			25
Expected return on plan assets	(11		)	(11		)	(33		)	(33		)
Net amortization	—			—			1			1
Net periodic benefit (credit) cost	$	(1	)	$	—		$	(2	)	$	1

Other postretirement:
Service cost	$	2		$	1		$	4		$	4
Interest cost	3			2			7			7
Expected return on plan assets	(3		)	(3		)	(10		)	(10		)
Net amortization	(1		)	(1		)	(3		)	(3		)
Net periodic benefit cost (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 2017. As of September 30, 2017, $5 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.


(7)	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 financial 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, 2017:
Assets:
Commodity derivatives	$	—	$	2		$	2		$	(2	)	$	2
Money market mutual funds⁽²⁾	520		—			—			—			520
Debt securities:
United States government obligations	168		—			—			—			168
International government obligations	—		5			—			—			5
Corporate obligations	—		37			—			—			37
Municipal obligations	—		2			—			—			2
Agency, asset and mortgage-backed obligations	—		1			—			—			1
Equity securities:
United States companies	270		—			—			—			270
International companies	7		—			—			—			7
Investment funds	15		—			—			—			15
	$	980	$	47		$	2		$	(2	)	$	1,027

Liabilities - commodity derivatives	$	—	$	(6	)	$	(4	)	$	2		$	(8	)



	Input Levels for Fair Value Measurements
	Level 1		Level 2			Level 3			Other⁽¹⁾			Total
As of December 31, 2016:
Assets:
Commodity derivatives	$	—	$	9		$	1		$	(2	)	$	8
Money market mutual funds⁽²⁾	1		—			—			—			1
Debt securities:
United States government obligations	161		—			—			—			161
International government obligations	—		3			—			—			3
Corporate obligations	—		36			—			—			36
Municipal obligations	—		2			—			—			2
Agency, asset and mortgage-backed obligations	—		2			—			—			2
Equity securities:
United States companies	250		—			—			—			250
International companies	5		—			—			—			5
Investment funds	9		—			—			—			9
	$	426	$	52		$	1		$	(2	)	$	477

Liabilities - commodity derivatives	$	—	$	(3	)	$	(3	)	$	3		$	(3	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $- million and $1 million as of September 30, 2017 and December 31, 2016, 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.

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 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
2017:
Beginning balance	$	(1	)	$	—	$	(2	)	$	—
Changes in fair value recognized in net regulatory assets	(2		)	—		(2		)	—
Settlements	1			—		2			—
Ending balance	$	(2	)	$	—	$	(2	)	$	—

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

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

Long-term debt	$	4,894	$	5,446	$	4,301	$	4,735

(8) Commitments and Contingencies

Natural Gas Commitments

Construction Commitments

Easements

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. Customer refunds relative to the first complaint occurred in February 2017. It is uncertain when the FERC will rule on the second complaint, 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, as of September 30, 2017, has accrued a $9 million liability for refunds under the second complaint of amounts collected under the higher ROE from February 2015 through May 2016.


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

The following table shows the change in accumulated other comprehensive income (loss), net 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, 2015	$	(3	)	$	(27	)	$	(30	)
Other comprehensive income	2			—			2
Dividend	—			27			27
Balance at September 30, 2016	$	(1	)	$	—		$	(1	)


(10)	Segment Information

MidAmerican Energy has identified two reportable segments: regulated electric and regulated gas. 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.

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



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2017		2016
Operating revenue:
Regulated electric	$	707		$	692		$	1,677	$	1,572
Regulated gas	103			102			485		430
Other	3			1			4		2
Total operating revenue	$	813		$	795		$	2,166	$	2,004

Depreciation and amortization:
Regulated electric	$	101		$	107		$	338	$	306
Regulated gas	10			11			31		32
Total depreciation and amortization	$	111		$	118		$	369	$	338

Operating income:
Regulated electric	$	290		$	289		$	485	$	481
Regulated gas	(2		)	(5		)	45		42
Total operating income	$	288		$	284		$	530	$	523



	As of
	September 30, 2017		December 31, 2016
Assets:
Regulated electric	$	15,556	$	14,113
Regulated gas	1,339		1,345
Other	7		1
Total assets	$	16,902	$	15,459

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, 2017, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2017 and 2016, and of changes in equity and cash flows for the nine-month periods ended September 30, 2017 and 2016. These interim financial statements are the responsibility of MidAmerican Funding's management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States) and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. 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) and with auditing standards generally accepted in the United States of America, 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.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

November 3, 2017

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	September 30,		December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	512	$	15
Receivables, net	318		287
Income taxes receivable	—		9
Inventories	235		264
Other current assets	21		35
Total current assets	1,086		610

Property, plant and equipment, net	13,602		12,835
Goodwill	1,270		1,270
Regulatory assets	1,335		1,161
Investments and restricted cash and investments	709		655
Other assets	194		216

Total assets	$	18,196	$	16,747

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,
	2017		2016
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	256	$	302
Accrued interest	54		52
Accrued property, income and other taxes	227		138
Note payable to affiliate	52		31
Short-term debt	—		99
Current portion of long-term debt	350		250
Other current liabilities	159		160
Total current liabilities	1,098		1,032

Long-term debt	4,870		4,377
Deferred income taxes	3,777		3,568
Regulatory liabilities	927		883
Asset retirement obligations	515		510
Other long-term liabilities	307		291
Total liabilities	11,494		10,661

Commitments and contingencies (Note 8)

Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	5,023		4,407
Total member's equity	6,702		6,086

Total liabilities and member's equity	$	18,196	$	16,747

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,
	2017			2016			2017			2016
Operating revenue:
Regulated electric	$	707		$	692		$	1,677		$	1,572
Regulated gas and other	108			105			493			436
Total operating revenue	815			797			2,170			2,008

Operating costs and expenses:
Cost of fuel, energy and capacity	130			130			342			312
Cost of gas sold and other	54			56			289			239
Operations and maintenance	202			181			549			511
Depreciation and amortization	111			118			369			338
Property and other taxes	30			28			90			84
Total operating costs and expenses	527			513			1,639			1,484

Operating income	288			284			531			524

Other income (expense):
Interest expense	(59		)	(55		)	(177		)	(164		)
Allowance for borrowed funds	4			3			9			6
Allowance for equity funds	11			6			25			14
Other, net	6			3			14			9
Total other income (expense)	(38		)	(43		)	(129		)	(135		)

Income before income tax benefit	250			241			402			389
Income tax benefit	(133		)	(77		)	(214		)	(129		)

Net income	$	383		$	318		$	616		$	518

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

Balance, December 31, 2016	$	1,679	$	4,407		$	—		$	6,086
Net income	—		616			—			616
Balance, September 30, 2017	$	1,679	$	5,023		$	—		$	6,702

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,
	2017			2016
Cash flows from operating activities:
Net income	$	616		$	518
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	369			338
Deferred income taxes and amortization of investment tax credits	64			113
Changes in other assets and liabilities	28			34
Other, net	(24		)	(42		)
Changes in other operating assets and liabilities:
Receivables, net	(31		)	(67		)
Inventories	29			(26		)
Derivative collateral, net	3			4
Contributions to pension and other postretirement benefit plans, net	(8		)	(5		)
Accounts payable	(4		)	14
Accrued property, income and other taxes, net	96			160
Other current assets and liabilities	14			24
Net cash flows from operating activities	1,152			1,065

Cash flows from investing activities:
Utility construction expenditures	(1,162		)	(1,129		)
Purchases of available-for-sale securities	(126		)	(96		)
Proceeds from sales of available-for-sale securities	127			92
Other, net	(3		)	5
Net cash flows from investing activities	(1,164		)	(1,128		)

Cash flows from financing activities:
Proceeds from long-term debt	842			33
Repayments of long-term debt	(255		)	(38		)
Net change in note payable to affiliate	21			16
Net repayments of short-term debt	(99		)	—
Net cash flows from financing activities	509			11

Net change in cash and cash equivalents	497			(52		)
Cash and cash equivalents at beginning of period	15			103
Cash and cash equivalents at end of period	$	512		$	51

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, 2017, and for the three- and nine-month periods ended September 30, 2017 and 2016. The results of operations for the three- and nine-month periods ended September 30, 2017, 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, 2016, 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, 2017.


