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, 2018~~March 31, 2019

[ ] 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 every Interactive Data File required to be submitted 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 such files). Yes x No o

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



Registrant	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company	Emerging growth company
BERKSHIRE HATHAWAY ENERGY COMPANY			X
PACIFICORP			X
MIDAMERICAN FUNDING, LLC			X
MIDAMERICAN ENERGY COMPANY			X
NEVADA POWER COMPANY			X
SIERRA PACIFIC POWER COMPANY			X

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

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

Yes o No x

All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of ~~October 31, 2018, 76,996,944~~April 30, 2019, 76,549,232 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, 2018,~~April 30, 2019, 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, 2018.~~April 30, 2019.

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, 2018,~~April 30, 2019, 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, 2018,~~April 30, 2019, 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, 2018,~~April 30, 2019, 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	~~165~~150
Item 4.	Controls and Procedures	~~165~~150

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		Berkshire Hathaway Inc.
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
BHE Pipeline Group		Consists of Northern Natural Gas Company and Kern River Gas Transmission Company
Northern Natural Gas		Northern Natural Gas Company
Kern River		Kern River Gas Transmission Company
~~AltaLink~~BHE Transmission		Consists of BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada		BHE Canada Holdings Corporation
~~ALP~~AltaLink		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
HomeServices		HomeServices of America, Inc. and its subsidiaries
Utilities		PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company
~~Berkshire Hathaway~~Domestic Regulated Businesses		~~Berkshire Hathaway Inc.~~PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Northern Natural Gas Company and Kern River Gas Transmission Company
Topaz		Topaz Solar Farms LLC
Agua Caliente		Agua Caliente Solar, LLC

Certain Industry Terms
2017 Tax Reform		The Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018
AESO		Alberta Electric System Operator
AFUDC		Allowance for Funds Used During Construction
AUC		Alberta Utilities Commission
CPUC		California Public Utilities Commission
Dth		~~Decatherms~~Decatherm
EBA		Energy Balancing Account
ECAM		Energy Cost Adjustment Mechanism
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
~~GHG~~GAAP		~~Greenhouse Gases~~Accounting principles generally accepted in the United States of America
~~GWh~~GEMA		~~Gigawatt Hours~~
~~GTA~~		~~General Tariff Application~~
~~IPUC~~		~~Idaho Public Utilities Commission~~
~~IUB~~		~~Iowa Utilities Board~~Gas and Electricity Markets Authority



GHG		Greenhouse Gases
GWh		Gigawatt Hour
GTA		General Tariff Application
IPUC		Idaho Public Utilities Commission
IRP		Integrated Resource Plan
IUB		Iowa Utilities Board
kV		Kilovolt
MW		~~Megawatts~~Megawatt
MWh		Megawatt ~~Hours~~Hour
Ofgem		Office of Gas and Electric Markets
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 incidents, litigation, wars, terrorism, embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;

iii

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;

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 franchising industries and regulations that could affect brokerage, mortgage and 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; 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		5651
Consolidated Balance Sheets		5752
Consolidated Statements of Operations		5954
Consolidated Statements of Changes in Shareholders' Equity		6055
Consolidated Statements of Cash Flows		6156
Notes to Consolidated Financial Statements		6257
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		8374
Balance Sheets		8475
Statements of Operations		8677
Statements of Changes in Shareholder's Equity		8778
Statements of Cash Flows		8879
Notes to Financial Statements		8980
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		9989
Consolidated Balance Sheets		~~100~~90
Consolidated Statements of Operations		~~102~~92
Consolidated Statements of Changes in Member's Equity		~~103~~93
Consolidated Statements of Cash Flows		~~104~~94
Notes to Consolidated Financial Statements		~~105~~95
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		~~122~~109
Consolidated Balance Sheets		~~123~~110
Consolidated Statements of Operations		~~124~~111
Consolidated Statements of Changes in Shareholder's Equity		~~125~~112
Consolidated Statements of Cash Flows		~~126~~113
Notes to Consolidated Financial Statements		~~127~~114
Sierra Pacific Power Company ~~and its subsidiaries~~
Report of Independent Registered Public Accounting Firm		~~144~~130
~~Consolidated~~ Balance Sheets		~~145~~131
~~Consolidated~~ Statements of Operations		~~146~~132
~~Consolidated~~ Statements of Changes in Shareholder's Equity		~~147~~133
~~Consolidated~~ Statements of Cash Flows		~~148~~134
Notes to ~~Consolidated~~ Financial Statements		~~149~~135


