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~~2018

[ ] 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	Accelerated filer	Non-accelerated ~~Filer~~filer	Smaller ~~Reporting Company~~reporting company	Emerging ~~Growth Company~~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~~2018, 76,996,944 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,~~2018, 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.~~2018.

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,~~2018, 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,~~2018, 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,~~2018, 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~~165
Item 4.	Controls and Procedures	~~151~~165

PART II

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
EBA		Energy Balancing Account
ECAM		Energy Cost Adjustment Mechanism
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~~



kV		Kilovolt
MW		Megawatts
MWh		Megawatt Hours
OPUC		Oregon Public Utility Commission
PCAM		Power Cost Adjustment Mechanism
PUCN		Public Utilities Commission of Nevada
REC		Renewable Energy Credit
RPS		Renewable Portfolio Standards
RRA		Renewable Energy Credit and Sulfur DioxideRevenue Adjustment Mechanism
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
TAM		Transition Adjustment Mechanism
UPSC		Utah Public Service Commission
WPSC		Wyoming Public Service Commission
WUTC		Washington Utilities and Transportation Commission

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 severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining ~~accidents,~~incidents, 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;

iii

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, mortgage and ~~mortgage~~franchising industries and regulations that could affect brokerage, mortgage and ~~mortgage~~franchising transactions;

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

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		5456
Consolidated Balance Sheets		5557
Consolidated Statements of Operations		5759
Consolidated Statements of Changes in Shareholders' Equity		5860
Consolidated Statements of Cash Flows		5961
Notes to Consolidated Financial Statements		6062
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		7683
Balance Sheets		7784
Statements of Operations		7986
Statements of Changes in Shareholder's Equity		8087
Statements of Cash Flows		8188
Notes to Financial Statements		8289
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		9199
Consolidated Balance Sheets		92100
Consolidated Statements of Operations		94102
Consolidated Statements of Changes in Member's Equity		95103
Consolidated Statements of Cash Flows		96104
Notes to Consolidated Financial Statements		97105
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~111~~122
Consolidated Balance Sheets		~~112~~123
Consolidated Statements of Operations		~~113~~124
Consolidated Statements of Changes in Shareholder's Equity		~~114~~125
Consolidated Statements of Cash Flows		~~115~~126
Notes to Consolidated Financial Statements		~~116~~127
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~132~~144
Consolidated Balance Sheets		~~133~~145
Consolidated Statements of Operations		~~134~~146
Consolidated Statements of Changes in Shareholder's Equity		~~135~~147
Consolidated Statements of Cash Flows		~~136~~148
Notes to Consolidated Financial Statements		~~137~~149


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		6874
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		~~100~~109
Nevada Power Company and its subsidiaries		~~125~~136
Sierra Pacific Power Company and its subsidiaries		~~145~~158

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~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of September 30, ~~2017~~2018, ~~and~~ the related consolidated statements of operations and comprehensive income for the three-month and nine-month periods ended September 30, ~~2017~~2018 and ~~2016,~~2017, and of changes in equity and cash flows for the nine-month periods ended September 30, 2018 and 2017, and ~~2016. These~~the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2017, and the related consolidated statements ~~are~~of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2018, 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, 2017 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

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~~2, 2018

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		September 30,		December 31,
	2017		2016		2018		2017
ASSETS
Current assets:
Cash and cash equivalents	$	1,142	$	721	$	1,016	$	935
Restricted cash and cash equivalents					358		327
Trade receivables, net	1,994		1,751		2,198		2,014
Income tax receivable					—		334
Inventories	887		925		851		888
Mortgage loans held for sale	534		359		501		465
Other current assets	1,095		917		860		815
Total current assets	5,652		4,673		5,784		5,778

Property, plant and equipment, net	64,979		62,509		67,587		65,871
Goodwill	9,700		9,010		9,683		9,678
Regulatory assets	4,582		4,307		2,778		2,761
Investments and restricted cash and investments	4,987		3,945
Investments and restricted cash and cash equivalents and investments					4,754		4,872
Other assets	1,154		996		1,276		1,248

Total assets	$	91,054	$	85,440	$	91,862	$	90,208

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						As of
	September 30,			December 31,			September 30,			December 31,
	2017			2016			2018			2017
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,303		$	1,317		$	1,331		$	1,519
Accrued interest	523			454			518			488
Accrued property, income and other taxes	780			389			543			354
Accrued employee expenses	392			261			414			274
Short-term debt	2,493			1,869			1,784			4,488
Current portion of long-term debt	3,070			1,006			2,205			3,431
Other current liabilities	1,034			1,017			1,026			1,049
Total current liabilities	9,595			6,313			7,821			11,603

Regulatory liabilities	3,086			2,933
BHE senior debt	6,771			7,418			8,620			5,452
BHE junior subordinated debentures	100			944			100			100
Subsidiary debt	26,183			26,748			26,633			26,210
Regulatory liabilities							7,553			7,309
Deferred income taxes	14,832			13,879			8,895			8,242
Other long-term liabilities	2,883			2,742			2,552			2,984
Total liabilities	63,450			60,977			62,174			61,900

Commitments and contingencies (Note 11)
Commitments and contingencies (Note 10)

Equity:
BHE shareholders' equity:
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding	—			—			—			—
Additional paid-in capital	6,362			6,390			6,357			6,368
Long-term income tax receivable							(494		)	—
Retained earnings	21,534			19,448			25,361			22,206
Accumulated other comprehensive loss, net	(423		)	(1,511		)	(1,667		)	(398		)
Total BHE shareholders' equity	27,473			24,327			29,557			28,176
Noncontrolling interests	131			136			131			132
Total equity	27,604			24,463			29,688			28,308

Total liabilities and equity	$	91,054		$	85,440		$	91,862		$	90,208

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						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Operating revenue:
Energy	$	4,322		$	4,272		$	11,501		$	11,102		$	4,419		$	4,322		$	11,818		$	11,501
Real estate	961			820			2,502			2,152			1,218			961			3,252			2,502
Total operating revenue	5,283			5,092			14,003			13,254			5,637			5,283			15,070			14,003

Operating costs and expenses:
Operating expenses:
Energy:
Cost of sales	1,212			1,187			3,380			3,252			1,271			1,212			3,565			3,380
Operating expense	930			948			2,763			2,739
Operations and maintenance													901			772			2,534			2,334
Depreciation and amortization	635			639			1,905			1,898			667			635			2,110			1,905
Property and other taxes													142			142			428			421
Real estate	882			733			2,311			1,973			1,133			882			3,067			2,311
Total operating costs and expenses	3,659			3,507			10,359			9,862
Total operating expenses													4,114			3,643			11,704			10,351

Operating income	1,624			1,585			3,644			3,392			1,523			1,640			3,366			3,652

Other income (expense):
Interest expense	(464		)	(460		)	(1,379		)	(1,401		)	(453		)	(464		)	(1,380		)	(1,379		)
Capitalized interest	14			14			34			128			17			14			44			34
Allowance for equity funds	24			17			59			147			30			24			75			59
Interest and dividend income	32			39			85			93			27			32			85			85
Gains (losses) on marketable securities, net													260			3			(336		)	8
Other, net	2			15			24			26			19			(17		)	50			8
Total other income (expense)	(392		)	(375		)	(1,177		)	(1,007		)	(100		)	(408		)	(1,462		)	(1,185		)

Income before income tax expense and equity income	1,232			1,210			2,467			2,385
Income tax expense	184			199			319			394
Income before income tax expense (benefit) and equity income													1,423			1,232			1,904			2,467
Income tax expense (benefit)													23			184			(366		)	319
Equity income	30			36			80			96			9			30			35			80
Net income	1,078			1,047			2,228			2,087			1,409			1,078			2,305			2,228
Net income attributable to noncontrolling interests	10			11			30			25			8			10			19			30
Net income attributable to BHE shareholders	$	1,068		$	1,036		$	2,198		$	2,062		$	1,401		$	1,068		$	2,286		$	2,198

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						Three-Month Periods					Nine-Month Periods
	Ended September 30,					Ended September 30,						Ended September 30,					Ended September 30,
	2017		2016			2017			2016			2018			2017		2018			2017

Net income	$	1,078	$	1,047		$	2,228		$	2,087		$	1,409		$	1,078	$	2,305		$	2,228

Other comprehensive income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $1, $7, $(3), and $26	15		18			16			80
Unrecognized amounts on retirement benefits, net of tax of $-, $1, $12 and $(3)												(1		)	15		50			16
Foreign currency translation adjustment	227		(134		)	535			(339		)	(2		)	227		(236		)	535
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		)
Unrealized gains on marketable securities, net of tax of $-, $284, $- and $355												—			423		—			542
Unrealized gains (losses) on cash flow hedges, net of tax of $(1), $1, $(1) and $(3)												1			1		2			(5		)
Total other comprehensive (loss) income, net of tax												(2		)	666		(184		)	1,088

Comprehensive income	1,744		1,008			3,316			1,977			1,407			1,744		2,121			3,316
Comprehensive income attributable to noncontrolling interests	10		11			30			25			8			10		19			30
Comprehensive income attributable to BHE shareholders	$	1,734	$	997		$	3,286		$	1,952		$	1,399		$	1,734	$	2,102		$	3,286

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																		BHE Shareholders' Equity
										Accumulated															Long-term						Accumulated
				Additional						Other												Additional			Income						Other
	Common			Paid-in			Retained			Comprehensive			Noncontrolling			Total			Common			Paid-in			Tax			Retained			Comprehensive			Noncontrolling			Total
	Shares	Stock		Capital			Earnings			Loss, Net			Interests			Equity			Shares	Stock		Capital			Receivable			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		77	$	—	$	6,390		$	—		$	19,448		$	(1,511	)	$	136		$	24,463
Net income	—	—		—			2,198			—			14			2,212			—	—		—			—			2,198			—			14			2,212
Other comprehensive income	—	—		—			—			1,088			—			1,088			—	—		—			—			—			1,088			—			1,088
Distributions	—	—		—			—			—			(16		)	(16		)
Common stock purchases	—	—		(1		)	(18		)	—			—			(19		)	—	—		(1		)	—			(18		)	—			—			(19		)
Common stock exchange	—	—		(6		)	(94		)	—			—			(100		)	—	—		(6		)	—			(94		)	—			—			(100		)
Distributions																			—	—		—			—			—			—			(16		)	(16		)
Other equity transactions	—	—		(21		)	—			—			(3		)	(24		)	—	—		(21		)	—			—			—			(3		)	(24		)
Balance, September 30, 2017	77	$	—	$	6,362		$	21,534		$	(423	)	$	131		$	27,604		77	$	—	$	6,362		$	—		$	21,534		$	(423	)	$	131		$	27,604

Balance, December 31, 2017																			77	$	—	$	6,368		$	—		$	22,206		$	(398	)	$	132		$	28,308
Adoption of ASU 2016-01																			—	—		—			—			1,085			(1,085		)	—			—
Net income																			—	—		—			—			2,286			—			16			2,302
Other comprehensive loss																			—	—		—			—			—			(184		)	—			(184		)
Reclassification of long-term income tax receivable																			—	—		—			(609		)	—			—			—			(609		)
Long-term income tax receivable adjustments																			—	—		—			115			(115		)	—			—			—
Common stock purchases																			—	—		(6		)	—			(101		)	—			—			(107		)
Distributions																			—	—		—			—			—			—			(17		)	(17		)
Other equity transactions																			—	—		(5		)	—			—			—			—			(5		)
Balance, September 30, 2018																			77	$	—	$	6,357		$	(494	)	$	25,361		$	(1,667	)	$	131		$	29,688

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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income	$	2,228		$	2,087		$	2,305		$	2,228
Adjustments to reconcile net income to net cash flows from operating activities:
Losses (gains) on marketable securities, net							336			(8		)
Depreciation and amortization	1,943			1,922			2,147			1,943
Allowance for equity funds	(59		)	(147		)	(75		)	(59		)
Equity income, net of distributions	(14		)	(62		)	17			(14		)
Changes in regulatory assets and liabilities	17			41			263			17
Deferred income taxes and amortization of investment tax credits	573			546			(116		)	573
Other, net	13			(60		)	40			21
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(98		)	(348		)	(192		)	(82		)
Derivative collateral, net	(16		)	22			9			(16		)
Pension and other postretirement benefit plans	(29		)	(73		)	(61		)	(29		)
Accrued property, income and other taxes	390			713
Accrued property, income and other taxes, net							190			390
Accounts payable and other liabilities	170			183			168			170
Net cash flows from operating activities	5,118			4,824			5,031			5,134

Cash flows from investing activities:
Capital expenditures	(3,179		)	(3,521		)	(4,203		)	(3,179		)
Acquisitions, net of cash acquired	(1,102		)	(66		)	(105		)	(1,102		)
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
Purchases of marketable securities							(287		)	(167		)
Proceeds from sales of marketable securities							266			186
Equity method investments	(54		)	(462		)	(236		)	(80		)
Other, net	(12		)	(47		)	48			(12		)
Net cash flows from investing activities	(4,373		)	(4,117		)	(4,517		)	(4,354		)

Cash flows from financing activities:
Proceeds from BHE senior debt							3,166			—
Repayments of BHE senior debt and junior subordinated debentures	(1,344		)	(1,500		)	(650		)	(1,344		)
Common stock purchases	(19		)	—			(107		)	(19		)
Proceeds from subsidiary debt	1,562			1,484			2,353			1,562
Repayments of subsidiary debt	(834		)	(1,613		)	(2,297		)	(834		)
Net proceeds from short-term debt	365			887
Net (repayments of) proceeds from short-term debt							(2,694		)	365
Purchase of redeemable noncontrolling interest							(131		)	—
Other, net	(60		)	(50		)	(32		)	(60		)
Net cash flows from financing activities	(330		)	(792		)	(392		)	(330		)

Effect of exchange rate changes	6			(5		)	(3		)	6

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
Net change in cash and cash equivalents and restricted cash and cash equivalents							119			456
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period							1,283			1,003
Cash and cash equivalents and restricted cash and cash equivalents at end of period							$	1,402		$	1,459

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~~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~~Company's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. ("NV Energy") (which primarily consists of Nevada Power Company ("Nevada Power") and Sierra Pacific Power Company ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("AltaLink") (which primarily consists of AltaLink, L.P. ("ALP")) and BHE U.S. Transmission, LLC), BHE Renewables (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~~investing in solar, wind, geothermal and hydroelectric ~~sources under long-term contracts,~~projects, the second largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States.

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~~2018 and for the three- and nine-month periods ended September 30, ~~2017~~2018 and ~~2016~~.2017. The results of operations for the three- and nine-month periods ended September 30, ~~2017~~2018 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~~2017 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~~2018.


(2)	(2) New Accounting Pronouncements

In August ~~2017,~~2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. ~~2017-12,~~2018-14, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments in this guidance remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures and add disclosure requirements identified as relevant. The updated disclosure requirements make a number of changes to improve the effectiveness of disclosures in the notes to the financial statements. This guidance is effective for annual reporting periods beginning after December 15, 2020, with early adoption permitted, and is required to be adopted retrospectively. The adoption of ASU No. 2018-14 will not have a material impact on the Company's Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In February 2018, the FASB issued ASU No. 2018-02, which amends FASB ASC Topic 220, "Income Statement - Reporting Comprehensive Income." The amendments in this guidance require a reclassification from accumulated other comprehensive income to retained earnings for the stranded tax effects that were created from the Tax Cuts and Jobs Act enacted on December 22, 2017 ("2017 Tax Reform"). The reclassification is the difference between the historical income tax rates and the enacted rate for the items previously recorded in accumulated other comprehensive income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted retrospectively to each period in which the effect of the change in 2017 Tax Reform is recognized. Considering the significant components of the Company's accumulated other comprehensive income relate to (a) unrecognized amounts on retirement benefits of foreign pension plans and (b) unrealized gains on available-for-sale securities, which were reclassified as required by ASU No. 2016-01 that was adopted on January 1, 2018, the adoption of ASU No. 2018-02 did not have a material impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In August 2017, the FASB issued ASU No. 2017-12, which amends FASB ASC Topic 815, "Derivatives and Hedging." The amendments in this guidance update the hedge accounting model to enable entities to better portray the economics of their risk management activities in the financial statements, expands an ~~entity’s~~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 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. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases" and ASU No. 2018-11 that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings recognized in the period of adoption. 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 in the process of evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.


(3)	Business Acquisitions

The Company completed various acquisitions totaling $105 million, net of cash acquired, for the nine-month period ended September 30, 2018. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which primarily related to residential real estate brokerage businesses. There were no other material assets acquired or liabilities assumed. Additionally, in April 2018, HomeServices acquired the remaining 33.3% interest in a real estate brokerage franchise business from the noncontrolling interest member at a contractually determined option exercise price totaling $131 million.

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	2018			2017
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	75,751		$	74,660
Interstate natural gas pipeline assets	3-80 years	7,295			7,176
		83,046			81,836
Accumulated depreciation and amortization		(25,566		)	(24,478		)
Regulated assets, net		57,480			57,358

Nonregulated assets:
Independent power plants	5-30 years	6,551			6,010
Other assets	3-30 years	1,605			1,489
		8,156			7,499
Accumulated depreciation and amortization		(1,773		)	(1,542		)
Nonregulated assets, net		6,383			5,957

Net operating assets		63,863			63,315
Construction work-in-progress		3,724			2,556
Property, plant and equipment, net		$	67,587		$	65,871

Construction work-in-progress includes $3.2 billion as of September 30, 2018 and $2.2 billion as of December 31, 2017, related to the construction of regulated assets.


(5)	Investments and Restricted Cash and Cash Equivalents and Investments

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



	As of
	September 30,		December 31,
	2018		2017
Investments:
BYD Company Limited common stock	$	1,616	$	1,961
Rabbi trusts	398		441
Other	186		124
Total investments	2,200		2,526

Equity method investments:
BHE Renewables tax equity investments	1,221		1,025
Electric Transmission Texas, LLC	530		524
Bridger Coal Company	116		137
Other	163		148
Total equity method investments	2,030		1,834

Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	543		515
Restricted cash and cash equivalents	385		348
Total restricted cash and cash equivalents and investments	928		863

Total investments and restricted cash and cash equivalents and investments	$	5,158	$	5,223

Reflected as:
Current assets	$	404	$	351
Noncurrent assets	4,754		4,872
Total investments and restricted cash and cash equivalents and investments	$	5,158	$	5,223

Investments

In January 2016, the FASB issued ASU 2016-01 which amended FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance addressed 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. The Company adopted this guidance effective January 1, 2018 with a cumulative-effect increase to retained earnings of $1,085 million and a corresponding decrease to accumulated other comprehensive income (loss) ("AOCI").

The portion of unrealized losses related to investments still held as of September 30, 2018 is calculated as follows (in millions):



	Three-Month Period		Nine-Month Period
	Ended September 30,		Ended September 30,
	2018		2018
Gains (losses) on marketable securities recognized during the period	$	260	$	(336	)
Less: Net gains recognized during the period on marketable securities sold during the period	—		1
Unrealized gains (losses) recognized during the period on marketable securities still held at the reporting date	$	260	$	(337	)

Equity Method Investments

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. The Company adopted this guidance retrospectively effective January 1, 2018 which resulted in the reclassification of certain cash distributions received from equity method investees of $26 million previously recognized within investing cash flows to operating cash flows for the nine-month period ended September 30, 2017.

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents



	As of
	September 30,		December 31,
	2018		2017
Cash and cash equivalents	$	1,016	$	935
Restricted cash and cash equivalents	358		327
Investments and restricted cash and cash equivalents and investments	28		21
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,402	$	1,283


(6)	Recent Financing Transactions

Long-Term Debt

In July 2018, BHE issued $1.0 billion of its 4.45% Senior Notes due 2049. BHE used the net proceeds to refinance a portion of the Company's short-term indebtedness and for general corporate purposes.

In July 2018, Northern Natural Gas issued $450 million of its 4.30% Senior Bonds due 2049. Northern Natural Gas used the net proceeds to repay at maturity all of its $200 million 5.75% Senior Notes due July 2018 and for general corporate purposes.

In July 2018, PacifiCorp issued $600 million of its 4.125% First Mortgage Bonds due 2049. PacifiCorp used a portion of the net proceeds to repay all of its $500 million 5.65% First Mortgage Bonds due July 2018 and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

In April 2018, Nevada Power issued $575 million of its 2.75% General and Refunding Mortgage Notes, Series BB, due April 2020. Nevada Power used a portion of the net proceeds to repay all of its $325 million 6.50% General and Refunding Mortgage Notes, Series O, maturing in May 2018. In August 2018, Nevada Power used the remaining net proceeds, together with available cash, to repay all of Nevada Power's $500 million 6.50% General and Refunding Mortgage Notes, Series S, maturing in August 2018.

In February 2018, MidAmerican Energy issued $700 million of its 3.65% First Mortgage Bonds due 2048. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from February 2, 2017 to October 31, 2017, with respect to investments in MidAmerican Energy's 2,000-megawatt (nameplate capacity) Wind XI project and the repowering of certain of MidAmerican Energy's existing wind facilities, which were previously financed with MidAmerican Energy's general funds.

In January 2018, BHE issued $450 million of its 2.375% Senior Notes due 2021, $400 million of its 2.80% Senior Notes due 2023, $600 million of its 3.25% Senior Notes due 2028 and $750 million of its 3.80% Senior Notes due 2048. The net proceeds were used to refinance a portion of the Company's short-term indebtedness and for general corporate purposes.

Credit Facilities

In April 2018, BHE terminated its $1.0 billion unsecured credit facility expiring May 2018 and amended and restated, with lender consent, its existing $2.0 billion unsecured credit facility expiring June 2020, increasing the lender commitment to $3.5 billion, extending the expiration date to June 2021 and increasing from one to two, the available one-year extension options, subject to lender consent.

In April 2018, PacifiCorp amended and restated its existing $400 million unsecured credit facility expiring June 2020, increasing the lender commitment to $600 million, extending the expiration date to June 2021 and increasing from one to two, the available one-year extension options, subject to lender consent.

In April 2018, PacifiCorp and MidAmerican Energy amended and restated their existing $600 million and $900 million unsecured credit facilities, respectively, each expiring June 2020, extending the expiration dates to June 2021 and reducing from two to one, the available one-year extension options, subject to lender consent.

In April 2018, Nevada Power and Sierra Pacific amended and restated their existing $400 million and $250 million secured credit facilities, respectively, each expiring June 2020, extending the expiration dates to June 2021 and reducing from two to one, the available one-year extension options, subject to lender consent.

In April 2018, ALP amended its existing C$750 million secured credit facility expiring December 2019, decreasing the lender commitment to C$500 million effective December 2018 and extending the expiration date to December 2022. ALP also amended its C$75 million secured credit facility expiring December 2019, extending the expiration date to December 2022.


(7)	Income Taxes

Tax Cuts and Jobs Act

2017 Tax Reform impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018, the one-time repatriation tax of foreign earnings and profits and limitations on bonus depreciation for utility property.

In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. The Company has recorded the impacts of 2017 Tax Reform and believes all the impacts to be complete with the exception of the repatriation tax on foreign earnings and interpretations of the bonus depreciation rules. The Company has determined the amounts recorded and the interpretations relating to these two items to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. The Company believes the estimates for the repatriation tax to be reasonable, however, additional time is required to validate the inputs to the foreign earnings and profits calculation, the basis on which the repatriation tax is determined, and additional guidance is required to determine state income tax implications. The Company also believes its interpretations for bonus depreciation to be reasonable, however, as the guidance is clarified, estimates may change. During the first half of 2018, the Company reduced the liability estimate by $45 million based on additional guidance for certain state income tax implications of the repatriation tax. During the third quarter of 2018, the Company recorded a current tax benefit and deferred tax expense of $37 million following clarified bonus depreciation guidance. As a result of 2017 Tax Reform and the nature of the Company's regulated businesses, the Company reduced the associated deferred income tax liabilities $14 million and increased regulatory liabilities by the same amount. The accounting will be completed by December 2018.

Iowa Senate File 2417

In May 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduces the state of Iowa corporate tax rate from 12% to 9.8% and eliminates corporate federal deductibility, both for tax years starting in 2021. GAAP requires the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. As a result of Iowa Senate File 2417, the Company reduced deferred income tax liabilities $61 million and decreased deferred income tax expense by $2 million. As it is probable the change in deferred taxes for the Company's regulated businesses will be passed back to customers through regulatory mechanisms, the Company increased net regulatory liabilities by $59 million. In connection with Iowa Senate File 2417, the Company determined it was more appropriate to present the deferred income tax assets of $609 million associated with the state of Iowa net operating loss carryforward as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity. As the Company does not currently expect to receive any income tax amounts from Berkshire Hathaway related to the state of Iowa prior to the 2021 effective date, the Company has remeasured the long-term income tax receivable with Berkshire Hathaway at the enactment date and recorded a decrease to the long-term income tax receivable from Berkshire Hathaway of $115 million for the nine-month period ended September 30, 2018.

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,
	2018		2017		2018		2017

Federal statutory income tax rate	21	%	35	%	21	%	35	%
Income tax credits	(19	)	(19	)	(29	)	(18	)
State income tax, net of federal income tax benefit	1		—		(6	)	(1	)
Income tax effect of foreign income	—		(3	)	(3	)	(4	)
Effects of ratemaking	(2	)	—		(3	)	—
Equity income	—		1		—		1
Other, net	1		1		1		—
Effective income tax rate	2	%	15	%	(19	)%	13	%

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.

The Company's provision for income tax has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its United States federal and Iowa state income tax returns and substantially all of its currently payable or receivable income tax is remitted to or received from Berkshire Hathaway. For the nine-month periods ended September 30, 2018 and 2017, the Company received net cash payments for federal income taxes from Berkshire Hathaway totaling $450 million and $659 million, respectively. As of September 30, 2018, the Company had a long-term income tax receivable from Berkshire Hathaway of $494 million for Iowa state income tax reflected as a component of BHE's shareholders' equity.


(8)	Employee Benefit Plans

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~~The Company adopted this guidance ~~is effective~~January 1, 2018 prospectively for ~~interim~~the capitalization of the service cost component in the Consolidated Balance Sheets 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~~Consolidated Statements of ~~operations and prospectively for~~Operations applying the ~~capitalization of~~practical expedient to use the ~~service cost component~~amounts previously disclosed 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 November 2016,~~Statements as 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~~estimation basis for applying the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. The Company 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 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 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.requirement. As a result, ofamounts other than the ~~various acquisitions, the Company acquired assets of $1.1 billion, assumed liabilities of $476 million~~service cost for pension 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 millionother postretirement benefit plans 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~~$16 million and ~~$860~~$8 million, ~~respectively.~~respectively, have been reclassified to Other, net in the Consolidated Statements of Operations.


(8)	~~Employee Benefit Plans~~

Domestic Operations

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


	Three-Month Periods						Nine-Month Periods						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Pension:
Service cost	$	6		$	7		$	18		$	22		$	5		$	6		$	15		$	18
Interest cost	29			31			87			94			26			29			78			87
Expected return on plan assets	(40		)	(39		)	(120		)	(120		)	(41		)	(40		)	(123		)	(120		)
Net amortization	7			12			22			36			8			7			23			22
Net periodic benefit cost	$	2		$	11		$	7		$	32
Net periodic benefit (credit) cost													$	(2	)	$	2		$	(7	)	$	7

Other postretirement:
Service cost	$	3		$	2		$	7		$	7		$	1		$	3		$	6		$	7
Interest cost	7			7			21			23			7			7			19			21
Expected return on plan assets	(9		)	(10		)	(30		)	(31		)	(9		)	(9		)	(31		)	(30		)
Net amortization	(3		)	(2		)	(10		)	(9		)	(3		)	(3		)	(9		)	(10		)
Net periodic benefit credit	$	(2	)	$	(3	)	$	(12	)	$	(10	)	$	(4	)	$	(2	)	$	(15	)	$	(12	)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be ~~$15~~$39 million and $5$7 million, respectively, during ~~2017.~~2018. As of September 30, ~~2017, $9~~2018, $34 million and $5$6 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						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017

Service cost	$	6		$	5		$	19		$	16		$	5		$	6		$	15		$	19
Interest cost	15			17			44			55			14			15			42			44
Expected return on plan assets	(25		)	(27		)	(74		)	(85		)	(25		)	(25		)	(78		)	(74		)
Settlement	18			—			18			—			12			18			36			18
Net amortization	17			11			50			34			9			17			38			50
Net periodic benefit cost	$	31		$	6		$	57		$	20		$	15		$	31		$	53		$	57

Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £4546 million during ~~2017~~2018. As of September 30, ~~2017~~2018, £3435 million, or $4347 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~~9)	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
																Input Levels for Fair Value Measurements
																Level 1			Level 2			Level 3			Other⁽¹⁾			Total
As of September 30, 2018
Assets:
Commodity derivatives	$	5		$	49		$	87		$	(22	)	$	119		$	—		$	53		$	99		$	(35	)	$	117
Interest rate derivatives	—			16			7			—			23			3			22			11			—			36
Mortgage loans held for sale	—			359			—			—			359			—			501			—			—			501
Money market mutual funds⁽²⁾	586			—			—			—			586			716			—			—			—			716
Debt securities:
United States government obligations	161			—			—			—			161			183			—			—			—			183
International government obligations	—			3			—			—			3			—			4			—			—			4
Corporate obligations	—			36			—			—			36			—			47			—			—			47
Municipal obligations	—			2			—			—			2			—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			2			—			—			2
Equity securities:
United States companies	250			—			—			—			250			300			—			—			—			300
International companies	1,190			—			—			—			1,190			1,622			—			—			—			1,622
Investment funds	147			—			—			—			147			187			—			—			—			187
	$	2,339		$	467		$	94		$	(22	)	$	2,878		$	3,011		$	629		$	110		$	(35	)	$	3,715
Liabilities:
Commodity derivatives	$	(2	)	$	(199	)	$	(27	)	$	96		$	(132	)	$	(1	)	$	(168	)	$	(15	)	$	110		$	(74	)
Interest rate derivatives	(1		)	(11		)	(1		)	—			(13		)	—			(5		)	(1		)	—			(6		)
	$	(3	)	$	(210	)	$	(28	)	$	96		$	(145	)	$	(1	)	$	(173	)	$	(16	)	$	110		$	(80	)



	Input Levels for Fair Value Measurements
	Level 1			Level 2			Level 3			Other⁽¹⁾			Total
As of December 31, 2017
Assets:
Commodity derivatives	$	1		$	42		$	104		$	(29	)	$	118
Interest rate derivatives	—			15			9			—			24
Mortgage loans held for sale	—			465			—			—			465
Money market mutual funds⁽²⁾	685			—			—			—			685
Debt securities:
United States government obligations	176			—			—			—			176
International government obligations	—			5			—			—			5
Corporate obligations	—			36			—			—			36
Municipal obligations	—			2			—			—			2
Equity securities:
United States companies	288			—			—			—			288
International companies	1,968			—			—			—			1,968
Investment funds	178			—			—			—			178
	$	3,296		$	565		$	113		$	(29	)	$	3,945
Liabilities:
Commodity derivatives	$	(3	)	$	(167	)	$	(10	)	$	105		$	(75	)
Interest rate derivatives	—			(8		)	—			—			(8		)
	$	(3	)	$	(175	)	$	(10	)	$	105		$	(83	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $8575 million and $7476 million as of September 30, ~~2017~~2018 and December 31, ~~2016~~2017, 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.~~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. 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								Three-Month Periods						Nine-Month Periods
	Ended September 30,								Ended September 30,								Ended September 30,						Ended September 30,
				Interest			Auction					Interest			Auction					Interest						Interest
	Commodity			Rate			Rate		Commodity			Rate			Rate		Commodity			Rate			Commodity			Rate
	Derivatives			Derivatives			Securities		Derivatives			Derivatives			Securities		Derivatives			Derivatives			Derivatives			Derivatives
2017:
2018:
Beginning balance	$	81		$	8		$	—	$	60		$	6		$	—	$	83		$	17		$	94		$	9
Changes included in earnings	7			34			—		19			100			—		(1		)	54			3			140
Changes in fair value recognized in OCI	(1		)	—			—		(3		)	—			—		1			—			1			—
Changes in fair value recognized in net regulatory assets	(3		)	—			—		(5		)	—			—		3			—			(11		)	—
Purchases	—			8			—		1			6			—		1			—			2			—
Settlements	2			(37		)	—		14			(99		)	—		(3		)	(61		)	(5		)	(139		)
Ending balance	$	86		$	13		$	—	$	86		$	13		$	—	$	84		$	10		$	84		$	10


	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:
2017:
Beginning balance	$	44		$	14		$	18	$	47		$	4		$	44		$	81		$	8		$	60		$	6
Changes included in earnings	9			49			—		8			103			—			7			34			19			100
Changes in fair value recognized in OCI	(2		)	—			—		(2		)	—			6			(1		)	—			(3		)	—
Changes in fair value recognized in net regulatory assets	(1		)	—			—		(12		)	—			—			(3		)	—			(5		)	—
Purchases	1			—			—		1			—			—			—			8			1			6
Redemptions	—			—			—		—			—			(32		)
Settlements	5			(52		)	—		14			(96		)	—			2			(37		)	14			(99		)
Ending balance	$	56		$	11		$	18	$	56		$	11		$	18		$	86		$	13		$	86		$	13

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



	As of September 30, 2018				As of December 31, 2017
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	37,558	$	40,520	$	35,193	$	40,522


(~~11)~~10)	Commitments and Contingencies

~~Fuel, Capacity and Transmission Contract~~ Commitments

During the nine-month period ended September 30, ~~2017, MidAmerican Energy amended~~2018, PacifiCorp entered into non-cancelable agreements through 2045 totaling $1.0 billion related to power purchase agreements to meet customer requests for renewable energy, $566 million related to agreements for repowering certain existing wind facilities in Wyoming, Washington and Oregon and $273 million related to fuel supply contracts. The power purchase agreements are from facilities that have not yet achieved commercial operation. To the extent any of ~~its natural gas supply and transportation contracts increasing minimum payments~~these facilities do not achieve commercial operation by ~~$247 million through 2021 and $70 million for 2022 through 2037.~~

~~Construction Commitments~~contractually agreed upon dates, PacifiCorp has no obligation to the counterparty.

During the nine-month period ended September 30, ~~2017,~~2018, MidAmerican Energy entered into ~~contracts~~firm commitments totaling ~~$675~~$563 million for the remainder of 2018 through 2020 related to 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.~~facilities.

~~Operating Leases and~~ Easements

During the nine-month period ended September 30, ~~2017,~~2018, MidAmerican Energy entered into non-cancelable easements with minimum payments totaling ~~$114~~$422 million through ~~2057~~2058 for land in Iowa on which some of its wind-powered generating facilities will be located.

Maintenance and Service Contracts

During the nine-month period ended September 30, 2018, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling $226 million through 2028.

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

Congress failed to pass legislation needed to implement the original KHSA. OnIn April 6, 2016, ~~PacifiCorp,~~the principal parties to the KHSA (PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and ~~Commerce and other stakeholders~~Commerce) executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, onin September ~~23,~~ 2016, PacifiCorp and the Klamath River Renewal Corporation ("KRRC"), a private, independent nonprofit 501(c)(3) organization formed by certain signatories of the amended KSHA, 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 onin September ~~23,~~ 2016, the KRRC filed an application with the FERC to surrender the license and decommission the same four 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. In March 2018, the FERC issued an order splitting the existing license for the Klamath Project into two licenses: the Klamath Project (P‑2082) contains East Side, West Side, Keno and Fall Creek developments; the new Lower Klamath Project (P‑14803) contains J.C. Boyle, Copco No. 1, Copco No. 2 and Iron Gate developments. In the same order, the FERC deferred consideration of the transfer of the license for the Lower Klamath facilities from PacifiCorp to the KRRC until some point in the future. PacifiCorp is currently the licensee for both the Klamath Project and Lower Klamath Project facilities and will retain ownership of the Klamath Project facilities after the approval and transfer of the Lower Klamath Project facilities. In April 2018, PacifiCorp filed a motion to stay the effective date of the license amendment until transfer is approved. In June 2018, the FERC granted PacifiCorp's motion to stay the effective date of the Lower Klamath Project license and all related compliance obligations, pending a Commission order on the license transfer. Meanwhile, the FERC continues to assess the KRRC's capacity to become a project licensee for purposes of dam removal.

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~~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

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.


(11)	Revenue from Contracts with Customers

Adoption

In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" ("ASC 606") and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize revenue from contracts with customers ("Customer 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. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. The Company adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.

Customer Revenue

The Company recognizes revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

Energy Products and Services

A majority of the Company's energy revenue is derived from tariff based sales arrangements approved by various regulatory bodies. These tariff based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. The Company's energy revenue that is nonregulated primarily relates to the Company's renewable energy business. Other revenue consists primarily of revenue recognized in accordance with ASC 815, "Derivatives and Hedging", ASC 840, "Leases" and amounts not considered Customer Revenue within ASC 606.