(2)	New Accounting Pronouncements

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


(3)	Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had as of September 30, 2017 and December 31, 2016, nonregulated property gross of $25 million and $22 million, respectively, related accumulated depreciation and amortization of $10 million and $9 million, respectively, and construction work-in-progress of $- million and $1 million, respectively, which consisted primarily of a corporate aircraft owned by MHC.

(4) Recent Financing Transactions

Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.


(5)	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 is as follows:



	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2017		2016		2017		2016

Federal statutory income tax rate	35	%	35	%	35	%	35	%
Income tax credits	(76	)	(60	)	(76	)	(61	)
State income tax, net of federal income tax benefit	(10	)	(7	)	(8	)	(4	)
Effects of ratemaking	(2	)	—		(4	)	(3	)
Effective income tax rate	(53	)%	(32	)%	(53	)%	(33	)%

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 $386 million and $422 million for the nine-month periods ended September 30, 2017 and 2016, respectively.


(6)	Employee Benefit Plans

Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.


(7)	Fair Value Measurements

Refer to Note 7 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, 2017				As of December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	5,220	$	5,873	$	4,627	$	5,164

(8) 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 8 of MidAmerican Energy's Notes to Financial Statements.

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

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

(10) Segment Information

MidAmerican Funding has identified two reportable segments: regulated electric and regulated gas. 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,
	2017			2016			2017		2016
Operating revenue:
Regulated electric	$	707		$	692		$	1,677	$	1,572
Regulated gas	103			102			485		430
Other	5			3			8		6
Total operating revenue	$	815		$	797		$	2,170	$	2,008

Depreciation and amortization:
Regulated electric	$	101		$	107		$	338	$	306
Regulated gas	10			11			31		32
Total depreciation and amortization	$	111		$	118		$	369	$	338

Operating income:
Regulated electric	$	290		$	289		$	485	$	481
Regulated gas	(2		)	(5		)	45		42
Other	—			—			1		1
Total operating income	$	288		$	284		$	531	$	524



	As of
	September 30, 2017		December 31, 2016
Assets⁽¹⁾:
Regulated electric	$	16,747	$	15,304
Regulated gas	1,418		1,424
Other	31		19
Total assets	$	18,196	$	16,747



(1)	Assets by reportable segment reflect the assignment of goodwill to applicable reporting units.


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. 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 2017 and 2016

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the third quarter of 2017 was $385 million, an increase of $65 million, or 20%, compared to 2016 due to higher recognized production tax credits of $45 million, higher margins of $11 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense), lower depreciation and amortization of $7 million, substantially from changes in accruals for Iowa regulatory arrangements, and higher allowance for borrowed and equity funds of $6 million, partially offset by higher operations and maintenance expenses, primarily from higher generating facility maintenance, including additional wind turbines. The increase in electric margins of $7 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense), reflects higher recoveries through bill riders, higher transmission revenue and higher retail customer volumes from industrial growth net of lower residential and commercial volumes due to milder temperatures, partially offset by lower wholesale revenue from lower sales volumes and prices.

MidAmerican Energy's net income for the first nine months of 2017 was $624 million, an increase of $97 million, or 18%, compared to 2016 primarily due to higher margins of $64 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense), higher recognized production tax credits of $71 million and higher allowance for borrowed and equity funds of $14 million, partially offset by higher operations and maintenance expenses of $21 million, primarily from higher maintenance from additional wind turbines, and higher depreciation and amortization of $31 million from accruals for Iowa regulatory arrangements and wind-powered generating facilities placed in-service in the second half of 2016, net of a reduction in depreciation rates in December 2016. The increase in electric margins of $60 million, excluding the impact of demand side management program revenue (offset in operations and maintenance expense), reflects higher recoveries through bill riders, higher wholesale revenue from higher sales volumes and prices, higher transmission revenue and higher retail customer volumes from industrial growth, net of lower residential and commercial volumes due to milder temperatures, partially offset by higher coal-fueled generation and purchased power costs.

MidAmerican Funding -

MidAmerican Funding's net income for the third quarter of 2017 was $383 million, an increase of $65 million, or 20%, compared to 2016. MidAmerican Funding's net income for the first nine months of 2017 was $616 million, an increase of $98 million, or 19%, compared to 2016.The increases were primarily due to the changes in MidAmerican Energy's earnings discussed above.

100

Regulated Electric Gross Margin

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



	Third Quarter									First Nine Months
	2017		2016		Change					2017		2016		Change
Gross margin (in millions):
Operating revenue	$	707	$	692	$	15		2	%	$	1,677	$	1,572	$	105		7	%
Cost of fuel, energy and capacity	130		130		—			—		342		312		30			10
Gross margin	$	577	$	562	$	15		3		$	1,335	$	1,260	$	75		6

Electricity Sales (GWh):
Residential	1,790		1,969		(179		)	(9	)%	4,753		5,018		(265		)	(5	)%
Commercial	987		1,023		(36		)	(4	)	2,796		2,859		(63		)	(2	)
Industrial	3,366		3,106		260			8		9,621		8,999		622			7
Other	411		427		(16		)	(4	)	1,185		1,213		(28		)	(2	)
Total retail	6,554		6,525		29			—		18,355		18,089		266			1
Wholesale	1,571		2,037		(466		)	(23	)	7,162		5,620		1,542			27
Total sales	8,125		8,562		(437		)	(5	)	25,517		23,709		1,808			8

Average number of retail customers (in thousands)	771		761		10			1	%	769		759		10			1	%

Average revenue per MWh:
Retail	$	98.15	$	94.02	$	4.13		4	%	$	78.62	$	76.75	$	1.87		2	%
Wholesale	$	25.57	$	28.13	$	(2.56	)	(9	)%	$	23.90	$	22.84	$	1.06		5	%

Heating degree days	44		27		17			63	%	3,203		3,388		(185		)	(5	)%
Cooling degree days	752		855		(103		)	(12	)%	1,098		1,284		(186		)	(14	)%

Sources of energy (GWh)⁽¹⁾:
Coal	4,354		4,618		(264		)	(6	)%	11,019		9,907		1,112			11	%
Nuclear	961		1,003		(42		)	(4	)	2,820		2,887		(67		)	(2	)
Natural gas	257		307		(50		)	(16	)	274		515		(241		)	(47)
Wind and other⁽²⁾	1,929		1,950		(21		)	(1	)	9,129		7,981		1,148			14
Total energy generated	7,501		7,878		(377		)	(5	)	23,242		21,290		1,952			9
Energy purchased	812		916		(104		)	(11	)	2,756		3,030		(274		)	(9	)
Total	8,313		8,794		(481		)	(5	)	25,998		24,320		1,678			7


(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.

101

Regulated electric gross margin increased $15 million for the third quarter of 2017 compared to 2016 primarily due to:


(1)	Higher retail gross margin of $16 million due to -


•	an increase of $38 million from higher recoveries through bill riders;


•	an increase of $3 million from non-weather-related usage factors, including higher industrial sales volumes;


•	a decrease of $12 million from the impact of milder temperatures; and


•	a decrease of $13 million from higher retail energy costs primarily due to higher coal-fueled generation and higher purchased power costs;


(2)	Higher Multi-Value Projects ("MVPs") transmission revenue of $6 million due to continued capital additions; and


(3)	Lower wholesale gross margin of $7 million due to lower margins per unit from lower market prices and lower sales volumes.

Regulated electric gross margin increased $75 million for the first nine months of 2017 compared to 2016 primarily due to:


(1)	Higher wholesale gross margin of $37 million primarily due to higher margins per unit from higher market prices and higher sales volumes enabled by greater availability of lower cost generation;


(2)	Higher retail gross margin of $25 million due to -


•	an increase of $47 million from higher recoveries through bill riders;


•	an increase of $28 million from non-weather-related usage factors, including higher industrial sales volumes;


•	a decrease of $25 million from higher retail energy costs primarily due to higher coal-fueled generation and higher purchased power costs; and


•	a decrease of $25 million from the impact of milder temperatures; and


(3)	Higher MVPs transmission revenue of $11 million due to continued capital additions.