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



Berkshire Hathaway Energy Company and its subsidiaries		3028
PacifiCorp and its subsidiaries		7467
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		~~109~~99
Nevada Power Company and its subsidiaries		~~136~~123
Sierra Pacific Power Company ~~and its subsidiaries~~		~~158~~144

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

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, 2018~~March 31, 2019, the related consolidated statements of operations, ~~and~~ comprehensive income, ~~for the three-month and nine-month periods ended September 30, 2018 and 2017, and of~~ changes in equity and cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ and 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~~2018, 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 ~~23, 2018~~22, 2019, 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~~2018 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 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 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.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 2, 2018~~May 3, 2019

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	1,016	$	935	$	1,661	$	627
Restricted cash and cash equivalents	358		327		181		227
Trade receivables, net	2,198		2,014		1,898		2,038
Income tax receivable	—		334
Inventories	851		888		785		844
Mortgage loans held for sale	501		465		506		468
Other current assets	860		815		1,080		943
Total current assets	5,784		5,778		6,111		5,147

Property, plant and equipment, net	67,587		65,871		68,948		68,087
Goodwill	9,683		9,678		9,663		9,595
Regulatory assets	2,778		2,761		2,898		2,896
Investments and restricted cash and cash equivalents and investments	4,754		4,872		4,877		4,903
Other assets	1,276		1,248		2,048		1,561

Total assets	$	91,862	$	90,208	$	94,545	$	92,189

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,			March 31,			December 31,
	2018			2017			2019			2018
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,331		$	1,519		$	1,434		$	1,809
Accrued interest	518			488			522			469
Accrued property, income and other taxes	543			354			475			599
Accrued employee expenses	414			274			316			275
Short-term debt	1,784			4,488			2,214			2,516
Current portion of long-term debt	2,205			3,431			1,078			2,081
Other current liabilities	1,026			1,049			1,358			1,021
Total current liabilities	7,821			11,603			7,397			8,770

BHE senior debt	8,620			5,452			8,228			8,577
BHE junior subordinated debentures	100			100			100			100
Subsidiary debt	26,633			26,210			28,510			25,492
Regulatory liabilities	7,553			7,309			7,347			7,346
Deferred income taxes	8,895			8,242			9,080			9,047
Other long-term liabilities	2,552			2,984			3,721			3,134
Total liabilities	62,174			61,900			64,383			62,466

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	6,357			6,368			6,355			6,371
Long-term income tax receivable	(494		)	—			(457		)	(457		)
Retained earnings	25,361			22,206			25,968			25,624
Accumulated other comprehensive loss, net	(1,667		)	(398		)	(1,830		)	(1,945		)
Total BHE shareholders' equity	29,557			28,176			30,036			29,593
Noncontrolling interests	131			132			126			130
Total equity	29,688			28,308			30,162			29,723

Total liabilities and equity	$	91,862		$	90,208		$	94,545		$	92,189

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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Energy	$	4,419		$	4,322		$	11,818		$	11,501		$	3,825		$	3,679
Real estate	1,218			961			3,252			2,502			785			761
Total operating revenue	5,637			5,283			15,070			14,003			4,610			4,440

Operating expenses:
Energy:
Cost of sales	1,271			1,212			3,565			3,380			1,214			1,168
Operations and maintenance	901			772			2,534			2,334			802			785
Depreciation and amortization	667			635			2,110			1,905			720			704
Property and other taxes	142			142			428			421			149			143
Real estate	1,133			882			3,067			2,311			806			769
Total operating expenses	4,114			3,643			11,704			10,351			3,691			3,569

Operating income	1,523			1,640			3,366			3,652			919			871

Other income (expense):
Interest expense	(453		)	(464		)	(1,380		)	(1,379		)	(477		)	(466		)
Capitalized interest	17			14			44			34			16			12
Allowance for equity funds	30			24			75			59			32			21
Interest and dividend income	27			32			85			85			30			26
Gains (losses) on marketable securities, net	260			3			(336		)	8
Losses on marketable securities, net													(68		)	(209		)
Other, net	19			(17		)	50			8			35			30
Total other income (expense)	(100		)	(408		)	(1,462		)	(1,185		)	(432		)	(586		)