Revenue recognized is equal to what the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. As of September 30, 2018 and December 31, 2017, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $624 million and $665 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

The following table summarizes the Company's energy products and services revenue by regulated energy and nonregulated energy, with further disaggregation of regulated energy by customer class and line of business, including a reconciliation to the Company's reportable segment information included in Note 14 (in millions):



	For the Three-Month Period Ended September 30, 2018
	PacifiCorp			MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group			BHE Transmission		BHE Renewables		BHE and Other⁽¹⁾			Total
Customer Revenue:
Regulated:
Retail Electric	$	1,323		$	647	$	1,002	$	—	$	—		$	—	$	—	$	(1	)	$	2,971
Retail Gas	—			83		13		—		—			—		—		—			96
Wholesale⁽²⁾	(10		)	82		9		—		—			—		—		(1		)	80
Transmission and distribution	30			14		28		196		—			171		—		—			439
Interstate pipeline	—			—		—		—		283			—		—		(25		)	258
Other	—			—		—		—		—			—		—		—			—
Total Regulated	1,343			826		1,052		196		283			171		—		(27		)	3,844
Nonregulated	—			2		—		10		—			3		235		176			426
Total Customer Revenue	1,343			828		1,052		206		283			174		235		149			4,270
Other revenue⁽³⁾	26			4		7		27		(24		)	—		85		24			149
Total	$	1,369		$	832	$	1,059	$	233	$	259		$	174	$	320	$	173		$	4,419



	For the Nine-Month Period Ended September 30, 2018
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group			BHE Transmission		BHE Renewables		BHE and Other⁽¹⁾			Total
Customer Revenue:
Regulated:
Retail Electric	$	3,534	$	1,538	$	2,232	$	—	$	—		$	—	$	—	$	(1	)	$	7,303
Retail Gas	—		428		72		—		—			—		—		—			500
Wholesale	21		262		26		—		—			—		—		(3		)	306
Transmission and distribution	82		44		73		661		—			525		—		—			1,385
Interstate pipeline	—		—		—		—		893			—		—		(91		)	802
Other	—		—		1		—		—			—		—		—			1
Total Regulated	3,637		2,272		2,404		661		893			525		—		(95		)	10,297
Nonregulated	—		7		1		31		—			6		538		478			1,061
Total Customer Revenue	3,637		2,279		2,405		692		893			531		538		383			11,358
Other revenue⁽³⁾	109		18		21		65		(22		)	—		182		87			460
Total	$	3,746	$	2,297	$	2,426	$	757	$	871		$	531	$	720	$	470		$	11,818


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


(2)	Includes net payments to counterparties for the financial settlement of certain non-derivative forward contracts for energy sales at PacifiCorp.


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

Real Estate Services

The Company's HomeServices reportable segment consists of separate brokerage, mortgage and franchise businesses. Rates charged for brokerage, mortgage and franchise real estate services are established through contractual arrangements that establish the transaction price and the allocation of the price amongst the separate performance obligations. Other revenue consists primarily of revenue related to the mortgage businesses recognized in accordance with ASC 815, "Derivatives and Hedging", ASC 825, "Financial Instruments" and ASC 860, "Transfers and Servicing."

The full-service residential real estate brokerage business has performance obligations to deliver integrated real estate services including brokerage services, title and closing services, property and casualty insurance, home warranties, relocation services, and other home-related services to customers. All performance obligations related to the full-service residential real estate brokerage business are satisfied in less than one year at the point in time when a real estate transaction is closed or when services are provided. Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title and escrow closing fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing. Payments for amounts billed are generally due from the customer at closing.

The franchise business operates a network that has performance obligations to provide the right to use certain brand names and other related service marks as well as to provide orientation programs, training and consultation services, advertising programs and other services to its franchisees. The performance obligations related to the franchise business are satisfied over time or when the services are provided. Franchise royalty fees are sales-based variable consideration and are based on a percentage of commissions earned by franchisees on real estate sales, which are recognized when the sale closes. Meetings and training revenue, referral fees, late fees, service fees and franchise termination fees are earned when services have been completed. Payments for amounts billed are generally due from the franchisee within 30 days of billing.

The following table summarizes the Company's real estate services revenue by line of business (in millions):



	HomeServices
	Three-Month Period		Nine-Month Period
	Ended September 30,		Ended September 30,
	2018		2018
Customer Revenue:
Brokerage	$	1,122	$	2,975
Franchise	18		52
Total Customer Revenue	1,140		3,027
Other revenue	78		225
Total	$	1,218	$	3,252

Contract Assets and Liabilities

In the event one of the parties to a contract has performed before the other, the Company would recognize a contract asset or contract liability depending on the relationship between the Company's performance and the customer's payment. As of September 30, 2018 and December 31, 2017, there were no material contract assets or contract liabilities recorded on the Consolidated Balance Sheets. During the three- and nine-month periods ended September 30, 2018, there was no material revenue recognized that was included in the contract liability balance at the beginning of the period or from performance obligations satisfied in previous periods.

Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of September 30, 2018, by reportable segment (in millions):



	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	835	$	5,879	$	6,714
BHE Transmission	176		—		176
Total	$	1,011	$	5,879	$	6,890


(12)	BHE Shareholders' Equity

Common Stock

For the nine-month periods ended September 30, 2018 and 2017, BHE repurchased from certain family interests of Mr. Walter Scott, Jr. 177,381 shares of its common stock for $107 million and 35,000 shares of its common stock for $19 million, respectively.


(1213)	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~~tax (in millions):


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

Balance, December 31, 2015	$	(438	)	$	(1,092	)	$	615	$	7		$	(908	)
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	)	$	(447	)	$	(1,675	)	$	585		$	26		$	(1,511	)
Other comprehensive income (loss)	16			535			542		(5		)	1,088			16			535			542			(5		)	1,088
Balance, September 30, 2017	$	(431	)	$	(1,140	)	$	1,127	$	21		$	(423	)	$	(431	)	$	(1,140	)	$	1,127		$	21		$	(423	)

Balance, December 31, 2017															$	(383	)	$	(1,129	)	$	1,085		$	29		$	(398	)
Adoption of ASU 2016-01															—			—			(1,085		)	—			(1,085		)
Other comprehensive income (loss)															50			(236		)	—			2			(184		)
Balance, September 30, 2018															$	(333	)	$	(1,365	)	$	—		$	31		$	(1,667	)

~~Reclassifications from AOCI to net income for the periods ended~~ ~~September 30, 2017~~ ~~and~~ ~~2016~~ ~~were insignificant.~~ For more information regarding ~~cash flow hedge reclassifications from AOCI to net income in their entirety,~~the adoption of ASU 2016-01, 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.~~5.


(1314)	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					Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,					Ended September 30,				Ended September 30,
	2017		2016		2017			2016		2018		2017		2018		2017
Operating revenue:
PacifiCorp	$	1,430	$	1,434	$	3,956		$	3,919	$	1,369	$	1,430	$	3,746	$	3,956
MidAmerican Funding	815		797		2,170			2,008		832		815		2,297		2,170
NV Energy	1,047		987		2,384			2,309		1,059		1,047		2,426		2,384
Northern Powergrid	221		220		685			748		233		221		757		685
BHE Pipeline Group	193		201		700			704		259		193		871		700
BHE Transmission	182		169		506			309		174		182		531		506
BHE Renewables	283		273		647			582		320		283		720		647
HomeServices	961		820		2,502			2,152		1,218		961		3,252		2,502
BHE and Other⁽¹⁾	151		191		453			523		173		151		470		453
Total operating revenue	$	5,283	$	5,092	$	14,003		$	13,254	$	5,637	$	5,283	$	15,070	$	14,003

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						Three-Month Periods					Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,					Ended September 30,
	2017			2016			2017			2016			2018			2017		2018			2017
Operating income:
Depreciation and amortization:
PacifiCorp	$	467		$	445		$	1,150		$	1,108		$	203		$	200	$	602		$	598
MidAmerican Funding	288			284			531			524			133			112		499			370
NV Energy	393			394			682			656			114			105		341			315
Northern Powergrid	81			90			308			373			62			55		189			156
BHE Pipeline Group	65			68			328			320			27			42		99			115
BHE Transmission	86			81			236			35			61			58		184			165
BHE Renewables	157			157			256			233			68			63		198			187
HomeServices	79			87			191			179			14			16		37			38
BHE and Other⁽¹⁾	8			(21		)	(38		)	(36		)	(1		)	—		(2		)	(1		)
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
Total depreciation and amortization													$	681		$	651	$	2,147		$	1,943


Interest expense:
Operating income:
PacifiCorp	$	95	$	95	$	285	$	286	$	386		$	461		$	917		$	1,133
MidAmerican Funding	59		55		177		164		278			284			444			517
NV Energy	57		60		173		190		307			393			540			683
Northern Powergrid	34		33		98		105		102			106			360			346
BHE Pipeline Group	11		13		33		39		105			66			388			328
BHE Transmission	45		40		125		114		82			86			244			236
BHE Renewables	51		51		153		148		176			157			308			256
HomeServices	1		1		3		2		85			79			185			191
BHE and Other⁽¹⁾	111		112		332		353		2			8			(20		)	(38		)
Total interest expense	$	464	$	460	$	1,379	$	1,401
Total operating income									1,523			1,640			3,366			3,652
Interest expense									(453		)	(464		)	(1,380		)	(1,379		)
Capitalized interest									17			14			44			34
Allowance for equity funds									30			24			75			59
Interest and dividend income									27			32			85			85
Gains (losses) on marketable securities, net									260			3			(336		)	8
Other, net									19			(17		)	50			8
Total income before income tax expense and equity income									$	1,423		$	1,232		$	1,904		$	2,467

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



Interest expense:
PacifiCorp	$	96	$	95	$	288	$	285
MidAmerican Funding	61		59		185		177
NV Energy	52		57		169		173
Northern Powergrid	34		34		107		98
BHE Pipeline Group	11		11		31		33
BHE Transmission	42		45		127		125
BHE Renewables	49		51		150		153
HomeServices	6		1		16		3
BHE and Other⁽¹⁾	102		111		307		332
Total interest expense	$	453	$	464	$	1,380	$	1,379

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



	Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,
	2018		2017		2018		2017
Operating revenue by country:
United States	$	5,209	$	4,869	$	13,757	$	12,793
United Kingdom	232		221		754		685
Canada	174		182		531		506
Philippines and other	22		11		28		19
Total operating revenue by country	$	5,637	$	5,283	$	15,070	$	14,003



Income before income tax expense and equity income by country:
United States	$	1,290	$	1,113	$	1,501	$	2,065
United Kingdom	59		49		220		213
Canada	43		47		125		127
Philippines and other	31		23		58		62
Total income before income tax expense and equity income by country	$	1,423	$	1,232	$	1,904	$	2,467



	As of
	September 30,		December 31,
	2018		2017
Assets:
PacifiCorp	$	23,501	$	23,086
MidAmerican Funding	19,499		18,444
NV Energy	14,078		13,903
Northern Powergrid	7,527		7,565
BHE Pipeline Group	5,285		5,134
BHE Transmission	8,863		9,009
BHE Renewables	8,590		7,687
HomeServices	2,860		2,722
BHE and Other⁽¹⁾	1,659		2,658
Total assets	$	91,862	$	90,208


(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~~2018 (in millions):

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



										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, 2017	$	1,129	$	2,102	$	2,369	$	991		$	73	$	1,571		$	95	$	1,348	$	9,678
Acquisitions																	70		70
Foreign currency translation							(24		)			(41		)					(65		)
September 30, 2018	$	1,129	$	2,102	$	2,369	$	967		$	73	$	1,530		$	95	$	1,418	$	9,683


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~~Company's operations are 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~~investing in solar, wind, geothermal and hydroelectric ~~sources under long-term contracts,~~projects, the second largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States. 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~~2018 and ~~2016~~2017

Overview

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


	Third Quarter											First Nine Months											Third Quarter										First Nine Months
	2017			2016			Change					2017			2016			Change					2018		2017			Change					2018			2017			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	263		$	254		$	9		4	%	$	618		$	596		$	22		4	%	$	270	$	263		$	7		3	%	$	603		$	618		$	(15	)	(2	)%
MidAmerican Funding	383			318			65			20		616			518			98			19		479		383			96			25		685			616			69			11
NV Energy	223			222			1			—		347			319			28			9		201		223			(22		)	(10	)	311			347			(36		)	(10	)
Northern Powergrid	39			60			(21		)	(35	)	174			228			(54		)	(24	)	44		39			5			13		169			174			(5		)	(3	)
BHE Pipeline Group	35			36			(1		)	(3	)	183			175			8			5		79		35			44			*		286			183			103			56
BHE Transmission	58			57			1			2		171			173			(2		)	(1	)	55		58			(3		)	(5	)	164			171			(7		)	(4	)
BHE Renewables	89			98			(9		)	(9	)	194			142			52			37		139		89			50			56		304			194			110			57
HomeServices	45			49			(4		)	(8	)	107			105			2			2		60		45			15			33		127			107			20			19
BHE and Other	(67		)	(58		)	(9		)	(16	)	(212		)	(194		)	(18		)	(9	)	74		(67		)	141			*		(363		)	(212		)	(151		)	(71	)
Total net income attributable to BHE shareholders	$	1,068		$	1,036		$	32		3		$	2,198		$	2,062		$	136		7		$	1,401	$	1,068		$	333		31		$	2,286		$	2,198		$	88		4

* Not meaningful

Net income attributable to BHE shareholders increased ~~$32~~$333 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 due to an after-tax unrealized gain on the ~~following:~~investment in BYD Company Limited in 2018 totaling $182 million and the following factors:

PacifiCorp's net income increased $9$7 million primarily due to ~~higher gross margins~~a decrease in income tax expense of ~~$30~~$78 million ~~excluding~~from a lower federal tax rate due to the impact of ~~demand side management program revenue (offset in operating expense)~~the Tax Cuts and Jobs Act enacted on December 22, 2017 ("2017 Tax Reform"), partially offset by lower utility margin of $61 million and higher ~~depreciation~~operations and ~~amortization~~maintenance expense of ~~$7 million, primarily from additional plant placed in-service. Gross margins increased~~$12 million. Utility margin decreased due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $53 million, higher ~~retail customer volumes,~~natural gas costs, higher purchased electricity costs and lower ~~coal costs, lower natural gas-fueled generation, and higher wheeling~~wholesale revenue, partially offset by higher ~~purchased electricity costs, lower average~~ retail ~~rates~~customer volumes and lower ~~wholesale revenue from lower volumes.~~coal costs. Retail customer volumes increased ~~2.1%~~1.8% due to ~~impacts of weather on~~higher customer usage, primarily from industrial, commercial and 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~~across the service territory, offset by ~~lower irrigation usage in Idaho and Oregon and lower industrial usage in Utah and Oregon.~~

impacts of weather across the service territory.

MidAmerican Funding's net income increased ~~$65~~$96 million primarily due to a higher income tax benefit of $95 million from a $53 million increase in recognized production tax credits ~~of $45 million~~and a lower federal tax rate 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),~~2017 Tax Reform, higher electric utility margin of $10 million and ~~lower depreciation~~higher allowances for borrowed and ~~amortization~~equity funds 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~~increases for Iowa revenue sharing. Electric utility margin increased due to higher retail customer volumes ~~lower natural gas-fueled generation,~~of 5.9%, primarily from industrial growth and the favorable impact of weather, higher electric wholesale revenue ~~from higher short-term market prices and volumes~~ and higher ~~wheeling revenue,~~recoveries through bill riders, partially offset by lower average retail rates of $33 million, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform, and higher generation and purchased power costs.

NV Energy's net income decreased $22 million primarily due to an increase in operations and maintenance expense of $60 million, primarily due to earnings sharing of $36 million established in 2018 as part of the Nevada Power 2017 regulatory rate review and higher political activity expenses, a decrease in electric utility margin of $17 million and an increase in depreciation and amortization of $9 million as a result of various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review, partially offset by a decrease in income tax expense of $55 million primarily from a lower federal tax rate due to the impact of 2017 Tax Reform. Electric utility margin decreased due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $30 million, partially offset by higher retail customer volumes of 2.9%, mainly from the favorable impact of weather.

Northern Powergrid's net income increased $5 million primarily due to lower overall pension expense of $4 million, which includes pension settlement losses recognized in 2017 and 2018, and higher smart meter net income of $2 million reflecting growth in that business.

BHE Pipeline Group's net income increased $44 million primarily due to higher transportation revenue of $58 million at Northern Natural Gas and Kern River from higher volumes and rates due to unique market opportunities, partially offset by $30 million of higher operations and maintenance expense, primarily due to increased pipeline integrity projects at Northern Natural Gas.

BHE Transmission's net income decreased $3 million primarily due to lower earnings at AltaLink from the release of contingent liabilities in 2017 and a stronger United States dollar, partially offset by higher non-regulated revenue.

BHE Renewables' net income increased $50 million primarily due to $35 million of increased revenue from overall higher generation and pricing at existing projects, $15 million of 2017 make-whole payments associated with early debt retirements and $8 million of net income from additional wind and solar capacity placed in-service, partially offset by an unfavorable derivative valuation movement of $8 million and unfavorable earnings of $3 million from tax equity investments, largely due to higher equity losses from certain tax equity investments due to unfavorable operating results, partially offset by earnings from additional tax equity investments.

HomeServices' net income increased $15 million primarily due to net income of $19 million contributed from acquired businesses and a decrease in income tax expense from a lower federal tax rate due to the impact of 2017 Tax Reform, partially offset by lower margin and higher operating expenses at existing businesses and higher interest expense from increased borrowings related to acquisitions.

BHE and Other had net income of $74 million for the third quarter of 2018 compared to a net loss of $67 million for the third quarter of 2017 primarily due to the aforementioned after-tax unrealized gain on the investment in BYD Company Limited totaling $182 million, partially offset by lower federal income tax credits recognized on a consolidated basis, higher other operating costs and a lower income tax benefit of $12 million from a lower federal tax rate due to the impact of 2017 Tax Reform.

Net income attributable to BHE shareholders increased $88 million for the first nine months of 2018 compared to 2017 due to the following factors, partially offset by an after-tax unrealized loss on the investment in BYD Company Limited in 2018 totaling $250 million:

PacifiCorp's net income decreased $15 million primarily due to lower utility margin of $205 million and higher operations and maintenance expenses of $6 million, partially offset by a decrease in income tax expense of $194 million from a lower federal tax rate due to the impact of 2017 Tax Reform. Utility margin decreased due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $159 million, lower retail customer volumes, higher purchased electricity costs and higher natural gas costs, partially offset by lower ~~average retail rates.~~coal costs. Retail customer volumes ~~increased 2.4%~~decreased 0.9% due to ~~impacts~~the unfavorable impact of weather across the service territory and lower customer usage, primarily ~~on residential~~from industrial customers in Oregon ~~Washington~~ and Utah, partially offset by higher commercial and irrigation customer 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.~~territory.

MidAmerican Funding's net income increased ~~$98~~$69 million primarily due to a higher income tax benefit of $124 million from a lower federal tax rate due to the impact of 2017 Tax Reform and a $44 million increase in recognized production tax credits, higher electric utility margin of ~~$71~~$84 million, ~~due to~~ higher ~~generation from wind-powered facilities placed in-service in the second half~~allowances for borrowed and equity funds of ~~2016~~$19 million and higher ~~electric gross margins~~natural gas utility margin of ~~$60~~$12 million, ~~excluding the impact of demand side management program revenue (offset in operating expense),~~ partially offset by higher depreciation and amortization of ~~$31~~$130 million ~~primarily due to accruals~~from increases for Iowa ~~regulatory arrangements~~revenue sharing and ~~the increase~~additional plant in-service, higher wind-powered generation maintenance of $17 million, higher fossil-fueled generation maintenance of $12 million and increases in ~~wind-powered generating facilities,~~other operations and ~~higher operating~~maintenance expenses. Electric ~~gross margins~~utility margin increased due to ~~higher wholesale revenue from higher sales volumes and prices,~~ higher recoveries through bill riders, higher retail customer volumes of 6.9% from industrial growth and the favorable impact of weather and higher ~~transmission~~electric wholesale revenue, partially offset by lower average retail rates of $86 million, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform, and 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~~decreased $36 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 operations and maintenance expense of $77 million, primarily due to earnings sharing of $42 million established in 2018 as part of the ~~average number~~Nevada Power 2017 regulatory rate review and higher political activity expenses, a decrease in electric utility margin of ~~customers, customer usage patterns~~$38 million and an increase in ~~transmission revenues.~~depreciation and amortization of $26 million as a result of various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review, partially offset by a decrease in income tax expense of $99 million primarily from a lower federal tax rate due to the impact of 2017 Tax Reform. Electric utility margin decreased due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $52 million, partially offset by higher retail customer volumes of 1.1%, mainly due to the favorable impact of weather.

Northern Powergrid's net income decreased ~~$54~~$5 million primarily due to $22 million of higher distribution-related operating and depreciation expenses and higher pension expense of $14 million, largely resulting from pension settlement losses recognized in 2018 due to higher lump sum payments, partially offset by the ~~stronger~~weaker United States dollar of ~~$19~~$11 million, higher ~~pension expense of $21 million, lower~~ distribution revenue of ~~$17~~$10 million and ~~$17~~higher smart meter net income of $3 million ~~of deferred income tax benefits reflected~~reflecting growth 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 Gasthat business. Distribution revenue ~~decreased~~increased mainly due to ~~lower units distributed, the recovery in 2016 of the December 2013 customer rebate and~~higher tariff rates, partially offset by unfavorable movements in regulatory ~~provisions, partially offset by higher tariff rates.~~provisions.

BHE Pipeline ~~Group’s~~Group's net income increased $8$103 million primarily due to higher transportation revenue of $102 million at Northern Natural Gas and Kern River from higher volumes and rates due to unique market opportunities and colder temperatures and a ~~reduction~~decrease in ~~expenses and regulatory liabilities related~~income tax expense of $30 million from a lower federal tax rate due to the impact of ~~an alternative rate structure approved~~2017 Tax Reform, partially offset by ~~the FERC at Kern River~~$49 million of higher operations and ~~higher transportation revenues~~maintenance expense, primarily due to increased pipeline integrity projects 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$7 million ~~from~~primarily due to 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~~a regulatory rate order 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.2017.

BHE Renewables' net income increased ~~$52~~$110 million ~~mainly~~primarily due to ~~favorable earnings~~$59 million of increased revenue from ~~tax equity investments reaching commercial operation,~~overall higher generation and pricing at existing projects, $20 million of net income from additional wind and solar capacity placed in-service, ~~higher generation at the Solar Star projects~~favorable earnings of $16 million from tax equity investments, largely due to ~~transformer related forced outages in 2016 and higher production at the Casecnan project due to higher rainfall,~~earnings from additional tax equity investments, partially offset by higher equity losses from certain tax equity investments due to unfavorable operating results, $15 million of make-whole ~~payments associated with the~~premiums paid in 2017 due to early ~~redemptions~~debt retirements and a settlement of ~~certain project debt.~~$7 million received in 2018 related to transformer issues in 2016, partially offset by an unfavorable derivative valuation movement of $13 million.

HomeServices' net income increased $2$20 million primarily due to ~~higher earnings at franchise~~net income of $44 million contributed from acquired businesses and a decrease in income tax expense from a lower federal tax rate due to the impact of 2017 Tax Reform, partially offset by lower ~~earnings~~margin and higher operating expenses at ~~brokerage~~existing businesses and ~~mortgage businesses.~~higher interest expense from increased borrowings related to acquisitions.

BHE and Other net loss increased ~~$18~~$151 million primarily due to the aforementioned after-tax unrealized loss on the investment in BYD Company Limited totaling $250 million and a lower income tax benefit of $41 million from a lower federal tax rate due to the impact of 2017 Tax Reform, partially offset by lower consolidated state income tax expense, including a reduction to the state provision for the repatriation tax of $45 million, lower United States income tax on foreign earnings and higher 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.basis.

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									Third Quarter									First Nine Months
	2017		2016		Change					2017		2016		Change					2018		2017		Change					2018		2017		Change
Operating revenue:
PacifiCorp	$	1,430	$	1,434	$	(4	)	—	%	$	3,956	$	3,919	$	37		1	%	$	1,369	$	1,430	$	(61	)	(4	)%	$	3,746	$	3,956	$	(210	)	(5	)%
MidAmerican Funding	815		797		18			2		2,170		2,008		162			8		832		815		17			2		2,297		2,170		127			6
NV Energy	1,047		987		60			6		2,384		2,309		75			3		1,059		1,047		12			1		2,426		2,384		42			2
Northern Powergrid	221		220		1			—		685		748		(63		)	(8	)	233		221		12			5		757		685		72			11
BHE Pipeline Group	193		201		(8		)	(4	)	700		704		(4		)	(1	)	259		193		66			34		871		700		171			24
BHE Transmission	182		169		13			8		506		309		197			64		174		182		(8		)	(4	)	531		506		25			5
BHE Renewables	283		273		10			4		647		582		65			11		320		283		37			13		720		647		73			11
HomeServices	961		820		141			17		2,502		2,152		350			16		1,218		961		257			27		3,252		2,502		750			30
BHE and Other	151		191		(40		)	(21	)	453		523		(70		)	(13	)	173		151		22			15		470		453		17			4
Total operating revenue	$	5,283	$	5,092	$	191		4		$	14,003	$	13,254	$	749		6		$	5,637	$	5,283	$	354		7		$	15,070	$	14,003	$	1,067		8

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



Operating income:
PacifiCorp	$	386	$	461	$	(75	)	(16	)%	$	917		$	1,133		$	(216	)	(19	)%
MidAmerican Funding	278		284		(6		)	(2	)	444			517			(73		)	(14	)
NV Energy	307		393		(86		)	(22	)	540			683			(143		)	(21	)
Northern Powergrid	102		106		(4		)	(4	)	360			346			14			4
BHE Pipeline Group	105		66		39			59		388			328			60			18
BHE Transmission	82		86		(4		)	(5	)	244			236			8			3
BHE Renewables	176		157		19			12		308			256			52			20
HomeServices	85		79		6			8		185			191			(6		)	(3	)
BHE and Other	2		8		(6		)	(75)		(20		)	(38		)	18			47
Total operating income	$	1,523	$	1,640	$	(117	)	(7	)	$	3,366		$	3,652		$	(286	)	(8	)

PacifiCorp

Operating revenue decreased $4$61 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 due to lower retail revenue of $8$40 million ~~partially offset by higher~~and lower wholesale and other revenue of $4$21 million. Retail revenue decreased $59 million due to lower average rates, ~~and~~including the impact of a lower ~~demand side management program revenue (offset in operating expense), primarily driven by the establishment~~federal tax rate due to 2017 Tax Reform of ~~the Utah Sustainable Transportation and Energy Plan program,~~$53 million, partially offset by $19 million from higher ~~customer~~ volumes. Retail customer volumes increased ~~2.1%~~1.8% due to ~~impacts of weather on~~higher usage, primarily from industrial, commercial and 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~~across the service territory, offset by ~~lower irrigation usage in Idaho and Oregon, and lower industrial usage in Utah and Oregon.~~impacts of weather across the service territory. Wholesale and other revenue ~~increased~~decreased primarily due to ~~higher wheeling and REC revenues,~~lower wholesale market prices, partially offset by ~~lower~~higher wholesale sales volumes.

Operating income ~~increased $22~~decreased $75 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to lower ~~operating expenses~~utility margin of ~~$23~~$61 million and higher ~~gross margins~~operations and maintenance expense of ~~$9 million, partially offset by higher depreciation and amortization of $7 million from additional plant placed in-service. Operating expenses~~$12 million. Utility margin decreased due to lower average retail rates, including the impact of a ~~decrease in demand side management program expense (offset in operating revenue)~~lower federal tax rate due to 2017 Tax Reform of ~~$21~~$53 million, higher natural gas costs from higher generation volumes, higher purchased electricity costs from higher prices and volumes and lower ~~pension expense. Gross margins increased due to~~wholesale revenue, partially offset by higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, higher retail customer volumes and lower coal costs ~~and~~largely from favorable prices.

Operating revenue decreased $210 million for the first nine months of 2018 compared to 2017 due to lower ~~natural gas-fueled generation,~~retail revenue of $218 million, partially offset by higher wholesale and other revenue of $8 million. Retail revenue decreased $185 million due to lower average rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $159 million, and $33 million from lower volumes. Retail customer volumes decreased 0.9% due to the unfavorable impact of weather across the service territory and lower usage, primarily from industrial customers in Oregon and Utah, partially offset by higher commercial and irrigation usage in Utah and an increase in the average number of customers across the service territory. Wholesale and other revenue increased due to higher other revenue.

Operating income decreased $216 million for the first nine months of 2018 compared to 2017 primarily due to lower utility margin of $205 million and higher operations and maintenance expenses of $6 million. Utility margin decreased due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $159 million, lower retail customer volumes, 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~~natural gas costs from higher ~~customer~~generation volumes offset by lower prices, 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~~lower generation volumes and prices.

MidAmerican Funding

Operating revenue increased ~~$18~~$17 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 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~~$20 million. Electric operating revenue increased due to higher wholesale and other revenue of ~~$53~~$18 million and higher retail revenue of ~~$52~~$2 million. Electric wholesale and other revenue increased primarily due ~~primarily~~ to ~~higher~~an increase in wholesale volumes of ~~$34 million, higher transmission revenue of $11 million and higher wholesale prices of $6~~$17 million. Electric retail revenue increased ~~$47~~$29 million from industrial growth and higher customer usage, $4 million from higher recoveries through bill riders (substantially offset in cost of ~~sales, operating~~fuel and energy, operations and maintenance expense and income tax expense) and ~~$33 million from non-weather usage and rate factors, including higher industrial sales volumes, partially offset by $28~~$2 million from the impact of ~~milder temperatures~~weather in ~~2017.~~2018, partially offset by lower average rates of $33 million, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform. Electric retail customer volumes increased ~~1.5%~~5.9% primarily from industrial growth ~~partially offset by~~and the ~~unfavorable~~favorable 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.weather.

Operating income ~~increased $7~~decreased $6 million for the ~~first nine months~~third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to higher ~~electric gross margins~~depreciation and amortization of ~~$75~~$22 million and higher ~~natural gas gross margins~~wind-powered generation maintenance of $3$6 million, partially offset by higher ~~depreciation~~electric utility margin of $10 million, net of a decrease in electric demand-side management program revenue of $2 million (offset in operations and ~~amortization~~maintenance expense), higher natural gas utility margin of ~~$31 million, higher property and other taxes of $6~~$4 million and ~~higher operating~~decreases in other operations and maintenance 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 $18 million related to additional wind generation and other plant placed in-service and $4 million of Iowa revenue sharing. Electric utility margin was higher ~~accruals for Iowa regulatory arrangements,~~due to higher retail customer volumes, higher wholesale revenue and higher recoveries through bill riders, partially offset by ~~a reduction of $26 million from~~ lower ~~depreciation~~average retail rates, ~~implemented in December 2016. Operating expenses~~higher generation and purchased power costs and lower transmission revenue. Natural gas utility margin increased ~~primarily~~ due to higher ~~demand side management program expense (offset in operating revenue)~~retail sales volumes, partially offset by lower average rates from the impact of ~~$17 million and higher generation maintenance costs.~~

~~NV Energy~~a lower federal tax rate due to 2017 Tax Reform.

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~~$127 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to higher electric operating revenue of ~~$89~~$108 million ~~partially offset by lower~~and higher natural gas operating revenue of ~~$15~~$20 million. Electric operating revenue increased due to higher retail revenue of ~~$81~~$96 million and higher ~~transmission~~wholesale and other revenue of $9$12 million. Electric retail revenue increased ~~due to $130~~$91 million from higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense), $58 million from higher customer usage, including higher industrial sales volumes, and $33 million from the impact of weather in 2018, partially offset by lower average rates ~~primarily~~of $86 million predominantly from ~~energy costs~~the impact of a lower federal tax rate due to 2017 Tax Reform. Electric retail customer volumes increased 6.9% from industrial growth and the favorable impact of weather. Electric wholesale revenue increased due to higher average per-unit prices of $7 million and a 0.2% growth in sales volumes. Natural gas operating revenue increased due to 22.3% higher retail sales volumes from the impact of weather in 2018 and industrial growth, partially offset by a lower average per-unit price of $27 million (offset in cost of ~~sales), $36 million from higher distribution only service revenue~~gas purchased for resale and other) and other usage and rate factors, including the impact ~~fees received~~of a lower federal tax rate due to ~~customers purchasing energy from alternative providers~~2017 Tax Reform.

Operating income decreased $73 million for the first nine months of 2018 compared to 2017 primarily due to higher depreciation and ~~becoming distribution only service customers, $18~~amortization of $130 million, ~~from~~higher wind-powered generation maintenance of $17 million, higher fossil-fueled generation maintenance of $12 million and increases in other operations and maintenance expenses, partially offset by higher electric utility margin of $84 million, including the impact of an increase in electric demand-side management program revenue of $10 million (offset in operations and maintenance expense), and higher natural gas utility margin of $12 million. The increase in depreciation and amortization reflects increases for Iowa revenue sharing of $83 million and $47 million related to additional wind generation and other plant placed in-service. Electric utility margin increased due to higher recoveries through bill riders, higher retail customer volumes and higher wholesale revenue, partially offset by lower average retail rates and higher generation and purchased power costs. Natural gas utility margin increased due to higher retail sales volumes from colder temperatures, partially offset by lower average rates partially from the ~~average number customers~~impact of a lower federal tax rate due to 2017 Tax Reform.

NV Energy

Operating revenue increased $12 million for the third quarter of 2018 compared to 2017 due to higher electric operating revenue of $12 million. Electric operating revenue increased due to higher electric retail revenue of $6 million and ~~$11~~higher wholesale and other revenue of $6 million. Electric retail revenue increased primarily due to higher energy rates (offset in cost of fuel and energy) of $26 million, higher customer ~~usage mainly from~~volumes of $18 million, primarily due to the impacts of weather, and customer growth of $6 million, partially offset by ~~$93~~a decrease from the impact of a lower federal tax rate due to 2017 Tax Reform of $30 million and lower rates from ~~lower commercial and industrial revenue, mainly from customers purchasing energy from alternative providers, and $23 million~~the Nevada Power 2017 regulatory rate review of ~~lower energy efficiency program revenue (offset in operating expense).~~$16 million. Electric retail customer volumes, including distribution only service customers, increased ~~2.4%~~4.7% compared to ~~2016. Natural gas operating revenue decreased due to lower energy rates, partially offset by higher customer usage.~~2017.

Operating income decreased $86 million for the third quarter of 2018 compared to 2017 due to an increase in operations and maintenance expense of $60 million, primarily due to earnings sharing of $36 million established in 2018 as part of the Nevada Power 2017 regulatory rate review and higher political activity expenses, a decrease in electric utility margin of $17 million and higher depreciation and amortization of $9 million as a result of various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review. Electric utility margin decreased as higher energy costs of $29 million were offset by higher electric operating revenue of $12 million. Energy costs increased ~~$26~~due to higher purchased power costs of $29 million.

Operating revenue increased $42 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to higher electric operating revenue of $34 million and higher natural gas operating revenue of $8 million. Electric operating revenue increased due to higher electric retail revenue of $38 million, partially offset by lower ~~operating expenses~~wholesale and other revenue of ~~$23~~$4 million. Electric retail revenue increased primarily due to higher energy rates (offset in cost of fuel and energy) of $82 million, higher customer volumes of $20 million, primarily due to the impacts of weather, and customer growth of $7 million, partially offset by a decrease from the impact of a lower ~~energy efficiency program expense~~federal tax rate due to 2017 Tax Reform of $52 million and lower rates from the Nevada Power 2017 regulatory rate review of $23 million. Electric retail customer volumes, including distribution only service customers, increased 2.7% compared to 2017. Natural gas operating revenue increased $8 million due to a higher average per-unit price (offset in ~~electric operating revenue)~~cost of natural gas purchased for resale) of $10 million, partially offset by lower volumes.

Operating income decreased $143 million for the first nine months of 2018 compared to 2017 due to an increase in operations and maintenance expense of $77 million, primarily due to earnings sharing of $42 million established in 2018 as part of the Nevada Power 2017 regulatory rate review and higher ~~electric gross margins of $2 million. Electric gross margins were higher due to the increase~~political activity expenses, a decrease in electric ~~operating revenue, partially offset by~~utility margin of $38 million and higher depreciation and amortization of $26 million as a result of various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review. Electric utility margin decreased as higher energy costs of ~~$87~~$72 million were offset by higher electric operating revenue of $34 million. Energy costs increased due to higher net deferred power costs of $103 million and higher purchased power costs of $21 million, partially offset by a ~~higher~~lower average cost of fuel for generation of ~~$62 million, lower net deferred power costs of $23 million and higher purchased power costs of $3~~$53 million.

Northern Powergrid

Operating revenue increased $1$12 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 due to ~~lower~~higher smart meter revenue of $8 million from additional smart meter assets placed in-service and higher distribution revenue of $7$6 million ~~partially offset by higher smart metering revenue of $6 million. Distribution revenue decreased~~ mainly due to ~~lower~~higher tariff ~~rates of $4 million and lower units distributed of $2 million.~~rates. Operating income decreased $9$4 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to higher ~~pension~~distribution-related operations and maintenance 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,~~and higher depreciation ~~of $7 million from~~expense related to additional smart meter and distribution assets placed in-service, ~~and higher distribution costs of $4 million,~~ partially offset by ~~$19 million of asset provisions recognized~~the increase in ~~the third quarter of 2016 at the CE Gas business.~~operating revenue.

Operating revenue ~~decreased $63~~increased $72 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to the ~~stronger~~weaker United States dollar of ~~$66~~$45 million, higher smart meter revenue of $21 million from additional smart meter assets placed in-service and ~~lower~~higher distribution revenue of $11 million. Distribution revenue increased mainly due to higher tariff rates 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~~increased $14 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to the ~~stronger~~increase in operating revenue and the weaker 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$24 million, partially offset by ~~$19~~higher distribution-related operations and maintenance expense and higher depreciation expense related to additional smart meter and distribution assets placed in-service.

BHE Pipeline Group

Operating revenue increased $66 million ~~of asset provisions recognized in~~for the third quarter of ~~2016~~2018 compared to 2017 due to higher transportation revenues of $58 million at Northern Natural Gas and Kern River from higher volumes and rates due to unique market opportunities and higher gas sales of $10 million related to system balancing activities (largely offset in cost of sales) at Northern Natural Gas. Operating income increased $39 million for the ~~CE Gas business.~~third quarter of 2018 compared to 2017 primarily due to the increase in transportation revenue and lower depreciation expense at Kern River, partially offset by higher operations and maintenance expense, primarily due to increased pipeline integrity projects at Northern Natural Gas.