102

Regulated Gas Gross Margin

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



	Third Quarter									First Nine Months
	2017		2016		Change					2017		2016		Change
Gross margin (in millions):
Operating revenue	$	103	$	102	$	1		1	%	$	485	$	430	$	55		13	%
Cost of gas sold	54		54		—			—		288		236		52			22
Gross margin	$	49	$	48	$	1		2		$	197	$	194	$	3		2

Natural gas throughput (000's Dth):
Residential	2,773		2,820		(47		)	(2)	%	29,442		31,121		(1,679		)	(5)	%
Commercial	1,788		1,840		(52		)	(3	)	14,797		15,729		(932		)	(6	)
Industrial	717		922		(205		)	(22	)	3,070		3,574		(504		)	(14	)
Other	2		1		1			100		29		26		3			12
Total retail sales	5,280		5,583		(303		)	(5	)	47,338		50,450		(3,112		)	(6	)
Wholesale sales	8,815		8,568		247			3		29,111		28,615		496			2
Total sales	14,095		14,151		(56		)	—		76,449		79,065		(2,616		)	(3	)
Gas transportation service	19,784		18,087		1,697			9		65,431		60,117		5,314			9
Total gas throughput	33,879		32,238		1,641			5		141,880		139,182		2,698			2

Average number of retail customers (in thousands)	746		738		8			1	%	747		738		9			1	%
Average revenue per retail Dth sold	$	13.33	$	12.77	$	0.56		4	%	$	7.93	$	6.80	$	1.13		17	%
Average cost of natural gas per retail Dth sold	$	5.56	$	5.49	$	0.07		1	%	$	4.33	$	3.45	$	0.88		26	%

Combined retail and wholesale average cost of natural gas per Dth sold	$	3.82	$	3.82	$	—		—	%	$	3.76	$	2.99	$	0.77		26	%

Heating degree days	45		27		18			67	%	3,406		3,572		(166		)	(5)	%

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 first nine months of 2017, MidAmerican Energy's combined retail and wholesale average per-unit cost of gas sold increased 26%, resulting in an increase of $59 million in gas revenue and cost of gas sold compared to 2016, partially offset by lower gas sales volumes.

Regulated gas gross margin increased $1 million for the third quarter of 2017 compared to 2016 due to higher recoveries of demand side management program revenue (offset in operations and maintenance expense).

Regulated gas gross margin increased $3 million for the first nine months of 2017 compared to 2016 primarily due to -


(1)	higher recoveries of demand side management program revenue (offset in operations and maintenance expense) of $2 million;


(2)	a higher average per-unit margin of $2 million;


(3)	higher gas transportation throughput of $1 million, and


(4)	lower retail sales volumes of $3 million from warmer winter temperatures.

103

Operating Costs and Expenses

MidAmerican Energy -

Operations and maintenance increased $20 million for the third quarter of 2017 compared to 2016 primarily due to higher demand side management program expense (offset in operating revenue) of $8 million, higher wind-powered generation maintenance from additional wind turbines of $6 million and higher coal-fueled and nuclear generation maintenance of $4 million.

Operations and maintenance increased $37 million for the first nine months of 2017 compared to 2016 primarily due to higher demand side management program expense (offset in operating revenue) of $17 million, higher wind-powered generation maintenance from additional wind turbines of $13 million and higher coal-fueled and nuclear generation maintenance of $4 million.

Depreciation and amortization decreased $7 million for the third quarter of 2017 compared to 2016 due to lower accruals for Iowa regulatory arrangements of $9 million and $9 million from lower depreciation rates implemented in December 2016, partially offset by utility plant additions, including wind-powered generating facilities placed in-service in the second half of 2016.

Depreciation and amortization increased $31 million for the first nine months of 2017 compared to 2016 due to utility plant additions, including wind-powered generating facilities placed in-service in the second half of 2016, accruals for Iowa regulatory arrangements of $26 million, partially offset by $26 million from lower depreciation rates implemented in December 2016.

Property and other taxes increased $2 million and $6 million for the third quarter and first nine months of 2017 compared to 2016 primarily due to higher Iowa utility property replacement taxes.

Other Income (Expense)

MidAmerican Energy -

Interest expense increased $4 million and $13 million for the third quarter and first nine months of 2017, respectively, compared to 2016 due to higher interest expense from the issuance of $850 million of first mortgage bonds in February 2017, partially offset by the redemption of a $250 million of 5.95% Senior Notes in February 2017.

Allowance for borrowed and equity funds increased $6 million and $14 million for the third quarter and first nine months of 2017, respectively, compared to 2016 primarily due to higher construction work-in-progress balances related to wind-powered generation.

Other, net increased $2 million and $5 million for the third quarter and first nine months of 2017, respectively, compared to 2016 primarily due to higher returns on corporate-owned life insurance policies.

Income Tax Benefit

MidAmerican Energy -

MidAmerican Energy's income tax benefit increased $57 million for the third quarter of 2017 compared to 2016, and the effective tax rate was (52)% for 2017 and (30)% for 2016. For the first nine months of 2017 compared to 2016, MidAmerican Energy's income tax benefit increased $84 million, and the effective tax rate was (50)% for 2017 and (30)% for 2016. The changes in the effective tax rates for 2017 compared to 2016 were substantially due to an increase in recognized production tax credits and the effects of ratemaking.

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 first nine months of 2017 were $306 million, or $71 million higher than the first nine months of 2016, while production tax credits earned in the first nine months of 2017 were $200 million, or $29 million higher than the first nine months of 2016 primarily due to wind-powered generation placed in-service in late 2016. The excess of production tax credits recognized over earned of $106 million as of September 30, 2017, will reduce earnings over the remainder of 2017.

104

MidAmerican Funding -

MidAmerican Funding's income tax benefit increased $56 million for the third quarter of 2017 compared to 2016, and the effective tax rate was (53)% for 2017 and (32)% for 2016. MidAmerican Funding's income tax benefit increased $85 million for the first nine months of 2017 compared to 2016, and the effective tax rate was (53)% for 2017 and (33)% for 2016.The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.

Liquidity and Capital Resources

As of September 30, 2017, MidAmerican Energy's total net liquidity was $1,197 million consisting of $512 million of cash and cash equivalents and $905 million of credit facilities reduced by $220 million of the credit facilities reserved to support MidAmerican Energy's variable-rate tax-exempt bond obligations. As of September 30, 2017, MidAmerican Funding's total net liquidity was $1,201 million, including 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, 2017 and 2016, were $1,171 million and $1,080 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2017 and 2016, were $1,152 million and $1,065 million, respectively. Cash flows from operating activities increased primarily due to higher cash gross margins for MidAmerican Energy's regulated electric business, including fuel inventory reductions, partially offset by the timing of MidAmerican Energy's income tax cash flows with BHE. MidAmerican Energy's income tax cash flows with BHE totaled net cash receipts from BHE of $381 million and $416 million, respectively. Income tax cash flows for 2016 reflect the receipt of $106 million of income tax benefits generated in 2015. 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 projects for which construction begins before the end of the respective year as follows: at full value for 2016, at 80% of value for 2017, at 60% of value for 2018, and 40% of 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, 2017 and 2016, were $(1,161) million and $(1,128) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2017 and 2016, were $(1,164) million and $(1,128) million, respectively. Net cash flows from investing activities consist almost entirely of utility construction expenditures, which increased due to higher environmental and other operating construction expenditures. Purchases and proceeds related to available-for-sale securities primarily consist of activity within the Quad Cities Generating Station nuclear decommissioning trust.

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the nine-month periods ended September 30, 2017 and 2016 were $488 million and $(5) million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2017 and 2016, were $509 million and $11 million, respectively. In February 2017, MidAmerican Energy issued $375 million of its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95% First Mortgage Bonds due August 2047. An amount equal to the net proceeds was used to finance capital expenditures disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds. In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017. In January 2016, MidAmerican Energy repaid $4 million of variable-rate tax-exempt pollution control refunding revenue bonds due January 2016. Through its commercial paper program, MidAmerican Energy made payments totaling $99 million in 2017. MidAmerican Funding received $21 million and $16 million in 2017 and 2016, respectively, through its note payable with BHE.

105

Debt Authorizations and Related Matters

MidAmerican Energy has authority from the FERC to issue through February 28, 2019, commercial paper and bank notes aggregating $905 million at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of up to 400 basis points. MidAmerican Energy has a $900 million unsecured credit facility expiring in June 2020. 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 the Eurodollar rate 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. MidAmerican Energy has authorization from the FERC to issue, through August 31, 2019, preferred stock up to an aggregate of $500 million and long-term debt securities up to an aggregate of $2.4 billion at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points. Additionally, MidAmerican Energy has authorization from the Illinois Commerce Commission to issue preferred stock up to an aggregate of $500 million through November 1, 2020 and additional long-term debt securities up to an aggregate of $2.4 billion of additional long-term debt securities, of which $350 million expires March 15, 2018, $150 million expires September 22, 2018, $500 million expires March 15, 2019 and $1.4 billion expires November 1, 2020.