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	9			30			35			80
Income before income tax benefit and equity (loss) income													487			285
Income tax benefit													(148		)	(221		)
Equity (loss) income													(10		)	12
Net income	1,409			1,078			2,305			2,228			625			518
Net income attributable to noncontrolling interests	8			10			19			30			3			5
Net income attributable to BHE shareholders	$	1,401		$	1,068		$	2,286		$	2,198		$	622		$	513

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
	Ended September 30,					Ended September 30,						Ended March 31,
	2018			2017		2018			2017			2019			2018

Net income	$	1,409		$	1,078	$	2,305		$	2,228		$	625		$	518

Other comprehensive income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $-, $1, $12 and $(3)	(1		)	15		50			16
Unrecognized amounts on retirement benefits, net of tax of $(7) and $(4)												(32		)	(3		)
Foreign currency translation adjustment	(2		)	227		(236		)	535			155			73
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
Unrealized losses on cash flow hedges, net of tax of $(2) and $(1)												(8		)	(2		)
Total other comprehensive income, net of tax												115			68

Comprehensive income	1,407			1,744		2,121			3,316			740			586
Comprehensive income attributable to noncontrolling interests	8			10		19			30			3			5
Comprehensive income attributable to BHE shareholders	$	1,399		$	1,734	$	2,102		$	3,286		$	737		$	581

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
							Long-term						Accumulated															Long-term						Accumulated
				Additional			Income						Other												Additional			Income						Other
	Common			Paid-in			Tax			Retained			Comprehensive			Noncontrolling			Total			Common			Paid-in			Tax			Retained			Comprehensive			Noncontrolling			Total
	Shares	Stock		Capital			Receivable			Earnings			Loss, Net			Interests			Equity			Shares	Stock		Capital			Receivable			Earnings			Loss, Net			Interests			Equity

Balance, December 31, 2016	77	$	—	$	6,390		$	—		$	19,448		$	(1,511	)	$	136		$	24,463
Balance, December 31, 2017																						77	$	—	$	6,368		$	—		$	22,206		$	(398	)	$	132		$	28,308
Adoption of ASU 2016-01																						—	—		—			—			1,085			(1,085		)	—			—
Net income	—	—		—			—			2,198			—			14			2,212			—	—		—			—			513			—			4			517
Other comprehensive income	—	—		—			—			—			1,088			—			1,088			—	—		—			—			—			68			—			68
Common stock purchases	—	—		(1		)	—			(18		)	—			—			(19		)	—	—		(5		)	—			(85		)	—			—			(90		)
Common stock exchange	—	—		(6		)	—			(94		)	—			—			(100		)
Distributions	—	—		—			—			—			—			(16		)	(16		)	—	—		—			—			—			—			(9		)	(9		)
Other equity transactions	—	—		(21		)	—			—			—			(3		)	(24		)
Balance, September 30, 2017	77	$	—	$	6,362		$	—		$	21,534		$	(423	)	$	131		$	27,604
Balance, March 31, 2018																						77	$	—	$	6,363		$	—		$	23,719		$	(1,415	)	$	127		$	28,794

Balance, December 31, 2017	77	$	—	$	6,368		$	—		$	22,206		$	(398	)	$	132		$	28,308
Adoption of ASU 2016-01	—	—		—			—			1,085			(1,085		)	—			—
Balance, December 31, 2018																						77	$	—	$	6,371		$	(457	)	$	25,624		$	(1,945	)	$	130		$	29,723
Net income	—	—		—			—			2,286			—			16			2,302			—	—		—			—			622			—			3			625
Other comprehensive loss	—	—		—			—			—			(184		)	—			(184		)
Reclassification of long-term income tax receivable	—	—		—			(609		)	—			—			—			(609		)
Long-term income tax receivable adjustments	—	—		—			115			(115		)	—			—			—
Other comprehensive income																						—	—		—			—			—			115			—			115
Common stock purchases	—	—		(6		)	—			(101		)	—			—			(107		)	—	—		(16		)	—			(277		)	—			—			(293		)
Distributions	—	—		—			—			—			—			(17		)	(17		)	—	—		—			—			—			—			(7		)	(7		)
Other equity transactions	—	—		(5		)	—			—			—			—			(5		)	—	—		—			—			(1		)	—			—			(1		)
Balance, September 30, 2018	77	$	—	$	6,357		$	(494	)	$	25,361		$	(1,667	)	$	131		$	29,688
Balance, March 31, 2019																						77	$	—	$	6,355		$	(457	)	$	25,968		$	(1,830	)	$	126		$	30,162