Operating revenue increased $171 million for the first nine months of 2018 compared to 2017 due to higher transportation revenues of $102 million at Northern Natural Gas and Kern River from higher volumes and rates due to unique market opportunities and colder temperatures and higher gas sales of $70 million related to system balancing activities (largely offset in cost of sales) at Northern Natural Gas. Operating income increased $60 million for the first nine months of 2018 compared to 2017 primarily due to the increase in transportation revenue and lower depreciation expense at Kern River, partially offset by higher operations and maintenance expense, primarily due to increased pipeline integrity projects at Northern Natural Gas.

BHE ~~Pipeline Group~~Transmission

Operating revenue decreased $8 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to lower ~~transportation revenues~~operating revenue at ~~Kern River,~~AltaLink from a stronger United States dollar and the release of contingent liabilities in 2017, partially offset by additional assets placed in-service and higher ~~transportation revenues at Northern Natural Gas.~~non-regulated revenue. Operating income decreased $3$4 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to the lower ~~transportation revenues at Kern River and higher~~ operating ~~expenses at Northern Natural Gas,~~revenue, partially offset by lower ~~depreciation expense and higher transportation revenues~~non-regulated operating costs at ~~Northern Natural Gas.~~AltaLink.

Operating revenue ~~decreased $4~~increased $25 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due ~~lower transportation revenues~~to higher operating revenue at ~~Kern River,~~AltaLink from a weaker United States dollar, additional assets placed in-service and higher non-regulated revenue, partially offset by ~~higher gas sales~~the release of ~~$15 million related to system balancing activities (largely offset~~contingent liabilities in ~~cost of sales) and higher transportation revenues at Northern Natural Gas.~~2017. Operating income increased $8 million for the first nine months of ~~2017~~2018 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.additional assets placed in-service.

BHE Renewables

Operating revenue increased ~~$10~~$37 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 due to overall higher generation and favorable pricing of $35 million at existing projects and $10 million from additional ~~wind~~solar and ~~solar~~wind capacity placed in-service, ~~of $17 million,~~ partially offset by ~~lower geothermal revenues~~an unfavorable derivative valuation movement of ~~$6 million due to unfavorable pricing and lower capacity revenues.~~$8 million. Operating income ~~was unchanged~~increased $19 million for the third quarter of ~~2017~~2018 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 2016primarily due to the increase in operating revenue, partially offset by higher ~~operating~~operations and maintenance expense of ~~$24~~$14 million and higher depreciation expense of $6 million, primarily related to additional solar and ~~amortization~~wind capacity placed in-service.

Operating revenue increased $73 million for the first nine months of ~~$17 million, each primarily~~2018 compared to 2017 due to ~~the~~overall higher generation and pricing of $59 million at existing projects and $27 million from additional wind and solar capacity placed ~~in-service.~~in-service, partially offset by an unfavorable derivative valuation movement of $13 million. Operating income increased $52 million for the first nine months of 2018 compared to 2017 due to the increase in operating revenue and a decrease in property and other taxes of $4 million due to a property tax refund received in 2018, partially offset by higher operations and maintenance expense ~~also increased from the scope~~of $14 million and ~~timing~~higher depreciation expense of ~~maintenance at certain geothermal plants. The change in depreciation~~$11 million, primarily related to additional solar 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.~~wind capacity placed in-service.

HomeServices

Operating revenue increased ~~$141~~$257 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 due to an increase from acquired businesses ~~totaling $139~~of $273 million. Operating income ~~decreased $8~~increased $6 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~lower~~higher earnings from acquired businesses of $21 million, offset by lower brokerage segment earnings at existing businesses of $10 million, mainly due to lower margin and higher operating ~~expenses, and lower mortgage revenue.~~expenses.

Operating revenue increased ~~$350~~$750 million for the first nine months of ~~2017~~2018 compared to ~~2016 primarily~~2017 due to an increase from acquired businesses ~~totaling $279 million and a 3.8% increase in average home sales prices for existing businesses.~~of $769 million. Operating income ~~increased $12~~decreased $6 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~higher~~lower brokerage segment earnings ~~from franchise~~at existing businesses of $30 million, mainly due to ~~a favorable settlement~~lower margin and higher operating expenses, and a gain on the collection of ~~notes receivable,~~receivables in 2017 in the franchise segment, partially offset by ~~lower~~higher earnings from ~~brokerage~~acquired businesses ~~mainly due to higher operating expenses, and lower mortgage revenue.~~of $47 million.

BHE and Other

Operating revenue ~~decreased $40~~increased $22 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 due to ~~lower~~higher electricity and natural gas volumes ~~and rates~~ at MidAmerican Energy Services, LLC. Operating income ~~improved $29~~decreased $6 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 due to ~~lower~~higher other operating ~~expenses,~~costs, partially offset by ~~lower margins of $8 million~~higher margin at MidAmerican Energy Services, LLC.

Operating revenue ~~decreased $70~~increased $17 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 due to ~~lower~~higher electricity and natural gas volumes ~~and rates~~ at MidAmerican Energy Services, LLC. Operating loss ~~increased $2~~improved $18 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 due to ~~lower margins of $9 million~~higher margin at MidAmerican Energy Services, LLC ~~partially offset by~~and lower other operating ~~expenses.~~costs.

Consolidated Other Income and Expense Items

Interest ~~Expense~~expense

Interest expense is summarized as follows (in millions):


	Third Quarter									First Nine Months									Third Quarter									First Nine Months
	2017		2016		Change					2017		2016		Change					2018		2017		Change					2018		2017		Change

Subsidiary debt	$	354	$	345	$	9		3	%	$	1,045	$	1,042	$	3		—	%	$	347	$	354	$	(7	)	(2	)%	$	1,062	$	1,045	$	17		2	%
BHE senior debt and other	106		101		5			5		317		305		12			4		105		106		(1		)	(1	)	314		317		(3		)	(1	)
BHE junior subordinated debentures	4		14		(10		)	(71	)	17		54		(37		)	(69	)	1		4		(3		)	(75	)	4		17		(13		)	(76	)
Total interest expense	$	464	$	460	$	4		1		$	1,379	$	1,401	$	(22	)	(2	)	$	453	$	464	$	(11	)	(2	)	$	1,380	$	1,379	$	1		—

Interest expense ~~increased $4~~decreased $11 million for the third quarter of ~~2017~~2018 compared to ~~2016 and decreased $22 million for the first nine months of~~ 2017 ~~compared to 2016~~primarily due to repayments of BHE junior subordinated debentures of $944 million in 2017, ~~and $2.0 billion in 2016,~~ scheduled maturities and principal payments and early redemptions ~~and the impact~~ of ~~foreign currency exchange rate movements of $8 million in the first nine months,~~subsidiary debt, partially offset by debt issuances at BHE, MidAmerican Funding, ~~Northern Powergrid, AltaLink~~BHE Renewables and ~~BHE Renewables.~~

HomeServices.

Capitalized ~~Interest~~interest

Capitalized interest ~~decreased $94~~increased $3 million for the third quarter of 2018 compared to 2017 and $10 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due ~~to $96~~higher construction work-in-progress balances at MidAmerican Energy and BHE Renewables.

Allowance for equity funds

Allowance for equity funds increased $6 million ~~recorded in~~for the ~~second~~third quarter of ~~2016 from~~2018 compared to 2017 and $16 million for the ~~2015-2016 GTA decision received in May 2016 at AltaLink, which was offset in operating revenue, partially offset by~~first nine months of 2018 compared to 2017 primarily due to 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~~dividend income

Interest and dividend income decreased $7$5 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to lower financial asset income from the lower financial asset balance at BHE Renewables and $8the timing of dividends from the Company's investment in BYD Company Limited.

Gains (losses) on marketable securities, net

Gains (losses) on marketable securities, net increased $257 million for the third quarter of 2018 compared to 2017 primarily due to an unrealized gain on the Company's investment in BYD Company Limited totaling $252 million. The Company had losses on marketable securities for the first nine months of ~~2017~~2018 of $336 million compared to ~~2016~~gains on marketable securities in 2017 of $8 million primarily due to ~~lower dividends received from~~an unrealized loss in 2018 on the Company's investment in BYD Company ~~Limited.~~Limited totaling $346 million in the first nine months of 2018.

Other, net

Other, net ~~decreased $13~~was income of $19 million for the third quarter of ~~2017~~2018 compared to ~~2016~~an expense of $17 million in 2017 primarily due to costs incurred in 2017 associated with the early redemption of subsidiary long-term debt and lower non-service pension expense which includes pension settlement losses recognized in ~~2017.~~2017 and 2018 at Northern Powergrid.

Other, net ~~decreased $2~~increased $42 million for the first nine months of ~~2017~~2018 compared to ~~2016 mainly~~2017 primarily due to costs incurred in 2017 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.~~derivatives of $8 million and a settlement received in 2018 related to transformer related outages at the Solar Star projects in 2016.

Income ~~Tax Expense~~tax expense (benefit)

Income tax expense decreased ~~$15~~$161 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 and the effective tax rate was 2% for 2018 and 15% for ~~2017 and 16% for 2016.~~2017. The effective tax rate decreased primarily due to the reduction in the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, the favorable impacts of ratemaking and higher production tax credits recognized of ~~$34~~$35 million, partially offset by income tax expense of $70 million related to an unrealized gain on the Company's investment in BYD Company Limited.

For the first nine months of 2018, the Company had an income tax benefit of $366 million, including a $96 million benefit related to an unrealized loss on the Company's investment in BYD Company Limited. For the first nine months of 2017, the Company had an income tax expense of $319 million. The effective tax rate was (19)% for 2018 and 13% for 2017. The effective tax rate decreased primarily due to the reduction in the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, lower consolidated state income tax expense, including a reduction to the state provision for the repatriation tax of $45 million, higher production tax credits recognized of $97 million, lower United States income tax on foreign earnings 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.making.

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~~2018 were ~~$432~~$529 million, or ~~$96~~$97 million higher than ~~2016,~~2017, while production tax credits earned in ~~2017~~2018 were ~~$346~~$413 million, or ~~$79~~$67 million higher than ~~2016.~~2017. The difference between production tax credits recognized and earned of ~~$86~~$116 million as of September 30, ~~2017,~~2018, primarily at MidAmerican Energy, will be reflected in earnings over the remainder of ~~2017.~~2018.

Equity ~~Income~~income

Equity income decreased $6$21 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 and ~~$16~~$45 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily 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 retail rates effective in March 2017.

Net ~~Income Attributable~~income attributable to ~~Noncontrolling Interests~~noncontrolling interests

Net income attributable to noncontrolling interests ~~increased $5~~decreased $2 million for the third quarter of 2018 compared to 2017 and $11 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~higher earnings~~the April 2018 purchase of a redeemable noncontrolling interest at ~~HomeServices' franchise business.~~HomeServices.

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~~2017 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of September 30, ~~2017~~2018, the Company's total net liquidity was as follows (in millions):


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

Cash and cash equivalents	$	75		$	104		$	512		$	109		$	62	$	9		$	271		$	1,142		$	92		$	308		$	115		$	148		$	36		$	59		$	258		$	1,016

Credit facilities(2)	3,000			1,000			909			650			201		1,062			1,660			8,482			3,500			1,200			909			650			202			1,026			1,635			9,122
Less:
Short-term debt	(1,405		)	—			—			—			—		(286		)	(802		)	(2,493		)	(508		)	—			—			—			(43		)	(380		)	(853		)	(1,784		)
Tax-exempt bond support and letters of credit	(7		)	(130		)	(220		)	(80		)	—		(7		)	—			(444		)	—			(89		)	(370		)	(80		)	—			(5		)	—			(544		)
Net credit facilities	1,588			870			689			570			201		769			858			5,545			2,992			1,111			539			570			159			641			782			6,794

Total net liquidity	$	1,663		$	974		$	1,201		$	679		$	263	$	778		$	1,129		$	6,687		$	3,084		$	1,419		$	654		$	718		$	195		$	700		$	1,040		$	7,810
Credit facilities:
Maturity dates(1)	2018, 2020			2020			2018, 2020			2020			2020		2017, 2018, 2021			2017, 2018, 2022						2021			2021			2019, 2021			2021			2020			2018, 2022			2018, 2019, 2022


⁽¹⁾	Refer to Note 6 of the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for further discussion regarding the Company's recent financing transactions.


⁽²⁾	Includes the drawn uncommitted credit facilities totaling $7 million at Northern Powergrid.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2018 and 2017 ~~and 2016~~ were ~~$5.1~~$5.0 billion and ~~$4.8~~$5.1 billion, respectively. The ~~change~~decrease 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, partially offset by changes in working capital.

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 ~~higher~~assumptions used for each payment date.

2017 Tax Reform reduced the federal corporate tax rate from 35% to 21% effective January 1, 2018, created a one-time repatriation tax of foreign earnings and profits, eliminated bonus depreciation on qualifying regulated utility assets acquired after December 31, 2017 and extended and modified the additional first-year bonus depreciation for non-regulated property. BHE's regulated subsidiaries anticipate passing the benefits of lower tax expense to customers through regulatory mechanisms including lower rates and reductions to rate base. 2017 Tax Reform and the related regulatory outcomes will result in lower revenue, income tax and cash ~~payments for interest.~~flow in 2018 and future years compared to 2017. BHE does not expect 2017 Tax Reform and related regulatory treatment to have a material adverse impact on its cash flows, subject to actual regulatory outcomes, which will be determined based on rulings by regulatory commissions expected in 2018 and 2019.

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

As a result of 2017 Tax Reform, bonus depreciation on qualifying assets acquired after December 31, 2017 is eliminated for regulated utility property and is extended and modified for non-regulated property. The ~~timing of the Company's income tax cash flows from period~~Company believes property acquired on or before September 27, 2017 will remain subject to ~~period can be significantly affected by the estimated federal income tax payment methods and assumptions used for each payment date.~~

PATH.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2018 and 2017 ~~and 2016~~ were ~~$(4.4)~~$(4.5) billion and ~~$(4.1)~~$(4.4) billion, respectively. The change was primarily due to higher ~~cash paid for acquisitions~~capital expenditures of $1.0 billion, partially offset by lower cash paid for acquisitions, net of cash acquired, of $997 million. Refer to "Future Uses of Cash" for further discussion of capital ~~expenditures~~expenditures.

Acquisitions

The Company completed various acquisitions totaling $105 million, net of ~~$342~~cash acquired, for the nine-month period ended September 30, 2018. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which primarily related to residential real estate brokerage businesses. There were no other material assets acquired or liabilities assumed.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2018 was $(392) million. Uses of cash totaled $5.9 billion and consisted mainly of net repayments of short-term debt totaling $2.7 billion, repayments of subsidiary debt totaling $2.3 billion, repayments of BHE senior debt of $650 million and the purchase of redeemable noncontrolling interest of $131 million. Sources of cash totaled $5.5 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.4 billion.

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, 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, impacts to customers' rates; 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		Nine-Month Periods				Annual
	Ended September 30,				Forecast		Ended September 30,				Forecast
	2016		2017		2017		2017		2018		2018
Capital expenditures by business:
PacifiCorp	$	586	$	553	$	798	$	553	$	713	$	1,198
MidAmerican Funding	1,129		1,165		2,006		1,165		1,466		2,365
NV Energy	386		333		433		333		342		545
Northern Powergrid	435		434		616		434		446		535
BHE Pipeline Group	150		174		309		174		251		480
BHE Transmission	386		255		343		255		203		269
BHE Renewables	430		239		315		239		741		868
HomeServices	13		18		34		18		34		49
BHE and Other	6		8		13		8		7		11
Total	$	3,521	$	3,179	$	4,867	$	3,179	$	4,203	$	6,320


Capital expenditures by type:
Wind generation	$	1,110	$	804	$	1,292	$	804	$	1,696	$	2,658
Solar generation	15		95		125
Electric transmission	339		267		330		267		118		194
Environmental	52		56		111
Other growth	302		400		560		495		504		706
Operating	1,703		1,557		2,449		1,613		1,885		2,762
Total	$	3,521	$	3,179	$	4,867	$	3,179	$	4,203	$	6,320

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

•Wind generation includes the following:

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Construction of wind-powered generating facilities at MidAmerican Energy totaling ~~$455~~$704 million and ~~$732~~$455 million for the nine-month periods ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively. MidAmerican Energy anticipates costs for wind-powered generating facilities will total an additional ~~$254~~$550 million for ~~2017.~~2018. 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.~~2019, including 334 MW (nominal ratings) placed in-service in 2017. 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.~~effect prior to 2018. The revised sharing mechanism, ~~will be~~which was effective inJanuary 1, 2018, ~~and~~ will be triggered each year by actual equity returns ~~if they are above the~~exceeding a weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. ~~Each~~MidAmerican Energy expects all of these ~~projects is expected~~wind-powered generating facilities to qualify for 100% of production tax credits ~~currently~~ available.

◦

Construction of wind-powered generating facilities at PacifiCorp totaling $5 million and $4 million for the nine-month periods ended September 30, 2018 and 2017, respectively. PacifiCorp anticipates costs for these activities will total an additional $62 million for 2018. The new wind-powered generating facilities are expected to be placed in-service in 2020. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal production tax credits available for ten years once the equipment is placed in-service.

◦

Repowering certain existing wind-powered generating facilities at PacifiCorp and MidAmerican Energy totaling $303 million and ~~the construction of new wind-powered generating facilities at PacifiCorp totaling $280~~$276 million for the nine-month ~~period~~periods ended September 30, ~~2017.~~2018 and 2017, respectively. PacifiCorp and MidAmerican Energy anticipate costs for these activities will total an additional ~~$221~~$297 million for ~~2017. The repowering projects entail the replacement of significant components of older turbines.~~2018. The energy production from ~~the~~such 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.~~following each facility's return to service.

◦

Construction of wind-powered generating facilities at BHE Renewables totaling ~~$69~~$684 million and ~~$378~~$69 million for the nine-month periods ended September 30, 2018 and 2017, ~~and 2016,~~ respectively. In April 2018, BHE Renewables completed the asset acquisition of 300 MW of wind-powered generating facilities in Texas totaling $495 million. BHE Renewables anticipates costs ~~for wind-powered generating facilities~~ will total an additional ~~$11~~$51 million in ~~2017~~2018 for development and ~~$263 million in 2018. BHE Renewables is developing and constructing~~construction of up to 212 MW of wind-powered generating ~~facilities in the state of Illinois.~~facilities.

~~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~~Other growth 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 expendituresinvestments in solar generation for the ~~management~~construction of ~~coal combustion residuals.~~

~~Other growth includes~~the community solar gardens project in Minnesota comprised of 28 locations with a nominal facilities capacity of 98 MW, 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.~~demand and environmental spending relating to emissions control equipment and the management of coal combustion residuals.

~~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~~May 2018, MidAmerican Energy filed ~~its 2017 Integrated Resource Plan ("IRP")~~ with ~~its state commissions. The IRP includes investments in renewable energy resources, upgrades~~the IUB an application for ratemaking principles related to the ~~existing wind fleet,~~construction of up to 591 MW (nominal ratings) of additional wind-powered generating facilities ("Wind XII") expected to be placed in-service by the end of 2020. The filing, which is subject to IUB approval, establishes a cost cap of $922 million, including AFUDC, a fixed rate of return on equity of 11.25% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding, and maintains the revenue sharing mechanism currently in effect. 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. In September 2018, MidAmerican Energy filed with the IUB a settlement agreement signed by a majority of the parties to the ratemaking principles proceeding for Wind XII. The settlement agreement, which is subject to IUB approval, establishes 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 and provides that all Iowa retail energy ~~efficiency measures to meet future customer needs. Implementation of wind upgrades, new transmission, and new wind renewable resources~~benefits from Wind XII 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~~be excluded from the ~~forecast included~~Iowa energy adjustment clause and, instead, will reduce rate base. Additionally, the settlement agreement modifies the current revenue sharing mechanism, effective January 1, 2019, such that revenue sharing will be triggered each year by actual equity returns above a threshold calculated annually or 11%, whichever is less, and MidAmerican Energy will share 90% of the revenue in ~~BHE's 2016 Annual Report~~excess of the trigger, instead of the current 100% sharing. The calculated threshold will be the year-end weighted average of equity returns for rate base as authorized via ratemaking principles and, for remaining rate base, interest rates on ~~Form 10-K as~~30-year single A-rated utility bond yields plus 400 basis points, with a ~~result~~minimum return of ~~its 2017 IRP.~~9.5%. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of production tax credits available.

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 $403 million, $584 million and $170 million in ~~2015, $584 million in~~2017, 2016 and ~~$85~~2015, respectively. Additionally, the Company has made contributions of $252 million through September 30, ~~2017,~~2018, and ~~expects~~has commitments as of September 30, 2018, subject to ~~contribute $317~~satisfaction of certain specified conditions, to provide equity contributions of $540 million for the remainder of ~~2017~~2018 and ~~$254~~$348 million in ~~2018~~2019 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~~2018, 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~~2017 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 ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission credits will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. For the nuclear assets already in rate base, MidAmerican Energy's customers will not be charged for the subsidy, and MidAmerican Energy will not receive additional revenue from the subsidy.

On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of Illinois ("Northern District of Illinois") against the Illinois Power Agency alleging that the ~~state’s~~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~~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~~Circuit ("Seventh Circuit"). On May 29, 2018, the ~~appeals. MidAmerican Energy cannot predict~~U.S. Department of Justice and the ~~outcome~~FERC filed an amicus brief concluding federal rules do not preempt Illinois' ZEC program. On September 13, 2018, the Seventh Circuit upheld the Northern District of ~~these lawsuits.~~Illinois' ruling concluding that Illinois' ZEC program does not violate the Federal Power Act and is thus constitutional.

On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Offer 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~~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~~2017, and new regulatory matters occurring in ~~2017.~~2018.

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~~sought approvals to construct or procure four new Wyoming wind resources with a total capacity of 860 MWs identified as benchmark resources and certain transmission facilities. A request for proposals was issued in September 2017 seeking up to 1,270 MWs to compete against PacifiCorp's benchmark resources in the final resource selection process for the project. ~~PacifiCorp estimates the~~The combined new wind and transmission projects will cost approximately $2 billion. In October 2018, the WPSC approved a settlement agreement and certificates of public convenience and necessity for the transmission facilities and three of the winning wind resources. The ~~WPSC,~~settlement supports 950 MWs of owned wind resources and the 200 MW purchase power agreement. Hearings were held by the UPSC and IPUC ~~have set procedural schedules with hearings~~in May 2018. The UPSC approved the application in an order issued in June 2018. The order grants approval of the 1,150 MWs of new wind and transmission facilities up to ~~occur~~the projected costs. PacifiCorp can seek recovery of any actual costs in excess of the ~~first quarter of~~estimates in a general rate case. The IPUC approved a partial settlement agreement in an order issued in July 2018. The settlement provides cost recovery through a tracking mechanism. The IPUC order caps cost recovery at the overall estimated costs for the new wind and transmission facilities. The second application ~~seeks~~sought approval of PacifiCorp's resource decision to upgrade or "repower" existing wind resources, as prudent and in the public interest. PacifiCorp estimates the wind repowering project will cost approximately $1 billion. ~~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~~rate-making treatment associated with the ~~projects.~~projects, including recovery of the replaced equipment. In December 2017, the IPUC approved an all-party stipulation for approval of the application to repower existing wind facilities and allow recovery of costs in rates through an adjustment to the annual ECAM filing. In May 2018, the UPSC approved the application for repowering, up to the estimated costs, with the exception of the Leaning Juniper project, for which the commission expressed concern with the economics. If PacifiCorp chooses to proceed with this project, the project will be subject to a standard prudence review in future general rate cases. The WPSC approved an all-party settlement agreement to repower wind facilities in a bench decision in June 2018. In the decision, the WPSC specifically removed the Leaning Juniper project, located in Oregon, from the agreement and the approval, consistent with the treatment in Utah.

2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. PacifiCorp has agreed to defer the impact of the tax law change with each of its state regulatory bodies. PacifiCorp proposed reducing customer rates for a portion of the lower annual income tax expense resulting from the decrease in federal tax rates and deferring the remainder to offset other costs as approved by the regulatory bodies. In March 2018, PacifiCorp proposed 1% rate reductions in Utah, Wyoming and Idaho. PacifiCorp proposed the rate reductions to be effective May 1, 2018 in Utah, July 1, 2018 in Wyoming and June 1, 2018 in Idaho. In April 2018, the UPSC ordered a rate reduction of $61 million, or 3.1%, effective May 1, 2018 through December 31, 2018, based on a preliminary estimate of the revenue requirement impact of 2017 Tax Reform. In October 2018, PacifiCorp filed an all-party settlement with the UPSC that continues the current rate reduction of $61 million, with other benefits provided to customers through a combination of a reduction to thermal steam plant and deferral to offset costs in the next general rate case. PacifiCorp filed a partial settlement with the WPSC in April 2018 that provides a rate reduction of $23 million, or 3.3%, effective July 1, 2018 through June 30, 2019, with the remaining tax savings to be deferred with offsets to other costs. In June 2018, the WPSC approved the rate reduction on an interim basis. In May 2018, the IPUC approved an all-party settlement to implement a rate reduction of $6 million, or 2.2%, effective June 1, 2018 through May 31, 2019, to pass back a portion of the tax benefit. The credit may be adjusted following the next phase of the proceeding. In June 2018, PacifiCorp filed reports with the WPSC and IPUC with the calculation of the full impact of the tax law change on revenue requirements. These reports initiated the next phase of the proceedings in these states. The WPSC scheduled a hearing for January 2019. A hearing has not yet been scheduled in Idaho.

In September 2018, PacifiCorp filed applications for depreciation rate changes with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC based on PacifiCorp's most recent depreciation study. The proposed depreciation rate changes would result in an increase in annual depreciation expense of approximately $300 million. The depreciation study will be evaluated by the state commissions during 2018 and 2019 and is subject to their review and approval. PacifiCorp requested that the new depreciation rates become effective January 1, 2021. The impacts of the new depreciation study will be included in rates as part of a future regulatory proceeding.

Utah

In March ~~2017,~~2018, PacifiCorp filed its annual ~~Energy Balancing Account ("EBA")~~EBA with the UPSC seeking approval to ~~refund to~~recover from customers $7$3 million in deferred net power costs for the period January 1, ~~2016~~2017 through December 31, ~~2016,~~2017, reflecting the difference between base and actual net power costs in the ~~2016~~2017 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~~was approved by the UPSC effective May 1, 2018 on an interim ~~basis May 1, 2017.~~

basis. A hearing on final approval is scheduled for February 2019.

In March ~~2017,~~2018, PacifiCorp filed its annual REC balancing account application with the UPSC seeking to ~~refund to customers~~recover $1 million from customers for the period January 1, ~~2016~~2017 through December 31, ~~2016~~2017 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~~2018, with final approval received 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, 2017.2018.

Oregon

In March ~~2017,~~2018, PacifiCorp submitted its filing for the annual ~~Transitional Adjustment Mechanism ("TAM")~~TAM filing in Oregon requesting an annual increase of ~~$18~~$17 million, or an average price increase of ~~1.5%~~1.3%, based on forecasted net power costs and loads for calendar year ~~2018. Consistent with Oregon Senate Bill 1547, the~~2019. The filing includes an update of the impact of expiring production tax credits, which accounts for $6$11 million of the total rate ~~adjustment.~~adjustment, consistent with Oregon Senate Bill 1547 and reflecting the decrease in the revenue requirement benefit of production tax credits due to the change in the federal income tax rate. The filing was updated in July to reflect an all-parties partial stipulation resolving all but one issue in the proceeding and to update changes in contracts and market conditions. The updated filing is requesting an annual increase of ~~$8 million, or~~$1 million. The OPUC approved the all-parties partial stipulation and resolved all issues in the proceeding in an ~~average price increase of 0.6%.~~order issued in October 2018. The filing will be updated for changes in contracts and market conditions again in November ~~2017,~~2018, before final rates become effective in January ~~2018.~~2019.

Wyoming

In April ~~2017,~~2018, PacifiCorp filed its annual ~~Energy Cost Adjustment Mechanism ("ECAM")~~ECAM and ~~REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") applications~~RRA application with the WPSC. The ~~ECAM~~ filing requests approval to refund to customers $5$3 million in deferred net power costs for the period January 1, ~~2016~~2017 through December 31, ~~2016, and~~2017. The rate change was approved by 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~~effective July 1, 2018. PacifiCorp expects the interim rates to become final ~~order is issued by the WPSC, which is expected~~ in the ~~first~~fourth quarter of 2018.

Washington

In December 2017, PacifiCorp submitted a tariff filing to implement the first price change for the decoupling mechanism approved in PacifiCorp's 2015 regulatory rate review. WUTC staff disputed PacifiCorp's interpretation of the WUTC's order for the decoupling mechanism and PacifiCorp's subsequent calculations requesting additional funds be booked for return to customers. In February 2018, the WUTC granted the staff's motions and rejected PacifiCorp's tariff revision and required that PacifiCorp re-file price changes for its decoupling mechanism. In March 2018, the WUTC issued a letter accepting PacifiCorp's revised compliance filing in the Washington Decoupling Revenue Adjustment docket. The filing resulted in a net credit to customers of $2 million, effective April 1, 2018.

In May 2018, PacifiCorp filed a settlement stipulation and joint narrative in support of the settlement stipulation resolving all issues in the 2016 PCAM with the WUTC. The settlement agreement resulted in a net credit to the PCAM balancing account of $5 million. The WUTC issued an order in July 2018 approving the settlement in full.

In June 2018, PacifiCorp submitted its 2017 PCAM filing with WUTC seeking approval to credit $13 million to the PCAM balancing account. No rate changes were requested. In August ~~2017,~~2018, the WUTC issued an order approving PacifiCorp's filing and directed PacifiCorp to amortize the PCAM balance of $18 million over 12 months and allowed PacifiCorp to petition the WUTC to alter the amortization period. In October 2018, PacifiCorp submitted a compliance filing and petition requesting to ~~implement~~amortize the ~~second-year rate increase approved as part of the two-year rate plan in the 2015 regulatory rate review.~~balance over 24 months effective January 1, 2019. The WUTC denied PacifiCorp's petition and ordered PacifiCorp to submit a compliance filing ~~included rates based on~~with tariffs supporting a 12-month amortization period effective November 1, 2018.

In June 2018, PacifiCorp filed with WUTC a proposal to decrease the ~~$8 million, or 2.3%, increase ordered~~System Benefits Charge ("SBC") collection rate by $2 million. In July 2018, the WUTC ~~in September 2016. The compliance filing was~~ approved by the ~~WUTC on September 14, 2017, with~~proposed rates ~~effective September 15, 2017.~~

to go into effect August 1, 2018.

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,~~2018, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $8 million for deferred costs in ~~2016.~~2017. 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 recovery of the ~~ECAM application with rates~~deferred costs, which resulted in a rate reduction of $2 million, or 0.8% effective June 1, ~~2017.~~2018.

California

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

In ~~August 2017,~~April 2018, PacifiCorp filed a general rate case with the CPUC for aan overall rate ~~decrease~~increase of $1 million, or ~~1.1%~~0.9%, ~~through its annual Energy Cost Adjustment Clause. If approved by~~effective January 1, 2019.

In December 2014, PacifiCorp filed an advice letter with the CPUC to request approval to sell certain Utah mining assets and to establish memorandum accounts to track the costs associated with the Utah Mine Disposition for future recovery. In July 2015, the CPUC Energy Division issued a letter requiring PacifiCorp to file a formal application for approval of the sale of certain Utah mining assets. Accordingly, in September 2015, PacifiCorp filed an application with the CPUC. In February 2017, a joint motion was filed with the CPUC seeking approval of a settlement agreement reached by PacifiCorp and all other parties. The agreement states, among other things, that the decision to sell certain Utah mining assets is in the public interest. Parties also reserve their rights to additional testimony, briefs and hearings to the extent the CPUC determines that additional California Environmental Quality Act proceedings are necessary. In September 2018, the CPUC issued a decision that (1) approves, with modification, the stipulation entered into between PacifiCorp and all other parties; (2) finds that the sale of the mining assets and early closure of the Deer Creek mine was in the public interest; and (3) finds that the California Environmental Quality Act ("CEQA") does not apply to the sale of the mining assets.

MidAmerican Energy

2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. Accumulated deferred income tax balances were re-measured at the 21% rate and regulatory liabilities increased pursuant to mechanisms approved in Iowa. MidAmerican Energy has made filings or has been in discussions with each of its state rate regulatory bodies proposing either a reduction in retail rates ~~would~~or rate base for all or a portion of the net benefits of 2017 Tax Reform for 2018 and beyond. MidAmerican Energy proposed in Iowa, its largest jurisdiction, to reduce customer revenue via a rider mechanism for the impact of the lower statutory rate on current operations, subject to change depending on actual results, and defer as a regulatory liability the amortization of excess deferred income taxes. The Iowa Utilities Board approved MidAmerican Energy's Iowa tax reform rate reduction tariff on April 27, 2018, although it has opened a docket to consider concerns by certain stakeholders. The Illinois Commerce Commission approved MidAmerican Energy's Illinois tax reform rate reduction tariff on March 21, 2018. MidAmerican Energy currently estimates that its 2018 revenue will be ~~effective January 2018.~~reduced by approximately $86 million due to rate reductions for tax reform.

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~~In December 2017, ~~but~~ the PUCN ~~has not indicated when they will issue a final~~issued an 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 andwhich reduced ~~Sierra Pacific's electric~~Nevada Power's revenue requirement by $3$26 million ~~spread evenly~~and requires Nevada Power to ~~all rate classes. In December 2016, the PUCN approved the settlement agreement and established an additional six MW~~share 50% of ~~net metering capacity under the grandfathered rates, which are those net metering rates that were in effect prior to January 2016;~~regulatory earnings above 9.7%. As a result of the order, ~~establishes cost-based rates and~~Nevada Power recorded expense of $28 million in December 2017 primarily due to the reduction of a ~~value-based excess energy credit~~regulatory asset to return to customers revenue collected for ~~customers who choose to install private generation after the six MW limitation is reached.~~costs not incurred. The new rates were effective ~~January 1, 2017.~~on February 15, 2018. In January ~~2017, Sierra Pacific~~2018, Nevada Power filed a petition for ~~reconsideration relating to~~clarification of certain findings and directives in the ~~creation of~~order and intervening parties filed motions for reconsideration. The PUCN has not yet ruled on the ~~additional six MWs of net metering at~~filed motions. Nevada Power cannot predict the ~~grandfathered rates. Sierra Pacific believes the effects~~timing or ultimate outcome 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.rulings.

2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. In ~~June 2016, Sierra Pacific filed a gas regulatory rate review with~~February 2018, the ~~PUCN. The filing requested a slight decrease in its incremental annual revenue requirement. In October 2016, Sierra Pacific filed~~Nevada Utilities made filings with the PUCN proposing a ~~settlement agreement resolving all issues in~~tax rate reduction rider for the ~~proceeding~~lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and ~~reduced~~beyond. The filings supported an annual rate reduction of $59 million and $25 million for Nevada Power and Sierra ~~Pacific's gas revenue requirement by $2 million.~~Pacific, respectively. In ~~December 2016,~~March 2018, the PUCN ~~approved~~issued an order approving the ~~settlement agreement.~~rate reduction proposed by the Nevada Utilities. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing the Nevada Utilities to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, ~~2017.~~2018.

In March 2018, the FERC issued a Show Cause Order related to 2017 Tax Reform. In May 2018, in response to the Show Cause Order, the Nevada Utilities proposed a reduction to transmission and certain ancillary service rates under the NV Energy Open Access Transmission Tariff for the lower annual income tax expense anticipated from 2017 Tax Reform. The new rates are expected to become effective March 21, 2018. Upon the FERC's acceptance of the rates and the effective date, the Nevada Utilities will begin billing transmission customers under the new rates subject to refund from the effective date. As of September 30, 2018, the Nevada Utilities accrued $2 million for amounts subject to rate refund.

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~~October 2016, Wynn Las Vegas, LLC ("Wynn"), ~~filed applications with the PUCN to purchase energy from alternative providers of~~became 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 customerscustomer 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 that established the impact fee that was paid in September 2016 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~~September 2018, the ~~Bureau of Consumer Protection was filed~~PUCN granted relief requiring Nevada Power to credit ~~$16~~$3 million as an offset against ~~MGM's~~Wynn's remaining impact fee obligation. In October 2018, Wynn elected to pay the net present value lump sum of its Renewable Base Tariff Energy Rate obligation of $2 million, net of the credit of $3 million. The PUCN ordered Nevada Power to establish a regulatory liability and amortize the lump sum payment amount in ~~June 2017, the PUCN approved the stipulation as filed.~~equal monthly installments through December 2022.

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 monthly for three and six years at Sierra Pacific and Nevada Power, respectively, and proceed with purchasing energy from alternative providers. In July 2017, Caesars made the required compliance filings and, in September 2017, the PUCN issued an order allowing Caesars to acquire electric energy and ancillary services from another energy supplier and become a distribution only service customer of the Nevada Utilities. In January 2018, Caesars became a distribution only service customer and started procuring energy from another energy supplier for its eligible meters in the Sierra Pacific service territory. In February 2018, Caesars became a distribution only service customer and started procuring energy from another energy supplier for its eligible meters in the Nevada Power service territory. Following the PUCN's order from March 2017, Caesars' will pay Nevada Power and Sierra Pacific impact fees of $44 million in 72 equal monthly payments and $4 million in 36 monthly payments, respectively.

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. In April 2018, Peppermill paid a one-time impact fee of $3 million and became a distribution only service customer and started procuring energy from another energy supplier.

In June 2018, Station Casinos LLC ("Station"), 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 October 2018, the PUCN approved a stipulation allowing Station to purchase energy from alternative providers subject to conditions, including paying an impact fee of $15 million.

As of October 2018, the Nevada Utilities have received communications from seven additional current and pending customers, of which four provided a letter of intent to file with the PUCN an application and three have filed an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers.