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, 2017, 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.

106

MidAmerican Energy'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
	2016		2017		2017

Wind-powered generation	$	732	$	455	$	709
Wind-powered generation repowering	—		272		496
Transmission Multi-Value Projects	73		18		25
Other	324		417		773
Total	$	1,129	$	1,162	$	2,003

MidAmerican Energy's forecast utility construction expenditures for 2017 include the following:

•

The construction of 2,000 MW (nominal ratings) of wind-powered generating facilities expected to be placed in-service in 2017 through 2019. 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 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. Each of these projects is expected to qualify for 100% of production tax credits currently available.

•

The repowering of certain existing wind-powered generating facilities in Iowa. This project entails the replacement of significant components of the oldest turbines in MidAmerican Energy’s fleet. The energy production from such repowered facilities is expected to qualify for 100% of the federal production tax credits available for ten years following completion. Under MidAmerican Energy's Iowa electric tariff, federal production tax credits related to facilities that were in-service prior to 2013 must be included in its Iowa energy adjustment clause. In August 2017, the IUB approved a tariff change that excludes from MidAmerican Energy's Iowa energy adjustment clause any future federal production tax credits related to these repowered facilities.


•	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, when complete, will have added approximately 250 miles of 345 kV transmission line to MidAmerican Energy's transmission system since 2012.


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

Contractual Obligations

As of September 30, 2017, 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, 2016.

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.

107

Quad Cities Generating Station Operating Status

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.

108

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, 2016. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2016.

109

Nevada Power Company and its subsidiaries

Consolidated Financial Section

110

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, 2017, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2017 and 2016, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 2017 and 2016. 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, 2016, 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 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 3, 2017

111

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	September 30,			December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	69		$	279
Accounts receivable, net	362			243
Inventories	59			73
Regulatory assets	34			20
Other current assets	50			38
Total current assets	574			653

Property, plant and equipment, net	6,890			6,997
Regulatory assets	1,110			1,000
Other assets	39			39

Total assets	$	8,613		$	8,689

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	192		$	187
Accrued interest	39			50
Accrued property, income and other taxes	109			93
Regulatory liabilities	35			37
Current portion of long-term debt and financial and capital lease obligations	842			17
Customer deposits	78			78
Other current liabilities	31			39
Total current liabilities	1,326			501

Long-term debt and financial and capital lease obligations	2,231			3,049
Regulatory liabilities	423			416
Deferred income taxes	1,529			1,474
Other long-term liabilities	281			277
Total liabilities	5,790			5,717

Commitments and contingencies (Note 9)

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	518			667
Accumulated other comprehensive loss, net	(3		)	(3		)
Total shareholder's equity	2,823			2,972

Total liabilities and shareholder's equity	$	8,613		$	8,689

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

112

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,
	2017			2016			2017			2016

Operating revenue	$	819		$	766		$	1,785		$	1,690

Operating costs and expenses:
Cost of fuel, energy and capacity	318			251			721			618
Operating and maintenance	97			105			278			304
Depreciation and amortization	77			76			231			227
Property and other taxes	10			10			29			30
Total operating costs and expenses	502			442			1,259			1,179

Operating income	317			324			526			511

Other income (expense):
Interest expense	(44		)	(45		)	(132		)	(140		)
Allowance for borrowed funds	1			—			1			2
Allowance for equity funds	—			—			1			3
Other, net	5			7			18			17
Total other income (expense)	(38		)	(38		)	(112		)	(118		)

Income before income tax expense	279			286			414			393
Income tax expense	103			98			151			136
Net income	$	176		$	188		$	263		$	257

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

113

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

Balance, December 31, 2016	1,000	$	—	$	2,308	$	667		$	(3	)	$	2,972
Net income	—	—		—		263			—			263
Dividends declared	—	—		—		(412		)	—			(412		)
Balance, September 30, 2017	1,000	$	—	$	2,308	$	518		$	(3	)	$	2,823

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

114

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2017			2016
Cash flows from operating activities:
Net income	$	263		$	257
Adjustments to reconcile net income to net cash flows from operating activities:
Gain on nonrecurring items	(1		)	—
Depreciation and amortization	231			227
Deferred income taxes and amortization of investment tax credits	61			52
Allowance for equity funds	(1		)	(3		)
Changes in regulatory assets and liabilities	25			139
Deferred energy	(22		)	(3		)
Amortization of deferred energy	13			(87		)
Other, net	(1		)	3
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(122		)	(96		)
Inventories	6			7
Accrued property, income and other taxes	11			98
Accounts payable and other liabilities	9			7
Net cash flows from operating activities	472			601

Cash flows from investing activities:
Capital expenditures	(202		)	(249		)
Acquisitions	(77		)	—
Other, net	4			—
Net cash flows from investing activities	(275		)	(249		)

Cash flows from financing activities:
Proceeds from issuance of long-term debt	91			—
Repayments of long-term debt and financial and capital lease obligations	(86		)	(221		)
Dividends paid	(412		)	(365		)
Net cash flows from financing activities	(407		)	(586		)

Net change in cash and cash equivalents	(210		)	(234		)
Cash and cash equivalents at beginning of period	279			536
Cash and cash equivalents at end of period	$	69		$	302

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

115

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, 2017 and for the three- and nine-month periods ended September 30, 2017 and 2016. 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, 2017 and 2016. The results of operations for the three- and nine-month periods ended September 30, 2017 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 Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2016 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, 2017.

(2) New Accounting Pronouncements

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

116

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

In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. 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 plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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

(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	2017			2016
Utility plant:
Generation	30 - 55 years	$	3,725		$	4,271
Distribution	20 - 65 years	3,294			3,231
Transmission	45 - 65 years	1,860			1,846
General and intangible plant	5 - 65 years	784			738
Utility plant		9,663			10,086
Accumulated depreciation and amortization		(2,840		)	(3,205		)
Utility plant, net		6,823			6,881
Other non-regulated, net of accumulated depreciation and amortization	45 years	2			2
Plant, net		6,825			6,883
Construction work-in-progress		65			114
Property, plant and equipment, net		$	6,890		$	6,997

117

Acquisitions

In April 2017, Nevada Power purchased the remaining 25% interest in the Silverhawk natural gas-fueled generating facility for $77 million. The Public Utilities Commission of Nevada ("PUCN") approved the purchase of the facility in Nevada Power’s triennial Integrated Resource Plan filing in December 2015. The purchase price was allocated to the assets acquired, consisting primarily of generation utility plant, and no significant liabilities were assumed.

(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 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

Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one megawatt ("MW") or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs.

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

In November 2016, Caesars Enterprise Service ("Caesars"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers. In July 2017, Caesars made the required compliance filings and, in September 2017, the PUCN issued an order allowing Caesars to acquire electric energy and ancillary services from another energy supplier and become a distribution only service customer of Nevada Power.

118

Emissions Reduction and Capacity Replacement Plan ("ERCR Plan")

In March 2017, Nevada Power retired Reid Gardner Unit 4, a 257-MW coal-fueled generating facility. The early retirement was approved by the PUCN in December 2016 as a part of Nevada Power's second amendment to the ERCR Plan. The remaining net book value of $151 million was moved from property, plant and equipment, net to noncurrent regulatory assets on the Consolidated Balance Sheet in March 2017, in compliance with the ERCR Plan. Refer to Note 9 for additional information on the ERCR Plan.

(5) Recent Financing Transactions

In January 2017, Nevada Power (1) issued a notice to the bondholders for the repurchase of the remaining outstanding amounts of its $38 million Pollution Control Revenue Bonds, Series 2006 and $38 million Pollution Control Revenue Bonds, Series 2006A and (2) redeemed the Pollution Control Revenue Bonds, Series 2006A, aggregate principal amount outstanding plus accrued interest with the use of cash on hand. In February 2017, Nevada Power redeemed the Pollution Control Revenue Bonds, Series 2006, aggregate principal amount outstanding plus accrued interest with the use of cash on hand.