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						Three-Month Periods
	Ended September 30,						Ended March 31,
	2018			2017			2019			2018
Cash flows from operating activities:
Net income	$	2,305		$	2,228		$	625		$	518
Adjustments to reconcile net income to net cash flows from operating activities:
Losses (gains) on marketable securities, net	336			(8		)
Losses on marketable securities, net							68			209
Depreciation and amortization	2,147			1,943			733			716
Allowance for equity funds	(75		)	(59		)	(32		)	(21		)
Equity income, net of distributions	17			(14		)
Equity loss (income), net of distributions							26			(5		)
Changes in regulatory assets and liabilities	263			17			(52		)	94
Deferred income taxes and amortization of investment tax credits	(116		)	573			(21		)	(166		)
Other, net	40			21			1			19
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(192		)	(82		)	144			250
Derivative collateral, net	9			(16		)	(3		)	(14		)
Pension and other postretirement benefit plans	(61		)	(29		)	(21		)	(21		)
Accrued property, income and other taxes, net	190			390			(48		)	(60		)
Accounts payable and other liabilities	168			170			68			(40		)
Net cash flows from operating activities	5,031			5,134			1,488			1,479

Cash flows from investing activities:
Capital expenditures	(4,203		)	(3,179		)	(1,393		)	(1,075		)
Acquisitions, net of cash acquired	(105		)	(1,102		)	(26		)	—
Purchases of marketable securities	(287		)	(167		)	(159		)	(155		)
Proceeds from sales of marketable securities	266			186			153			132
Equity method investments	(236		)	(80		)	(7		)	(156		)
Other, net	48			(12		)	17			31
Net cash flows from investing activities	(4,517		)	(4,354		)	(1,415		)	(1,223		)

Cash flows from financing activities:
Proceeds from BHE senior debt	3,166			—			—			2,176
Repayments of BHE senior debt and junior subordinated debentures	(650		)	(1,344		)
Common stock purchases	(107		)	(19		)	(293		)	(90		)
Proceeds from subsidiary debt	2,353			1,562			2,945			687
Repayments of subsidiary debt	(2,297		)	(834		)	(1,420		)	(550		)
Net (repayments of) proceeds from short-term debt	(2,694		)	365
Purchase of redeemable noncontrolling interest	(131		)	—
Net repayments of short-term debt							(311		)	(1,873		)
Other, net	(32		)	(60		)	(21		)	(14		)
Net cash flows from financing activities	(392		)	(330		)	900			336

Effect of exchange rate changes	(3		)	6			1			1

Net change in cash and cash equivalents and restricted cash and cash equivalents	119			456			974			593
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,283			1,003			883			1,283
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,402		$	1,459		$	1,857		$	1,876

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

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	General

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

The Company'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"~~BHE Canada") (which primarily consists of AltaLink, L.P. ("~~ALP"~~AltaLink")) 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 investing in wind, solar, ~~wind,~~ geothermal and hydroelectric projects, the ~~second~~ largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States.

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, 2018~~March 31, 2019 and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The results of operations for the ~~three- and nine-month periods~~three-month period ended ~~September 30, 2018~~March 31, 2019 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, ~~2017~~2018 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, except as disclosed in Note 4, during the ~~nine-month~~three-month period ended ~~September 30, 2018~~March 31, 2019.


(2)	~~New Accounting Pronouncements~~

In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 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 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)~~(2)	Property, Plant and Equipment, Net

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


		As of							As of
	Depreciable	September 30,			December 31,			Depreciable	March 31,			December 31,
	Life	2018			2017			Life	2019			2018
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	75,751		$	74,660		5-80 years	$	77,659		$	76,707
Interstate natural gas pipeline assets	3-80 years	7,295			7,176			3-80 years	7,547			7,524
		83,046			81,836				85,206			84,231
Accumulated depreciation and amortization		(25,566		)	(24,478		)		(26,253		)	(25,894		)
Regulated assets, net		57,480			57,358				58,953			58,337

Nonregulated assets:
Independent power plants	5-30 years	6,551			6,010			5-30 years	6,844			6,826
Other assets	3-30 years	1,605			1,489			3-30 years	1,474			1,424
		8,156			7,499				8,318			8,250
Accumulated depreciation and amortization		(1,773		)	(1,542		)		(1,711		)	(1,610		)
Nonregulated assets, net		6,383			5,957				6,607			6,640

Net operating assets		63,863			63,315				65,560			64,977
Construction work-in-progress		3,724			2,556				3,388			3,110
Property, plant and equipment, net		$	67,587		$	65,871			$	68,948		$	68,087

Construction work-in-progress includes $3.2 billion as of ~~September 30, 2018~~March 31, 2019 and ~~$2.2~~$2.9 billion as of December 31, ~~2017~~2018, related to the construction of regulated assets.