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. As of September 30, 2018, the cumulative installed and applied-for capacity of all net metering systems in Nevada was 97 MWs. In July 2017, the Nevada Utilities filed with the PUCN proposed amendments to their tariffs necessary to comply with the provisions of AB 405. The filing in July 2017 also included a proposed optional time of use rate tariff for both Nevada Power and Sierra Pacific, which has not yet been set for procedural review. In September 2017, the PUCN issued an order directing the Nevada Utilities to place all new private generation customers who have submitted applications after June 15, 2017, into a new rate class with rates equal to the rate class they would be in if they were not private generation customers. Private generation customers with installed net metering systems less than 25 kilowatts prior to June 15, 2017, may elect to migrate to the new rate class created under AB 405 or stay in their otherwise-applicable rate class. The new AB 405 rates became effective December 1, 2017. In February 2018, the Nevada Utilities filed with the PUCN a settlement agreement resolving the outstanding issues related to its proposal for optional time-differentiated rate schedules. In March 2018, the PUCN approved the settlement agreement.

Energy Choice Initiative - Deregulation

In November 2016, a majority of Nevada voters supported a ballot measure to amend Article 1 of the Nevada Constitution. If approved again in ~~the general election of~~November 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~~Governor's Committee on Energy Choice in which the Nevada Utilities have representation. The Nevada Utilities ~~are~~have been engaged in the ~~initiative~~legislative process before the Governor's committee and ~~with~~related proceedings before the PUCN and the legislature. In April 2018, the PUCN released a study on the potential effects of electricity deregulation on Nevada. In July 2018, the Governor's Committee on Energy Choice ~~but~~released a report of findings and recommendations to the Governor. The Nevada Utilities cannot assess or predict the outcome of the potential constitutional amendment or the financial impact, if any, at this time. The uncertainty created by the ballot initiative complicates both the short-term allocation of resources and long-term resource planning for the Nevada Utilities, including the ability to forecast load growth and the timing of resource additions. This uncertainty in planning is evidenced by a ~~recent~~ decision the PUCN issued denying Nevada ~~Power’s~~Power's proposed purchase of the South Point Energy Center, citing the unknown outcomes of the ~~energy choice initiative~~Energy Choice Initiative as one of the factors considered in their decision.

Northern Powergrid Distribution Companies

The Gas and Electricity Markets Authority through its office of gas and electric markets (known as "Ofgem") published its RIIO-2 framework consultation on March 7, 2018, marking the first milestone in the development of the price control arrangements that will apply to Northern Powergrid from April 2023. Ofgem published its RIIO-2 framework decision on July 30, 2018. A significant part of the framework relates to setting the allowed return on capital, where Ofgem has set out an early view of the allowed cost of equity which is no higher than 5% (plus inflation calculated using the Consumer Prices Index including owner occupiers' housing costs as the measure of UK inflation rather than the currently used retail price index).

BHE Pipeline Group

In July 2018, the FERC issued a final rule adopting procedures for determining which natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the federal corporate tax rate from 2017 Tax Reform. Pursuant to the final rule, in October 2018, Northern Natural Gas filed an informational filing on FERC Form No. 501-G and a Statement Demonstrating Why No Rate Adjustment is Necessary. Likewise, in October 2018, Kern River filed an informational filing on FERC Form No. 501-G and a Statement Explaining Why No Rate Adjustment is Necessary, along with a Tax Reform Credit Rate Settlement in a companion docket. Kern River's Tax Reform Credit Rate Settlement offered an 11% rate credit against the Maximum Base Tariff Rates for firm service and any one-part rate that includes fixed costs. The Tax Reform Credit Rate Settlement is subject to approval by FERC. Responses to Northern Natural Gas' and Kern River's FERC Form Nos. 501-G filings and Kern River's Tax Reform Credit Rate Settlement were due October 23, 2018 and both Northern Natural Gas and Kern River have responded to all issues raised. The FERC's evaluation of Northern Natural Gas' and Kern River's filings will occur thereafter and the impact of the FERC's action, if any, would be prospective.

ALP

2019-2021 General Tariff ~~Applications~~Application

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.August 2018, ALP filed its ~~2015-2016 GTA compliance filing in July 2016 to comply~~2019-2021 general tariff application ("GTA") with the ~~AUC's decision~~AUC, delivering on the first three years of its commitment to keep rates lower or flat for customers for the next five years. The three-year application achieves flat tariffs by keeping operating and maintenance expenses flat, with the exception of salaries and wages and software licensing fees, transitioning to ~~provide customers with tariff relief through: (i)~~a new salvage recovery approach and continuing the ~~discontinuance~~use of ~~construction work-in-progress ("CWIP") in rate base and~~ the ~~return~~flow-through income tax method. In addition, similar 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 directedapproved 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~~of C$31 million, ALP proposes 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 transmissionprovide a further 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 expendituresreduction over the ~~two~~three years as well as an increase to miscellaneous revenue of C$3 million. These reductions resulted in a C$24 million, or 1.3%, net decrease to the two-year total revenue requirement applied for in ALP’s 2017-2018 GTA amendment filed in October 2016. In addition, ALP proposed to provide significant tariff relief through the refund ofby refunding previously collected accumulated depreciation surplus of an additional C$~~130~~31 million. The application requests the approval of revenue requirements of C$885 million, ~~(C$125~~C$887 million ~~net~~and C$889 million for 2019, 2020 and 2021 respectively, which are lower than the approved 2018 revenue requirement of ~~other related impacts).~~C$904 million. The ~~negotiated settlement agreement also provides~~forecast revenue requirement is based on an 8.5% return on equity and 37% deemed equity approved by the AUC for ~~additional potential reductions over~~2019 and 2020 and assumes the ~~two years through a 50/50 cost savings sharing mechanism.~~same for 2021 as placeholders.

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’~~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.

In October 2017, ALP's expert witness evidence and company evidence was submitted recommending a range of 9% to 10.75% return on equity, on a recommended equity ratio of 40%. ALP also filed company evidence that outlined increased uncertainties in the Alberta utility regulatory environment. In January 2018, the Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the City of Calgary filed intervenor evidence. The ~~AUC also confirmed~~return on equity recommended by the ~~process timelines with~~intervenors ranges from 6.3% to 7.75%. The equity ratio recommended by the intervenors for ALP ranges from 35% to 37%.

In March 2018, an oral hearing ~~scheduled~~was held and in August 2018, the AUC issued Decision 22570-D01-2018 on the 2018 Generic Cost of Capital proceeding approving ALP's return on equity at 8.5% with a 37% equity ratio for ~~March 2018.~~2018, 2019 and 2020.

Deferral Account Reconciliation Application

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

In ~~June~~December 2017, ALP amended its application to include the ~~AUC also suspended~~remaining capital projects completed in 2015. The amended 2014 and 2015 deferral account reconciliation application includes 110 completed projects with total gross capital additions, excluding AFUDC, of C$3.8 billion. An oral hearing was held in September 2018 after the completion of an extensive information request process earlier in ~~order to address~~the year. Following written arguments in October 2018, a ~~conflict of interest issue related to the provision of confidential documents.~~decision is expected in late 2018 or early 2019.

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,~~RPS, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by ~~the EPA and~~ various federal state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. Refer to "Liquidity and Capital Resources" of each respective Registrant in 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~~,2017, and new environmental matters occurring in ~~2017.~~2018.

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~~Colorado 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 ofrequires selective catalytic reduction ("SCR") controls at ~~Hunter~~Craig Unit 2 and Hayden Units 1 and 2, ~~and Huntington Units 1 and 2 within five years. EPA's final action on~~in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are either already in service or currently being constructed. In addition, in February 2015, the ~~Utah~~state of Colorado finalized an amendment to its regional haze SIP ~~was effective August 4, 2016. The EPA approved~~relating to Craig Unit 1, in ~~part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring~~which PacifiCorp has an ownership interest, to require the installation of SCR controls ~~at Hunter~~by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and ~~Huntington Units~~federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR controls to retire Unit 1 ~~and 2 within five years~~by December 31, 2025, in lieu of SCR controls installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021 with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR controls installation. The terms of the ~~effective date~~agreement were approved by the Colorado Air Quality Board in December 2016. The terms of the ~~rule. PacifiCorp~~agreement were incorporated into an amended Colorado regional haze SIP in 2017 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 requestswere submitted to the EPA ~~to reconsider~~for its ~~decision in issuing the FIP. By letter dated July 14, 2017, from Administrator Scott Pruitt, the EPA indicated that based on existing~~review 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 reconsiderationapproval. The EPA's approval 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~~amended Colorado regional haze SIP ~~requiring, among other things,~~was published in 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 SIPFederal Register July 5, 2018, with an effective date of ~~April 26, 2017.~~August 6, 2018. Until the EPA takes final action in each state and decisions have been made in the pending appeals, PacifiCorp, cannot fully determine the impacts of the Regional Haze Rule on its respective generating facilities.

The Navajo Generating Station, in which Nevada Power is a joint owner with an 11.3% ownership share, is also a source that is subject to the regional haze BART requirements. In January 2013, the EPA announced a proposed FIP addressing BART and an alternative for the Navajo Generating Station that includes a flexible timeline for reducing nitrogen oxides emissions. 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. On June 1, 2017, President Trump announced the United States would withdraw from the Paris Agreement. Under the terms of the agreement, the withdrawal would be effective in November 2020. The cornerstone of the United States' commitment was the Clean Power Plan which was finalized by the EPA in 2015 ~~and is currently under review, was~~but has since been proposed for repeal by 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.EPA.

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards ~~have been~~were appealed to the D.C. Circuit and oral argument was scheduled ~~to be heard~~for April 17, ~~2017; however,~~2017. However, oral argument was deferred and 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~~for an indefinite period of ~~the court.~~time. Until such time as the ~~court renders a final determination regarding~~EPA undertakes further action to reconsider the ~~validity of the~~new source performance standards or the ~~EPA rescinds the standards,~~court takes action, any new fossil-fueled generating facilities constructed by the relevant Registrants will be required to meet the GHG new source performance standards.

Clean Power Plan

In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The ~~EPA also changed the~~ compliance period ~~to begin~~would have begun in 2022, with three interim periods of compliance and with the final goal to be achieved by ~~2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh~~2030 and ~~1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is~~was expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. 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~~2016. 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 EPA took comments on the proposed repeal until April 26, 2018. In addition, the EPA published in the Federal Register an Advance Notice of Proposed Rulemaking on December 28, 2017, seeking public input on, without committing to, a potential replacement rule. The public comment period ~~closes~~for the Advance Notice of Proposed Rulemaking concluded February 26, 2018. On August 21, 2018, the EPA proposed the Affordable Clean Energy rule, which would replace the Clean Power Plan. The Affordable Clean Energy rule would determine that the best system of emissions reduction for existing coal-fueled power plants is heat rate improvements and proposes a set of candidate technologies and measures that could improve heat rates. The EPA did not propose to set a specific numerical standard of performance for all affected units. Instead, states would be required to evaluate the candidate technologies and measures to establish standards of performance on a unit-specific basis, setting a standard of performance for each affected unit, measured in terms of pounds of carbon dioxide per megawatt hour. Measures taken to meet the standards of performance must be achieved at the source itself. Under the proposed rule, states would have three years from rule finalization to submit a plan to the EPA, which would have one year to determine the approvability of the plan. If a state does not submit a plan or a submitted plan is not satisfactory, the EPA would have two years to develop a federal plan. Comments on the proposal ~~December 15, 2017. EPA has not determined whether it will issue a replacement rule.~~were due October 31, 2018. Until ~~such time as~~ the ~~EPA takes final action on~~proposed rule is finalized and state plans are developed, the ~~repeal and determines whether there will be a replacement rule, the impact of EPA’s actions~~full impacts on the Registrants cannot be determined. However, PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and ~~advancement of~~advanced customer energy efficiency programs.

GHG Litigation

~~Water Quality Standards~~

Each Registrant closely monitors ongoing environmental litigation applicable to its respective operations. Numerous lawsuits have been unsuccessfully pursued against the industry that attempt to link GHG emissions to public or private harm. The lower courts initially refrained from adjudicating the cases under the "political question" doctrine, because of their inherently political nature. These cases have typically been appealed to federal ~~Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining~~appellate courts and, ~~improving water quality~~ in certain circumstances, to 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.Supreme Court. 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~~Court's 2011 decision in the ~~rule. On June 27, 2017,~~case of American Electric Power Co., Inc., et al. v. Connecticut et al., the court addressed the question of whether federal common law nuisance claims could be maintained against certain electric power companies' for their GHG emissions and require the setting of an emissions cap for the emitters. The court held that the Clean Air Act and the EPA ~~initiated~~actions it authorizes displace any federal common law right to seek abatement of carbon dioxide emissions from fossil-fuel-fired power plants. Recent efforts by the ~~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~~Clean Power Plan could increase the filing of common law nuisance lawsuits against emitters of GHG. Adverse rulings in GHG-related cases could result in increased or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities. While the Registrants are not a party to pending climate-related lawsuits, there are several suits pending in federal and state courts related to product liability, public nuisance, consumer protection and trespass cases against certain fossil fuel companies, as well as a case brought under the public trust doctrine against several federal government entities and officials. The GHG rules, changes to those rules, and the ~~second step~~Registrants' compliance requirements are subject to ~~carry out a notice-and-comment rulemaking in which a substantive re-evaluation of~~potential outcomes from proceedings and litigation challenging 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.

rules.

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~~was effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of coal combustion residuals. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. The final rule requires regulated entities to post annual groundwater monitoring and corrective action reports. The first of these reports were posted to the respective Registrant's coal combustion rule compliance data and information websites prior to March 2, 2018. Based on the results in those reports, additional monitoring and action may be required under the rule.

On ~~August 10, 2017,~~March 15, 2018, the EPA issued ~~proposed permitting guidance~~a proposal to address provisions of the final coal combustion rule that were remanded back to the agency on ~~how states’~~June 14, 2016, by the D.C. Circuit. The proposal included provisions that establish alternative performance standards for owners and operators of coal combustion residuals units located in states that have approved permit programs ~~should comply with~~or are otherwise subject to oversight through a permit program administered by the ~~requirements~~EPA. The EPA published the first phase of the ~~final~~coal combustion rule ~~as authorized under~~amendments on July 30, 2018, with an effective date of August 28, 2018. Additional substantive revisions to 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,~~rule are expected to be finalized by the EPA ~~granted reconsideration on aspects~~by December 2019 but have not yet been released for public comment. If adopted, certain elements of the ~~final rule. On September 18, 2017,~~proposal have the ~~EPA filed a motion~~potential to ~~hold the pending litigation on the final rule in abeyance; however,~~reduce costs of compliance. The U.S. Court of Appeals for the D.C. Circuit ~~has not made~~issued a decision August 21, 2018, vacating several elements of the rule, including closure provisions for unlined surface impoundments, and finding that the Resource Conservation and Recovery Act provides the EPA authority to regulate inactive surface impoundments at inactive facilities. The court's order was effective October 15, 2018, and as a result, the EPA will need to undertake additional rulemaking to implement the Court's order. Until such time as additional rulemaking is final, ~~ruling~~the impacts 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.Registrants cannot be determined.

At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and ~~hence~~ are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston Generating Station were hydraulically connected and effectively constitute a single impoundment. A total of eight existing surface impoundments, plus a new surface impoundment placed into service in November 2017 at the Naughton Generating Station, and four active landfills remain subject to the final rule. Three of the surface impoundments are inactive and undergoing closure. 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~~two surface impoundments ~~to no longer receive coal combustion byproducts. These six impoundments~~were closed and are not subject to the rule. Three surface impoundments were closed in December 2017, and the remaining four are undergoing closure. Two landfills are lined and remain active and subject to the final rule. Two landfills are unlined and will commence closure ~~on or before~~by December 2018 and April ~~2018.~~2019, respectively. 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~~removed eight surface impoundments ~~four impoundments discontinued receipt of coal combustion byproducts~~from service and ~~are subject to final closure on or before April 2018, and two~~commenced closure. 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~~2017 for discussion of the impacts on asset retirement obligations as a result of the final rule.

Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit in 2015, resulting in settlement of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive surface impoundments to regulation. On September 13, 2017, EPA Administrator Pruitt issued a letter to parties petitioning for administrative reconsideration of certain aspects of the coal combustion byproducts rule concluding it was appropriate and in the public interest to reconsider the provisions of the final rule addressed in the petitions. On September 27, 2017, the D.C. Circuit issued an order to the EPA requiring the agency to identify provisions of the rule that the agency intended to reconsider. The EPA submitted its list of potential issues to be reconsidered on November 15, 2017 and oral argument was held by the D.C. Circuit November 20, 2017 over certain portions of the final rule. The court has not yet issued a decision on the issues presented in the oral arguments. Separately, on August 10, 2017, the EPA issued proposed permitting guidance on how states' coal combustion residuals permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. Utilizing that guidance, the state of Oklahoma submitted an application to the EPA for approval of its state program and, on June 28, 2018, the EPA's approval of the application was published in the Federal Register. Environmental groups, including Waterkeeper Alliance and the Sierra Club, filed suit in the U.S. District Court for the District of Columbia on September 26, 2018, alleging that the EPA unlawfully approved Oklahoma's permit program. This suit also incorporates claims first identified in a July 26, 2018 notice of intent to sue that alleged the EPA failed to perform nondiscretionary duties related to the development and publication of minimum guidelines for public participation in the approval of state permit programs for coal combustion residuals. To date, none of the states in which the Registrants operate has submitted an application for approval of state permitting authority. The state of Utah adopted the federal final rule in September 2016, which required two landfills to submit permit applications by March 2017. It is anticipated that the state of Utah will submit an application for approval of its coal combustion residuals permit program prior to the end of 2019.

Notwithstanding the status of the final coal combustion residuals rule, citizens' suits have been filed against regulated entities seeking judicial relief for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately released or connected to surface water. In addition, actions have been filed against regulated entities seeking to require that surface impoundments containing coal combustion residuals be subject to closure by removal rather than being allowed to effectuate closure in place as provided under the final rule. The Registrants are not a party to these lawsuits and until they are resolved, the Registrants cannot predict the impact on overall compliance obligations.

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~~2017. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, ~~2016~~2017.

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~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, ~~2017, and~~2018, the related consolidated statements of operations for the three-month and nine-month periods ended September 30, ~~2017~~2018 and ~~2016, and~~2017, of changes in shareholders' equity and of cash flowsfor the nine-month periods ended September 30, 2018 and 2017, and ~~2016. These~~the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~PacifiCorp's management.~~America.

We ~~conducted our reviews~~have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2017, 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 23, 2018, 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, 2017, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of PacifiCorp's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

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~~2, 2018

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		September 30,		December 31,
	2017		2016		2018		2017
ASSETS
Current assets:
Cash and cash equivalents	$	104	$	17	$	308	$	14
Accounts receivable, net	722		728		761		684
Income taxes receivable	—		17
Inventories:
Materials and supplies	237		228
Fuel	207		215
Regulatory assets	30		53
Inventories					429		433
Prepaid expenses					59		73
Other current assets	72		96		55		111
Total current assets	1,372		1,354		1,612		1,315

Property, plant and equipment, net	19,135		19,162		19,338		19,203
Regulatory assets	1,518		1,490		1,028		1,030
Other assets	388		388		358		372

Total assets	$	22,413	$	22,394	$	22,336	$	21,920

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

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of						As of
	September 30,			December 31,			September 30,			December 31,
	2017			2016			2018			2017
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	398		$	408		$	438		$	453
Income taxes payable	64			—
Accrued interest							106			115
Accrued property, income and other taxes							219			66
Accrued employee expenses	115			67			126			70
Accrued interest	106			115
Accrued property and other taxes	136			63
Short-term debt	—			270			—			80
Current portion of long-term debt and capital lease obligations	591			58			352			588
Regulatory liabilities	67			54
Other current liabilities	164			164			245			245
Total current liabilities	1,641			1,199			1,486			1,617

Long-term debt and capital lease obligations							6,682			6,437
Regulatory liabilities	1,032			978			3,151			2,996
Long-term debt and capital lease obligations	6,436			7,021
Deferred income taxes	4,884			4,880			2,560			2,582
Other long-term liabilities	913			926			700			733
Total liabilities	14,906			15,004			14,579			14,365

Commitments and contingencies (Note 8)
Commitments and contingencies (Note 11)

Shareholders' equity:
Preferred stock	2			2			2			2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—			—			—			—
Additional paid-in capital	4,479			4,479			4,479			4,479
Retained earnings	3,038			2,921			3,291			3,089
Accumulated other comprehensive loss, net	(12		)	(12		)	(15		)	(15		)
Total shareholders' equity	7,507			7,390			7,757			7,555

Total liabilities and shareholders' equity	$	22,413		$	22,394		$	22,336		$	21,920

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						Three-Month Periods							Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,							Ended September 30,
	2017			2016			2017			2016				2018			2017			2018			2017

Operating revenue	$	1,430		$	1,434		$	3,956		$	3,919			$	1,369		$	1,430		$	3,746		$	3,956

Operating costs and expenses:
Energy costs	465			478			1,305			1,295
Operating expenses:
Cost of fuel and energy														465			465			1,300			1,305
Operations and maintenance	248			272			754			800				266			254			777			771
Depreciation and amortization	200			193			598			576				203			200			602			598
Taxes, other than income taxes	50			47			149			141
Total operating costs and expenses	963			990			2,806			2,812
Property and other taxes														49			50			150			149
Total operating expenses														983			969			2,829			2,823

Operating income	467			444			1,150			1,107				386			461			917			1,133

Other income (expense):
Interest expense	(95		)	(95		)	(285		)	(285		)		(96		)	(95		)	(288		)	(285		)
Allowance for borrowed funds	4			4			12			12				5			4			13			12
Allowance for equity funds	7			7			21			21				9			7			24			21
Other, net	6			3			13			9				14			12			36			30
Total other income (expense)	(78		)	(81		)	(239		)	(243		)		(68		)	(72		)	(215		)	(222		)

Income before income tax expense	389			363			911			864				318			389			702			911
Income tax expense	126			110			294			270				48			126			100			294
Net income	$	263		$	253		$	617		$	594			$	270		$	263		$	602		$	617

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															Accumulated
					Additional					Other			Total							Additional					Other			Total
	Preferred		Common		Paid-in		Retained			Comprehensive			Shareholders'			Preferred		Common		Paid-in		Retained			Comprehensive			Shareholders'
	Stock		Stock		Capital		Earnings			Loss, Net			Equity			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		$	2	$	—	$	4,479	$	2,921		$	(12	)	$	7,390
Net income	—		—		—		617			—			617			—		—		—		617			—			617
Common stock dividends declared	—		—		—		(500		)	—			(500		)	—		—		—		(500		)	—			(500		)
Balance, September 30, 2017	$	2	$	—	$	4,479	$	3,038		$	(12	)	$	7,507		$	2	$	—	$	4,479	$	3,038		$	(12	)	$	7,507

Balance, December 31, 2017																$	2	$	—	$	4,479	$	3,089		$	(15	)	$	7,555
Net income																—		—		—		602			—			602
Common stock dividends declared																—		—		—		(400		)	—			(400		)
Balance, September 30, 2018																$	2	$	—	$	4,479	$	3,291		$	(15	)	$	7,757

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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income	$	617		$	594		$	602		$	617
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	598			576			602			598
Allowance for equity funds	(21		)	(21		)	(24		)	(21		)
Changes in regulatory assets and liabilities							127			21
Deferred income taxes and amortization of investment tax credits	14			76			(53		)	14
Changes in regulatory assets and liabilities	21			85
Other, net	1			6			(1		)	1
Changes in other operating assets and liabilities:
Accounts receivable and other assets	25			19			(31		)	42
Inventories							4			(1		)
Derivative collateral, net	(4		)	2			4			(4		)
Inventories	(1		)	(32		)
Income taxes	75			133
Prepaid expenses							10			9
Accrued property, income and other taxes, net							204			145
Accounts payable and other liabilities	110			(66		)	36			40
Net cash flows from operating activities	1,435			1,372			1,480			1,461

Cash flows from investing activities:
Capital expenditures	(553		)	(586		)	(713		)	(553		)
Other, net	32			26			2			5
Net cash flows from investing activities	(521		)	(560		)	(711		)	(548		)

Cash flows from financing activities:
Proceeds from long-term debt, net							593			—
Repayments of long-term debt and capital lease obligations	(54		)	(56		)	(588		)	(54		)
Net repayments of short-term debt	(270		)	(20		)	(80		)	(270		)
Common stock dividends	(500		)	(550		)
Dividends paid							(400		)	(500		)
Other, net	(3		)	—			—			(3		)
Net cash flows from financing activities	(827		)	(626		)	(475		)	(827		)

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
Net change in cash and cash equivalents and restricted cash and cash equivalents							294			86
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period							29			33
Cash and cash equivalents and restricted cash and cash equivalents at end of period							$	323		$	119

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

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	~~(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~~and 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~~2018 and for the three- and nine-month periods ended September 30, ~~2017~~2018 and ~~2016.~~2017. 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~~2018 and ~~2016.~~2017. The results of operations for the three- and nine-month periods ended September 30, ~~2017~~2018 and ~~2016~~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 PacifiCorp's Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017 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.~~2018.

~~(2) New Accounting Pronouncements~~


(2)	New Accounting Pronouncements

In ~~March 2017,~~August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. ~~2017-07,~~2018-14, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance ~~require~~modify the disclosure requirements for employers that ~~an employer disaggregate~~sponsor defined benefit pension or other postretirement plans. The amendments in this guidance remove disclosures that no longer are considered cost beneficial, clarify the ~~service cost component from~~specific requirements of disclosures and add disclosure requirements identified as relevant. The updated disclosure requirements make a number of changes to improve the ~~other components~~effectiveness of ~~net benefit cost and report the service cost component~~disclosures in the ~~same line item as other compensation costs arising from services rendered by~~notes to 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.financial statements. This guidance is effective for ~~interim and~~ annual reporting periods beginning after December 15, ~~2017,~~2020, with early adoption ~~permitted. This guidance must~~permitted, and is required to be adopted ~~retrospectively for the presentation~~retrospectively. The adoption 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 doesASU No. 2018-14 will not ~~believe this will~~ have a material impact on ~~its~~PacifiCorp's Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. 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 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. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases" and ASU No. 2018-11 that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings recognized in the period of adoption. 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 in the process of evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.


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

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

In ~~January~~November 2016, the FASB issued ASU No. ~~2016-01,~~2016-18, which amends FASB ASC Subtopic ~~825-10, "Financial Instruments~~230-10, "Statement of Cash Flows - Overall." The amendments in this guidance ~~address certain aspects~~require that a statement of ~~recognition, measurement, presentation~~cash flows explain the change during the period in the total of cash, cash equivalents, and ~~disclosure~~amounts generally described as restricted cash and restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of ~~financial instruments including~~cash flows. PacifiCorp adopted this guidance January 1, 2018.

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a ~~requirement that all investments in equity securities that do not qualify for equity method accounting~~maturity of three months or ~~result in consolidation~~less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. A reconciliation of ~~the investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim~~cash and ~~annual reporting periods beginning after December 15, 2017, with early adoption not permitted,~~cash equivalents and ~~is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet~~restricted cash and cash equivalents as of September 30, 2018 and December 31, 2017, as presented in the ~~beginning~~Consolidated Statements of Cash Flows is outlined below and disaggregated by the ~~fiscal year of adoption. PacifiCorp is currently evaluating~~line items in which they appear on 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.Balance Sheets (in millions):



	As of
	September 30,		December 31,
	2018		2017
Cash and cash equivalents	$	308	$	14
Restricted cash included in other current assets	13		13
Restricted cash included in other assets	2		2
Total cash and cash equivalents and restricted cash and cash equivalents	$	323	$	29

Equity Method Investments

In ~~May 2014,~~August 2016, the FASB issued ASU No. ~~2014-09,~~2016-15, which ~~creates~~amends FASB ASC Topic ~~606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition.~~230, "Statement of Cash Flows." 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 customersamendments 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 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. PacifiCorp adopted this guidance retrospectively 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 revenuewhich resulted in the ~~required financial statement footnote by customer class.~~reclassification of certain cash distributions received from equity method investees of $26 million previously recognized within investing cash flows to operating cash flows for the nine-month period ended September 30, 2017.

~~(3) Property, Plant and Equipment, Net~~


(4)	Property, Plant and Equipment, Net

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

As of
September 30, December 31,
Depreciable Life 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



		As of
		September 30,			December 31,
	Depreciable Life	2018			2017
Utility Plant:
Utility plant in-service	5-75 years	$	28,201		$	27,880
Accumulated depreciation and amortization		(9,750		)	(9,366		)
Utility plant in-service, net		18,451			18,514
Other non-regulated, net of accumulated depreciation and amortization	45 years	10			11
Plant, net		18,461			18,525
Construction work-in-progress		877			678
Property, plant and equipment, net		$	19,338		$	19,203


(5)	Regulatory Matters

~~(4)~~

Retail Regulated Rates

The Tax Cuts and Jobs Act enacted on December 22, 2017 ("2017 Tax Reform") enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. PacifiCorp has agreed to defer the impact of the tax law change with each of its state regulatory bodies. PacifiCorp proposed reducing customer rates for a portion of the lower annual income tax expense resulting from the decrease in federal tax rates and deferring the remainder to offset other costs as approved by the regulatory bodies. In March 2018, PacifiCorp proposed 1% rate reductions in Utah, Wyoming and Idaho. PacifiCorp proposed the rate reductions to be effective May 1, 2018 in Utah, July 1, 2018 in Wyoming and June 1, 2018 in Idaho. In April 2018, the Utah Public Service Commission ("UPSC") ordered a rate reduction of $61 million, or 3.1%, effective May 1, 2018 through December 31, 2018, based on a preliminary estimate of the revenue requirement impact of 2017 Tax Reform. In October 2018, PacifiCorp filed an all-party settlement with the UPSC that continues the current rate reduction of $61 million, with other benefits provided to customers through a combination of a reduction to thermal steam plant and deferral to offset costs in the next general rate case. PacifiCorp filed a partial settlement with the Wyoming Public Service Commission ("WPSC") in April 2018 that provides a rate reduction of $23 million, or 3.3%, effective July 1, 2018 through June 30, 2019, with the remaining tax savings to be deferred with offsets to other costs. In June 2018, the WPSC approved the rate reduction on an interim basis. In May 2018, the Idaho Public Utilities Commission ("IPUC") approved an all-party settlement to implement a rate reduction of $6 million, or 2.2%, effective June 1, 2018 through May 31, 2019, to pass back a portion of the tax benefit. The credit may be adjusted following the next phase of the proceeding. In June 2018, PacifiCorp filed reports with the WPSC and IPUC with the calculation of the full impact of the tax law change on revenue requirements. These reports initiated the next phase of the proceedings in these states. The WPSC scheduled a hearing for January 2019. A hearing has not yet been scheduled in Idaho. As of September 30, 2018, the estimated potential refund liability attributable to lower customer rates enabled by the benefits of tax reform was $112 million.


(6)	Recent Financing Transactions

Long-Term Debt

In ~~June 2017,~~July 2018, PacifiCorp ~~extended, with lender consent,~~issued $600 million of its 4.125% First Mortgage Bonds due 2049. PacifiCorp used a portion of the ~~maturity date~~net proceeds to ~~June 2020~~repay all of PacifiCorp's $500 million 5.65% First Mortgage Bonds due July 2018 and intends to use the remaining net proceeds to fund capital expenditures and for ~~its $400 million unsecured credit facility by exercising the first of two available one-year extensions.~~general corporate purposes.

Credit Facilities

In ~~June 2017,~~April 2018, PacifiCorp ~~terminated~~amended and restated, its ~~$600 million unsecured credit facility expiring March 2018 and entered into a $600~~existing $400 million unsecured credit facility expiring June 2020, ~~with~~increasing the lender commitment to $600 million, extending the expiration date to June 2021 and increasing from one to two, the available one-year extension options, subject to lender consent.

~~These~~In April 2018, PacifiCorp amended and restated, its existing $600 million unsecured credit ~~facilities, which support PacifiCorp's commercial paper program~~facility expiring June 2020, extending the expiration date to June 2021 and ~~certain series of its tax-exempt bond obligations and provide for~~reducing from two to one, 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,available one-year extension options, subject to ~~total capitalization not exceed 0.65 to 1.0 as of the last day of each quarter.~~lender consent.


(7)	Income Taxes

~~(5)~~

Tax Cuts and Jobs Act

2017 Tax Reform impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018 and limitations on bonus depreciation for utility property.

In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") 118 to assist in the implementation process of 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. PacifiCorp has recorded the impacts of 2017 Tax Reform and believes all the impacts to be complete with the exception of the interpretations of the bonus depreciation rules. PacifiCorp has determined the amounts recorded and the interpretations relating to this item to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. PacifiCorp believes its interpretations for bonus depreciation to be reasonable, however, as the guidance is clarified estimates may change. PacifiCorp recorded a current tax benefit and deferred tax expense of $21 million during the three-month period ended September 30, 2018 following clarified bonus depreciation guidance. As a result of 2017 Tax Reform and PacifiCorp's regulatory nature, PacifiCorp reduced the associated deferred income tax liabilities $8 million and increased regulatory liabilities by the same amount. The accounting will be completed by December 2018.

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,
	2018		2017		2018		2017

Federal statutory income tax rate	21	%	35	%	21	%	35	%
State income tax, net of federal income tax benefit	4		3		4		3
Federal income tax credits	(5	)	(5	)	(5	)	(5	)
Effects of ratemaking	(4	)	1		(4	)	1
Other	(1	)	(2	)	(2	)	(2	)
Effective income tax rate	15	%	32	%	14	%	32	%

Income tax credits relate primarily to production tax credits earned by PacifiCorp'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.


(8)	Employee Benefit Plans

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. PacifiCorp adopted this guidance January 1, 2018 prospectively for the capitalization of the service cost component in the Consolidated Balance Sheets and retrospectively for the presentation of the service cost component and the other components of net benefit cost in the Consolidated Statements of Operations utilizing the practical expedient to use the amounts previously disclosed in the Notes to Consolidated Financial Statements as the estimation basis for applying the retrospective presentation requirement. As a result, amounts other than the service cost for pension and other postretirement benefit plans for the three- and nine-month periods ended September 30, 2017 of $6 million and $17 million, respectively, have been reclassified to Other, net in the Consolidated Statements of Operations.

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


	Three-Month Periods						Nine-Month Periods						Three-Month Periods				Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,				Ended September 30,
	2017			2016			2017			2016			2018		2017		2018		2017
Pension:
Service cost	$	—		$	1		$	—		$	3		—		—		—		—
Interest cost	12			14			37			41			11		12		32		37
Expected return on plan assets	(18		)	(18		)	(54		)	(56		)	(18	)	(18	)	(54	)	(54	)
Net amortization	3			8			10			25			3		3		10		10
Net periodic benefit (credit) cost	$	(3	)	$	5		$	(7	)	$	13
Net periodic benefit credit													(4	)	(3	)	(12	)	(7	)

Other postretirement:
Service cost	$	1		$	1		$	2		$	2		—		1		1		2
Interest cost	3			3			10			11			3		3		9		10
Expected return on plan assets	(5		)	(5		)	(16		)	(16		)	(5	)	(5	)	(16	)	(16	)
Net amortization	(1		)	(1		)	(4		)	(4		)	(1	)	(1	)	(4	)	(4	)
Net periodic benefit credit	$	(2	)	$	(2	)	$	(8	)	$	(7	)	(3	)	(2	)	(10	)	(8	)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $5$4 million and $- million, respectively, during ~~2017~~2018. As of September 30, ~~2017,~~2018, $3 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.