In May 2017, Nevada Power entered into a Financing Agreement with Clark County, Nevada (the "Clark Issuer") whereby the Clark Issuer loaned to Nevada Power the proceeds from the issuance, on behalf of Nevada Power, of $39.5 million of its 1.60% tax-exempt Pollution Control Refunding Revenue Bonds, Series 2017, due 2036 ("Series 2017 Bonds"). The Series 2017 Bonds are subject to mandatory purchase by Nevada Power in May 2020, and on and after the purchase date, the interest rate may be adjusted from time to time.

In May 2017, Nevada Power entered into a Financing Agreement with the Coconino County, Arizona Pollution Control Corporation (the "Coconino Issuer") whereby the Coconino Issuer loaned to Nevada Power the proceeds from the issuance, on behalf of Nevada Power, of $40 million of its 1.80% tax-exempt Pollution Control Refunding Revenue Bonds, Series 2017A, due 2032 and $13 million of its 1.60% tax-exempt Pollution Control Refunding Revenue Bonds, Series 2017B, due 2039 (collectively, the "Series 2017AB Bonds"). The Series 2017AB Bonds are subject to mandatory purchase by Nevada Power in May 2020, and on and after the purchase date, the interest rate may be adjusted from time to time.

To provide collateral security for its obligations, Nevada Power issued its General and Refunding Mortgage Notes, Series AA, No. AA-1 in the amount of $39.5 million and No. AA-2 in the amount of $53 million (collectively, the "Series AA Notes").The obligation of Nevada Power to make any payment of the principal and interest on any Series AA Notes is discharged to the extent Nevada Power has made payment on the Series 2017 Bonds and the Series 2017AB Bonds.

The collective proceeds from the tax-exempt bond issuances were used to refund at par value, plus accrued interest, the Clark Issuer's $39.5 million of Pollution Control Refunding Revenue Bonds, Series 2006 and the Coconino Issuer's $40 million of Pollution Control Refunding Revenue Bonds, Series 2006A and $13 million of Pollution Control Refunding Revenue Bonds, Series 2006B, each previously issued on behalf of Nevada Power.

(6) 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 $1 million to the Non-Qualified Pension Plans for the nine-month period ended September 30, 2017. 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.

119

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,
	2017			2016
Qualified Pension Plan -
Other long-term liabilities	$	(27	)	$	(24	)

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

Other Postretirement Plans -
Other long-term liabilities	(4		)	(4		)

(7) 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, 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 8 for additional information on derivative contracts.

120

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, 2017
Commodity liabilities⁽¹⁾	$	(3	)	$	(1	)	$	(4	)

As of December 31, 2016
Commodity liabilities⁽¹⁾	$	(7	)	$	(7	)	$	(14	)


(1)	Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates and as of September 30, 2017 and December 31, 2016, a regulatory asset of $4 million and $14 million, respectively, was recorded related to the derivative liability of $4 million and $14 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 (in millions):



		As of
	Unit of	September 30,	December 31,
	Measure	2017	2016

Electricity sales	Megawatt hours	—	(2	)
Natural gas purchases	Decatherms	149	114

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, 2017, 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 $2 million as of September 30, 2017 and December 31, 2016, 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.

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(8)	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 financial 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, 2017
Assets - investment funds	$	2	$	—	$	—		$	2

Liabilities - commodity derivatives	$	—	$	—	$	(4	)	$	(4	)

As of December 31, 2016
Assets:
Money market mutual funds⁽¹⁾	$	220	$	—	$	—		$	220
Investment funds	6		—		—			6
	$	226	$	—	$	—		$	226

Liabilities - commodity derivatives	$	—	$	—	$	(14	)	$	(14	)


(1)	Amounts are included in cash and cash equivalents 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 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. 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, 2017 and December 31, 2016, 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 7 for further discussion regarding Nevada Power's risk management and hedging activities.

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Nevada Power's investments in money market mutual funds and equity securities are accounted for as available-for-sale 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,
	2017			2016			2017			2016

Beginning balance	$	(4	)	$	(22	)	$	(14	)	$	(22	)
Changes in fair value recognized in regulatory assets	(1		)	(1		)	(3		)	(6		)
Settlements	1			4			13			9
Ending balance	$	(4	)	$	(19	)	$	(4	)	$	(19	)

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

Long-term debt	$	2,599	$	3,055	$	2,581	$	3,040


(9)	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.

123

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 facilities and other generating facilities. In May 2014, Nevada Power filed its 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 the ERCR Plan, Nevada Power acquired a 272-MW natural gas co-generating facility in 2014, acquired a 210-MW natural gas peaking facility in 2014, constructed a 15-MW solar photovoltaic facility in 2015, contracted two renewable power purchase agreements with 100-MW solar photovoltaic generating facilities in 2015, contracted a renewable power purchase agreement with 100-MW solar photovoltaic generating facility in 2016 and acquired the remaining 130 MW, 25%, of the Silverhawk natural gas-fueled generating facility in April 2017, of which 54 MW were approved as part of the ERCR Plan. Nevada Power has the option to acquire 35 MW of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval. Nevada Power retired Reid Gardner Units 1, 2, and 3, 300 MW of coal-fueled generation, in 2014 and Reid Gardner Unit 4, 257 MW of coal-fueled generation, in March 2017. These transactions are related to Nevada Power's compliance 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.

124

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 2017 and 2016

Net income for the third quarter of 2017 was $176 million, a decrease of $12 million, or 6%, compared to 2016 due to lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers, refinement of the unbilled revenue estimate and increased other operating costs. The decrease in net income was partially offset by higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers, customer usage patterns, higher transmission revenue and customer growth.

Net income for the first nine months of 2017 was $263 million, an increase of $6 million, or 2%, compared to 2016 due to higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers, lower interest on deferred charges and long-term debt, customer growth, higher transmission revenue, customer usage patterns and lower planned maintenance. The increase in net income was partially offset by lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers, higher depreciation and amortization primarily due to higher plant placed in-service and increased other operating costs.

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.

125

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



	Third Quarter										First Nine Months
	2017		2016		Change						2017		2016		Change
Gross margin (in millions):
Operating revenue	$	819	$	766	$	53		7		%	$	1,785	$	1,690	$	95		6		%
Cost of fuel, energy and capacity	318		251		67			27			721		618		103			17
Gross margin	$	501	$	515	$	(14	)	(3	)		$	1,064	$	1,072	$	(8	)	(1	)

GWh sold:
Residential	3,899		3,814		85			2		%	7,899		7,802		97			1		%
Commercial	1,517		1,440		77			5			3,669		3,600		69			2
Industrial	1,783		2,149		(366		)	(17	)		4,870		5,772		(902		)	(16	)
Other	60		59		1			2			154		155		(1		)	(1	)
Total fully bundled⁽¹⁾	7,259		7,462		(203		)	(3	)		16,592		17,329		(737		)	(4	)
Distribution only service	617		119		498			*			1,367		305		1,062			*
Total retail	7,876		7,581		295			4			17,959		17,634		325			2
Wholesale	59		76		(17		)	(22	)		214		177		37			21
Total GWh sold	7,935		7,657		278			4			18,173		17,811		362			2

Average number of retail customers (in thousands):
Residential	813		799		14			2		%	809		795		14			2		%
Commercial	106		105		1			1			106		105		1			1
Industrial	2		2		—			—			2		2		—			—
Total	921		906		15			2			917		902		15			2

Average retail revenue per MWh:
Fully bundled⁽¹⁾	$	109.85	$	101.22	$	8.63		9		%	$	104.06	$	95.69	$	8.37		9		%

Heating degree days	—		—		—			—		%	791		829		(38		)	(5	)	%
Cooling degree days	2,319		2,295		24			1		%	3,808		3,674		134			4		%

Sources of energy (GWh)⁽²⁾:
Natural gas	4,592		4,657		(65		)	(1	)	%	10,338		11,569		(1,231		)	(11	)	%
Coal	367		599		(232		)	(39	)		1,182		1,140		42			4
Renewables	19		26		(7		)	(27	)		57		47		10			21
Total energy generated	4,978		5,282		(304		)	(6	)		11,577		12,756		(1,179		)	(9	)
Energy purchased	2,500		2,471		29			1			5,665		5,410		255			5
Total	7,478		7,753		(275		)	(4	)		17,242		18,166		(924		)	(5	)

Average total cost of energy per MWh⁽³⁾:	$	42.46	$	32.30	$	10.16		31		%	$	41.80	$	34.01	$	7.79		23		%

* Not meaningful


(1)	Fully bundled includes sales to customers for combined energy, transmission and distribution services.