(53)	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				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Investments:
BYD Company Limited common stock	$	1,616	$	1,961	$	1,356	$	1,435
Rabbi trusts	398		441		394		371
Other	186		124		180		168
Total investments	2,200		2,526		1,930		1,974

Equity method investments:
BHE Renewables tax equity investments	1,221		1,025		1,627		1,661
Electric Transmission Texas, LLC	530		524		529		527
Bridger Coal Company	116		137		97		99
Other	163		148		158		153
Total equity method investments	2,030		1,834		2,411		2,440

Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	543		515		545		504
Restricted cash and cash equivalents	385		348		196		256
Total restricted cash and cash equivalents and investments	928		863		741		760

Total investments and restricted cash and cash equivalents and investments	$	5,158	$	5,223	$	5,082	$	5,174

Reflected as:
Current assets	$	404	$	351	$	205	$	271
Noncurrent assets	4,754		4,872		4,877		4,903
Total investments and restricted cash and cash equivalents and investments	$	5,158	$	5,223	$	5,082	$	5,174

Investments

~~In January 2016,~~Losses on marketable securities, net recognized during 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 consolidationperiod consists 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~~following (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 )



	Three-Month Periods
	Ended March 31,
	2019			2018
Unrealized losses recognized on marketable securities still held at the reporting date	$	(68	)	$	(211	)
Net gains recognized on marketable securities sold during the period	—			2
Losses on marketable securities, net	$	(68	)	$	(209	)

~~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

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 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 cash flows. The Company 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 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~~March 31, 2019 and December 31, ~~2017,~~2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Cash and cash equivalents	$	1,016	$	935	$	1,661	$	627
Restricted cash and cash equivalents	358		327		181		227
Investments and restricted cash and cash equivalents and investments	28		21		15		29
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,402	$	1,283	$	1,857	$	883

(4) Leases

Adoption

The Company has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842.

Leases

Lessee

The Company has non-cancelable operating leases primarily for office space, office equipment, generating facilities, land and rail cars and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company does not include options in its lease calculations unless there is a triggering event indicating the Company is reasonably certain to exercise the option. The Company’s accounting policy is to not recognize lease obligations and corresponding right-of-use assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with ASC 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

The Company's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

The Company's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and subsidiary debt, respectively, to conform to the current period presentation. The following table summarizes the Company's leases recorded on the Consolidated Balance Sheet (in millions):



	As of
	March 31,
	2019
Right-of-use assets:
Operating leases	$	544
Finance leases	509
Total right-of-use assets	$	1,053

Lease liabilities:
Operating leases	$	586
Finance leases	522
Total lease liabilities	$	1,108

The following table summarizes the Company's lease costs (in millions):



	Three-Month Period
	Ended March 31,
	2019

Variable	$	144
Operating	41
Finance:
Amortization	4
Interest	11
Short-term	1
Total lease costs	$	201

Weighted-average remaining lease term (years):
Operating leases	7.5
Finance leases	29.5

Weighted-average discount rate:
Operating leases	5.3		%
Finance leases	8.7		%

The following table summarizes the Company's supplemental cash flow information relating to leases (in millions):



	Three-Month Period
	Ended March 31,
	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	(37	)
Operating cash flows from finance leases	(12		)
Financing cash flows from finance leases	(5		)
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$	12
Finance leases	1

The Company has the following remaining lease commitments as of (in millions):



	March 31, 2019									December 31, 2018⁽¹⁾
	Operating			Finance			Total			Operating		Capital		Total
2019	$	115		$	53		$	168		$	147	$	69	$	216
2020	138			68			206			128		68		196
2021	116			74			190			110		73		183
2022	92			67			159			87		67		154
2023	66			56			122			61		56		117
Thereafter	198			775			973			159		772		931
Total undiscounted lease payments	725			1,093			1,818			$	692	$	1,105	$	1,797
Less - amounts representing interest	(139		)	(571		)	(710		)
Lease liabilities	$	586		$	522		$	1,108

(1) Amounts included for comparability and accounted for in accordance with ASC 840, "Leases".