~~(6) Risk Management and Hedging Activities~~


(9)	Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Note 710 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						Other					Other			Other
	Current			Other		Current			Long-term						Current			Other		Current			Long-term
	Assets			Assets		Liabilities			Liabilities			Total			Assets			Assets		Liabilities			Liabilities			Total

As of September 30, 2017
As of September 30, 2018
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	4		$	1	$	2		$	—		$	7		$	10		$	4	$	6		$	—		$	20
Commodity liabilities	(1		)	—		(24		)	(82		)	(107		)	(6		)	2		(47		)	(74		)	(125		)
Total	3			1		(22		)	(82		)	(100		)	4			6		(41		)	(74		)	(105		)

Total derivatives	3			1		(22		)	(82		)	(100		)	4			6		(41		)	(74		)	(105		)
Cash collateral receivable	—			—		16			57			73			—			—		18			52			70
Total derivatives - net basis	$	3		$	1	$	(6	)	$	(25	)	$	(27	)	$	4		$	6	$	(23	)	$	(22	)	$	(35	)

As of December 31, 2016
As of December 31, 2017
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	24		$	2	$	1		$	—		$	27		$	11		$	1	$	1		$	—		$	13
Commodity liabilities	(6		)	—		(14		)	(84		)	(104		)	(3		)	—		(32		)	(82		)	(117		)
Total	18			2		(13		)	(84		)	(77		)	8			1		(31		)	(82		)	(104		)

Total derivatives	18			2		(13		)	(84		)	(77		)	8			1		(31		)	(82		)	(104		)
Cash collateral receivable	—			—		10			59			69			—			—		17			57			74
Total derivatives - net basis	$	18		$	2	$	(3	)	$	(25	)	$	(8	)	$	8		$	1	$	(14	)	$	(25	)	$	(30	)


(1)	PacifiCorp's commodity derivatives are generally included in rates and as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, a regulatory asset of ~~$97~~$102 million and ~~$73~~$101 million, respectively, was recorded related to the net derivative liability of ~~$100~~$105 million and ~~$77~~$104 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						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017

Beginning balance	$	95		$	89		$	73		$	133		$	116		$	95		$	101		$	73
Changes in fair value recognized in net regulatory assets	6			15			36			(4		)	14			6			48			36
Net (losses) gains reclassified to operating revenue	(5		)	(2		)	8			8			(36		)	(5		)	(30		)	8
Net gains (losses) reclassified to energy costs	1			—			(20		)	(35		)
Net gains (losses) reclassified to cost of fuel and energy													8			1			(17		)	(20		)
Ending balance	$	97		$	102		$	97		$	102		$	102		$	97		$	102		$	97

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,		Unit of	September 30,		December 31,
	Measure	2017		2016		Measure	2018		2017

Electricity sales	Megawatt hours	(3	)	(3	)	Megawatt hours	(7	)	(9	)
Natural gas purchases	Decatherms	97		84		Decatherms	115		113
Fuel oil purchases	Gallons	2		11		Gallons	2		—

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,~~2018, 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~~$108 million and ~~$97~~$110 million as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, respectively, for which PacifiCorp had posted collateral of ~~$73~~$70 million and ~~$69~~$74 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~~2018 and December 31, ~~2016,~~2017, PacifiCorp would have been required to post $26 million and ~~$22~~$34 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~~


(10)	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													Input Levels for Fair Value Measurements
	Level 1		Level 2			Level 3		Other⁽¹⁾			Total			Level 1		Level 2			Level 3		Other⁽¹⁾			Total
As of September 30, 2017
As of September 30, 2018
Assets:
Commodity derivatives	$	—	$	7		$	—	$	(3	)	$	4		$	—	$	20		$	—	$	(10	)	$	10
Money market mutual funds⁽²⁾	100		—			—		—			100			310		—			—		—			310
Investment funds	20		—			—		—			20			26		—			—		—			26
	$	120	$	7		$	—	$	(3	)	$	124		$	336	$	20		$	—	$	(10	)	$	346

Liabilities - Commodity derivatives	$	—	$	(107	)	$	—	$	76		$	(31	)	$	—	$	(125	)	$	—	$	80		$	(45	)

As of December 31, 2016
As of December 31, 2017
Assets:
Commodity derivatives	$	—	$	27		$	—	$	(7	)	$	20		$	—	$	13		$	—	$	(4	)	$	9
Money market mutual funds⁽²⁾	13		—			—		—			13			21		—			—		—			21
Investment funds	17		—			—		—			17			21		—			—		—			21
	$	30	$	27		$	—	$	(7	)	$	50		$	42	$	13		$	—	$	(4	)	$	51

Liabilities - Commodity derivatives	$	—	$	(104	)	$	—	$	76		$	(28	)	$	—	$	(117	)	$	—	$	78		$	(39	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of ~~$73~~$70 million and ~~$69~~$74 million as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, 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~~three 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~~three 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 69 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.~~value. 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



	As of September 30, 2018				As of December 31, 2017
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	7,014	$	7,862	$	7,005	$	8,370

~~(8)~~


(11)	Commitments and Contingencies

Commitments

During the nine-month period endedSeptember 30,2018, PacifiCorp entered into non-cancelable agreements through 2045 totaling $1.0 billion related to power purchase agreements to meet customer requests for renewable energy, $566 million related to agreements for repowering certain existing wind facilities in Wyoming, Washington and Oregon, and $273 million related to fuel supply contracts. The power purchase agreements are from facilities that have not yet achieved commercial operation. To the extent any of these facilities do not achieve commercial operation by contractually agreed upon dates, PacifiCorp has no obligation to the counterparty.

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").

Among other things, the KHSA provided that the United States Department of the Interior would conduct scientific and engineering studies to assess whether removal of the Klamath hydroelectric system's mainstem dams was in the public interest and would advance restoration of the Klamath Basin's salmonid fisheries. If it is determined dam removal should proceed, dam removal would begin no earlier than 2020.

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.


(12)	Revenue from Contracts with Customers

Adoption

In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" ("ASC 606") and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize revenue from contracts with customers ("Customer 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. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. PacifiCorp adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method. The adoption did not have a cumulative effect impact at the date of initial adoption.

Customer Revenue

PacifiCorp recognizes revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or services. PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

Substantially all of PacifiCorp's Customer Revenue is derived from tariff based sales arrangements approved by various regulatory bodies. These tariff based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 815, "Derivatives and Hedging."

Revenue recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp's performance to date and includes billed and unbilled amounts. As of September 30, 2018 and December 31, 2017, accounts receivable from contracts with customers, net of allowance for doubtful accounts was $673 million and $635 million, respectively, including unbilled revenue of $229 million and $255 million, respectively, and was included in accounts receivables, net on the Consolidated Balance Sheets. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

The following table summarizes PacifiCorp's revenue by regulated energy, with further disaggregation of regulated energy by customer class, for the three- and nine-month periods ended September 30, 2018 (in millions):



	Three-Month Period			Nine-Month Period
	Ended September 30,			Ended September 30,
	2018			2018
Customer Revenue:
Retail:
Residential	$	478		$	1,284
Commercial	418			1,129
Industrial	305			862
Other retail	106			204
Total retail	1,307			3,479
Wholesale ⁽¹⁾	(10		)	21
Transmission	30			82
Other Customer Revenue	16			55
Total Customer Revenue	1,343			3,637
Other revenue	26			109
Total operating revenue	$	1,369		$	3,746


(1)	During the three-month period endedSeptember 30, 2018, PacifiCorp financially settled certain non-derivative forward contracts for energy sales by making net payments to counterparties.

Contract Assets and Liabilities

In the event one of the parties to a contract has performed before the other, PacifiCorp would recognize a contract asset or contract liability depending on the relationship between PacifiCorp's performance and the customer's payment. As of September 30, 2018 and December 31, 2017, there were no material contract assets or contract liabilities recorded on the Consolidated Balance Sheets. During the three- and nine-month periods ended September 30, 2018, there was no material revenue recognized that was included in the contract liability balance at the beginning of the period or from performance obligations satisfied in previous periods.

~~(9) Related Party Transactions~~


(13)	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 federal and state income ~~taxes~~tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income ~~taxes are~~tax is remitted to or received from BHE. For the nine-month periods ended September 30, ~~2017~~2018 and ~~2016,~~2017, PacifiCorp made net cash payments for federal and state income ~~taxes~~tax to BHE totaling ~~$205~~$21 million and ~~$61~~$205 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~~2018 and ~~2016~~2017

Overview

Net income for the third quarter of ~~2017~~2018 was ~~$263~~$270 million, an increase of ~~$10~~$7 million, or 4%3%, compared to ~~2016.~~2017. Net income increased primarily due to ~~higher gross margins~~a decrease in income tax expense of ~~$30~~$78 million ~~excluding~~from a lower federal tax rate due to the impact of ~~demand side management program revenue (offset in~~the Tax Cuts and Jobs Act enacted on December 22, 2017 ("2017 Tax Reform"), partially offset by lower utility margin of $61 million and higher operations and maintenance ~~expense)~~expense of ~~$21~~$12 million. Utility margin decreased due to lower average retail and wholesale rates, including $53 million of refund accruals related to 2017 Tax Reform, higher natural gas costs from higher volumes and higher purchased electricity from higher prices, partially offset by higher ~~depreciation~~retail volumes 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.prices. Retail customer volumes increased ~~2.1%~~2% due to ~~impacts of weather on~~higher customer usage, primarily from industrial, commercial and 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~~across the service territory, offset by ~~lower irrigation usage in Idaho and Oregon, and lower industrial usage in Utah and Oregon.~~impacts of weather across the service territory. Energy generated ~~decreased 2%~~increased 7% for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~lower~~higher natural ~~gas-fueled~~gas and wind-powered generation, ~~partially~~ offset by ~~higher~~lower coal-fueled and hydroelectric generation. Wholesale electricity sales volumes ~~decreased 11%~~increased 33% and purchased electricity volumes ~~increased 19%~~decreased 17%.

Net income for the first nine months of ~~2017~~2018 was ~~$617~~$602 million, ~~an increase~~a decrease of ~~$23~~$15 million, or 4%2%, compared to ~~2016.~~2017. Net income ~~increased~~decreased primarily due to ~~higher gross margins~~lower utility margin of ~~$71~~$205 million, ~~excluding the impact of demand side management program revenue (offset in~~and higher operations and maintenance ~~expense)~~expenses of ~~$44~~$6 million, partially offset by ~~higher depreciation and amortization~~lower income tax expense of ~~$22~~$194 million from ~~additional plant placed in-service and higher property taxes of $6 million. Gross margins increased~~a lower federal tax rate due to ~~higher~~the impact of 2017 Tax Reform. Utility margin decreased due to lower retail ~~customer volumes, lower natural gas-fueled generation, higher wholesale~~ revenue from lower average retail rates, including $159 million of refund accruals related to 2017 Tax Reform, and lower retail volumes, higher ~~short-term market~~purchased electricity from higher prices and volumes, lower average wholesale prices, and higher ~~wheeling revenue,~~natural gas generation volumes, partially offset by higher ~~purchased electricity~~wholesale volumes, lower coal costs from ~~higher~~lower volumes and prices, and lower average ~~retail rates.~~natural gas prices. Retail customer volumes ~~increased 2.4%~~decreased 1% due to ~~impacts~~the unfavorable impact of weather across the service territory, and lower customer usage, primarily ~~on residential~~from industrial customers in Oregon ~~Washington~~ and Utah, partially offset by higher commercial and irrigation customer usage ~~primarily~~ in ~~Oregon,~~Utah and 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.~~territory. Energy generated ~~decreased~~increased 2% for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~lower~~higher natural ~~gas-fueled~~gas and wind-powered generation, ~~partially~~ offset by ~~higher~~lower hydroelectric and ~~coal~~coal-fueled generation. Wholesale electricity sales volumes ~~decreased 3%~~increased 37% and purchased electricity volumes increased ~~20%~~4%.

~~Operating~~Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, Utility Margin, to help evaluate results of operations. Utility Margin is calculated as operating revenue less cost of fuel and energy, ~~costs~~which are captions presented on the ~~key drivers~~Consolidated Statements of Operations.

PacifiCorp's ~~results~~cost of ~~operations~~fuel and energy is directly recovered from its customers through regulatory recovery mechanisms and as ~~they encompass retail~~a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes Utility Margin more appropriately and ~~wholesale electricity revenue and the direct costs associated with providing electricity to customers. PacifiCorp believes that~~concisely explains profitability rather than a discussion of ~~gross~~revenue and cost of fuel and energy separately. Management believes the presentation of Utility Margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Utility Margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin ~~representing~~to operating ~~revenue less energy costs, is therefore meaningful.~~income (in millions):



	Third Quarter									First Nine Months
	2018		2017		Change					2018		2017		Change
Utility margin:
Operating revenue	$	1,369	$	1,430	$	(61	)	(4	)%	$	3,746	3,956		$	(210	)	(5	)%
Cost of fuel and energy	465		465		—			—		1,300		1,305		(5		)	—
Utility margin	904		965		(61		)	(6	)	2,446		2,651		(205		)	(8	)
Operations and maintenance	266		254		12			5		777		771		6			1
Depreciation and amortization	203		200		3			2		602		598		4			1
Property and other taxes	49		50		(1		)	(2	)	150		149		1			1
Operating income	$	386	$	461	$	(75	)	(16	)	$	917	$	1,133	$	(216	)	(19	)

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


	Third Quarter									First Nine Months									Third Quarter									First Nine Months
	2017		2016		Change					2017		2016		Change					2018		2017		Change					2018		2017		Change
Gross margin (in millions):
Utility margin (in millions):
Operating revenue	$	1,430	$	1,434	$	(4	)	—	%	$	3,956	$	3,919	$	37		1	%	$	1,369	$	1,430	$	(61	)	(4	)%	$	3,746	$	3,956	$	(210	)	(5	)%
Energy costs	465		478		(13		)	(3	)%	1,305		1,295		10			1	%
Gross margin	$	965	$	956	$	9		1	%	$	2,651	$	2,624	$	27		1	%
Cost of fuel and energy																			465		465		—			—		1,300		1,305		(5		)	—
Utility margin																			$	904	$	965	$	(61	)	(6	)	$	2,446	$	2,651	$	(205	)	(8	)

Sales (GWh):
Residential	4,372		4,147		225			5	%	12,410		11,909		501			4	%	4,347		4,372		(25		)	(1	)%	11,996		12,410		(414		)	(3	)%
Commercial⁽¹⁾	4,783		4,544		239			5	%	13,303		12,863		440			3	%	4,941		4,783		158			3		13,530		13,303		227			2
Industrial, irrigation and other⁽¹⁾	5,683		5,839		(156		)	(3	)%	16,061		16,004		57			—	%	5,823		5,683		140			2		15,889		16,061		(172		)	(1	)
Total retail	14,838		14,530		308			2	%	41,774		40,776		998			2	%	15,111		14,838		273			2		41,415		41,774		(359		)	(1	)
Wholesale	1,350		1,513		(163		)	(11	)%	4,362		4,493		(131		)	(3	)%	1,802		1,350		452			33		5,963		4,362		1,601			37
Total sales	16,188		16,043		145			1	%	46,136		45,269		867			2	%	16,913		16,188		725			4		47,378		46,136		1,242			3

Average number of retail customers
(in thousands)	1,868		1,842		26			1	%	1,863		1,837		26			1	%	1,902		1,868		34			2	%	1,896		1,863		33			2	%

Average revenue per MWh:
Retail	$	90.58	$	93.10	$	(2.52	)	(3	)%	$	88.41	$	90.44	$	(2.03	)	(2	)%	$	86.29	$	90.58	$	(4.29	)	(5	)%	$	83.92	$	88.41	$	(4.49	)	(5	)%
Wholesale	$	28.74	$	28.32	$	0.42		1	%	$	29.55	$	25.41	$	4.14		16	%	$	9.12	$	28.74	$	(19.62	)	(68	)%	$	21.62	$	29.55	$	(7.93	)	(27	)%

Heating degree days	304		236		68			29	%	6,472		5,726		746			13	%	208		304		(96		)	(32	)%	5,655		6,472		(817		)	(13	)%
Cooling degree days	1,804		1,494		310			21	%	2,342		2,051		291			14	%	1,532		1,804		(272		)	(15	)%	1,980		2,342		(362		)	(15	)%

Sources of energy (GWh)⁽²⁾:
Sources of energy (GWh)⁽¹⁾:
Coal	10,764		10,775		(11		)	—	%	27,120		26,637		483			2	%	10,510		10,764		(254		)	(2	)%	26,231		27,120		(889		)	(3	)%
Natural gas	2,486		2,743		(257		)	(9	)%	5,647		7,642		(1,995		)	(26	)%	3,841		2,486		1,355			55		7,770		5,647		2,123			38
Hydroelectric⁽³⁾⁽²⁾	641		488		153			31	%	3,598		2,719		879			32	%	467		641		(174		)	(27	)	2,640		3,598		(958		)	(27	)
Wind and other⁽³⁾⁽²⁾	460		647		(187		)	(29	)%	2,030		2,337		(307		)	(13	)%	569		460		109			24		2,353		2,030		323			16
Total energy generated	14,351		14,653		(302		)	(2	)%	38,395		39,335		(940		)	(2	)%	15,387		14,351		1,036			7		38,994		38,395		599			2
Energy purchased	3,023		2,542		481			19	%	10,845		9,031		1,814			20	%	2,506		3,023		(517		)	(17	)	11,279		10,845		434			4
Total	17,374		17,195		179			1	%	49,240		48,366		874			2	%	17,893		17,374		519			3		50,273		49,240		1,033			2

Average cost of energy per MWh:
Energy generated⁽⁴⁾⁽³⁾	$	19.89	$	20.86	$	(0.97	)	(5	)%	$	19.21	$	19.36	$	(0.15	)	(1	)%	$	19.45	$	19.89	$	(0.44	)	(2	)%	$	18.96	$	19.21	$	(0.25	)	(1	)%
Energy purchased	$	53.34	$	49.68	$	3.66		7	%	$	42.20	$	43.02	$	(0.82	)	(2	)%	$	70.75	$	53.34	$	17.41		33	%	$	44.43	$	42.20	$	2.23		5	%


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


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

~~Gross~~Utility margin ~~increased $9~~decreased $61 million, or 1%6%, for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to:

$59 million of lower retail revenue primarily due to lower average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $53 million;

$3830 million of lower wholesale revenues from lower average prices;

$23 million of higher ~~retail revenues~~natural gas costs due to ~~increased volumes~~higher volumes; and

$16 million of ~~2.1%~~higher purchased electricity costs due to ~~impacts of weather~~higher prices and ~~higher usage, primarily in Utah and Oregon;~~volumes.

The decreases above were partially offset by:

$2831 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms;

$19 million of higher retail revenue from higher volumes. Retail volumes increased 2% due to due to higher customer usage, primarily from industrial, commercial and residential customers in Utah, and an increase in the average number of customers across the service territory, offset by impacts of weather across the service territory;

$228 million of lower coal costs from lower prices; and

$8 million of higher wholesale revenues from higher volumes.

Operations and maintenance increased $12 million, or 5%, for the third quarter of 2018 compared to 2017 primarily due to ~~prior year charges related~~reserves accrued for 2018 wildfires and higher labor costs.

Depreciation and amortization increased $3 million, or 2%, for the third quarter of 2018 compared to ~~damaged longwall mining equipment,~~2017 primarily due to higher plant-in-service.

Income tax expense decreased $78 million, or 62%, for the third quarter of 2018 compared to 2017. The effective tax rate was 15% for 2018 and ~~current quarter lower volumes;~~32% for 2017. The effective tax rate decreased primarily as a result of the reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018, and the amortization of the excess deferred income taxes resulting from the reduction in the U.S. federal corporate income tax rate.

Utility margin decreased $205 million, or 8%, for the first nine months of 2018 compared to 2017 primarily due to:

$7184 million of lower ~~natural gas costs~~retail revenue primarily due to lower ~~gas-fueled generation as gas prices were higher in 2017.~~

~~The increases above were partially offset by:~~

average retail rates, including the impact of a lower federal tax rate due to 2017 Tax Reform of $159 million;

$3544 million of higher purchased electricity costs due to higher prices and volumes;

$2236 million of lower wholesale revenue from lower average ~~retail rates;~~

prices;

$2134 million of higher natural gas costs due to higher volumes; and

$33 million of lower ~~demand side management program~~retail 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~~from lower retail customer volumes. Retail volumes decreased ~~$24 million, or 9%, for the third quarter of 2017 compared to 2016 primarily~~1% 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~~unfavorable impacts of weather across the service territory, and lower customer usage, primarily ~~on residential~~from industrial customers in Oregon ~~Washington~~ and Utah, partially offset by higher commercial and irrigation customer usage ~~primarily~~ in ~~Oregon,~~Utah and 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;~~territory.

The decreases above were partially offset by:

$3655 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms;

$2836 million of ~~lower natural gas costs primarily due to lower gas-fueled generation~~higher wholesale revenue due to higher ~~gas prices in 2017;~~

volumes;

$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~~lower volumes and ~~short-term prices.~~

~~The increases above were partially offset by:~~

prices; and

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

~~$49~~12 million of lower natural gas costs from 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.~~

prices.

Operations and maintenance ~~decreased $46~~increased $6 million, or 6%1%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 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 werereserves accrued for 2018 wildfires, partially offset by ~~higher injury and damage expenses, primarily due to a prior year accrual for insurance proceeds, and higher~~lower labor ~~costs related to storm damage restoration.~~costs.

Depreciation and amortization increased ~~$22~~$4 million, or 4%1%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to higher ~~plant-in-service.~~plant-in-service, partially offset by an adjustment to the Oregon accelerated depreciation reserve based on the Oregon allocation factor in 2018.

~~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~~decreased $194 million, or 9%66%, for the first nine months of ~~2017~~2018 compared to ~~2016 and the~~2017. The effective tax rate was 14% for 2018 and 32% ~~and 31%~~ for ~~2017 and 2016, respectively.~~2017. The effective tax rate ~~increased~~decreased primarily ~~due to lower production tax credits associated with PacifiCorp's wind-powered generating facilities~~ as a result of the ~~expiration~~reduction in the U.S. federal corporate income tax rate from 35% to 21%, effective January 1, 2018, and the amortization of the ~~10-year production~~excess deferred income taxes resulting from the reduction in the U.S. federal corporate income tax ~~credit period for certain wind-powered generating facilities.~~rate.

Liquidity and Capital Resources

As of September 30, ~~2017,~~2018, PacifiCorp's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	104		$	308

Credit facilities	1,000			1,200
Less:
Short-term debt	—			-
Tax-exempt bond support	(130		)	(89		)
Net credit facilities	870			1,111

Total net liquidity	$	974		$	1,419

Credit facilities:
Maturity dates	2020			2021

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2018 and 2017 ~~and 2016~~ were ~~$1,435~~$1,480 million and ~~$1,372~~$1,461 million, respectively. The change was primarily due to ~~the payment for USA Power final judgment~~lower current year income tax paid and ~~post-judgment interest in the prior~~higher current year ~~higher receipts~~collections from wholesale ~~and retail~~ customers, ~~and lower fuel payments,~~primarily due to timing, partially offset by higher current year ~~higher cash payments for income taxes~~purchased power costs and ~~purchased power.~~lower current year collections from retail customers, primarily due to the 2017 Tax Reform.

~~In December 2015,~~2017 Tax Reform reduced the ~~Protecting Americans~~federal corporate tax rate from ~~Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before~~35% to 21% effective 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. As a result of PATH, PacifiCorp's cash flows from operations are expected to benefit due to~~eliminated bonus depreciation on qualifying regulated utility assets ~~placed in-service~~acquired after December 31, 2017. PacifiCorp anticipates passing the benefits of lower tax expense to customers through regulatory mechanisms. PacifiCorp expects lower revenue and income tax as well as lower bonus depreciation benefits compared to 2017 as a result of 2017 Tax Reform and related regulatory treatment. PacifiCorp does not expect 2017 Tax Reform and related regulatory treatment to have a material adverse impact on its cash flows, subject to actual regulatory outcomes, which will be determined based on rulings by regulatory commissions expected in 2018 and 2019.

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.

Internal Revenue Service ("IRS") rules provide for re-establishment of the production tax credit for an existing wind-powered generating facility upon the replacement of a significant portion of its components. Such component replacement is commonly referred to as repowering. If the degree of component replacement in such projects meets IRS guidelines, production tax credits are re-established for ten years at rates that depend upon the date in which construction begins. PacifiCorp's current repowering projects are expected to earn production tax credits at 100% of the value of such credits.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2018 and 2017 ~~and 2016~~ were ~~$(521)~~$(711) million and ~~$(560)~~$(548) million, respectively. The change ~~mainly reflects~~is primarily the result of a current year ~~decrease~~increase in capital expenditures of ~~$33~~$160 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, 2018 was $(475) million. Uses of cash consisted substantially of $586 million for the repayment of long term debt, $400 million for common stock dividends paid to PPW Holdings LLC and $80 million for the repayment of short-term debt, offset by $593 million net proceeds from the issuance of long-term debt.

Net cash flows from financing activities for the nine-month period ended September 30, 2017 was $(827) million. Uses of cash consisted substantially of $270 million for the repayment of short-term debt, $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,~~2018, PacifiCorp had no short-term debt outstanding. As of December 31, ~~2016,~~2017, PacifiCorp had ~~$270~~$80 million of short-term debt outstanding at a weighted average interest rate of ~~0.96%~~1.83%.

Long-term Debt

In July 2018, PacifiCorp issued $600 million of its 4.125% First Mortgage Bonds due January 2049. PacifiCorp used a portion of the net proceeds to repay all of PacifiCorp's $500 million 5.65% First Mortgage Bonds due July 2018 and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional ~~$1.3 billion~~$725 million of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance.

As of September 30, ~~2017,~~2018, PacifiCorp had ~~$216~~$170 million of letters of credit providing credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling ~~$213~~$168 million plus interest. These letters of credit were fully available as of September 30, ~~2017~~2018 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, impacts to customers' rates; 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		Nine-Month Periods				Annual
	Ended September 30,				Forecast		Ended September 30,				Forecast
	2016		2017		2017		2017		2018		2018

Transmission system investment	$	68	$	75	$	118	$	75	$	34	$	66
Environmental	42		18		28
Wind investment	—		8		8		8		76		384
Advanced meter infrastructure							20		44		74
Operating and other	476		452		644		450		559		674
Total	$	586	$	553	$	798	$	553	$	713	$	1,198

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~~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~~$45 million in ~~2017.~~2018.

~~Environmental~~Construction of wind-powered generating facilities at PacifiCorp totaling $5 million and $4 million for the nine-month periods ended September 30, 2018 and 2017. PacifiCorp anticipates costs for these activities will total an additional $62 million for 2018. The new wind-powered generating facilities are expected to be placed in-service in 2020. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal production tax credits available for ten years once the equipment is placed in-service.

Repowering certain existing wind-powered generating facilities at PacifiCorp totaling $70 million and $4 million for the nine-month periods ended September 30, 2018 and 2017, respectively. PacifiCorp anticipates costs for these activities will total an additional $246 million for 2018. The repowering projects are expected to be placed in-service at various dates in 2019 and 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal renewable electricity production tax credits available for ten years following each facility's return to service.

Advanced meter infrastructure ("AMI") includes ~~the~~costs for customer meter replacements and installation of ~~new~~infrastructure and systems to implement smart meter features that improve customers' energy management capabilities and reduce company meter-related costs. AMI projects are in progress or ~~the replacement of existing emissions control equipment at certain generating facilities, including installation or upgrade of selective catalytic reduction control systems~~planned in Oregon, California, Utah 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.Idaho in 2018.

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.~~demand.

Integrated Resource Plan

In April 2017, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP") with its state commissions. The IRP, which includes the Energy Vision 2020 project in the preferred portfolio, 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~~The OPUC acknowledged PacifiCorp's 2017 IRP in December 2017, the UPSC acknowledged the 2017 IRP in March 2018, the IPUC acknowledged the 2017 IRP in April 2018, and ~~new wind renewable resources will require an estimated $3 billion~~the WUTC acknowledged the 2017 IRP 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 ofMay 2018. PacifiCorp filed its 2017 ~~IRP.~~IRP Update with its state commissions, except for California, in May 2018. In August 2018, PacifiCorp filed its 2017 IRP and its 2017 IRP Update with the California Public Utilities Commission to comply with new IRP requirements in California.

Request for Proposals

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

As required by applicable laws and regulations, PacifiCorp filed its draft 2017R ~~Request for Proposals ("RFP")~~RFP with the UPSC in June 2017 and with the OPUC in August 2017. The UPSC and the OPUC approved ~~PacifiCorp’s~~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~~sought up to approximately 1,270 MW of new wind resources that can interconnect to ~~PacifiCorp’s~~PacifiCorp's transmission system in Wyoming once a proposed high-voltage transmission line is constructed. The 2017R RFP is also ~~seeking~~sought 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~~received in October 2017 and best-and-final pricing, reflecting changes in federal tax law, was received in December 2017. PacifiCorp finalized its bid-selection process and established a final shortlist in February 2018. PacifiCorp is finalizing agreements to acquire energy and capacity from three wind facilities totaling 1,150 MWs, consisting of 950 MWs owned and 200 MWs as a power-purchase agreement.

Contractual Obligations

As of September 30, ~~2017,~~2018, 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.~~2017.

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.~~2017. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, ~~2016.~~2017.

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~~

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of September 30, ~~2017, and~~2018, the related statements of operations for the three-month and nine-month periods ended September 30, ~~2017~~2018 and ~~2016,~~2017, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 2018 and 2017, and ~~2016. These~~the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~MidAmerican Energy's management.~~America.

We ~~conducted our reviews~~have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2017, and the related statements of operations, comprehensive income, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2018, 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, 2017, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Energy's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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~~2, 2018

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		September 30,		December 31,
	2017		2016		2018		2017
ASSETS
Current assets:
Cash and cash equivalents	$	512	$	14	$	115	$	172
Receivables, net	312		285
Income taxes receivable	—		9
Accounts receivable, net					384		344
Income tax receivable					150		51
Inventories	235		264		205		245
Other current assets	21		35		104		134
Total current assets	1,080		607		958		946

Property, plant and equipment, net	13,587		12,821		15,233		14,207
Regulatory assets	1,335		1,161		230		204
Investments and restricted cash and investments	707		653
Investments and restricted investments					756		728
Other assets	193		217		211		233

Total assets	$	16,902	$	15,459	$	17,388	$	16,318

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

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		September 30,		December 31,
	2017		2016		2018		2017
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	256	$	303	$	348	$	452
Accrued interest	52		45		55		48
Accrued property, income and other taxes	228		137		155		132
Short-term debt	—		99
Current portion of long-term debt	350		250		500		350
Other current liabilities	158		159		153		128
Total current liabilities	1,044		993		1,211		1,110

Long-term debt	4,544		4,051		4,880		4,692
Regulatory liabilities					1,645		1,661
Deferred income taxes	3,781		3,572		2,322		2,237
Regulatory liabilities	927		883
Asset retirement obligations	515		510		546		528
Other long-term liabilities	307		290		325		326
Total liabilities	11,118		10,299		10,929		10,554

Commitments and contingencies (Note 8)
Commitments and contingencies (Note 10)

Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—		—		—		—
Additional paid-in capital	561		561		561		561
Retained earnings	5,223		4,599		5,898		5,203
Total shareholder's equity	5,784		5,160		6,459		5,764

Total liabilities and shareholder's equity	$	16,902	$	15,459	$	17,388	$	16,318

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						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Operating revenue:
Regulated electric	$	707		$	692		$	1,677		$	1,572		$	727		$	707		$	1,785		$	1,677
Regulated gas and other	106			103			489			432
Regulated natural gas and other													105			106			510			489
Total operating revenue	813			795			2,166			2,004			832			813			2,295			2,166

Operating costs and expenses:
Cost of fuel, energy and capacity	130			130			342			312
Cost of gas sold and other	54			55			288			237
Operating expenses:
Cost of fuel and energy													140			130			366			342
Cost of natural gas purchased for resale and other													50			54			296			288
Operations and maintenance	200			180			547			510			201			204			598			561
Depreciation and amortization	111			118			369			338			133			111			499			369
Property and other taxes	30			28			90			84			30			30			92			90
Total operating costs and expenses	525			511			1,636			1,481
Total operating expenses													554			529			1,851			1,650

Operating income	288			284			530			523			278			284			444			516

Other income (expense):
Interest expense	(54		)	(50		)	(160		)	(147		)	(56		)	(54		)	(170		)	(160		)
Allowance for borrowed funds	4			3			9			6			6			4			14			9
Allowance for equity funds	11			6			25			14			16			11			39			25
Other, net	5			3			13			8			13			9			34			27
Total other income (expense)	(34		)	(38		)	(113		)	(119		)	(21		)	(30		)	(83		)	(99		)

Income before income tax benefit	254			246			417			404			257			254			361			417
Income tax benefit	(131		)	(74		)	(207		)	(123		)	(226		)	(131		)	(334		)	(207		)

Net income	$	385		$	320		$	624		$	527		$	483		$	385		$	695		$	624

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

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S 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



	Common Stock		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity

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

Balance, December 31, 2017	$	—	$	561	$	5,203	$	5,764
Net income	—		—		695		695
Balance, September 30, 2018	$	—	$	561	$	5,898	$	6,459

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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income	$	624		$	527		$	695		$	624
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	369			338			499			369
Amortization of utility plant to other operating expenses							26			25
Allowance for equity funds							(39		)	(25		)
Deferred income taxes and amortization of investment tax credits	64			113			(35		)	64
Changes in other assets and liabilities	28			34
Other, net	(23		)	(42		)	13			5
Changes in other operating assets and liabilities:
Receivables, net	(28		)	(67		)
Accounts receivable and other assets							(46		)	(29		)
Inventories	29			(26		)	40			29
Derivative collateral, net	3			4			—			3
Contributions to pension and other postretirement benefit plans, net	(8		)	(5		)	(10		)	(8		)
Accounts payable	(5		)	14
Accrued property, income and other taxes, net	98			160			(77		)	98
Other current assets and liabilities	20			30
Accounts payable and other liabilities							(38		)	18
Net cash flows from operating activities	1,171			1,080			1,028			1,173

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
Capital expenditures							(1,466		)	(1,162		)
Purchases of marketable securities							(224		)	(126		)
Proceeds from sales of marketable securities							198			127
Other, net	—			5			29			(10		)
Net cash flows from investing activities	(1,161		)	(1,128		)	(1,463		)	(1,171		)

Cash flows from financing activities:
Proceeds from long-term debt	842			33			687			842
Repayments of long-term debt	(255		)	(38		)	(350		)	(255		)
Net repayments of short-term debt	(99		)	—			—			(99		)
Other, net							(1		)	—
Net cash flows from financing activities	488			(5		)	336			488

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
Net change in cash and cash equivalents and restricted cash and cash equivalents							(99		)	490
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period							282			26
Cash and cash equivalents and restricted cash and cash equivalents at end of period							$	183		$	516

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 holding company based in Des Moines, Iowa and 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,~~2018, and for the three- and nine-month periods ended September 30, ~~2017~~2018 and ~~2016.~~2017. The results of operations for the three- and nine-month periods ended September 30, ~~2017,~~2018, 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,~~2017, 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.~~2018.


(2)	New Accounting Pronouncements

In ~~March 2017,~~February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. ~~2017-07,~~2016-02, which ~~amends~~creates FASB Accounting Standards Codification ("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. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases" and ASU No. 2018-11 that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings recognized in the period of adoption. 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 in the process of evaluating the impact on its Financial Statements and disclosures included within Notes to Financial Statements.


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



	As of
	September 30,		December 31
	2018		2017

Cash and cash equivalents	$	115	$	172
Restricted cash and cash equivalents in other current assets	68		110
Total cash and cash equivalents and restricted cash and cash equivalents	$	183	$	282


(4)	Property, Plant and Equipment, Net

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



		As of
		September 30,			December 31,
	Depreciable Life	2018			2017
Utility plant in service, net:
Generation	20-70 years	$	12,500		$	12,107
Transmission	52-75 years	1,870			1,838
Electric distribution	20-75 years	3,519			3,380
Natural gas distribution	29-75 years	1,694			1,640
Utility plant in service		19,583			18,965
Accumulated depreciation and amortization		(5,850		)	(5,561		)
Utility plant in service, net		13,733			13,404
Nonregulated property, net:
Nonregulated property gross	20-50 years	7			7
Accumulated depreciation and amortization		(1		)	(1		)
Nonregulated property, net		6			6
		13,739			13,410
Construction work-in-progress		1,494			797
Property, plant and equipment, net		$	15,233		$	14,207


(5)	Recent Financing Transactions

Long-Term Debt

In March 2018, MidAmerican Energy repaid $350 million of its 5.30% Senior Notes due March 2018.

Credit Facilities

In April 2018, MidAmerican Energy amended and restated its existing $900 million unsecured credit facility, expiring June 2020, extending the expiration date to June 2021 and reducing from two to one, the available one-year extension options, subject to lender consent.


(6)	Income Taxes

Tax Cuts and Jobs Act

The Tax Cuts and Jobs Act ("2017 Tax Reform") impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018, and limitations on bonus depreciation for utility property.

Iowa Senate File 2417

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,
	2018		2017		2018		2017

Federal statutory income tax rate	21	%	35	%	21	%	35	%
Income tax credits	(95	)	(74	)	(97	)	(74	)
State income tax, net of federal income tax benefit	(10	)	(10	)	(9	)	(7	)
Effects of ratemaking	(4	)	(2	)	(7	)	(4	)
Other, net	—		(1	)	(1	)	—
Effective income tax rate	(88	)%	(52	)%	(93	)%	(50	)%

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 and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Energy received net cash payments for income tax from BHE totaling $232 million and $381 million for the nine-month periods ended September 30, 2018 and 2017, respectively.


(7)	Employee Benefit Plans

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~~MidAmerican Energy adopted this guidance ~~is effective~~January 1, 2018 prospectively for ~~interim~~the capitalization of the service cost component in the Balance Sheets 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~~Statements of ~~operations and prospectively for~~Operations, applying the ~~capitalization of~~practical expedient to use the ~~service cost component~~amounts previously disclosed 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,~~Statements as 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~~estimation basis for applying the retrospective presentation requirement. As 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 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

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~~amounts other than the ~~time~~service cost for pension and other postretirement benefit plans totaling $4 million and $15 million have been reclassified to other, net in the Statements of Operations of the ~~change.~~

~~(4) Recent Financing Transactions~~

~~Long-Term Debt~~

~~In February 2017, MidAmerican Energy issued $375~~participating subsidiaries, of which $4 million ~~of its 3.10% First Mortgage Bonds due May 2027~~ and ~~$475~~$14 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~~

~~(5) Income Taxes~~

~~A reconciliation of the federal statutory income tax rate~~respectively, relates to MidAmerican ~~Energy's effective income tax rate applicable to income before income tax benefit is as follows:~~Energy.

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 )%

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						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Pension:
Service cost	$	2		$	3		$	7		$	8		$	2		$	2		$	6		$	7
Interest cost	8			8			23			25			7			8			21			23
Expected return on plan assets	(11		)	(11		)	(33		)	(33		)	(11		)	(11		)	(33		)	(33		)
Net amortization	—			—			1			1			1			—			2			1
Net periodic benefit (credit) cost	$	(1	)	$	—		$	(2	)	$	1
Net periodic benefit credit													$	(1	)	$	(1	)	$	(4	)	$	(2	)

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

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $8 million and $1 million, respectively, during ~~2017.~~2018. As of September 30, ~~2017,~~2018, $5 million and $1$- million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(8) Asset Retirement Obligations

In January 2018, MidAmerican Energy completed groundwater testing at its coal combustion residuals ("CCR") surface impoundments. Based on this information, MidAmerican Energy discontinued sending CCR to surface impoundments effective April 2018 and will remove all CCR material located below the water table in such facilities, the latter of which is a more extensive closure activity than previously assumed. The incremental cost and timing of such actions is not currently reasonably determinable, but an evaluation of such estimates is expected to be completed in the first quarter of 2019, with any necessary adjustments to the related asset retirement obligations recognized at that time.