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


(3)	The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.

126

Gross margin decreased $14 million, or 3%, for the third quarter of 2017 compared to 2016 due to:


•	$15 million in lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers;


•	$10 million in lower energy efficiency program revenue (offset in operating and maintenance expense) and


•	$9 million from a refinement of the unbilled revenue estimate.

The decrease in gross margin was offset by:


•	$8 million in higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers;


•	$5 million from customer usage patterns;


•	$3 million in higher transmission revenue primarily due to customers becoming distribution only service customers and


•	$2 million due to customer growth.

Operating and maintenance decreased $8 million, or 8%, for the third quarter of 2017 compared to 2016 due to lower energy efficiency program expense (offset in operating revenue) of $8 million.

Income tax expense increased $5 million, or 5%, for the third quarter of 2017 compared to 2016. The effective tax rate was 37% in 2017 and 34% in 2016. The increase in the effective tax rate is primarily due to the qualified production activities deduction in 2016.

Gross margin decreased $8 million, or 1%, for the first nine months of 2017 compared to 2016 due to:


•	$24 million in lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers and


•	$22 million in lower energy efficiency program revenue (offset in operating and maintenance expense).

The decrease in gross margin was offset by:


•	$19 million in higher other retail revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers;


•	$7 million due to customer growth;


•	$6 million in higher transmission revenue primarily due to customers becoming distribution only service customers and


•	$5 million from customer usage patterns.

Operating and maintenance decreased $26 million, or 9%, for the first nine months of 2017 compared to 2016 due to lower energy efficiency program expense (offset in operating revenue); lower planned maintenance; and decreased expenses related to uncollectible accounts. These decreases are partially offset by higher other operating costs.

Depreciation and amortization increased $4 million, or 2%, for the first nine months of 2017 compared to 2016 primarily due to higher plant placed in-service.

Other income (expense) is favorable $6 million, or 5%, for the first nine months of 2017 compared to 2016 due to lower interest expense on deferred charges and the redemption of $210 million Series M, 5.950% General and Refunding Mortgage Notes in 2016, partially offset by lower allowance for funds used during construction.

Income tax expense increased $15 million, or 11%, for the first nine months of 2017 compared to 2016. The effective tax rate was 36% in 2017 and 35% in 2016. The increase in the effective tax rate is primarily due to the qualified production activities deduction in 2016.

127

Liquidity and Capital Resources

As of September 30, 2017, Nevada Power's total net liquidity was $469 million consisting of $69 million in cash and cash equivalents and $400 million of a credit facility.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2017 and 2016 were $472 million and $601 million, respectively. The change was due to higher impact fees received in 2016 and higher intercompany tax payments, partially offset by a 2016 contribution to the pension plan.

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.

The timing of Nevada Power'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.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2017 and 2016 were $(275) million and $(249) million, respectively. The change was due to the acquisition of the remaining 25% in the Silverhawk generating station, partially offset by decreased capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2017 and 2016 were $(407) million and $(586) million, respectively. The change was due to lower repayments of long‑term debt and proceeds from issuance of long‑term debt, partially offset by higher dividends paid to NV Energy, Inc. in 2017.

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, 2017, 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 $1.2 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, 2017.

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.

128

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. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition 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
	2016		2017		2017

Generation development	$	1	$	—	$	—
Distribution	110		41		58
Transmission system investment	29		6		10
Other	109		155		180
Total	$	249	$	202	$	248

Nevada Power's approved forecast capital expenditures include investments related to operating projects that consist of routine expenditures for transmission, distribution, generation and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of September 30, 2017, 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, 2016.

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.

129

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

130

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

131

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, 2017, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2017 and 2016, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 2017 and 2016. 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, 2016, 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 24, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

November 3, 2017

132

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	September 30,			December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	30		$	55
Accounts receivable, net	102			117
Inventories	47			45
Regulatory assets	38			25
Other current assets	20			13
Total current assets	237			255

Property, plant and equipment, net	2,862			2,822
Regulatory assets	400			410
Other assets	8			6

Total assets	$	3,507		$	3,493

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	75		$	146
Accrued interest	11			14
Accrued property, income and other taxes	11			10
Regulatory liabilities	17			69
Current portion of long-term debt and financial and capital lease obligations	1			1
Customer deposits	15			16
Other current liabilities	18			12
Total current liabilities	148			268

Long-term debt and financial and capital lease obligations	1,151			1,152
Regulatory liabilities	223			221
Deferred income taxes	663			617
Other long-term liabilities	134			127
Total liabilities	2,319			2,385

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
Retained earnings (deficit)	78			(2		)
Accumulated other comprehensive loss, net	(1		)	(1		)
Total shareholder's equity	1,188			1,108

Total liabilities and shareholder's equity	$	3,507		$	3,493

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

133

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,
	2017			2016			2017			2016
Operating revenue:
Electric	$	215		$	207		$	534		$	539
Natural gas	15			15			66			81
Total operating revenue	230			222			600			620

Operating costs and expenses:
Cost of fuel, energy and capacity	76			73			193			208
Natural gas purchased for resale	4			5			26			42
Operating and maintenance	40			40			121			126
Depreciation and amortization	29			30			85			88
Property and other taxes	6			5			18			18
Total operating costs and expenses	155			153			443			482

Operating income	75			69			157			138

Other income (expense):
Interest expense	(11		)	(12		)	(33		)	(42		)
Allowance for borrowed funds	1			—			1			1
Allowance for equity funds	1			1			2			2
Other, net	2			2			4			3
Total other income (expense)	(7		)	(9		)	(26		)	(36		)

Income before income tax expense	68			60			131			102
Income tax expense	24			22			46			37
Net income	$	44		$	38		$	85		$	65

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

134

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)



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

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

Balance, December 31, 2016	1,000	$	—	$	1,111	$	(2	)	$	(1	)	$	1,108
Net income	—	—		—		85			—			85
Dividends declared	—	—		—		(5		)	—			(5		)
Balance, September 30, 2017	1,000	$	—	$	1,111	$	78		$	(1	)	$	1,188

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

135

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Nine-Month Periods
	Ended September 30,
	2017			2016
Cash flows from operating activities:
Net income	$	85		$	65
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	85			88
Allowance for equity funds	(2		)	(2		)
Deferred income taxes and amortization of investment tax credits	46			37
Changes in regulatory assets and liabilities	9			(14		)
Deferred energy	(23		)	55
Amortization of deferred energy	(43		)	(35		)
Other, net	—			(1		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	13			12
Inventories	(2		)	1
Accrued property, income and other taxes	(2		)	—
Accounts payable and other liabilities	(54		)	(15		)
Net cash flows from operating activities	112			191

Cash flows from investing activities:
Capital expenditures	(131		)	(137		)
Net cash flows from investing activities	(131		)	(137		)

Cash flows from financing activities:
Proceeds from issuance of long-term debt, net of costs	—			1,089
Repayments of long-term debt and financial and capital lease obligations	(1		)	(1,137		)
Dividends paid	(5		)	(45		)
Net cash flows from financing activities	(6		)	(93		)

Net change in cash and cash equivalents	(25		)	(39		)
Cash and cash equivalents at beginning of period	55			106
Cash and cash equivalents at end of period	$	30		$	67

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

136

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, 2017 and for the three- and nine-month periods ended September 30, 2017 and 2016. 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, 2017 and 2016. The results of operations for the three- and nine-month periods ended September 30, 2017 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 Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2016 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, 2017.

(2) New Accounting Pronouncements

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

137

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

In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. 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 plans to adopt this guidance effective January 1, 2019 and is currently evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

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

138

(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	2017			2016
Utility plant:
Electric generation	25 - 60 years	$	1,140		$	1,137
Electric distribution	20 - 100 years	1,445			1,417
Electric transmission	50 - 100 years	782			771
Electric general and intangible plant	5 - 70 years	182			164
Natural gas distribution	35 - 70 years	388			381
Natural gas general and intangible plant	5 - 70 years	14			15
Common general	5 - 70 years	290			267
Utility plant		4,241			4,152
Accumulated depreciation and amortization		(1,496		)	(1,442		)
Utility plant, net		2,745			2,710
Other non-regulated, net of accumulated depreciation and amortization	70 years	5			5
Plant, net		2,750			2,715
Construction work-in-progress		112			107
Property, plant and equipment, net		$	2,862		$	2,822

During 2016, Sierra Pacific revised its electric and gas depreciation rates based on the results of a new depreciation study, the most significant impact of which was shorter estimated useful lives at the Valmy Generating Station. The effect of this change will increase depreciation and amortization expense by $9 million annually based on depreciable plant balances at the time of the change. However, the Public Utilities Commission of Nevada ("PUCN") ordered the change relating to the Valmy Generating Station of $7 million annually be deferred for future recovery through a regulatory asset.