(65)	Recent Financing Transactions

Long-Term Debt

In ~~July 2018, BHE~~March 2019, PacifiCorp 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~~$400 million of its ~~4.30% Senior~~3.50% First Mortgage 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~~June 2029 and ~~for general corporate purposes.~~

~~In July 2018, PacifiCorp issued~~ $600 million of its ~~4.125%~~4.15% First Mortgage Bonds due ~~2049.~~February 2050. PacifiCorp used a portion of the net proceeds to repay short-term debt partially incurred in January 2019 to repay all of ~~its $500~~PacifiCorp's $350 million ~~5.65%~~5.50% First Mortgage Bonds due ~~July 2018~~January 2019 and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

In ~~April 2018,~~February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest.

In January 2019, Nevada Power issued ~~$575~~$500 million of its ~~2.75%~~3.70% General and Refunding Mortgage Notes, Series ~~BB,~~CC, 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,~~2029. Nevada Power used the ~~remaining~~ net proceeds ~~together with available cash,~~ to repay all of Nevada Power's $500 million ~~6.50%~~7.125% General and Refunding Mortgage Notes, Series S,V, maturing in ~~August 2018.~~

March 2019.

In ~~February 2018,~~January 2019, MidAmerican Energy issued ~~$700~~$600 million of its 3.65% First Mortgage Bonds due ~~2048.~~April 2029 and $900 million of its 4.25% First Mortgage Bonds due July 2049. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from ~~February 2,~~November 1, 2017 to ~~October 31, 2017,~~December 14, 2018, with respect to investments in MidAmerican Energy's 2,000-megawatt (nameplate capacity) Wind XI project, MidAmerican Energy's 591-megawatt (nameplate capacity) Wind XII 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.


(76)	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				Three-Month Periods
	Ended September 30,				Ended September 30,				Ended March 31,
	2018		2017		2018		2017		2019		2018

Federal statutory income tax rate	21	%	35	%	21	%	35	%	21	%	21	%
Income tax credits	(19	)	(19	)	(29	)	(18	)	(29	)	(45	)
State income tax, net of federal income tax benefit	1		—		(6	)	(1	)	(17	)	(30	)
Income tax effect of foreign income	—		(3	)	(3	)	(4	)	(3	)	(16	)
Effects of ratemaking	(2	)	—		(3	)	—		(3	)	(8	)
Equity income	—		1		—		1		(1	)	1
Other, net	1		1		1		—		2		(1	)
Effective income tax rate	2	%	15	%	(19	)%	13	%	(30	)%	(78	)%

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~~the majority of all of its currently payable or receivable income tax is remitted to or received from Berkshire Hathaway. For the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, ~~2018~~2019 and ~~2017,~~2018, the Company ~~received net~~did not receive or make any cash payments for federal income taxes from or to 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.~~Hathaway.


(87)	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. The Company 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 applying 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 $16 million and $8 million, respectively, have been reclassified to Other, net in the Consolidated Statements of Operations.

Domestic Operations

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


	Three-Month Periods						Nine-Month Periods						Three-Month Periods
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Pension:
Service cost	$	5		$	6		$	15		$	18		$	4		$	5
Interest cost	26			29			78			87			27			26
Expected return on plan assets	(41		)	(40		)	(123		)	(120		)	(38		)	(41		)
Net amortization	8			7			23			22			9			8
Net periodic benefit (credit) cost	$	(2	)	$	2		$	(7	)	$	7
Net periodic benefit cost (credit)													$	2		$	(2	)

Other postretirement:
Service cost	$	1		$	3		$	6		$	7		$	2		$	2
Interest cost	7			7			19			21			6			6
Expected return on plan assets	(9		)	(9		)	(31		)	(30		)	(10		)	(10		)
Net amortization	(3		)	(3		)	(9		)	(10		)	(2		)	(3		)
Net periodic benefit credit	$	(4	)	$	(2	)	$	(15	)	$	(12	)	$	(4	)	$	(5	)