~~(7)~~(9)	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														Input Levels for Fair Value Measurements
	Level 1		Level 2			Level 3			Other⁽¹⁾			Total			Level 1		Level 2			Level 3			Other⁽¹⁾			Total
As of September 30, 2017:
As of September 30, 2018:
Assets:
Commodity derivatives	$	—	$	2		$	2		$	(2	)	$	2		$	—	$	4		$	1		$	(2	)	$	3
Money market mutual funds⁽²⁾	520		—			—			—			520			88		—			—			—			88
Debt securities:
United States government obligations	168		—			—			—			168			183		—			—			—			183
International government obligations	—		5			—			—			5			—		4			—			—			4
Corporate obligations	—		37			—			—			37			—		47			—			—			47
Municipal obligations	—		2			—			—			2			—		2			—			—			2
Agency, asset and mortgage-backed obligations	—		1			—			—			1
Equity securities:
United States companies	270		—			—			—			270			300		—			—			—			300
International companies	7		—			—			—			7			6		—			—			—			6
Investment funds	15		—			—			—			15			21		—			—			—			21
	$	980	$	47		$	2		$	(2	)	$	1,027		$	598	$	57		$	1		$	(2	)	$	654

Liabilities - commodity derivatives	$	—	$	(6	)	$	(4	)	$	2		$	(8	)	$	—	$	(7	)	$	(2	)	$	3		$	(6	)


	Input Levels for Fair Value Measurements														Input Levels for Fair Value Measurements
	Level 1		Level 2			Level 3			Other⁽¹⁾			Total			Level 1		Level 2			Level 3			Other⁽¹⁾			Total
As of December 31, 2016:
As of December 31, 2017:
Assets:
Commodity derivatives	$	—	$	9		$	1		$	(2	)	$	8		$	—	$	3		$	4		$	(2	)	$	5
Money market mutual funds⁽²⁾	1		—			—			—			1			133		—			—			—			133
Debt securities:
United States government obligations	161		—			—			—			161			176		—			—			—			176
International government obligations	—		3			—			—			3			—		5			—			—			5
Corporate obligations	—		36			—			—			36			—		36			—			—			36
Municipal obligations	—		2			—			—			2			—		2			—			—			2
Agency, asset and mortgage-backed obligations	—		2			—			—			2
Equity securities:
United States companies	250		—			—			—			250			288		—			—			—			288
International companies	5		—			—			—			5			7		—			—			—			7
Investment funds	9		—			—			—			9			15		—			—			—			15
	$	426	$	52		$	1		$	(2	)	$	477		$	619	$	46		$	4		$	(2	)	$	667

Liabilities - commodity derivatives	$	—	$	(3	)	$	(3	)	$	3		$	(3	)	$	—	$	(9	)	$	(1	)	$	2		$	(8	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $-$1 million and $1$- million as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, 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.~~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. 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 commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):


	Three-Month Periods					Nine-Month Periods						Three-Month Periods						Nine-Month Periods
	Ended September 30,					Ended September 30,						Ended September 30,						Ended September 30,
	Commodity Derivatives			Auction Rate Securities		Commodity Derivatives			Auction Rate Securities			2018			2017			2018			2017
2017:

Beginning balance	$	(1	)	$	—	$	(2	)	$	—		$	(1	)	$	(1	)	$	3		$	(2	)
Changes in fair value recognized in net regulatory assets	(2		)	—		(2		)	—			(1		)	(2		)	(4		)	(2		)
Settlements	1			—		2			—			1			1			—			2
Ending balance	$	(2	)	$	—	$	(2	)	$	—		$	(1	)	$	(2	)	$	(1	)	$	(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



	As of September 30, 2018				As of December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	5,380	$	5,612	$	5,042	$	5,686

~~(8) Commitments and Contingencies~~

~~Natural Gas 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.


(10)	Commitments and Contingencies

Construction Commitments

Easements

Maintenance and Service Contracts

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~~required 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,~~2018, has accrued a $9$10 million liability for refunds under the second complaint of amounts collected under the higher ROE from ~~February~~March 2015 through May 2016.

Retail Regulated Rates

In December 2017, 2017 Tax Reform was signed into law, reducing the federal tax rate from 35% to 21%. Accumulated deferred income tax balances were re-measured at the 21% rate and regulatory liabilities increased reflective of the probability of such balances being passed back to customers. MidAmerican Energy has made filings or has been in discussions with each of its state rate regulatory bodies proposing either a reduction in retail rates or rate base for all or a portion of the net benefits of 2017 Tax Reform for 2018 and beyond. MidAmerican Energy proposed in Iowa, its largest jurisdiction, to reduce customer revenue via a rider mechanism for the impact of the lower statutory rate on current operations, subject to change depending on actual results, and defer as a regulatory liability the amortization of excess deferred income taxes. The Illinois Commerce Commission approved MidAmerican Energy's Illinois tax reform rate reduction tariff on March 21, 2018, and the Iowa Utilities Board approved MidAmerican Energy's Iowa tax reform rate reduction tariff on April 27, 2018, although it has opened a docket to consider concerns by certain stakeholders. The approved tax reform rider mechanisms for each jurisdiction function consistent with MidAmerican Energy's other bill riders in that over or under collection from customers at any given time is included in accounts receivable, net, on the Balance Sheets.


~~(9)~~(11)	~~Components of Accumulated Other Comprehensive Income (Loss), Net~~Revenue from Contracts with Customers

Adoption

In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" ("ASC 606") and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize revenue from contracts with customers ("Customer 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. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. MidAmerican Energy adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method, and the adoption did not have a cumulative effect impact at the date of initial adoption.

Customer Revenue

MidAmerican Energy recognizes revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. MidAmerican Energy records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Statements of Operations and, accordingly, they do not impact revenue.

Substantially all of MidAmerican Energy's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory bodies. MidAmerican Energy's electric wholesale and transmission transactions, including the multi-value projects, are substantially with the Midcontinent Independent System Operator, Inc. under its tariffs approved by the Federal Energy Regulatory Commission. These tariff-based revenues have performance obligations to deliver energy products and services to customers, which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 815, "Derivatives and Hedging."

Revenue recognized is equal to what MidAmerican Energy has the right to invoice as it corresponds directly with the value to the customer of MidAmerican Energy's performance to date and includes billed and unbilled amounts. As of September 30, 2018 and December 31, 2017, receivables, net on the Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $98 million and $89 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

The following table ~~shows the change~~summarizes MidAmerican Energy's revenue by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in ~~accumulated other comprehensive income (loss), net by each component of other comprehensive income, net of applicable income taxes~~Note 12, (in millions):



	For the Three-Month Period Ended September 30, 2018
	Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	233	$	54	$	—	$	287
Commercial	100		17		—		117
Industrial	268		3		—		271
Natural gas transportation services	—		8		—		8
Other retail	46		1		—		47
Total retail	647		83		—		730
Wholesale	62		20		—		82
Multi-value transmission projects	14		—		—		14
Other Customer Revenue	—		—		2		2
Total Customer Revenue	723		103		2		828
Other revenue	4		—		—		4
Total operating revenue	$	727	$	103	$	2	$	832



	For the Nine-Month Period Ended September 30, 2018
	Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	567	$	287	$	—	$	854
Commercial	251		100		—		351
Industrial	608		13		—		621
Natural gas transportation services	—		27		—		27
Other retail	113		1		—		114
Total retail	1,539		428		—		1,967
Wholesale	187		75		—		262
Multi-value transmission projects	43		—		—		43
Other Customer Revenue	—		—		5		5
Total Customer Revenue	1,769		503		5		2,277
Other revenue	16		2		—		18
Total operating revenue	$	1,785	$	505	$	5	$	2,295

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 )

Contract Assets and Liabilities

In the event one of the parties to a contract has performed before the other, MidAmerican Energy would recognize a contract asset or contract liability depending on the relationship between MidAmerican Energy's performance and the customer's payment. As of September 30, 2018 and December 31, 2017, there were no contract assets or contract liabilities recorded on the Balance Sheets.


~~(10)~~(12)	Segment Information

MidAmerican Energy has identified two reportable 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 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				Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,				Ended September 30,						Ended September 30,
	2017			2016			2017		2016		2018			2017			2018			2017
Operating revenue:
Regulated electric	$	707		$	692		$	1,677	$	1,572	$	727		$	707		$	1,785		$	1,677
Regulated gas	103			102			485		430
Regulated natural gas											103			103			505			485
Other	3			1			4		2		2			3			5			4
Total operating revenue	$	813		$	795		$	2,166	$	2,004	$	832		$	813		$	2,295		$	2,166

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	$	278		$	287		$	392		$	475
Regulated gas	(2		)	(5		)	45		42
Regulated natural gas											1			(3		)	52			41
Other											(1		)	—			—			—
Total operating income	$	288		$	284		$	530	$	523	278			284			444			516
Interest expense											(56		)	(54		)	(170		)	(160		)
Allowance for borrowed funds											6			4			14			9
Allowance for equity funds											16			11			39			25
Other, net											13			9			34			27
Income before income tax benefit											$	257		$	254		$	361		$	417


	As of				As of
	September 30, 2017		December 31, 2016		September 30, 2018		December 31, 2017
Assets:
Regulated electric	$	15,556	$	14,113	$	16,066	$	14,914
Regulated gas	1,339		1,345
Regulated natural gas					1,322		1,403
Other	7		1		—		1
Total assets	$	16,902	$	15,459	$	17,388	$	16,318

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

~~Des Moines, Iowa~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of September 30, ~~2017, and~~2018, the related consolidated statements of operations for the three-month and nine-month periods ended September 30, ~~2017~~2018 and ~~2016,~~2017, and of changes in member's equity and cash flows for the nine-month periods ended September 30, 2018 and 2017, and ~~2016. These~~the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~MidAmerican Funding's management.~~America.

We ~~conducted our reviews~~have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2017, and the related consolidated statements of operations, comprehensive income, changes in member's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 23, 2018, 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, 2017, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB 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)~~PCAOB 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~~2, 2018

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		September 30,		December 31,
	2017		2016		2018		2017
ASSETS
Current assets:
Cash and cash equivalents	$	512	$	15	$	115	$	172
Receivables, net	318		287
Income taxes receivable	—		9
Accounts receivable, net					385		348
Income tax receivable					150		64
Inventories	235		264		205		245
Other current assets	21		35		104		134
Total current assets	1,086		610		959		963

Property, plant and equipment, net	13,602		12,835		15,246		14,221
Goodwill	1,270		1,270		1,270		1,270
Regulatory assets	1,335		1,161		230		204
Investments and restricted cash and investments	709		655
Investments and restricted investments					758		730
Other assets	194		216		208		233

Total assets	$	18,196	$	16,747	$	18,671	$	17,621

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				As of
	September 30,		December 31,		September 30,		December 31,
	2017		2016		2018		2017
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	256	$	302	$	348	$	451
Accrued interest	54		52		57		53
Accrued property, income and other taxes	227		138		155		133
Note payable to affiliate	52		31		158		164
Short-term debt	—		99
Current portion of long-term debt	350		250		500		350
Other current liabilities	159		160		153		128
Total current liabilities	1,098		1,032		1,371		1,279

Long-term debt	4,870		4,377		5,120		4,932
Regulatory liabilities					1,645		1,661
Deferred income taxes	3,777		3,568		2,319		2,235
Regulatory liabilities	927		883
Asset retirement obligations	515		510		546		528
Other long-term liabilities	307		291		325		326
Total liabilities	11,494		10,661		11,326		10,961

Commitments and contingencies (Note 8)
Commitments and contingencies (Note 10)

Member's equity:
Paid-in capital	1,679		1,679		1,679		1,679
Retained earnings	5,023		4,407		5,666		4,981
Total member's equity	6,702		6,086		7,345		6,660

Total liabilities and member's equity	$	18,196	$	16,747	$	18,671	$	17,621

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						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Operating revenue:
Regulated electric	$	707		$	692		$	1,677		$	1,572		$	727		$	707		$	1,785		$	1,677
Regulated gas and other	108			105			493			436
Regulated natural gas and other													105			108			512			493
Total operating revenue	815			797			2,170			2,008			832			815			2,297			2,170

Operating costs and expenses:
Cost of fuel, energy and capacity	130			130			342			312
Cost of gas sold and other	54			56			289			239
Operating expenses:
Cost of fuel and energy													140			130			366			342
Cost of natural gas purchased for resale and other													50			54			297			289
Operations and maintenance	202			181			549			511			201			206			599			563
Depreciation and amortization	111			118			369			338			133			111			499			369
Property and other taxes	30			28			90			84			30			30			92			90
Total operating costs and expenses	527			513			1,639			1,484
Total operating expenses													554			531			1,853			1,653

Operating income	288			284			531			524			278			284			444			517

Other income (expense):
Interest expense	(59		)	(55		)	(177		)	(164		)	(61		)	(59		)	(185		)	(177		)
Allowance for borrowed funds	4			3			9			6			6			4			14			9
Allowance for equity funds	11			6			25			14			16			11			39			25
Other, net	6			3			14			9			12			10			35			28
Total other income (expense)	(38		)	(43		)	(129		)	(135		)	(27		)	(34		)	(97		)	(115		)

Income before income tax benefit	250			241			402			389			251			250			347			402
Income tax benefit	(133		)	(77		)	(214		)	(129		)	(228		)	(133		)	(338		)	(214		)

Net income	$	383		$	318		$	616		$	518		$	479		$	383		$	685		$	616

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

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S 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



	Paid-in Capital		Retained Earnings		Total Member's Equity

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

Balance, December 31, 2017	$	1,679	$	4,981	$	6,660
Net income	—		685		685
Balance, September 30, 2018	$	1,679	$	5,666	$	7,345

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						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income	$	616		$	518		$	685		$	616
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	369			338			499			369
Amortization of utility plant to other operating expenses							26			25
Allowance for equity funds							(39		)	(25		)
Deferred income taxes and amortization of investment tax credits	64			113			(35		)	64
Changes in other assets and liabilities	28			34
Other, net	(24		)	(42		)	17			4
Changes in other operating assets and liabilities:
Receivables, net	(31		)	(67		)
Accounts receivable and other assets							(42		)	(32		)
Inventories	29			(26		)	40			29
Derivative collateral, net	3			4			—			3
Contributions to pension and other postretirement benefit plans, net	(8		)	(5		)	(10		)	(8		)
Accounts payable	(4		)	14
Accrued property, income and other taxes, net	96			160			(65		)	96
Other current assets and liabilities	14			24
Accounts payable and other liabilities							(41		)	13
Net cash flows from operating activities	1,152			1,065			1,035			1,154

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
Capital expenditures							(1,466		)	(1,162		)
Purchases of marketable securities							(224		)	(126		)
Proceeds from sales of marketable securities							198			127
Other, net	(3		)	5			29			(13		)
Net cash flows from investing activities	(1,164		)	(1,128		)	(1,463		)	(1,174		)

Cash flows from financing activities:
Proceeds from long-term debt	842			33			687			842
Repayments of long-term debt	(255		)	(38		)	(350		)	(255		)
Net change in note payable to affiliate	21			16			(6		)	21
Net repayments of short-term debt	(99		)	—			—			(99		)
Other, net							(2		)	—
Net cash flows from financing activities	509			11			329			509

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
Net change in cash and cash equivalents and restricted cash and cash equivalents							(99		)	489
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period							282			27
Cash and cash equivalents and restricted cash and cash equivalents at end of period							$	183		$	516

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 holding company based in Des Moines, Iowa and 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,~~2018, and for the three- and nine-month periods ended September 30, ~~2017~~2018 and ~~2016.~~2017. The results of operations for the three- and nine-month periods ended September 30, ~~2017,~~2018, 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,~~2017, 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.~~2018.


(2)	New Accounting Pronouncements

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


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



	As of
	September 30		December 31
	2018		2017

Cash and cash equivalents	$	115	$	172
Restricted cash and cash equivalents in other current assets	68		110
Total cash and cash equivalents and restricted cash and cash equivalents	$	183	$	282


(4)	Property, Plant and Equipment, Net

Refer to Note 34 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~~2018 and December 31, ~~2016,~~2017, nonregulated property gross of ~~$25~~$24 million and ~~$22 million, respectively,~~ related accumulated depreciation and amortization of ~~$10~~$11 million and ~~$9 million, respectively, and construction work-in-progress of $- million and $1~~$10 million, respectively, which consisted primarily of a corporate aircraft owned by MHC.

~~(4) Recent Financing Transactions~~


(5)	Recent Financing Transactions

Refer to Note 45 of MidAmerican Energy's Notes to Financial Statements.


~~(5)~~(6)	Income Taxes

Tax Cuts and Jobs Act

Iowa Senate File 2417

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				Three-Month Periods				Nine-Month Periods
	Ended September 30,				Ended September 30,				Ended September 30,				Ended September 30,
	2017		2016		2017		2016		2018		2017		2018		2017

Federal statutory income tax rate	35	%	35	%	35	%	35	%	21	%	35	%	21	%	35	%
Income tax credits	(76	)	(60	)	(76	)	(61	)	(97	)	(76	)	(101	)	(76	)
State income tax, net of federal income tax benefit	(10	)	(7	)	(8	)	(4	)	(10	)	(10	)	(10	)	(8	)
Effects of ratemaking	(2	)	—		(4	)	(3	)	(5	)	(2	)	(7	)	(4	)
Effective income tax rate	(53	)%	(32	)%	(53	)%	(33	)%	(91	)%	(53	)%	(97	)%	(53	)%

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax ~~return.~~returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income ~~taxes~~tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income ~~taxes are~~tax is remitted to or received from BHE. MidAmerican Funding received net cash payments for income ~~taxes~~tax from BHE totaling ~~$386~~$248 million and ~~$422~~$386 million for the nine-month periods ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively.


~~(6)~~(7)	Employee Benefit Plans

Refer to Note 67 of MidAmerican Energy's Notes to Financial Statements.


~~(7)~~(8)	Asset Retirement Obligations

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


(9)	Fair Value Measurements

Refer to Note 79 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



	As of September 30, 2018				As of December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	5,620	$	5,908	$	5,282	$	6,006

~~(8) Commitments and Contingencies~~


(10)	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~~10 of MidAmerican Energy's Notes to Financial Statements.


(11)	Revenue from Contracts with Customers

~~(10) Segment Information~~

Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had $- million and $2 million of other Accounting Standards Codification Topic 606 revenue for the three-month and nine-month periods ended September 30, 2018, respectively.


(12)	Segment Information

MidAmerican Funding has identified two reportable 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 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



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2018			2017			2018			2017
Operating revenue:
Regulated electric	$	727		$	707		$	1,785		$	1,677
Regulated natural gas	103			103			505			485
Other	2			5			7			8
Total operating revenue	$	832		$	815		$	2,297		$	2,170

Operating income:
Regulated electric	$	278		$	287		$	392		$	475
Regulated natural gas	1			(3		)	52			41
Other	(1		)	—			—			1
Total operating income	278			284			444			517
Interest expense	(61		)	(59		)	(185		)	(177		)
Allowance for borrowed funds	6			4			14			9
Allowance for equity funds	16			11			39			25
Other, net	12			10			35			28
Income before income tax benefit	$	251		$	250		$	347		$	402



	As of
	September 30, 2018		December 31, 2017
Assets⁽¹⁾:
Regulated electric	$	17,257	$	16,105
Regulated natural gas	1,401		1,482
Other	13		34
Total assets	$	18,671	$	17,621



(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~~2018 and ~~2016~~2017

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the third quarter of ~~2017~~2018 was ~~$385~~$483 million, an increase of ~~$65~~$98 million, or ~~20%~~25%, compared to ~~2016~~2017 primarily due to a higher income tax benefit of $95 million from a $53 million increase in recognized production tax credits ~~of $45 million, higher margins of $11 million, excluding~~and a lower federal tax rate due to the impact of ~~demand side management program revenue (offset in operations and maintenance expense), lower depreciation and amortization~~2017 Tax Reform, higher electric utility margin of $7$10 million, ~~substantially from changes in accruals for Iowa regulatory arrangements, and~~ higher ~~allowance~~allowances for borrowed and equity funds of $6$7 million due to higher construction balances for wind-powered generation, and higher natural gas utility margin of $4 million, partially offset by higher ~~operations~~depreciation and ~~maintenance expenses,~~amortization of $22 million from additional plant in-service and Iowa revenue sharing. Electric utility margin increased due to higher retail customer volumes of 6% primarily from ~~higher generating facility maintenance, including additional wind turbines. The increase in electric margins of $7 million, excluding~~industrial growth and the favorable impact of ~~demand side management program revenue (offset in operations~~weather, higher wholesale volumes of 37% 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~~average retail rates of $33 million predominantly from the impact of a lower ~~sales volumes~~federal tax rate due to 2017 Tax Reform and ~~prices.~~higher generation and purchased power costs.

MidAmerican Energy's net income for the first nine months of ~~2017~~2018 was ~~$624~~$695 million, an increase of ~~$97~~$71 million, or ~~18%~~11%, compared to ~~2016~~2017 primarily due to a higher ~~margins~~income tax benefit of ~~$64~~$127 million ~~excluding~~from a lower federal tax rate due to the impact of ~~demand side management program revenue (offset~~2017 Tax Reform and a $44 million increase in ~~operations and maintenance expense), higher~~ recognized production tax credits, higher electric utility margin of ~~$71~~$84 million, ~~and~~ higher ~~allowance~~allowances for borrowed and equity funds of ~~$14~~$19 million due to higher construction balances for wind-powered generation and higher natural gas utility margin of $12 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~~$130 million from ~~accruals for~~ Iowa ~~regulatory arrangements~~revenue sharing and additional plant in-service, higher wind-powered ~~generating facilities placed in-service~~generation maintenance of $17 million, higher fossil-fueled generation maintenance of $12 million and increases 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), reflectsother operating expenses. Electric utility margin increased due to higher recoveries through bill riders, higher ~~wholesale revenue from higher sales volumes and prices, higher transmission revenue and higher~~ retail customer volumes of 7% from industrial growth ~~net~~and the favorable impact of ~~lower residential~~weather and ~~commercial volumes due to milder temperatures,~~higher electric wholesale revenues from higher average prices, partially offset by lower average retail rates of $86 million predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform and higher ~~coal-fueled~~ generation and purchased power costs.

MidAmerican Funding -

MidAmerican Funding's net income for the third quarter of ~~2017~~2018 was ~~$383~~$479 million, an increase of ~~$65~~$96 million, or ~~20%~~25%, compared to ~~2016.~~2017. MidAmerican Funding's net income for the first nine months of ~~2017~~2018 was ~~$616~~$685 million, an increase of ~~$98~~$69 million, or ~~19%~~11%, compared to ~~2016.The~~2017. The increases were primarily due to the changes in MidAmerican Energy's earnings discussed above.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, Electric Utility Margin and Natural Gas Utility Margin, to help evaluate results of operations. Electric Utility Margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural Gas Utility Margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.

MidAmerican Energy's cost of fuel and energy and regulated cost of natural gas purchased for resale are directly recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's revenue from the related recovery mechanisms are comparable to changes in such expenses. As such, management believes Electric Utility Margin and Natural Gas Utility Margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of Electric Utility Margin and Natural Gas Utility Margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Electric Utility Margin and Natural Gas Utility Margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income, which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):



	Third Quarter									First Nine Months
	2018		2017		Change					2018		2017		Change
Electric utility margin:
Regulated electric operating revenue	$	727	$	707	$	20		3	%	$	1,785	$	1,677	$	108		6	%
Cost of fuel and energy	140		130		10			8		366		342		24			7
Electric utility margin	587		577		10			2		1,419		1,335		84			6
																	��
Natural gas utility margin:
Regulated natural gas operating revenue	103		103		—			—	%	505		485		20			4
Cost of natural gas purchased for resale	50		54		(4		)	(7	)	296		288		8			3
Natural gas utility margin	53		49		4			8		209		197		12			6

Utility margin	640		626		14			2	%	1,628		1,532		96			6

Other operating revenue	2		3		(1		)	(33	)	5		4		1			25
Operations and maintenance	201		204		(3		)	(1	)%	598		561		37			7
Depreciation and amortization	133		111		22			20		499		369		130			35
Property and other taxes	30		30		—			—		92		90		2			2

Operating income	$	278	$	284	$	(6	)	(2	)%	$	444	$	516	$	(72	)	(14	)

Regulated Electric ~~Gross~~Utility Margin

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


	Third Quarter									First Nine Months									Third Quarter									First Nine Months
	2017		2016		Change					2017		2016		Change					2018		2017		Change					2018		2017		Change
Gross margin (in millions):
Electric utility margin (in millions):
Operating revenue	$	707	$	692	$	15		2	%	$	1,677	$	1,572	$	105		7	%	$	727	$	707	$	20		3	%	$	1,785	$	1,677	$	108	6	%
Cost of fuel, energy and capacity	130		130		—			—		342		312		30			10
Gross margin	$	577	$	562	$	15		3		$	1,335	$	1,260	$	75		6
Cost of fuel and energy																			140		130		10			8		366		342		24		7
Electric utility margin																			$	587	$	577	$	10		2		$	1,419	$	1,335	$	84	6

Electricity Sales (GWh):
Residential	1,790		1,969		(179		)	(9	)%	4,753		5,018		(265		)	(5	)%	1,952		1,790		162			9	%	5,307		4,753		554		12	%
Commercial	987		1,023		(36		)	(4	)	2,796		2,859		(63		)	(2	)	1,025		987		38			4		2,944		2,796		148		5
Industrial	3,366		3,106		260			8		9,621		8,999		622			7		3,550		3,366		184			5		10,158		9,621		537		6
Other	411		427		(16		)	(4	)	1,185		1,213		(28		)	(2	)	415		411		4			1		1,218		1,185		33		3
Total retail	6,554		6,525		29			—		18,355		18,089		266			1		6,942		6,554		388			6		19,627		18,355		1,272		7
Wholesale	1,571		2,037		(466		)	(23	)	7,162		5,620		1,542			27		2,160		1,571		589			37		7,179		7,162		17		—
Total sales	8,125		8,562		(437		)	(5	)	25,517		23,709		1,808			8		9,102		8,125		977			12		26,806		25,517		1,289		5

Average number of retail customers (in thousands)	771		761		10			1	%	769		759		10			1	%	780		771		9			1	%	778		769		9		1	%

Average revenue per MWh:
Retail	$	98.15	$	94.02	$	4.13		4	%	$	78.62	$	76.75	$	1.87		2	%	$	93.39	$	98.15	$	(4.76	)	(5	)%	$	78.63	$	78.62	$	0.01	—	%
Wholesale	$	25.57	$	28.13	$	(2.56	)	(9	)%	$	23.90	$	22.84	$	1.06		5	%	$	27.19	$	25.57	$	1.62		6	%	$	25.09	$	23.90	$	1.19	5	%

Heating degree days	44		27		17			63	%	3,203		3,388		(185		)	(5	)%	91		44		47			*		4,126		3,203		923		29	%
Cooling degree days	752		855		(103		)	(12	)%	1,098		1,284		(186		)	(14	)%	784		752		32			4	%	1,295		1,098		197		18	%

Sources of energy (GWh)⁽¹⁾:
Coal	4,354		4,618		(264		)	(6	)%	11,019		9,907		1,112			11	%	4,559		4,354		205			5	%	11,293		11,019		274		2	%
Nuclear	961		1,003		(42		)	(4	)	2,820		2,887		(67		)	(2	)	990		961		29			3		2,838		2,820		18		1
Natural gas	257		307		(50		)	(16	)	274		515		(241		)	(47)		275		257		18			7		549		274		275		100
Wind and other⁽²⁾	1,929		1,950		(21		)	(1	)	9,129		7,981		1,148			14		2,428		1,929		499			26		9,693		9,129		564		6
Total energy generated	7,501		7,878		(377		)	(5	)	23,242		21,290		1,952			9		8,252		7,501		751			10		24,373		23,242		1,131		5
Energy purchased	812		916		(104		)	(11	)	2,756		3,030		(274		)	(9	)	1,054		812		242			30		3,010		2,756		254		9
Total	8,313		8,794		(481		)	(5	)	25,998		24,320		1,678			7		9,306		8,313		993			12		27,383		25,998		1,385		5


*	Not meaningful.


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


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

Regulated electric ~~gross~~utility margin increased ~~$15~~$10 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to:


(1)	Higher wholesale utility margin of $14 million due to higher margins per unit, reflecting higher market prices and lower costs, and higher sales volumes;


(2)	Higher retail utility margin of $1 million due to -

an increase of $25 million from non-weather-related usage factors, including higher industrial sales volumes;

an increase of $4 million from higher recoveries through bill riders, including lower electric demand-side management ("DSM") program revenue of $2 million (offset in operations and maintenance expense);

an increase of $4 million from various other revenue;

an increase of $2 million from the impact of weather; partially offset by

a decrease of $33 million in average rates predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform; and

a decrease of $1 million from higher retail energy costs; partially offset by


(3)	Lower Multi-Value Projects ("MVP") transmission revenue of $5 million due to refund accruals.

Regulated electric utility margin increased $84 million for the first nine months of 2018 compared to 2017 primarily due to:


(1)	Higher retail ~~gross~~utility margin of ~~$16~~$69 million due to -

an increase of ~~$38~~$91 million from higher recoveries through bill ~~riders;~~riders, including $10 million of electric DSM program revenue (offset in operations and maintenance expense);

an increase of $3$52 million from non-weather-related usage factors, including higher industrial sales volumes;

~~a decrease~~an increase of ~~$12~~$30 million from the impact of ~~milder temperatures;~~weather;

an increase of $4 million from various other revenue; partially offset by

a decrease of $86 million in averages rates, predominantly from the impact of a lower federal tax rate due to 2017 Tax Reform; and

a decrease of ~~$13~~$22 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$16 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~~lower fuel costs; partially offset by ~~greater availability of lower cost generation;~~


~~(2)~~(3)	~~Higher retail gross margin~~Lower MVP transmission revenue of ~~$25~~$1 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.~~refund accruals.

Regulated Natural Gas ~~Gross~~Utility Margin

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


	Third Quarter									First Nine Months									Third Quarter									First Nine Months
	2017		2016		Change					2017		2016		Change					2018		2017		Change					2018		2017		Change
Gross margin (in millions):
Natural gas utility margin (in millions):
Operating revenue	$	103	$	102	$	1		1	%	$	485	$	430	$	55		13	%	$	103	$	103	$	—		—	%	$	505	$	485	$	20		4	%
Cost of gas sold	54		54		—			—		288		236		52			22
Gross margin	$	49	$	48	$	1		2		$	197	$	194	$	3		2
Cost of natural gas purchased for resale																			50		54		(4		)	(7	)	296		288		8			3
Natural gas utility margin																			$	53	$	49	$	4		8		$	209	$	197	$	12		6

Natural gas throughput (000's Dth):
Residential	2,773		2,820		(47		)	(2)	%	29,442		31,121		(1,679		)	(5)	%	2,773		2,773		—			—	%	36,493		29,442		7,051			24	%
Commercial	1,788		1,840		(52		)	(3	)	14,797		15,729		(932		)	(6	)	1,651		1,788		(137		)	(8	)	17,661		14,797		2,864			19
Industrial	717		922		(205		)	(22	)	3,070		3,574		(504		)	(14	)	985		717		268			37		3,690		3,070		620			20
Other	2		1		1			100		29		26		3			12		3		2		1			50		33		29		4			14
Total retail sales	5,280		5,583		(303		)	(5	)	47,338		50,450		(3,112		)	(6	)	5,412		5,280		132			3		57,877		47,338		10,539			22
Wholesale sales	8,815		8,568		247			3		29,111		28,615		496			2		7,569		8,815		(1,246		)	(14	)	27,940		29,111		(1,171		)	(4	)
Total sales	14,095		14,151		(56		)	—		76,449		79,065		(2,616		)	(3	)	12,981		14,095		(1,114		)	(8	)	85,817		76,449		9,368			12
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
Natural gas transportation service																			21,876		19,784		2,092			11		73,968		65,431		8,537			13
Total natural gas throughput																			34,857		33,879		978			3		159,785		141,880		17,905			13

Average number of retail customers (in thousands)	746		738		8			1	%	747		738		9			1	%	754		746		8			1	%	755		747		8			1	%
Average revenue per retail Dth sold	$	13.33	$	12.77	$	0.56		4	%	$	7.93	$	6.80	$	1.13		17	%	$	13.90	$	13.33	$	0.57		4	%	$	6.95	$	7.93	$	(0.98	)	(12)	%
Average cost of natural gas per retail Dth sold	$	5.56	$	5.49	$	0.07		1	%	$	4.33	$	3.45	$	0.88		26	%	$	5.48	$	5.56	$	(0.08	)	(1)	%	$	3.81	$	4.33	$	(0.52	)	(12)	%

Combined retail and wholesale average cost of natural gas per Dth sold	$	3.82	$	3.82	$	—		—	%	$	3.76	$	2.99	$	0.77		26	%	$	3.86	$	3.82	$	0.04		1	%	$	3.44	$	3.76	$	(0.32	)	(9)	%

Heating degree days	45		27		18			67	%	3,406		3,572		(166		)	(5)	%	92		45		47			*		4,269		3,406		863			25	%

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.


*	Not meaningful.

Regulated natural gas ~~gross~~utility margin increased $1$4 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 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 -~~to:


(1)	~~higher recoveries~~An increase of ~~demand side management~~$5 million from rate and non-weather-related usage factors, including the impact of a lower federal tax rate due to 2017 Tax Reform; partially offset by


(2)	A decrease of $1 million from lower natural gas DSM program revenue (offset in operations and maintenance expense).

Regulated natural gas utility margin increased $12 million for the first nine months of 2018 compared to 2017 due to:


(1)	An increase of ~~$2 million;~~$13 million from higher retail sales volumes due to the impact of colder temperatures;


(2)	aAn increase of $1 million from higher ~~average per-unit margin of $2 million;~~natural gas transportation services; partially offset by


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


~~(4)~~	~~lower retail sales volumes of $3~~$2 million from ~~warmer winter temperatures.~~rate and non-weather-related usage factors, including the impact of a lower federal tax rate due to 2017 Tax Reform.

Operating ~~Costs and~~ Expenses

MidAmerican Energy -

Operations and maintenance ~~increased $20~~decreased $3 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~higher demand side management~~lower DSM program expense ~~(offset~~of $3 million, which is recoverable in bill riders and offset in operating ~~revenue)~~revenue, lower fossil-fueled generation maintenance of $8$3 million due to the timing of planned outages, and lower administrative and other costs, partially offset by higher wind-powered generation maintenance from additional wind turbines of ~~$6 million and higher coal-fueled and nuclear generation maintenance of $4~~$5 million.

Operations and maintenance increased $37 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 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~~$17 million, higher fossil-fueled generation maintenance of $12 million from planned outages, higher DSM program expense of $9 million and higher ~~coal-fueled~~transmission operations costs from MISO of $3 million, both of which are recoverable in bill riders and offset in operating revenue, partially offset by lower nuclear ~~generation~~operations and maintenance expense of $4 million.

Depreciation and amortization ~~decreased $7~~increased $22 million for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 due to ~~lower~~$18 million related to wind-powered generating facilities and other plant placed in-service and $4 million from higher 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.revenue sharing.

Depreciation and amortization increased ~~$31~~$130 million for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 due to ~~utility plant additions, including~~higher accruals for Iowa revenue sharing of $83 million and $47 million related to 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.~~plant placed in-service.

Other Income (Expense)

MidAmerican Energy -

Interest expense increased $4$2 million and ~~$13~~$10 million for the third quarter and first nine months of ~~2017,~~2018, respectively, compared to ~~2016~~2017 primarily due to higher interest expense from the issuance of ~~$850~~$700 million of first mortgage bonds in February ~~2017,~~2018, partially offset by the redemption of ~~a $250~~$350 million of ~~5.95% Senior Notes~~senior notes in March 2018, and additionally for the first nine months comparison, the issuance of $850 million of first mortgage bonds in February 2017.

Allowance for borrowed and equity funds increased $6$7 million and ~~$14~~$19 million for the third quarter and first nine months of ~~2017,~~2018, respectively, compared to ~~2016~~2017 primarily due to higher construction work-in-progress balances related to wind-powered generation.

Other, net increased $2$4 million and $5$7 million for the third quarter and first nine months of ~~2017,~~2018, respectively, compared to ~~2016~~2017 primarily due to higher returns on corporate-owned life insurance ~~policies.~~policies, higher income related to amounts other than the service cost for MidAmerican Energy's pension and other postretirement benefit plans and higher interest income from favorable cash positions.

Income Tax Benefit

MidAmerican Energy -

MidAmerican Energy's income tax benefit increased ~~$57~~$95 million for the third quarter of ~~2017~~2018 compared to ~~2016,~~2017, and the effective tax rate was (88)% for 2018 and (52)% for ~~2017 and (30)% for 2016.~~2017. For the first nine months of ~~2017~~2018 compared to ~~2016,~~2017, MidAmerican Energy's income tax benefit increased ~~$84~~$127 million in 2018 compared to 2017, and the effective tax rate was (93)% for 2018 and (50)% for ~~2017 and (30)% for 2016.~~2017. The changes in the effective tax rates for ~~2017~~2018 compared to ~~2016~~2017 were substantially due to ~~an increase~~the reduction in ~~recognized~~the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, the recognition of 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.~~in-service. Production tax credits recognized in the first nine months of ~~2017~~2018 were ~~$306~~$349 million, or ~~$71~~$43 million higher than the first nine months of ~~2016,~~2017, while production tax credits earned in the first nine months of ~~2017~~2018 were ~~$200~~$220 million, or ~~$29~~$20 million higher than the first nine months of ~~2016~~2017 primarily due to wind-powered generation placed in-service in late ~~2016.~~2017, partially offset by facilities no longer eligible to earn production tax credits. The ~~excess of~~difference between production tax credits recognized ~~over~~and earned of ~~$106~~$129 million as of September 30, ~~2017,~~2018, will ~~reduce~~be reflected in earnings over the remainder of ~~2017.~~

2018.