(4) Regulatory Matters

Deferred Energy

Regulatory Rate Review

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

139

Chapter 704B Applications

In September 2016, Switch, Ltd. ("Switch"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific. In December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions. In June 2017, Switch became a distribution only service customer and started procuring energy from another energy supplier.

In November 2016, Caesars Enterprise Service ("Caesars"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers. In July 2017, Caesars made the required compliance filings and, in September 2017, the PUCN issued an order allowing Caesars to acquire electric energy and ancillary services from another energy supplier and become a distribution only service customer of Sierra Pacific.

(5) Recent Financing Transactions

(6) Employee Benefit Plans

Sierra Pacific 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 Sierra Pacific. Sierra Pacific contributed $4 million to the Other Postretirement Plans for the nine-month period ended September 30, 2017. Amounts attributable to Sierra Pacific 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.

140

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,
	2017			2016
Qualified Pension Plan -
Other long-term liabilities	$	(13	)	$	(12	)

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

Other Postretirement Plans -
Other long-term liabilities	(25		)	(28		)

(7) Fair Value Measurements

The carrying value of Sierra Pacific'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. Sierra Pacific 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 Sierra Pacific has the ability to access at the measurement date.

•


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

The following table presents Sierra Pacific's financial 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, 2017
Assets - investment funds	$	—	$	—	$	—	$	—

As of December 31, 2016
Assets:
Money market mutual funds⁽¹⁾	$	35	$	—	$	—	$	35
Investment funds	1		—		—		1
	$	36	$	—	$	—	$	36


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

141

Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale 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.

Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific'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 Sierra Pacific'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 Sierra Pacific's long-term debt (in millions):



	As of September 30, 2017				As of December 31, 2016
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,120	$	1,201	$	1,119	$	1,191


(8)	Commitments and Contingencies

Environmental Laws and Regulations

Sierra Pacific 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 Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

Legal Matters

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

(9) Segment Information

Sierra Pacific has identified two reportable operating segments: regulated electric and regulated natural gas. 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 natural 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 natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

Sierra Pacific believes presenting gross margin allows the reader to assess the impact of Sierra Pacific's regulatory treatment and its overall regulatory environment on a consistent basis and is meaningful. Gross margin is calculated as operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale ("cost of sales").

142

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



	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2017		2016		2017		2016
Operating revenue:
Regulated electric	$	215	$	207	$	534	$	539
Regulated gas	15		15		66		81
Total operating revenue	$	230	$	222	$	600	$	620

Cost of sales:
Regulated electric	$	76	$	73	$	193	$	208
Regulated gas	4		5		26		42
Total cost of sales	$	80	$	78	$	219	$	250

Gross margin:
Regulated electric	$	139	$	134	$	341	$	331
Regulated gas	11		10		40		39
Total gross margin	$	150	$	144	$	381	$	370

Operating and maintenance:
Regulated electric	$	36	$	36	$	108	$	112
Regulated gas	4		4		13		14
Total operating and maintenance	$	40	$	40	$	121	$	126

Depreciation and amortization:
Regulated electric	$	25	$	26	$	74	$	76
Regulated gas	4		4		11		12
Total depreciation and amortization	$	29	$	30	$	85	$	88

Operating income:
Regulated electric	$	72	$	68	$	142	$	127
Regulated gas	3		1		15		11
Total operating income	$	75	$	69	$	157	$	138

Interest expense:
Regulated electric	$	10	$	11	$	30	$	38
Regulated gas	1		1		3		4
Total interest expense	$	11	$	12	$	33	$	42

143



	As of
	September 30,		December 31,
	2017		2016
Assets:
Regulated electric	$	3,165	$	3,119
Regulated gas	305		314
Regulated common assets⁽¹⁾	37		60
Total assets	$	3,507	$	3,493


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

144

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

General

Sierra Pacific'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. Sierra Pacific 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 Sierra Pacific. 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 Sierra Pacific.

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Sierra Pacific 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 Sierra Pacific's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific'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 2017 and 2016

Overview

Net income for the third quarter of 2017 was $44 million, an increase of $6 million, or 16%, compared to 2016 due to a decrease in interest expense from lower rates on outstanding debt balances and on deferred charges, higher electric margins primarily from increased customer usage due to the impacts of weather and customer usage patterns and decreased other operating costs. The increase in net income was partially offset by lower wholesale revenue.

Net income for the first nine months of 2017 was $85 million, an increase of $20 million, or 31%, compared to 2016 due to a decrease in interest expense from lower rates on outstanding debt balances and on deferred charges, higher electric margins primarily from increased customer usage due to the impacts of weather and customer usage patterns, higher transmission revenue and lower other operating costs. The increase in net income was partially offset by lower wholesale revenue.

Operating revenue, cost of fuel, energy and capacity and natural gas purchased for resale are key drivers of Sierra Pacific's results of operations as they encompass retail and wholesale electricity and natural gas revenue and the direct costs associated with providing electricity and natural gas to customers. Sierra Pacific believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale, is therefore meaningful.

145

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

Electric Gross Margin



	Third Quarter										First Nine Months
	2017		2016		Change						2017		2016		Change
Gross margin (in millions):
Operating electric revenue	$	215	$	207	$	8		4		%	$	534	$	539	$	(5	)	(1	)	%
Cost of fuel, energy and capacity	76		73		3			4			193		208		(15		)	(7	)
Gross margin	$	139	$	134	$	5		4			$	341	$	331	$	10		3

GWh sold:
Residential	736		694		42			6		%	1,904		1,798		106			6		%
Commercial	850		854		(4		)	—			2,271		2,241		30			1
Industrial	797		747		50			7			2,346		2,235		111			5
Other	4		4		—			—			12		12		—			—
Total fully bundled⁽¹⁾	2,387		2,299		88			4			6,533		6,286		247			4
Distribution only service	348		346		2			1			1,041		1,019		22			2
Total retail	2,735		2,645		90			3			7,574		7,305		269			4
Wholesale	103		147		(44		)	(30	)		392		481		(89		)	(19	)
Total GWh sold	2,838		2,792		46			2			7,966		7,786		180			2

Average number of retail customers (in thousands):
Residential	295		292		3			1		%	295		291		4			1		%
Commercial	47		47		—			—			47		47		—			—
Total	342		339		3			1			342		338		4			1

Average revenue per MWh:
Retail fully bundled⁽¹⁾	$	85.07	$	84.77	$	0.30		—		%	$	75.89	$	79.90	$	(4.01	)	(5	)	%
Wholesale	$	61.21	$	52.33	$	8.88		17			$	52.92	$	50.96	$	1.96		4

Heating degree days	118		43		75			*		%	2,823		2,487		336			14		%
Cooling degree days	1,070		796		274			34		%	1,401		1,088		313			29		%

Sources of energy (GWh)⁽²⁾:
Natural gas	1,221		1,215		6			—		%	3,227		3,195		32			1		%
Coal	355		392		(37		)	(9	)		457		691		(234		)	(34	)
Renewables	12		—		12			*			31		—		31			*
Total energy generated	1,588		1,607		(19		)	(1	)		3,715		3,886		(171		)	(4	)
Energy purchased	1,074		878		196			22			3,698		3,111		587			19
Total	2,662		2,485		177			7			7,413		6,997		416			6

Average total cost of energy per MWh⁽³⁾:	$	28.53	$	29.67	$	(1.14	)	(4	)	%	$	26.07	$	29.82	$	(3.75	)	(13	)	%

* Not meaningful


(1)	Fully bundled includes sales to customers for combined energy, transmission and distribution services.


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


(3)	The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.

146

Natural Gas Gross Margin



	Third Quarter										First Nine Months
	2017		2016		Change						2017		2016		Change
Gross margin (in millions):
Operating natural gas revenue	$	15	$	15	$	—		—		%	$	66	$	81	$	(15	)	(19	)	%
Natural gas purchased for resale	4		5		(1		)	(20	)		26		42		(16		)	(38	)
Gross margin	$	11	$	10	$	1		10			$	40	$	39	$	1		3

Dth sold:
Residential	835		727		108			15		%	6,866		5,958		908			15		%
Commercial	494		459		35			8			3,522		3,182		340			11
Industrial	244		216		28			13			1,255		1,080		175			16
Total retail	1,573		1,402		171			12			11,643		10,220		1,423			14

Average number of retail customers (in thousands)	164		162		2			1		%	164		161		3			2		%
Average revenue per retail Dth sold	$	8.59	$	10.22	$	(1.63	)	(16	)	%	$	5.47	$	7.68	$	(2.21	)	(29	)	%
Average cost of natural gas per retail Dth sold	$	2.53	$	3.11	$	(0.58	)	(19	)	%	$	2.20	$	4.09	$	(1.89	)	(46	)	%
Heating degree days	118		43		75			*		%	2,823		2,487		336			14		%

Electric gross margin increased $5 million, or 4%, for the third quarter of 2017 compared to 2016 due to:


•	$4 million higher customer usage primarily from the impacts of weather and


•	$3 million from customer usage patterns.

The increase in electric gross margin was partially offset by:


•	$2 million in decreased wholesale revenue due to lower volumes.

Other income (expense) is favorable $2 million, or 22%, for the third quarter of 2017 compared to 2016 primarily due to lower interest on deferred charges.

Income tax expense increased $2 million, or 9%, for the third quarter of 2017 compared to 2016. The effective tax rate was 35% in 2017 and 37% in 2016.

Electric gross margin increased $10 million, or 3%, for the first nine months of 2017 compared to 2016 due to:


•	$8 million higher customer usage primarily from the impacts of weather;


•	$3 million from customer usage patterns and


•	$2 million in higher transmission revenue.

The increase in electric gross margin was partially offset by:


•	$4 million in decreased wholesale revenue due to lower volumes.

Operating and maintenance decreased $5 million, or 4%, for the first nine months of 2017 compared to 2016 due to lower other operating costs, partially offset by lower operating and maintenance related regulatory credit amortizations.

Depreciation and amortization decreased $3 million, or 3%, for the first nine months of 2017 compared to 2016 primarily due to regulatory amortizations.

Other income (expense) is favorable $10 million, or 28%, for the first nine months of 2017 compared to 2016 due to a decrease in interest expense from lower rates on outstanding debt balances and lower interest on deferred charges.

147

Income tax expense increased $9 million, or 24%, for the first nine months of 2017 compared to 2016. The effective tax rate was 35% in 2017 and 36% in 2016.

Liquidity and Capital Resources

As of September 30, 2017, Sierra Pacific's total net liquidity was as follows (in millions):



Cash and cash equivalents	$	30

Credit facility	250
Less:
Tax-exempt bond support	(80		)
Net credit facility	170

Total net liquidity	$	200

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2017 and 2016 were $112 million and $191 million, respectively. The change was due to higher payments for fuel costs, partially offset by lower contributions to the pension plan.

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, Sierra Pacific'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.

The timing of Sierra Pacific'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.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2017 and 2016 were $(131) million and $(137) million, respectively. The change was due to decreased capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2017 and 2016 were $(6) million and $(93) million, respectively. The change was due to lower repayments of long-term debt and lower dividends paid to NV Energy, Inc. in 2017, partially offset by lower proceeds from issuance of long-term debt.

Ability to Issue Debt

Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2017, Sierra Pacific has financing authority from the PUCN consisting of the ability to: (1) issue additional long-term debt securities of up to $350 million; (2) refinance up to $55 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $600 million. Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of September 30, 2017.

148

Future Uses of Cash

Sierra Pacific 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 Sierra Pacific has access to external financing depends on a variety of factors, including Sierra Pacific's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

Sierra Pacific 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. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.

Sierra Pacific'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
	2016		2017		2017

Distribution	$	73	$	61	$	91
Transmission system investment	16		9		14
Other	48		61		80
Total	$	137	$	131	$	185

Sierra Pacific's forecast capital expenditures include investments that relate to operating projects that consist of routine expenditures for transmission, distribution, generation and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of September 30, 2017, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2016.

Regulatory Matters

Sierra Pacific 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 Sierra Pacific's current regulatory matters.

Environmental Laws and Regulations

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

149

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 Sierra Pacific, refer to Note 2 of Notes to Consolidated Financial Statements in Sierra Pacific'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 Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2016. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2016.

150


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2016. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2016. Refer to Note 9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, Note 6 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q and Note 7 of the Notes to Consolidated Financial Statements of Nevada Power in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of September 30, 2017.


Item 4.	Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended September 30, 2017 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

151

PART II


Item 1.	Legal Proceedings

Not applicable.


Item 1A.	Risk Factors

There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2016.


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

Not applicable.


Item 3.	Defaults Upon Senior Securities

Not applicable.


Item 4.	Mine Safety Disclosures

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


Item 5.	Other Information

Not applicable.


Item 6.	Exhibits

The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.

152

SIGNATURES

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



	BERKSHIRE HATHAWAY ENERGY COMPANY

Date: November 3, 2017	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Executive Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	PACIFICORP

Date: November 3, 2017	/s/ Nikki L. Kobliha
	Nikki L. Kobliha
	Vice President, Chief Financial Officer and Treasurer
	(principal financial and accounting officer)

	MIDAMERICAN FUNDING, LLC
	MIDAMERICAN ENERGY COMPANY

Date: November 3, 2017	/s/ Thomas B. Specketer
	Thomas B. Specketer
	Vice President and Controller
	of MidAmerican Funding, LLC
	and Vice President and Chief Financial Officer
	of MidAmerican Energy Company
	(principal financial and accounting officer)

	NEVADA POWER COMPANY

Date: November 3, 2017	/s/ E. Kevin Bethel
	E. Kevin Bethel
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	SIERRA PACIFIC POWER COMPANY

Date: November 3, 2017	/s/ E. Kevin Bethel
	E. Kevin Bethel
	Senior Vice President and Chief Financial Officer
	(principal financial and accounting officer)

153

EXHIBIT INDEX


Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY

10.1

$1,000,000,000 Credit Agreement, dated as of May 11, 2017, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, and The Bank of Tokyo-Mitsubishi UFJ, LTD., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).


15.1	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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

PACIFICORP


15.2	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

10.2

$600,000,000 Credit Agreement, dated as of June 30, 2017, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent, and the LC Issuing Banks (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).


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

MIDAMERICAN ENERGY


15.3	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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

BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY

10.3

$900,000,000 Credit Agreement, dated as of June 30, 2017, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Mizuho Bank, LTD., as Administrative Agent, and the LC Issuing Banks (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, 2017).

154

Exhibit No. Description

MIDAMERICAN FUNDING


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


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


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


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

NEVADA POWER


15.4	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER


4.1	Financing Agreement dated May 1, 2017 between Clark County, Nevada and Nevada Power Company (relating to Clark County, Nevada's $39,500,000 Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2017) (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).

4.2

Financing Agreement dated May 1, 2017 between the Coconino County, Arizona Pollution Control Corporation and Nevada Power Company (relating to the Coconino County, Arizona Pollution Control Corporation's $53,000,000 Pollution Control Refunding Revenue Bonds (Nevada Power Company Projects) Series 2017A and 2017B) (incorporated by reference to Exhibit 4.2 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).


4.3	Officer’s Certificate establishing the terms of Nevada Power Company’s General and Refunding Mortgage Notes, Series AA (Nos. AA-1 and AA-2) (incorporated by reference to Exhibit 4.3 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).

10.4

$400,000,000 Second Amended and Restated Credit Agreement, dated as of June 30, 2017, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent, and the LC Issuing Banks (incorporated by reference to Exhibit 10.4 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

SIERRA PACIFIC


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


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


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


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

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC

10.5

$250,000,000 Second Amended and Restated Credit Agreement, dated as of June 30, 2017, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent, and the LC Issuing Banks (incorporated by reference to Exhibit 10.5 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).

155

Exhibit No. Description

ALL REGISTRANTS

101

The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.

156