MidAmerican Funding -

MidAmerican Funding's income tax benefit increased ~~$56~~$95 million for the third quarter of ~~2017~~2018 compared to ~~2016,~~2017, and the effective tax rate was (91)% for 2018 and (53)% for 2017. For the first nine months of 2018 compared to 2017, ~~and (32)% for 2016.~~ MidAmerican Funding's income tax benefit increased ~~$85~~$124 million ~~for the first nine months~~ of ~~2017~~2018 compared to ~~2016,~~2017, and the effective tax rate was (97)% for 2018 and (53)% for ~~2017 and (33)% for 2016.The~~2017. 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,~~2018, 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.~~were as follows (in millions):



MidAmerican Energy:
Cash and cash equivalents	$	115

Credit facilities, maturing 2019 and 2021	905
Less:
Tax-exempt bond support	(370		)
Net credit facilities	535

MidAmerican Energy total net liquidity	$	650

MidAmerican Funding:
MidAmerican Energy total net liquidity	$	650
MHC, Inc. credit facility, maturing 2019	4
MidAmerican Funding total net liquidity	$	654

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2018 and 2017, ~~and 2016,~~ were ~~$1,171~~$1,028 million and ~~$1,080~~$1,173 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2018 and 2017, ~~and 2016,~~ were ~~$1,152~~$1,035 million and ~~$1,065~~$1,154 million, respectively. Cash flows from operating activities ~~increased~~decreased 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.~~BHE and greater payments to vendors, partially offset by higher cash gross margin for MidAmerican Energy's regulated electric business. MidAmerican Energy's income tax cash flows with BHE totaled net cash receipts ~~from BHE~~in 2018 and 2017 of $232 million and $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,~~2017, 2017 Tax Reform was enacted which, among other items, reduced the ~~Protecting Americans~~federal corporate tax rate from ~~Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in service before~~35% to 21% effective 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 toeliminated bonus depreciation on qualifying regulated utility assets ~~placed~~acquired after December 31, 2017, but did not impact production tax credits. MidAmerican Energy believes for qualifying assets acquired on or before December 31, bonus depreciation will be available for 2018 and 2019. MidAmerican Energy is required to pass the benefits of lower tax expense to customers in ~~service through 2019~~the form of either rate reductions or rate base reductions. MidAmerican Energy expects lower revenue and income tax as well as lower bonus depreciation benefits compared to 2017 as a result of 2017 Tax Reform and related regulatory treatment. MidAmerican Energy does not expect 2017 Tax Reform and related regulatory treatment to have a material adverse impact on its cash flows. Refer to Regulatory Matters for further discussion of regulatory matters associated with 2017 Tax Reform.

Internal Revenue Service ("IRS") rules provide for re-establishment of the production tax credit for an existing wind-powered generating facility upon the replacement of a significant portion of its components. Such component replacement is commonly referred to as repowering. If the degree of component replacement in such projects meets IRS guidelines, production tax credits ~~earned on qualifying wind~~are re-established for ten years at rates that depend upon the date in which construction begins, as noted in the above paragraph. MidAmerican Energy's current repowering projects ~~through 2029.~~are expected to earn production tax credits at 100% of the value of such credits.

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the nine-month periods ended September 30, 2018 and 2017, ~~and 2016,~~ were ~~$(1,161)~~$(1,463) million and ~~$(1,128)~~$(1,171) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2018 and 2017, ~~and 2016,~~ were ~~$(1,164)~~$(1,463) million and ~~$(1,128)~~$(1,174) million, respectively. Net cash flows from investing activities consist almost entirely of ~~utility construction~~capital expenditures, which increased due to higher ~~environmental and other operating~~wind-powered generating facility construction expenditures. Purchases and proceeds related to ~~available-for-sale~~marketable 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, 2018 and 2017 ~~and 2016~~ were ~~$488~~$336 million and ~~$(5)~~$488 million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2018 and 2017, were $329 million and ~~2016, were~~ $509 million, respectively. In February 2018, MidAmerican Energy issued $700 million of its 3.65% First Mortgage Bonds due 2048. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from February 2, 2017 to October 31, 2017, with respect to investments in MidAmerican Energy's 2,000-megawatt (nameplate capacity) Wind XI project and ~~$11~~the repowering of certain of MidAmerican Energy's existing wind facilities, which were previously financed with MidAmerican Energy's general funds. In March 2018, MidAmerican Energy repaid $350 million ~~respectively.~~of its 5.30% Senior Notes due March 2018. 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 its 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 repaid $6 million and received $21 million in 2018 and ~~$16 million in~~ 2017, ~~and 2016,~~ respectively, through its note payable with BHE.

Debt Authorizations and Related Matters

MidAmerican Energy has authority from the FERC to issue through ~~February 28, 2019,~~July 31, 2020, commercial paper and bank notes aggregating ~~$905 million~~$1.3 billion 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.~~2021 for which MidAmerican Energy may request that the banks extend the credit facility up to ~~two years.~~one year. 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~~SEC to issue an indeterminate amount of long-term debt securities through ~~September 16, 2018.~~June 26, 2021. Additionally, 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~~$1.5 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~~points and from the ~~Illinois Commerce Commission~~ICC 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~~$1.5 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~~$1.0 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,~~2018, MidAmerican Energy's common equity ratio was ~~53%~~52% 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~~Capital Expenditures

MidAmerican ~~Energy's primary need for~~Energy has significant future capital ~~is utility construction expenditures.~~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, impacts to customers' rates; changes in environmental and other rules and regulations; ~~impacts to customers' rates;~~ outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

MidAmerican Energy's 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		Nine-Month Periods				Annual
	Ended September 30,				Forecast		Ended September 30,				Forecast
	2016		2017		2017		2017		2018		2018

Wind-powered generation	$	732	$	455	$	709	$	455	$	704	$	1,254
Wind-powered generation repowering	—		272		496		272		233		284
Transmission Multi-Value Projects	73		18		25		18		33		52
Other	324		417		773		417		496		775
Total	$	1,129	$	1,162	$	2,003	$	1,162	$	1,466	$	2,365

MidAmerican Energy's forecast ~~utility construction~~capital expenditures for ~~2017~~2018 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.~~Iowa. 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.~~2019, including 334 MW (nominal ratings) placed in-service in 2017. 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.~~effect prior to 2018. The revised sharing mechanism, ~~will be~~which was effective inJanuary 1, 2018, ~~and~~ will be triggered each year by actual equity returns ~~above the~~exceeding a weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. ~~Each~~MidAmerican Energy expects all of these ~~projects is expected~~wind-powered generating facilities 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~~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.~~each facility's return to service. 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. In 2012, MidAmerican Energy ~~has approval from the Midcontinent Independent System Operator, Inc. for~~started the construction of four MVPs located in Iowa and Illinois ~~which, when~~that were approved by the Midcontinent Independent System Operator, Inc. When complete, the four MVPs will have added approximately 250 miles of 345 kV transmission line to MidAmerican Energy's transmission system ~~since 2012.~~and will be owned and operated by MidAmerican Energy. As of September 30, 2018, 224 miles of these MVP transmission lines have been placed in-service.

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

In May 2018, MidAmerican Energy filed with the IUB an application for ratemaking principles related to the construction of up to 591 MW (nominal ratings) of additional wind-powered generating facilities ("Wind XII") expected to be placed in-service by the end of 2020. The filing, which is subject to IUB approval, establishes a cost cap of $922 million, including AFUDC, a fixed rate of return on equity of 11.25% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding, and maintains the revenue sharing mechanism currently in effect. 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. In September 2018, MidAmerican Energy filed with the IUB a settlement agreement signed by a majority of the parties to the ratemaking principles proceeding for Wind XII. The settlement agreement, which is subject to IUB approval, establishes 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 and provides that all Iowa retail energy benefits from Wind XII will be excluded from the Iowa energy adjustment clause and, instead, will reduce rate base. Additionally, the settlement agreement modifies the current revenue sharing mechanism, effective January 1, 2019, such that revenue sharing will be triggered each year by actual equity returns above a threshold calculated annually or 11%, whichever is less, and MidAmerican Energy will share with customers 90% of the revenue in excess of the trigger, instead of the current 100% sharing. The calculated threshold will be the year-end weighted average of equity returns for rate base as authorized via ratemaking principles proceedings and, for remaining rate base, interest rates on 30-year single A-rated utility bond yields plus 400 basis points, with a minimum return of 9.5%. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of production tax credits available.

Contractual Obligations

As of September 30, ~~2017,~~2018, 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.~~2017.

Regulatory Matters

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

Quad Cities 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.

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.~~2017. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, ~~2016.~~2017.

Nevada Power Company and its subsidiaries

Consolidated Financial Section

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

~~Las Vegas, Nevada~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of September 30, ~~2017, and~~2018, the related consolidated statements of operations for the three-month and nine-month periods ended September 30, ~~2017~~2018 and ~~2016,~~2017, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 2018 and 2017 and ~~2016. These~~the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~Nevada Power's management.~~America.

We ~~conducted our reviews~~have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2017, 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 23, 2018, 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, 2017 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We 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~~2, 2018

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of						As of
	September 30,			December 31,			September 30,			December 31,
	2017			2016			2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	69		$	279		$	80		$	57
Accounts receivable, net	362			243			368			238
Inventories	59			73			58			59
Regulatory assets	34			20			16			28
Other current assets	50			38			79			44
Total current assets	574			653			601			426

Property, plant and equipment, net	6,890			6,997			6,830			6,877
Regulatory assets	1,110			1,000			880			941
Other assets	39			39			41			35

Total assets	$	8,613		$	8,689		$	8,352		$	8,279

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	192		$	187		$	168		$	156
Accrued interest	39			50			33			50
Accrued property, income and other taxes	109			93			128			63
Regulatory liabilities	35			37			51			91
Current portion of long-term debt and financial and capital lease obligations	842			17			519			842
Customer deposits	78			78			64			73
Other current liabilities	31			39			43			16
Total current liabilities	1,326			501			1,006			1,291

Long-term debt and financial and capital lease obligations	2,231			3,049			2,297			2,233
Regulatory liabilities	423			416			1,123			1,030
Deferred income taxes	1,529			1,474			757			767
Other long-term liabilities	281			277			264			280
Total liabilities	5,790			5,717			5,447			5,601

Commitments and contingencies (Note 9)
Commitments and contingencies (Note 10)

Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—			—			—			—
Other paid-in capital	2,308			2,308
Additional paid-in capital							2,308			2,308
Retained earnings	518			667			601			374
Accumulated other comprehensive loss, net	(3		)	(3		)	(4		)	(4		)
Total shareholder's equity	2,823			2,972			2,905			2,678

Total liabilities and shareholder's equity	$	8,613		$	8,689		$	8,352		$	8,279

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

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods						Nine-Month Periods						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017

Operating revenue	$	819		$	766		$	1,785		$	1,690		$	820		$	819		$	1,777		$	1,785

Operating costs and expenses:
Cost of fuel, energy and capacity	318			251			721			618
Operating and maintenance	97			105			278			304
Operating expenses:
Cost of fuel and energy													331			318			740			721
Operations and maintenance													146			96			344			276
Depreciation and amortization	77			76			231			227			85			77			253			231
Property and other taxes	10			10			29			30			11			10			31			29
Total operating costs and expenses	502			442			1,259			1,179
Total operating expenses													573			501			1,368			1,257

Operating income	317			324			526			511			247			318			409			528

Other income (expense):
Interest expense	(44		)	(45		)	(132		)	(140		)	(38		)	(44		)	(128		)	(132		)
Allowance for borrowed funds	1			—			1			2			—			1			1			1
Allowance for equity funds	—			—			1			3			1			—			2			1
Other, net	5			7			18			17			7			4			16			16
Total other income (expense)	(38		)	(38		)	(112		)	(118		)	(30		)	(39		)	(109		)	(114		)

Income before income tax expense	279			286			414			393			217			279			300			414
Income tax expense	103			98			151			136			53			103			72			151
Net income	$	176		$	188		$	263		$	257		$	164		$	176		$	228		$	263

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

NEVADA POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)


									Accumulated														Accumulated
				Other					Other			Total						Additional					Other			Total
	Common Stock			Paid-in		Retained			Comprehensive			Shareholder's			Common Stock			Paid-in		Retained			Comprehensive			Shareholder's
	Shares	Amount		Capital		Earnings			Loss, Net			Equity			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		1,000	$	—	$	2,308	$	667		$	(3	)	$	2,972
Net income	—	—		—		263			—			263			—	—		—		263			—			263
Dividends declared	—	—		—		(412		)	—			(412		)	—	—		—		(412		)	—			(412		)
Balance, September 30, 2017	1,000	$	—	$	2,308	$	518		$	(3	)	$	2,823		1,000	$	—	$	2,308	$	518		$	(3	)	$	2,823

Balance, December 31, 2017															1,000	$	—	$	2,308	$	374		$	(4	)	$	2,678
Net income															—	—		—		228			—			228
Other equity transactions															—	—		—		(1		)	—			(1		)
Balance, September 30, 2018															1,000	$	—	$	2,308	$	601		$	(4	)	$	2,905

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

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income	$	263		$	257		$	228		$	263
Adjustments to reconcile net income to net cash flows from operating activities:
Gain on marketable securities							(1		)	—
Gain on nonrecurring items	(1		)	—			—			(1		)
Depreciation and amortization	231			227			253			231
Deferred income taxes and amortization of investment tax credits	61			52
Allowance for equity funds	(1		)	(3		)	(2		)	(1		)
Changes in regulatory assets and liabilities	25			139			75			25
Deferred income taxes and amortization of investment tax credits							(7		)	61
Deferred energy	(22		)	(3		)	12			(22		)
Amortization of deferred energy	13			(87		)	13			13
Other, net	(1		)	3			9			(1		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(122		)	(96		)	(138		)	(125		)
Inventories	6			7			1			6
Accrued property, income and other taxes	11			98
Accrued property, income and other taxes, net							54			11
Accounts payable and other liabilities	9			7			(11		)	9
Net cash flows from operating activities	472			601			486			469

Cash flows from investing activities:
Capital expenditures	(202		)	(249		)	(203		)	(202		)
Acquisitions	(77		)	—			—			(77		)
Other, net	4			—			1			4
Net cash flows from investing activities	(275		)	(249		)	(202		)	(275		)

Cash flows from financing activities:
Proceeds from issuance of long-term debt	91			—
Proceeds from long-term debt							573			91
Repayments of long-term debt and financial and capital lease obligations	(86		)	(221		)	(836		)	(86		)
Dividends paid	(412		)	(365		)	—			(412		)
Net cash flows from financing activities	(407		)	(586		)	(263		)	(407		)

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
Net change in cash and cash equivalents and restricted cash and cash equivalents							21			(213		)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period							66			290
Cash and cash equivalents and restricted cash and cash equivalents at end of period							$	87		$	77

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

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~(1) Organization and Operations~~


(1)	General

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~~and 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~~2018 and for the three- and nine-month periods ended September 30, ~~2017~~2018 and ~~2016.~~2017. 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~~2018 and ~~2016.~~2017. The results of operations for the three- and nine-month periods ended September 30, ~~2017~~2018 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~~2017 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.~~2018.

~~(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.

In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. 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 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. 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.


(2)	New Accounting Pronouncements

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. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases" and ASU No. 2018-11 allowing companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings recognized in the period of adoption. 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 in the process of evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.


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

In ~~May 2014,~~November 2016, the FASB issued ASU No. ~~2014-09,~~2016-18, which ~~creates~~amends FASB ASC ~~Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition.~~Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance ~~replaces industry-specific guidance~~require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and ~~establishes a single five-step model to identify~~amounts generally described as restricted cash and ~~recognize revenue. The core principle~~restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of 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.cash flows. Nevada Power ~~plans to adopt~~adopted this guidance ~~effective~~ January 1, 2018.

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2018 ~~under~~and December 31, 2017, consist of funds restricted by 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 customerPublic Utilities Commission of Nevada ~~Power’s performance to date. Nevada Power's current plan is to quantitatively disaggregate revenue~~("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2018 and December 31, 2017, as presented in the ~~required financial statement footnote~~Consolidated Statements of Cash Flows is outlined below and disaggregated by ~~customer class.~~the line items in which they appear on the Consolidated Balance Sheets (in millions):



	As of
	September 30,		December 31,
	2018		2017
Cash and cash equivalents	$	80	$	57
Restricted cash and cash equivalents included in other current assets	7		9
Total cash and cash equivalents and restricted cash and cash equivalents	$	87	$	66

~~(3) Property, Plant and Equipment, Net~~


(4)	Property, Plant and Equipment, Net

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


		As of							As of
	Depreciable Life	September 30,			December 31,			Depreciable Life	September 30,			December 31,
		2017			2016				2018			2017
Utility plant:
Generation	30 - 55 years	$	3,725		$	4,271		30 - 55 years	$	3,702		$	3,707
Distribution	20 - 65 years	3,294			3,231			20 - 65 years	3,373			3,314
Transmission	45 - 65 years	1,860			1,846			45 - 70 years	1,864			1,860
General and intangible plant	5 - 65 years	784			738			5 - 65 years	820			793
Utility plant		9,663			10,086				9,759			9,674
Accumulated depreciation and amortization		(2,840		)	(3,205		)		(3,026		)	(2,871		)
Utility plant, net		6,823			6,881				6,733			6,803
Other non-regulated, net of accumulated depreciation and amortization	45 years	2			2			45 years	1			1
Plant, net		6,825			6,883				6,734			6,804
Construction work-in-progress		65			114				96			73
Property, plant and equipment, net		$	6,890		$	6,997			$	6,830		$	6,877

During 2017, Nevada Power revised its electric depreciations rates effective January 2018 based on the results of a new depreciation study, the most significant impact of which was shorter estimated useful lives at the Navajo Generating Station and longer average service lives for various other utility plant groups. The net effect of these changes will increase depreciation and amortization expense by $7 million annually, or $5 million for the nine-month period ended September 30, 2018, based on depreciable plant balances at the time of the change.

~~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~~


(5)	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~~energy in future time periods.

Regulatory Rate Review

In June 2017, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $29 million, or 2%, but requested no incremental annual revenue relief. In December 2017, the PUCN issued an order which reduced Nevada Power's revenue requirement by $26 million and requires Nevada Power to share 50% of regulatory earnings above 9.7%. As a result of the order, Nevada Power recorded expense of $28 million in December 2017 primarily due to the reduction of a regulatory asset to return to customers revenue collected for costs not incurred. The new rates were effective on February 15, 2018. In January 2018, Nevada Power filed a petition for clarification of certain findings and directives in the order and intervening parties filed motions for reconsideration. The PUCN has not yet ruled on the filed motions. Nevada Power cannot predict the timing or ultimate outcome of the PUCN rulings.

The Tax Cuts and Jobs Act ("2017 Tax Reform") enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. In February 2018, Nevada Power made a filing with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. The filing supports an annual rate reduction of $59 million. In March 2018, the PUCN issued an order approving the rate reduction proposed by Nevada Power. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing Nevada Power to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018.

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. In February 2018, Caesars became a distribution only service customer and started procuring energy from another energy supplier. Following the PUCN's order from March 2017, Caesars' will pay an impact fee of $44 million in 72 equal monthly payments.

~~Emissions Reduction and Capacity Replacement Plan~~In June 2018, Station Casinos LLC ("~~ERCR Plan"~~Station")

~~In March 2017,~~, a customer of Nevada Power, ~~retired Reid Gardner Unit 4, a 257-MW coal-fueled generating facility. The early retirement was approved by~~filed an application with the PUCN ~~in December 2016 as~~to purchase energy from alternative providers of a ~~part~~new electric resource and become a distribution only service customer of Nevada ~~Power's second amendment~~Power. In October 2018, the PUCN approved a stipulation allowing Station to ~~the ERCR Plan. The remaining net book value~~purchase energy from alternative providers subject to conditions, including paying an impact fee 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.$15 million.


(6)	~~(5)~~ Recent Financing Transactions

Long-Term Debt

In ~~January 2017,~~April 2018, 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$575 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~~2.75% General and Refunding Mortgage Notes, Series ~~AA, No. AA-1 in~~BB, due April 2020. Nevada Power used a portion of the ~~amount of $39.5 million and No. AA-2 in the amount of $53 million (collectively, the "Series AA Notes").The obligation~~net proceeds to repay all of Nevada ~~Power to make any payment of the principal~~Power's $325 million 6.50% General and ~~interest on any~~Refunding Mortgage Notes, Series ~~AA Notes is discharged to the extent~~O, maturing in May 2018. In August 2018, Nevada Power ~~has made payment on~~used the remaining net proceeds, together with available cash, to repay all of Nevada Power's $500 million 6.50% General and Refunding Mortgage Notes, Series ~~2017 Bonds and the Series 2017AB Bonds.~~S, maturing in August 2018.

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.Credit Facilities

In ~~June 2017,~~April 2018, Nevada Power amended and restated its existing $400 million secured credit facility, expiring June 2020, extending the ~~maturity~~expiration date to June ~~2020 with~~2021 and reducing from two to one, the available one-year extension options, subject to lender consent.


(7)	Income Taxes

Tax Cuts and Jobs Act

2017 Tax Reform impacts many areas of income tax law. The ~~amended credit facility, which is~~most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018, the elimination of the deduction for ~~general corporate purposes~~production activities and ~~provides~~limitations on bonus depreciation for utility property.

In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin 118 to assist in the implementation process of 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the ~~issuance~~accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. Nevada Power has recorded the impacts of ~~letters~~2017 Tax Reform and believes all the impacts to be complete with the exception of ~~credit,~~interpretations of the bonus depreciation rules. Nevada Power has determined the amounts recorded and the interpretations relating to this items to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. Nevada Power believes its interpretations for bonus depreciation to be reasonable, however, as the guidance is clarified estimates may change. Nevada Power recorded a ~~variable interest rate based on~~current tax benefit and deferred tax expense of $12 million during the ~~Eurodollar rate or~~three-month period ended September 30, 2018 following clarified bonus depreciation guidance. As a ~~base rate, at~~result of 2017 Tax Reform and Nevada Power's ~~option, plus a spread that varies based on~~regulatory nature, Nevada ~~Power's credit ratings for its senior secured long-term debt securities.~~Power reduced the associated deferred income tax liabilities $5 million and increased regulatory liabilities by the same amount. 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~~accounting will be completed by December 2018.

A reconciliation of the ~~last day of each quarter.~~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,
	2018		2017		2018		2017

Federal statutory income tax rate	21	%	35	%	21	%	35	%
Nondeductible expenses	3		—		3		—
Effects of ratemaking	1		—		—		—
Other	(1	)	2		—		1
Effective income tax rate	24	%	37	%	24	%	36	%

~~(6)~~(8) 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 $19 million to the Qualified Pension Plan and $1 million to the Non-Qualified Pension Plans for the nine-month period ended September 30, ~~2017.~~2018. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts ~~payable to~~receivable from (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.~~

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.



	As of
	September 30,			December 31,
	2018			2017
Qualified Pension Plan:
Other long-term liabilities	$	(4	)	$	(23	)

Non-Qualified Pension Plans:
Other current liabilities	(1		)	(1		)
Other long-term liabilities	(10		)	(10		)

Other Postretirement Plans:
Other assets	1			—
Other long-term liabilities	—			1


~~(8)~~(9)	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										Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3			Total			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
As of September 30, 2018
Assets:
Commodity derivatives											$	—	$	—	$	1		$	1
Money market mutual funds⁽¹⁾	$	220	$	—	$	—		$	220		67		—		—			67
Investment funds	6		—		—			6			2		—		—			2
	$	226	$	—	$	—		$	226		$	69	$	—	$	1		$	70

Liabilities - commodity derivatives	$	—	$	—	$	(14	)	$	(14	)	$	—	$	—	$	(8	)	$	(8	)

As of December 31, 2017
Assets - investment funds											$	2	$	—	$	—		$	2

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


(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~~2018 and December 31, ~~2016,~~2017, 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.~~

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 assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):


	Three-Month Periods						Nine-Month Periods						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017

Beginning balance	$	(4	)	$	(22	)	$	(14	)	$	(22	)	$	(9	)	$	(4	)	$	(3	)	$	(14	)
Changes in fair value recognized in regulatory assets	(1		)	(1		)	(3		)	(6		)	2			(1		)	(6		)	(3		)
Settlements	1			4			13			9			—			1			2			13
Ending balance	$	(4	)	$	(19	)	$	(4	)	$	(19	)	$	(7	)	$	(4	)	$	(7	)	$	(4	)

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



	As of September 30, 2018				As of December 31, 2017
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	2,351	$	2,653	$	2,600	$	3,088


~~(9)~~(10)	Commitments and Contingencies

Environmental Laws and Regulations

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

~~Senate Bill 123~~

In June 2013, the Nevada State Legislature passed Senate Bill No. 123 ("SB 123"), which included the retirement of coal plants and replacing the capacity with renewable 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.


(11)	Revenue from Contracts with Customers

Adoption

In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" ("ASC 606") and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize revenue from contracts with customers ("Customer 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. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. Nevada Power adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.

Customer Revenue

Nevada Power recognizes revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which Nevada Power expects to be entitled in exchange for those goods or services. Nevada Power records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

Substantially all of Nevada Power's Customer Revenue is derived from tariff based sales arrangements approved by various regulatory bodies. These tariff based revenues are mainly comprised of energy, transmission and distribution and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of amounts not considered Customer Revenue within ASC 606 and revenue recognized in accordance with ASC 840, "Leases".

Revenue recognized is equal to what Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power's performance to date and includes billed and unbilled amounts. As of September 30, 2018 and December 31, 2017, accounts receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $178 million and $111 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

The following table summarizes Nevada Power's revenue by customer class for the three- and nine-month periods ended September 30, 2018 (in millions):



	Three-Month Period		Nine-Month Period
	Ended September 30,		Ended September 30,
	2018		2018
Customer Revenue:
Retail:
Residential	$	484	$	989
Commercial	135		340
Industrial	164		351
Other	7		18
Total fully bundled	790		1,698
Distribution only service	9		24
Total retail	799		1,722
Wholesale, transmission and other	15		38
Total Customer Revenue	814		1,760
Other revenue	6		17
Total revenue	$	820	$	1,777

Contract Assets and Liabilities

In the event one of the parties to a contract has performed before the other, Nevada Power would recognize a contract asset or contract liability depending on the relationship between Nevada Power's performance and the customer's payment. As of September 30, 2018 and December 31, 2017, there were no contract assets or contract liabilities recorded on the Consolidated Balance Sheets.

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~~2018 and ~~2016~~2017

Overview

Net income for the third quarter of ~~2017~~2018 was ~~$176~~$164 million, a decrease of $12 million, or 6%7%, compared to ~~2016~~2017 primarily due to $50 million of higher operations and maintenance expense, mainly due to an accrual for earnings sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review and increased political activity expenses, $12 million of lower utility margin, primarily due to lower ~~commercial and industrial~~average retail ~~revenue from customers purchasing energy from alternative providers and becoming distribution only service customers, refinement~~rates including rate impacts related to the tax rate reduction rider as a result of the ~~unbilled revenue estimate~~Tax Cuts and ~~increased other operating costs. The decrease~~Jobs Act ("2017 Tax Reform"), and $8 million in ~~net income was~~higher depreciation and amortization, primarily due to various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review, partially offset by ~~higher other retail revenue~~a decrease in income tax expense of $50 million, primarily from a lower federal tax rate due to the impact ~~fees~~of 2017 Tax Reform, and ~~revenue relating to customers becoming distribution only service customers, customer usage patterns, higher transmission revenue and customer growth.~~$6 million of lower interest expense on long-term debt.

Net income for the first nine months of ~~2017~~2018 was ~~$263~~$228 million, ~~an increase~~a decrease of $6$35 million, or 2%13%, compared to ~~2016~~2017 primarily due to $68 million of higher ~~other~~operations and maintenance expense, mainly due to an accrual for earnings sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review and increased political activity expenses, $27 million of lower utility margin, primarily due to lower average retail ~~revenue primarily from impact fees~~rates including rate impacts related to the tax rate reduction rider as a result of 2017 Tax Reform, 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. Thea $22 million 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.~~various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review, partially offset by a decrease in income tax expense of $79 million, primarily from a lower federal tax rate due to the impact of 2017 Tax Reform.

~~Operating revenue and cost of fuel, energy and capacity~~Non-GAAP Financial Measure

Management utilizes various key financial measures that are ~~key drivers of Nevada Power's~~prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of ~~operations~~operations. Utility margin is calculated 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~~electric operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

Nevada Power's cost of fuel and ~~capacity,~~energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's revenue are comparable to changes in such expenses. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Utility margin is ~~therefore meaningful.~~not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):



	Third Quarter									First Nine Months
	2018		2017		Change					2018		2017		Change
Utility margin:
Operating revenue	$	820	$	819	$	1		—	%	$	1,777	$	1,785	$	(8	)	—	%
Cost of fuel and energy	331		318		13			4		740		721		19			3
Utility margin	489		501		(12		)	(2	)	1,037		1,064		(27		)	(3	)
Operations and maintenance	146		96		50			52		344		276		68			25
Depreciation and amortization	85		77		8			10		253		231		22			10
Property and other taxes	11		10		1			10		31		29		2			7
Operating income	$	247	$	318	$	(71	)	(22	)	$	409	$	528	$	(119	)	(23	)

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


	Third Quarter										First Nine Months										Third Quarter									First Nine Months
	2017		2016		Change						2017		2016		Change						2018		2017		Change					2018		2017		Change
Gross margin (in millions):
Utility margin (in millions):
Operating revenue	$	819	$	766	$	53		7		%	$	1,785	$	1,690	$	95		6		%	$	820	$	819	$	1		—	%	$	1,777	$	1,785	$	(8	)	—	%
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	)
Cost of fuel and energy																					331		318		13			4		740		721		19			3
Utility margin																					$	489	$	501	$	(12	)	(2	)	$	1,037	$	1,064	$	(27	)	(3	)

GWh sold:
Residential	3,899		3,814		85			2		%	7,899		7,802		97			1		%	4,213		3,899		314			8	%	8,299		7,899		400			5	%
Commercial	1,517		1,440		77			5			3,669		3,600		69			2			1,568		1,517		51			3		3,759		3,669		90			2
Industrial	1,783		2,149		(366		)	(17	)		4,870		5,772		(902		)	(16	)		1,631		1,783		(152		)	(9	)	4,281		4,870		(589		)	(12	)
Other	60		59		1			2			154		155		(1		)	(1	)		61		60		1			2		157		154		3			2
Total fully bundled⁽¹⁾	7,259		7,462		(203		)	(3	)		16,592		17,329		(737		)	(4	)		7,473		7,259		214			3		16,496		16,592		(96		)	(1	)
Distribution only service	617		119		498			*			1,367		305		1,062			*			775		617		158			26		1,938		1,367		571			42
Total retail	7,876		7,581		295			4			17,959		17,634		325			2			8,248		7,876		372			5		18,434		17,959		475			3
Wholesale	59		76		(17		)	(22	)		214		177		37			21			53		59		(6		)	(10	)	181		214		(33		)	(15	)
Total GWh sold	7,935		7,657		278			4			18,173		17,811		362			2			8,301		7,935		366			5		18,615		18,173		442			2

Average number of retail customers (in thousands):
Residential	813		799		14			2		%	809		795		14			2		%	828		813		15			2	%	823		809		14			2	%
Commercial	106		105		1			1			106		105		1			1			108		106		2			2		107		106		1			1
Industrial	2		2		—			—			2		2		—			—			2		2		—			—		2		2		—			—
Total	921		906		15			2			917		902		15			2			938		921		17			2		932		917		15			2

Average retail revenue per MWh:
Fully bundled⁽¹⁾	$	109.85	$	101.22	$	8.63		9		%	$	104.06	$	95.69	$	8.37		9		%
Average per MWh:
Revenue - fully bundled⁽¹⁾																					$	105.82	$	109.85	$	(4.03	)	(4	)%	$	102.93	$	104.06	$	(1.13	)	(1	)%
Total cost of energy⁽²⁾																					$	41.93	$	42.46	$	(0.53	)	(1	)%	$	44.14	$	41.80	$	2.34		6	%

Heating degree days	—		—		—			—		%	791		829		(38		)	(5	)	%	—		—		—			—	%	839		791		48			6	%
Cooling degree days	2,319		2,295		24			1		%	3,808		3,674		134			4		%	2,580		2,319		261			11	%	4,072		3,808		264			7	%

Sources of energy (GWh)⁽²⁾:
Sources of energy (GWh)⁽³⁾:
Natural gas	4,592		4,657		(65		)	(1	)	%	10,338		11,569		(1,231		)	(11	)	%	5,282		4,592		690			15	%	11,295		10,338		957			9	%
Coal	367		599		(232		)	(39	)		1,182		1,140		42			4			403		367		36			10		891		1,182		(291		)	(25	)
Renewables	19		26		(7		)	(27	)		57		47		10			21			20		19		1			5		56		57		(1		)	(2	)
Total energy generated	4,978		5,282		(304		)	(6	)		11,577		12,756		(1,179		)	(9	)		5,705		4,978		727			15		12,242		11,577		665			6
Energy purchased	2,500		2,471		29			1			5,665		5,410		255			5			2,214		2,500		(286		)	(11	)	5,209		5,665		(456		)	(8	)
Total	7,478		7,753		(275		)	(4	)		17,242		18,166		(924		)	(5	)		7,919		7,478		441			6		17,451		17,242		209			1

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.~~costs and excludes - and 39 GWh of coal and - and 481 GWh of gas generated energy that is purchased at cost by related parties for the third quarter of 2018 and 2017, respectively. The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs and excludes 93 and 226 GWh of coal and 1,043 and 1,631 GWh of gas generated energy that is purchased at cost by related parties for the first nine months of 2018 and 2017, respectively.


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

~~Gross~~Utility margin decreased ~~$14~~$12 million, or 3%2%, for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to:

$23 million in lower retail rates due to the tax rate reduction rider as a result of 2017 Tax Reform;

$15 million due to lower retail rates as a result of the 2017 regulatory rate review with rates effective February 2018 and

$3 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.~~customers.

The decrease in ~~gross~~utility margin was offset by:

$815 million in higher residential volumes primarily from the impacts of weather;

$4 million due to residential customer growth;

$3 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;~~

$32 million in higher ~~transmission~~energy efficiency program rate revenue, ~~primarily due to customers becoming distribution only service customers~~which is offset in operating and maintenance expense and

$2 million ~~due to customer growth.~~from higher transmission revenue.

~~Operating~~Operations and maintenance ~~decreased $8~~increased $50 million, or 8%52%, for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to an accrual for earnings sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review and higher political activity expenses.

Depreciation and amortization increased $8 million, or 10%, for the third quarter of 2018 compared to 2017 primarily due to various regulatory-directed amortizations and increased depreciation expense as a result of the Nevada Power 2017 regulatory rate review.

Other income (expense) is favorable $9 million, or 23%, for the third quarter of 2018 compared to 2017 primarily due to lower ~~energy efficiency program~~interest expense ~~(offset in operating revenue) of $8 million.~~on long-term debt and higher interest income.

Income tax expense ~~increased $5~~decreased $50 million, or 5%49%, for the third quarter of ~~2017~~2018 compared to ~~2016.~~2017. The effective tax rate was 24% in 2018 and 37% in ~~2017 and 34% in 2016.~~2017. The ~~increase~~decrease in the effective tax rate is primarily due to 2017 Tax Reform, which reduced the ~~qualified production activities deduction~~United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, partially offset by an increase in ~~2016.~~nondeductible expenses.

~~Gross~~Utility margin decreased $8$27 million, or 1%3%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to:

$2439 million in lower retail rates due to the tax rate reduction rider as a result of 2017 Tax Reform;

$23 million in lower retail rates as a result of the 2017 regulatory rate review with rates effective February 2018 and

$8 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).~~customers.

The decrease in ~~gross~~utility margin was offset by:

$1917 million in higher residential volumes primarily from the impacts of weather;

$8 million due to residential customer growth;

$7 million in higher other ~~retail~~ revenue primarily from impact fees and revenue relating to customers becoming distribution only service ~~customers;~~customers and

$~~7 million due to customer growth;~~

$63 million in higher ~~transmission~~energy efficiency program rate revenue, ~~primarily due to customers becoming distribution only service customers~~which is offset in operating and

~~$5 million from customer usage patterns.~~ maintenance expense.

~~Operating~~Operations and maintenance ~~decreased $26~~increased $68 million, or 9%25%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~lower energy efficiency program expense (offset~~an accrual for earnings sharing established in ~~operating revenue); lower planned maintenance;~~2018 as part of the Nevada Power 2017 regulatory rate review and ~~decreased expenses related to uncollectible accounts. These decreases are partially offset by~~ higher ~~other operating costs.~~political activity expenses.

Depreciation and amortizationincreased$4 $22 million, or 2%10%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~higher plant placed in-service.~~various regulatory-directed amortizations and increased depreciation expense as a result of the Nevada Power 2017 regulatory rate review.

Other income (expense) is favorable $6$5 million, or 5%4%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily 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.~~long-term debt.

Income tax expense ~~increased $15~~decreased $79 million, or ~~11%~~52%, for the first nine months of ~~2017~~2018 compared to ~~2016.~~2017. The effective tax rate was 24% in 2018 and 36% in ~~2017 and 35% in 2016. The increase~~2017.The decrease in the effective tax rate is primarily due to 2017 Tax Reform, which reduced the ~~qualified production activities deduction~~United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, partially offset by an increase in ~~2016.~~nondeductible expenses.

Liquidity and Capital Resources

As of September 30, ~~2017,~~2018, 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.~~as follows (in millions):



Cash and cash equivalents	$	80
Credit facility	400
Total net liquidity	$	480
Credit facility:
Maturity date	2021

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2018 and 2017 ~~and 2016~~ were ~~$472~~$486 million and ~~$601~~$469 million, respectively. ~~The change was~~Increases were due to lower federal tax payments and increased collections from customers due to higher deferred energy rates, partially offset by impact fees received in ~~2016~~2017, higher payments for operating costs and higher ~~intercompany tax payments, partially offset by a 2016 contribution~~contributions to the pension plan.

solar projects. In December 2017, 2017 Tax Reform was enacted which, among other items, reduces the federal corporate tax rate from 35% to 21% effective January 1, 2018, eliminated bonus depreciation on qualifying regulated utility assets acquired after December 31 and eliminated the deduction for production activities, but did not impact investment tax credits. Nevada Power believes for qualifying assets acquired on or before December 31, bonus depreciation will remain available for 2018 and 2019. In February 2018, Nevada Power made a filing with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. The filing supported an annual rate reduction of $59 million. In March 2018, the PUCN issued an order approving the rate reduction proposed by Nevada Power. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. Nevada Power expects lower revenue collections and income tax payments as well as lower bonus depreciation benefits compared to 2017 as a result of 2017 Tax Reform and related regulatory treatment. Nevada Power does not expect 2017 Tax Reform and related regulatory treatment to have a material adverse impact on its cash flows, subject to actual regulatory outcomes. 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, 2018 and 2017 ~~and 2016~~ were ~~$(275)~~$(202) million and ~~$(249)~~$(275) million, respectively. The change was primarily due to the acquisition of the remaining 25% in the Silverhawk generating station ~~partially offset by decreased capital expenditures.~~in 2017.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2018 and 2017 ~~and 2016~~ were ~~$(407)~~$(263) million and ~~$(586)~~$(407) million, respectively. The change was due to ~~lower repayments of long‑term debt and~~greater proceeds from issuance of ~~long‑term~~long-term debt ~~partially offset by higher~~in 2018 and dividends paid to NV Energy, Inc. of $412 million in ~~2017.~~2017 compared to no dividends paid in 2018, partially offset by higher repayments of long-term debt in 2018.

Ability to Issue Debt

Nevada Power's ability to issue debt is primarily impacted by its financing authority from the PUCN. AsFollowing the April 2018 issuance of ~~September 30, 2017,~~$575 million of general and refunding mortgage securities, 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~~$656 million 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.~~2018.

Future Uses of Cash

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

Capital Expenditures

Nevada Power has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; 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		Nine-Month Periods				Annual
	Ended September 30,				Forecast		Ended September 30,				Forecast
	2016		2017		2017		2017		2018		2018

Generation development	$	1	$	—	$	—
Distribution	110		41		58		41		93		155
Transmission system investment	29		6		10		6		6		19
Other	109		155		180		155		104		157
Total	$	249	$	202	$	248	$	202	$	203	$	331

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,~~2018, 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.~~2017.

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.

Integrated Resource Plan ("IRP")

In June 2018, Nevada Power and Sierra Pacific filed with the PUCN a joint application for approval of a 2019-2038 Triennial IRP, 2019-2021 Action Plan, and 2019-2021 Energy Supply Plan ("ESP"). As part of the filings, the Nevada Utilities seek the PUCN authorization to add 1,001 MW of renewable energy and 100 MW of energy storage capacity. The Nevada Utilities are requesting to achieve with power purchase agreements from six new solar generating resources, three battery storage systems, transmission network upgrades and the conditional early retirement of North Valmy Unit 1 generating station. The agreements are conditional upon voters not approving the ballot measure on energy choice in November 2018.

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.~~laws and regulations.

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.~~2017. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, ~~2016.~~2017.

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

PART I


Item 1.	Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

~~Las Vegas, Nevada~~

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of September 30, ~~2017, and~~2018, the related consolidated statements of operations for the three-month and nine-month periods ended September 30, ~~2017~~2018 and ~~2016,~~2017, and of changes in shareholder's equity and cash flows for the nine-month periods ended September 30, 2018 and 2017 and ~~2016. These~~the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial ~~statements are~~information for it to be in conformity with accounting principles generally accepted in the ~~responsibility~~United States of ~~Sierra Pacific's management.~~America.

We ~~conducted our reviews~~have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States). (PCAOB), the consolidated balance sheet of Sierra Pacific as of December 31, 2017, 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 23, 2018, 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, 2017 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Sierra Pacific's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We 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~~2, 2018

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of						As of
	September 30,			December 31,			September 30,			December 31,
	2017			2016			2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	30		$	55		$	71		$	4
Accounts receivable, net	102			117			106			112
Inventories	47			45			53			49
Regulatory assets	38			25			8			32
Other current assets	20			13			32			17
Total current assets	237			255			270			214

Property, plant and equipment, net	2,862			2,822			2,938			2,892
Regulatory assets	400			410			293			300
Other assets	8			6			15			7

Total assets	$	3,507		$	3,493		$	3,516		$	3,413

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	75		$	146		$	84		$	92
Accrued interest	11			14			11			14
Accrued property, income and other taxes	11			10			13			10
Regulatory liabilities	17			69			32			19
Current portion of long-term debt and financial and capital lease obligations	1			1			2			2
Customer deposits	15			16			19			15
Other current liabilities	18			12			25			12
Total current liabilities	148			268			186			164

Long-term debt and financial and capital lease obligations	1,151			1,152			1,153			1,152
Regulatory liabilities	223			221			489			481
Deferred income taxes	663			617			333			330
Other long-term liabilities	134			127			107			114
Total liabilities	2,319			2,385			2,268			2,241

Commitments and contingencies (Note 8)
Commitments and contingencies (Note 10)

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		)
Additional paid-in capital							1,111			1,111
Retained earnings							138			62
Accumulated other comprehensive loss, net	(1		)	(1		)	(1		)	(1		)
Total shareholder's equity	1,188			1,108			1,248			1,172

Total liabilities and shareholder's equity	$	3,507		$	3,493		$	3,516		$	3,413

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods						Nine-Month Periods						Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,						Ended September 30,						Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Operating revenue:
Electric	$	215		$	207		$	534		$	539
Natural gas	15			15			66			81
Regulated electric													$	225		$	215		$	575		$	534
Regulated natural gas													14			15			74			66
Total operating revenue	230			222			600			620			239			230			649			600

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
Operating expenses:
Cost of fuel and energy													90			76			245			193
Cost of natural gas purchased for resale													4			4			35			26
Operations and maintenance													53			41			140			122
Depreciation and amortization	29			30			85			88			30			29			89			85
Property and other taxes	6			5			18			18			6			6			18			18
Total operating costs and expenses	155			153			443			482
Total operating expenses													183			156			527			444

Operating income	75			69			157			138			56			74			122			156

Other income (expense):
Interest expense	(11		)	(12		)	(33		)	(42		)	(12		)	(11		)	(33		)	(33		)
Allowance for borrowed funds	1			—			1			1			—			1			1			1
Allowance for equity funds	1			1			2			2			1			1			3			2
Other, net	2			2			4			3			3			3			8			5
Total other income (expense)	(7		)	(9		)	(26		)	(36		)	(8		)	(6		)	(21		)	(25		)

Income before income tax expense	68			60			131			102			48			68			101			131
Income tax expense	24			22			46			37			13			24			25			46
Net income	$	44		$	38		$	85		$	65		$	35		$	44		$	76		$	85

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)


									Accumulated														Accumulated
				Other		Retained			Other			Total						Additional		Retained			Other			Total
	Common Stock			Paid-in		Earnings			Comprehensive			Shareholder's			Common Stock			Paid-in		Earnings			Comprehensive			Shareholder's
	Shares	Amount		Capital		(Deficit)			Loss, Net			Equity			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		1,000	$	—	$	1,111	$	(2	)	$	(1	)	$	1,108
Net income	—	—		—		85			—			85			—	—		—		85			—			85
Dividends declared	—	—		—		(5		)	—			(5		)	—	—		—		(5		)	—			(5		)
Balance, September 30, 2017	1,000	$	—	$	1,111	$	78		$	(1	)	$	1,188		1,000	$	—	$	1,111	$	78		$	(1	)	$	1,188

Balance, December 31, 2017															1,000	$	—	$	1,111	$	62		$	(1	)	$	1,172
Net income															—	—		—		76			—			76
Balance, September 30, 2018															1,000	$	—	$	1,111	$	138		$	(1	)	$	1,248

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2017			2016			2018			2017
Cash flows from operating activities:
Net income	$	85		$	65		$	76		$	85
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	85			88			89			85
Allowance for equity funds	(2		)	(2		)	(3		)	(2		)
Changes in regulatory assets and liabilities							32			9
Deferred income taxes and amortization of investment tax credits	46			37			9			46
Changes in regulatory assets and liabilities	9			(14		)
Deferred energy	(23		)	55			26			(23		)
Amortization of deferred energy	(43		)	(35		)	(6		)	(43		)
Other, net	—			(1		)
Changes in other operating assets and liabilities:
Accounts receivable and other assets	13			12			(3		)	11
Inventories	(2		)	1			(5		)	(2		)
Accrued property, income and other taxes	(2		)	—
Accrued property, income and other taxes, net							(2		)	(2		)
Accounts payable and other liabilities	(54		)	(15		)	(5		)	(54		)
Net cash flows from operating activities	112			191			208			110

Cash flows from investing activities:
Capital expenditures	(131		)	(137		)	(139		)	(131		)
Net cash flows from investing activities	(131		)	(137		)	(139		)	(131		)

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		)	(2		)	(1		)
Dividends paid	(5		)	(45		)	—			(5		)
Net cash flows from financing activities	(6		)	(93		)	(2		)	(6		)

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
Net change in cash and cash equivalents and restricted cash and cash equivalents							67			(27		)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period							8			60
Cash and cash equivalents and restricted cash and cash equivalents at end of period							$	75		$	33

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

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~(1) Organization and Operations~~


(1)	General

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~~and 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~~2018 and for the three- and nine-month periods ended September 30, ~~2017~~2018 and ~~2016.~~2017. 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~~2018 and ~~2016.~~2017. The results of operations for the three- and nine-month periods ended September 30, ~~2017~~2018 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~~2017 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.~~2018.

(2)

~~(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.

In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. 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 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. 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. During 2018, the FASB issued several ASUs that clarified the implementation guidance and provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases" and ASU No. 2018-11 that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. 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 in the process of evaluating the impact on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.


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

In ~~May 2014,~~November 2016, the FASB issued ASU No. ~~2014-09,~~2016-18, which ~~creates~~amends FASB ASC ~~Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition.~~Subtopic 230-10, "Statement of Cash Flows - Overall." The amendments in this guidance ~~replaces industry-specific guidance~~require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and ~~establishes a single five-step model to identify~~amounts generally described as restricted cash and ~~recognize revenue. The core principle~~restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of 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.cash flows. Sierra Pacific ~~plans to adopt~~adopted 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.2018.



	As of
	September 30,		December 31,
	2018		2017
Cash and cash equivalents	$	71	$	4
Restricted cash and cash equivalents included in other current assets	4		4
Total cash and cash equivalents and restricted cash and cash equivalents	$	75	$	8


(4)	~~(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,
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.



		As of
	Depreciable Life	September 30,			December 31,
	Depreciable Life	2018			2017
Utility plant:
Electric generation	25 - 60 years	$	1,144		$	1,144
Electric distribution	20 - 100 years	1,518			1,459
Electric transmission	50 - 100 years	817			786
Electric general and intangible plant	5 - 70 years	191			181
Natural gas distribution	35 - 70 years	398			390
Natural gas general and intangible plant	5 - 70 years	14			14
Common general	5 - 70 years	305			294
Utility plant		4,387			4,268
Accumulated depreciation and amortization		(1,573		)	(1,513		)
Utility plant, net		2,814			2,755
Other non-regulated, net of accumulated depreciation and amortization	70 years	5			5
Plant, net		2,819			2,760
Construction work-in-progress		119			132
Property, plant and equipment, net		$	2,938		$	2,892


(5)	~~(4)~~ Regulatory Matters

Deferred Energy

Regulatory Rate Review

The Tax Cuts and Jobs Act ("2017 Tax Reform") enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. In ~~June 2016,~~February 2018, Sierra Pacific ~~filed an electric regulatory rate review with the PUCN. The~~made a filing ~~requested no incremental annual revenue relief. In October 2016, Sierra Pacific filed~~ with the PUCN proposing a ~~settlement agreement resolving most, but not all, issues in~~tax rate reduction rider for the ~~proceeding~~lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and ~~reduced Sierra Pacific's electric revenue requirement by $3 million spread evenly to all~~beyond. The filing supports an annual rate ~~classes.~~reduction of $25 million. In ~~December 2016,~~March 2018, the PUCN ~~approved~~issued an order approving 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.rate reduction proposed by Sierra Pacific, The new rates were effective ~~January~~April 1, ~~2017.~~2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In ~~January 2017,~~September 2018, the PUCN issued an order directing Sierra Pacific ~~filed~~to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as 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.

~~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 wereliability effective January 1, ~~2017.~~2018.

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. In January 2018, Caesars became a distribution only service customer and started procuring energy from another energy supplier for its eligible meters in the Sierra Pacific service territory. Following the PUCN's order from March 2017, Caesars' will pay an impact fee of $4 million in 36 monthly payments.

~~(5)~~(6) Recent Financing Transactions

Credit Facilities

In ~~June 2017,~~April 2018, Sierra Pacific amended and restated its existing $250 million secured credit facility, expiring June 2020, extending the ~~maturity~~expiration date to June ~~2020 with~~2021 and reducing from two to one, the available 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.


(7)	Income Taxes

~~(6)~~ Tax Cuts and Jobs Act

2017 Tax Reform impacts many areas of income tax law. The most material items include the reduction of the federal corporate tax rate from 35% to 21% effective January 1, 2018, the elimination of the deduction for production activities and limitations on bonus depreciation for utility property.

In December 2017, the Securities and Exchange Commission issued Staff Accounting Bulletin 118 to assist in the implementation process of 2017 Tax Reform by allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable. Sierra Pacific has recorded the impacts of 2017 Tax Reform and believes all the impacts to be complete with the exception of interpretations of the bonus depreciation rules. Sierra Pacific has determined the amounts recorded and the interpretations relating to this items to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting. Sierra Pacific believes its interpretations for bonus depreciation to be reasonable, however, as the guidance is clarified estimates may change. Sierra Pacific recorded a current tax benefit and deferred tax expense of $4 million during the three-month period ended September 30, 2018 following clarified bonus depreciation guidance. As a result of 2017 Tax Reform and Sierra Pacific's regulatory nature, Sierra Pacific reduced the associated deferred income tax liabilities $2 million and increased regulatory liabilities by the same amount. The accounting will be completed by December 2018.

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,
	2018		2017		2018		2017

Federal statutory income tax rate	21	%	35	%	21	%	35	%
Nondeductible expenses	5		—		4		—
Effects of ratemaking	1		—		—		—
Effective income tax rate	27	%	35	%	25	%	35	%


(8)	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$6 million to the Qualified Pension Plan and $6 million to the Other Postretirement ~~Plans~~Plan for the nine-month period ended September 30, ~~2017.~~2018. 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.

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


	As of						As of
	September 30,			December 31,			September 30,			December 31,
	2017			2016			2018			2017
Qualified Pension Plan -
Qualified Pension Plan:
Other assets							$	6		$	—
Other long-term liabilities	$	(13	)	$	(12	)	—			(2		)

Non-Qualified Pension Plans:
Other current liabilities	(1		)	(1		)	(1		)	(1		)
Other long-term liabilities	(9		)	(9		)	(8		)	(8		)

Other Postretirement Plans -
Other Postretirement Plans:
Other long-term liabilities	(25		)	(28		)	(13		)	(20		)


(9)	~~(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



	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3			Total
As of September 30, 2018
Assets - money market mutual funds⁽¹⁾	$	18	$	—	$	—		$	18

Liabilities - commodity derivatives	$	—	$	—	$	(1	)	$	(1	)

As of December 31, 2017
Assets - investment funds	$	—	$	—	$	—		$	—


(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 Sierra Pacific transacts. When quoted prices for identical contracts are not available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific 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, Sierra Pacific 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 Sierra Pacific's nonperformance risk on its liabilities, which as of September 30, 2018 and December 31, 2017, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.

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.

The following table reconciles the beginning and ending balances of Sierra Pacific'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,
	2018			2017		2018			2017

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

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



	As of September 30, 2018				As of December 31, 2017
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,120	$	1,153	$	1,120	$	1,221


~~(8)~~(10)	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.


(11)	Revenue from Contracts with Customers

~~(9)~~

Adoption

In May 2014, the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers" ("ASC 606") and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and established a single five-step model to identify and recognize revenue from contracts with customers ("Customer 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. Following the issuance of ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2014-09 but did not change the core principle of the guidance. Sierra Pacific adopted this guidance for all applicable contracts as of January 1, 2018 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.

Customer Revenue

Sierra Pacific recognizes revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which Sierra Pacific expects to be entitled in exchange for those goods or services. Sierra Pacific records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.

Substantially all of Sierra Pacific's Customer Revenue is derived from tariff based sales arrangements approved by various regulatory bodies. These tariff based revenues are mainly comprised of energy, transmission, distribution and natural gas and have performance obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are provided. Other revenue consists primarily of revenue recognized in accordance with ASC 840, "Leases" and amounts not considered Customer Revenue within ASC 606.

Revenue recognized is equal to what Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific's performance to date and includes billed and unbilled amounts. As of September 30, 2018 and December 31, 2017, accounts receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $51 million and $62 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued.

The following table summarizes Sierra Pacific's revenue by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 12, for the three- and nine-month periods ended September 30, 2018 (in millions):



	Three-Month Period						Nine-Month Period
	Ended September 30,						Ended September 30,
	2018						2018
	Electric		Gas		Total		Electric		Gas		Total
Customer Revenue:
Retail:
Residential	$	76	$	9	$	85	$	203	$	48	$	251
Commercial	75		3		78		190		18		208
Industrial	59		1		60		136		6		142
Other	2		—		2		5		—		5
Total fully bundled	212		13		225		534		72		606
Distribution only service	1		—		1		3		—		3
Total retail	213		13		226		537		72		609
Wholesale, transmission and other	12		1		13		35		1		36
Total Customer Revenue	225		14		239		572		73		645
Other revenue	—		—		—		3		1		4
Total revenue	$	225	$	14	$	239	$	575	$	74	$	649

Contract Assets and Liabilities

In the event one of the parties to a contract has performed before the other, Sierra Pacific would recognize a contract asset or contract liability depending on the relationship between Sierra Pacific's performance and the customer's payment. As of September 30, 2018 and December 31, 2017, there were no contract assets or contract liabilities recorded on the Consolidated Balance Sheets.


(12)	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").

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



	Three-Month Periods						Nine-Month Periods
	Ended September 30,						Ended September 30,
	2018			2017			2018			2017
Operating revenue:
Regulated electric	$	225		$	215		$	575		$	534
Regulated natural gas	14			15			74			66
Total operating revenue	$	239		$	230		$	649		$	600

Operating income:
Regulated electric	$	56		$	71		$	111		$	141
Regulated natural gas	—			3			11			15
Total operating income	56			74			122			156
Interest expense	(12		)	(11		)	(33		)	(33		)
Allowance for borrowed funds	—			1			1			1
Allowance for equity funds	1			1			3			2
Other, net	3			3			8			5
Income before income tax expense	$	48		$	68		$	101		$	131


	As of				As of
	September 30,		December 31,		September 30,		December 31,
	2017		2016		2018		2017
Assets:
Regulated electric	$	3,165	$	3,119	$	3,131	$	3,103
Regulated gas	305		314
Regulated natural gas					300		300
Regulated common assets⁽¹⁾	37		60		85		10
Total assets	$	3,507	$	3,493	$	3,516	$	3,413


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

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~~2018 and ~~2016~~2017

Overview

Net income for the third quarter of ~~2017~~2018 was ~~$44~~$35 million, ~~an increase~~a decrease of $6$9 million, or ~~16%~~20%, compared to ~~2016~~2017 primarily due to $12 million of higher operations and maintenance expense, primarily due to increased political activity expenses, and $5 million of lower utility margin, primarily due to lower average retail rates including rate impacts related to the tax rate reduction rider as a result of the Tax Cuts and Jobs Act ("2017 Tax Reform"), partially offset by a decrease in ~~interest~~income tax expense ~~from lower rates on outstanding debt balances and on deferred charges, higher electric margins~~of $11 million, primarily from ~~increased customer usage~~a lower federal tax rate due to the ~~impacts~~impact of ~~weather and customer usage patterns and decreased other operating costs. The increase in net income was partially offset by lower wholesale revenue.~~2017 Tax Reform.

Net income for the first nine months of ~~2017~~2018 was ~~$85~~$76 million, ~~an increase~~a decrease of ~~$20~~$9 million, or ~~31%~~11%, compared to ~~2016~~2017 primarily due to $18 million of higher operations and maintenance expense, primarily due to increased political activity expenses, and $11 million of lower electric utility margin, primarily due to lower average retail rates including rate impacts related to the tax rate reduction rider as a result of 2017 Tax Reform, partially offset by a decrease in ~~interest~~income tax expense ~~from lower rates on outstanding debt balances and on deferred charges, higher electric margins~~of $21 million, primarily from ~~increased customer usage~~a lower federal tax rate due to the ~~impacts~~impact 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.~~2017 Tax Reform.

~~Operating~~Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Consolidated Statements of Operations.

Sierra Pacific's cost of fuel and energy and ~~capacity and~~cost of natural gas purchased for resale are ~~key drivers of~~directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's ~~results of operations as they encompass retail and wholesale electricity~~revenue are comparable to changes in such expenses. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the ~~direct costs associated with providing electricity~~presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to ~~customers. Sierra Pacific believes that~~running the business and a ~~discussion~~measure of ~~gross~~comparability to others in the industry.

Electric utility margin ~~representing operating revenue less cost of fuel, energy and capacity~~ and natural gas ~~purchased~~utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for ~~resale,~~operating income which is ~~therefore meaningful.~~the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):



	Third Quarter									First Nine Months
	2018		2017		Change					2018		2017		Change
Electric utility margin:
Electric operating revenue	$	225	$	215	$	10		5	%	$	575	$	534	$	41		8	%
Cost of fuel and energy	90		76		14			18		245		193		52			27
Electric utility margin	135		139		(4		)	(3	)	330		341		(11		)	(3	)

Natural gas utility margin:
Natural gas operating revenue	14		15		(1		)	(7	)%	74		66		8			12	%
Cost of natural gas purchased for resale	4		4		—			—		35		26		9			35
Natural gas utility margin	10		11		(1		)	(9	)	39		40		(1		)	(3	)

Utility margin	145		150		(5		)	(3	)%	369		381		(12		)	(3	)%

Operations and maintenance	53		41		12			29	%	140		122		18			15	%
Depreciation and amortization	30		29		1			3		89		85		4			5
Property and other taxes	6		6		—			—		18		18		—			—

Operating income	$	56	$	74	$	(18	)	(24	)%	$	122	$	156	$	(34	)	(22	)%

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

Electric ~~Gross~~Utility Margin


	Third Quarter										First Nine Months										Third Quarter									First Nine Months
	2017		2016		Change						2017		2016		Change						2018		2017		Change					2018		2017		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
Electric utility margin (in millions):
Electric operating revenue																					$	225	$	215	$	10		5	%	$	575	$	534	$	41		8	%
Cost of fuel and energy																					90		76		14			18		245		193		52			27
Electric utility margin																					$	135	$	139	$	(4	)	(3	)	$	330	$	341	$	(11	)	(3	)

GWh sold:
Residential	736		694		42			6		%	1,904		1,798		106			6		%	737		736		1			—	%	1,877		1,904		(27		)	(1	)%
Commercial	850		854		(4		)	—			2,271		2,241		30			1			874		850		24			3		2,282		2,271		11			—
Industrial	797		747		50			7			2,346		2,235		111			5			867		797		70			9		2,497		2,346		151			6
Other	4		4		—			—			12		12		—			—			4		4		—			—		12		12		—			—
Total fully bundled⁽¹⁾	2,387		2,299		88			4			6,533		6,286		247			4			2,482		2,387		95			4		6,668		6,533		135			2
Distribution only service	348		346		2			1			1,041		1,019		22			2			375		348		27			8		1,124		1,041		83			8
Total retail	2,735		2,645		90			3			7,574		7,305		269			4			2,857		2,735		122			4		7,792		7,574		218			3
Wholesale	103		147		(44		)	(30	)		392		481		(89		)	(19	)		109		103		6			6		391		392		(1		)	—
Total GWh sold	2,838		2,792		46			2			7,966		7,786		180			2			2,966		2,838		128			5		8,183		7,966		217			3

Average number of retail customers (in thousands):
Residential	295		292		3			1		%	295		291		4			1		%	300		295		5			2	%	299		295		4			1	%
Commercial	47		47		—			—			47		47		—			—			48		47		1			2		48		47		1			2
Total	342		339		3			1			342		338		4			1			348		342		6			2		347		342		5			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
Average per MWh:
Revenue - fully bundled⁽¹⁾																					$	84.84	$	85.07	$	(0.23	)	—	%	$	80.02	$	75.89	$	4.13		5	%
Revenue - wholesale																					$	58.09	$	61.21	$	(3.12	)	(5	)%	$	49.92	$	52.92	$	(3.00	)	(6	)%
Total cost of energy⁽²⁾																					$	36.76	$	28.53	$	8.23		29	%	$	34.57	$	26.07	$	8.50		33	%

Heating degree days	118		43		75			*		%	2,823		2,487		336			14		%	14		118		(104		)	(88	)%	2,639		2,823		(184		)	(7	)%
Cooling degree days	1,070		796		274			34		%	1,401		1,088		313			29		%	1,043		1,070		(27		)	(3	)%	1,283		1,401		(118		)	(8	)%

Sources of energy (GWh)⁽²⁾:
Sources of energy (GWh)⁽³⁾:
Natural gas	1,221		1,215		6			—		%	3,227		3,195		32			1		%	1,480		1,221		259			21	%	3,615		3,227		388			12	%
Coal	355		392		(37		)	(9	)		457		691		(234		)	(34	)		361		355		6			2		558		457		101			22
Renewables	12		—		12			*			31		—		31			*			12		12		—			—		30		31		(1		)	(3	)
Total energy generated	1,588		1,607		(19		)	(1	)		3,715		3,886		(171		)	(4	)		1,853		1,588		265			17		4,203		3,715		488			13
Energy purchased	1,074		878		196			22			3,698		3,111		587			19			785		1,074		(289		)	(27	)	3,090		3,698		(608		)	(16	)
Total	2,662		2,485		177			7			7,413		6,997		416			6			2,638		2,662		(24		)	(1	)	7,293		7,413		(120		)	(2	)

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.~~costs and excludes 35 GWh of coal and 136 GWh of gas generated energy that is purchased at cost by related parties for the third quarter of 2018. The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs and excludes 54 GWh of coal and 185 GWh of gas generated energy that is purchased at cost by related parties for the first nine months of 2018. In the third quarter and first nine months of 2017, there were no GWh of coal or gas excluded.


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

Natural Gas ~~Gross~~Utility Margin


	Third Quarter										First Nine Months										Third Quarter									First Nine Months
	2017		2016		Change						2017		2016		Change						2018		2017		Change					2018		2017		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
Natural gas utility margin (in millions):
Natural gas operating revenue																					$	14	$	15	$	(1	)	(7	)%	$	74	$	66	$	8		12	%
Cost of natural gas purchased for resale																					4		4		—			—		35		26		9			35
Natural gas utility margin																					$	10	$	11	$	(1	)	(9	)	$	39	$	40	$	(1	)	(3	)

Dth sold:
Residential	835		727		108			15		%	6,866		5,958		908			15		%	740		835		(95		)	(11	)%	6,520		6,866		(346		)	(5	)%
Commercial	494		459		35			8			3,522		3,182		340			11			464		494		(30		)	(6	)	3,364		3,522		(158		)	(4	)
Industrial	244		216		28			13			1,255		1,080		175			16			267		244		23			9		1,364		1,255		109			9
Total retail	1,573		1,402		171			12			11,643		10,220		1,423			14			1,471		1,573		(102		)	(6	)	11,248		11,643		(395		)	(3	)

Average number of retail customers (in thousands)	164		162		2			1		%	164		161		3			2		%	167		164		3			2	%	167		164		3			2	%
Average revenue per retail Dth sold	$	8.59	$	10.22	$	(1.63	)	(16	)	%	$	5.47	$	7.68	$	(2.21	)	(29	)	%	$	8.98	$	8.59	$	0.39		5	%	$	6.44	$	5.47	$	0.97		18	%
Average cost of natural gas per retail Dth sold	$	2.53	$	3.11	$	(0.58	)	(19	)	%	$	2.20	$	4.09	$	(1.89	)	(46	)	%	$	2.69	$	2.53	$	0.16		6	%	$	3.11	$	2.20	$	0.91		41	%
Heating degree days	118		43		75			*		%	2,823		2,487		336			14		%	14		118		(104		)	(88	)%	2,639		2,823		(184		)	(7	)%

Electric ~~gross~~utility margin ~~increased $5~~decreased $4 million, or 4%3%, for the third quarter of ~~2017~~2018 compared to ~~2016 due to:~~

~~$4 million higher customer usage~~2017 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.~~retail rates due to the tax rate reduction rider as a result of 2017 Tax Reform.

~~Other income (expense)~~ Operations and maintenance~~is favorable $2~~ increased $12 million, or ~~22%~~29%, for the third quarter of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~lower interest on deferred charges.~~increased political activity expenses and higher transmission and distribution costs.

Income tax expense ~~increased $2~~decreased $11 million, or 9%46%, for the third quarter of ~~2017~~2018 compared to ~~2016.~~2017. The effective tax rate was 27% in 2018 and 35% in 2017. The decrease in the effective tax rate is primarily due to 2017 Tax Reform, which reduced the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, offset by an increase in nondeductible expenses and ~~37% in 2016.~~unfavorable effects of ratemaking.

Electric ~~gross~~utility margin ~~increased $10~~decreased $11 million, or 3%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to:

$812 million ~~higher~~in lower retail rates due to the tax rate reduction rider as a result of 2017 Tax Reform and

$2 million in lower customer ~~usage~~volumes primarily from the impacts of ~~weather;~~

~~$3 million from customer usage patterns and~~

~~$2 million in higher transmission revenue.~~weather.

The ~~increase~~decrease in ~~electric gross~~utility margin was partially offset by:

$41 million ~~in decreased wholesale revenue~~ due to ~~lower volumes.~~customer growth.

~~Operating~~Operations and maintenance~~decreased $5~~ increased $18 million, or 4%15%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~lower other operating costs, partially offset by lower operating~~increased political activity expenses and ~~maintenance related regulatory credit amortizations.~~higher transmission and distribution costs.

Depreciation and amortization~~decreased $3~~ increased $4 million, or 3%5%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~regulatory amortizations.~~higher plant placed in service.

Other income (expense) is favorable ~~$10~~$4 million, or ~~28%~~16%, for the first nine months of ~~2017~~2018 compared to ~~2016~~2017 primarily due to ~~a decrease in interest expense from~~ lower ~~rates on outstanding debt balances and lower interest on deferred charges.~~pension expense.

Income tax expense ~~increased $9~~decreased $21 million, or ~~24%~~46%, for the first nine months of ~~2017~~2018 compared to ~~2016.~~2017. The effective tax rate was 25% in 2018 and 35% in 2017. The decrease in the effective tax rate is primarily due to 2017 ~~and 36%~~Tax Reform, which reduced the United States federal corporate income tax rate from 35% to 21%, effective January 1, 2018, offset by an increase in ~~2016.~~nondeductible expenses.

Liquidity and Capital Resources

As of September 30, ~~2017,~~2018, Sierra Pacific's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	30		$	71

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

Total net liquidity	$	200		$	241
Credit facility:
Maturity date				2021

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2018 and 2017 ~~and 2016~~ were ~~$112~~$208 million and ~~$191~~$110 million, respectively. The change was due to ~~higher payments for~~a decrease in fuel costs and increased collections from customers due to higher deferred energy rates, partially offset by ~~lower~~higher federal tax payments and higher 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 income tax cash flows benefited in 2017 and 2016 from ~~operations are expected to benefit due to~~50% bonus depreciation on qualifying assets placed ~~in-service through 2019 and investment~~in service. In December 2017, 2017 Tax Reform was enacted which, among other items, reduces the federal corporate tax ~~credits (once the net operating loss is fully utilized) earned~~rate from 35% to 21% effective January 1, 2018, eliminated bonus depreciation on qualifying ~~projects through 2021.~~

regulated utility assets acquired after December 31, 2017 and eliminated the deduction for production activities. Sierra Pacific believes for qualifying assets acquired on or before December 31, 2017, bonus depreciation will remain available for 2018 and 2019. In February 2018, Sierra Pacific made a filing with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. The filing supported an annual rate reduction of $25 million. In March 2018, the PUCN issued an order approving the rate reduction proposed by Sierra Pacific. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. Sierra Pacific expects lower revenue collections and income tax payments as well as lower bonus depreciation benefits compared to 2017 as a result of 2017 Tax Reform and the related regulatory treatment. Sierra Pacific does not expect 2017 Tax Reform and related regulatory treatment to have a material adverse impact on its cash flows, subject to actual regulatory outcomes. 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, 2018 and 2017 ~~and 2016~~ were ~~$(131)~~$(139) million and ~~$(137)~~$(131) million, respectively. The change was due to ~~decreased~~increased capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2018 and 2017 ~~and 2016~~ were ~~$(6)~~$(2) million and ~~$(93)~~$(6) million, respectively. The change was primarily 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.~~2017.

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,~~2018, 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.~~2018.

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, impacts to customers' rates; 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		Nine-Month Periods				Annual
	Ended September 30,				Forecast		Ended September 30,				Forecast
	2016		2017		2017		2017		2018		2018

Distribution	$	73	$	61	$	91	$	61	$	101	$	158
Transmission system investment	16		9		14		9		3		5
Other	48		61		80		61		35		51
Total	$	137	$	131	$	185	$	131	$	139	$	214

Sierra Pacific's forecast capital expenditures include investments ~~that relate~~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,~~2018, 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.~~2017.

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.

Integrated Resource Plan ("IRP")

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.

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.~~2017. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, ~~2016.~~2017.


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~~2017. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, ~~2016~~2017. 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~~2018.


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~~2018 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PART II


Item 1.	Legal Proceedings

Not applicable.


Item 1A.	Risk Factors

There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017.


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

Not applicable.


Item 3.	Defaults Upon Senior Securities

Not applicable.


Item 4.	Mine Safety Disclosures

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


Item 5.	Other Information

Not applicable.


Item 6.	Exhibits

The following is a list of exhibits ~~listed on the accompanying Exhibit Index are~~ filed as part of this Quarterly Report.


Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY


4.1	Thirteenth Supplemental Indenture, dated as of July 25, 2018, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 4.45% Senior Notes due 2049 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).


4.2	Fiscal Agency Agreement, dated as of July 12, 2018, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the $450,000,000 in principal amount of the 4.30% Senior Bonds due 2049 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).

10.1

$3,500,000,000 Amended and Restated Credit Agreement, dated as of April 30, 2018, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Union Bank, N.A, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).


10.2	Third Amending Agreement to Fourth Amended and Restated Credit Agreement, dated as of April 19, 2018, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).


10.3	Third Amending Agreement to Third Amended and Restated Credit Agreement, dated as of April 19, 2018, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).


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.


Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP


4.3	Twenty-Ninth Supplemental Indenture, dated as of July 1, 2018, to PacifiCorp's Mortgage and Deed of Trust dated as of January 9, 1989 (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated July 13, 2018).

10.4

$600,000,000 Amended and Restated Credit Agreement, dated as of April 30, 2018, 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 10.4 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).

10.5

$600,000,000 Amended and Restated Credit Agreement, dated as of April 30, 2018, 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 10.5 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).


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

10.6

$900,000,000 Amended and Restated Credit Agreement, dated as of April 30, 2018, 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 10.6 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).

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


3.1	Amended and Restated By-Laws of Nevada Power Company as amended December 21, 2017 (incorporated by reference to Exhibit 3.1 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).


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.


Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER


4.4	Officer's Certificate establishing the terms of Nevada Power Company’s 2.75% General and Refunding Mortgage Notes, Series BB, due 2020 (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated April 12, 2018).

10.7

$400,000,000 Third Amended and Restated Credit Agreement, dated as of April 30, 2018, 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 10.7 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).

SIERRA PACIFIC


3.2	Amended and Restated By-Laws of Sierra Pacific Power Company as amended December 21, 2017 (incorporated by reference to Exhibit 3.2 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).


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

10.8

$250,000,000 Third Amended and Restated Credit Agreement, dated as of April 30, 2018, 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 10.8 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).

ALL REGISTRANTS

101

The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018, is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.

SIGNATURES

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



	BERKSHIRE HATHAWAY ENERGY COMPANY

Date: November ~~3, 2017~~2, 2018	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Executive Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	PACIFICORP

Date: November ~~3, 2017~~2, 2018	/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~~2, 2018	/s/ Thomas B. Specketer
	Thomas B. Specketer
	Vice President and Controller
	of MidAmerican Funding, LLC and
	~~and~~ Vice President and Chief Financial Officer
	of MidAmerican Energy Company
	(principal financial and accounting officer)

	NEVADA POWER COMPANY

Date: November ~~3, 2017~~2, 2018	/s/ Michael E. ~~Kevin Bethel~~Cole
	Michael E. ~~Kevin Bethel~~Cole
	~~Senior~~ Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	SIERRA PACIFIC POWER COMPANY

Date: November ~~3, 2017~~2, 2018	/s/ Michael E. ~~Kevin Bethel~~Cole
	Michael E. ~~Kevin Bethel~~Cole
	~~Senior~~ Vice President and Chief Financial Officer
	(principal financial and accounting officer)

~~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).

~~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).

~~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~~170



Item 1.	Legal Proceedings	~~152~~166
Item 1A.	Risk Factors	~~152~~166
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~152~~166
Item 3.	Defaults Upon Senior Securities	~~152~~166
Item 4.	Mine Safety Disclosures	~~152~~166
Item 5.	Other Information	~~152~~166
Item 6.	Exhibits	~~152~~166
Signatures		~~153~~
~~Exhibit Index~~		~~154~~170



	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