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 ~~$39~~$13 million and $7$1 million, respectively, during ~~2018.~~2019. As of ~~September 30, 2018, $34~~March 31, 2019, $3 million and $6$- 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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018

Service cost	$	5		$	6		$	15		$	19		$	4		$	5
Interest cost	14			15			42			44			13			14
Expected return on plan assets	(25		)	(25		)	(78		)	(74		)	(25		)	(27		)
Settlement	12			18			36			18
Net amortization	9			17			38			50			9			15
Net periodic benefit cost	$	15		$	31		$	53		$	57		$	1		$	7

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 £4644 million during ~~2018~~2019. As of ~~September 30, 2018~~March 31, 2019, £3511 million, or $4714 million, of contributions had been made to the United Kingdom pension plan.

(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 initiated analysis of additional actions to be taken. As a result of that analysis, MidAmerican Energy will remove all CCR material located below the water table and cap the material in such facilities, which is a more extensive closure activity than previously assumed. In the first quarter of 2019, MidAmerican Energy increased by $237 million the asset retirement obligation for the cost of this closure activity. Closure activity on the six existing surface impoundments is estimated to extend through 2023.


(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 March 31, 2019
Assets:
Commodity derivatives	$	—		$	82		$	100		$	(40	)	$	142
Interest rate derivatives	—			10			19			—			29
Mortgage loans held for sale	—			506			—			—			506
Money market mutual funds⁽²⁾	1,169			—			—			—			1,169
Debt securities:
United States government obligations	190			—			—			—			190
International government obligations	—			4			—			—			4
Corporate obligations	—			47			—			—			47
Municipal obligations	—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			1			—			—			1
Equity securities:
United States companies	292			—			—			—			292
International companies	1,363			—			—			—			1,363
Investment funds	182			—			—			—			182
	$	3,196		$	652		$	119		$	(40	)	$	3,927
Liabilities:
Commodity derivatives	$	—		$	(162	)	$	(14	)	$	96		$	(80	)
Interest rate derivatives	(1		)	(17		)	(1		)	—			(19		)
	$	(1	)	$	(179	)	$	(15	)	$	96		$	(99	)

Input Levels for Fair Value Measurements
Level 1 Level 2 Level 3
Other⁽¹⁾
Total
As of September 30, 2018
Assets:
Commodity derivatives $ —
$ 53
$ 99
$ (35 ) $ 117
Interest rate derivatives 3
22
11
—
36
Mortgage loans held for sale —
501
—
—
501
Money market mutual funds⁽²⁾
716
—
—
—
716
Debt securities:
United States government obligations 183
—
—
—
183
International government obligations —
4
—
—
4
Corporate obligations —
47
—
—
47
Municipal obligations —
2
—
—
2
Equity securities:
United States companies 300
—
—
—
300
International companies 1,622
—
—
—
1,622
Investment funds 187
—
—
—
187
$ 3,011

$ 629

$ 110

$ (35 ) $ 3,715
Liabilities:

Commodity derivatives $ (1 )
$ (168 )
$ (15 )
$ 110
$ (74 )
Interest rate derivatives —
(5 ) (1 ) —
(6 )
$ (1 ) $ (173 ) $ (16 ) $ 110
$ (80 )


	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, 2017
As of December 31, 2018
Assets:
Commodity derivatives	$	1		$	42		$	104		$	(29	)	$	118		$	1		$	91		$	108		$	(52	)	$	148
Interest rate derivatives	—			15			9			—			24			1			13			10			—			24
Mortgage loans held for sale	—			465			—			—			465			—			468			—			—			468
Money market mutual funds⁽²⁾	685			—			—			—			685			409			—			—			—			409
Debt securities:
United States government obligations	176			—			—			—			176			187			—			—			—			187
International government obligations	—			5			—			—			5			—			4			—			—			4
Corporate obligations	—			36			—			—			36			—			46			—			—			46
Municipal obligations	—			2			—			—			2			—			2			—			—			2
Agency, asset and mortgage-backed obligations																—			1			—			—			1
Equity securities:
United States companies	288			—			—			—			288			256			—			—			—			256
International companies	1,968			—			—			—			1,968			1,441			—			—			—			1,441
Investment funds	178			—			—			—			178			128			—			—			—			128
	$	3,296		$	565		$	113		$	(29	)	$	3,945		$	2,423		$	625		$	118		$	(52	)	$	3,114
Liabilities:
Commodity derivatives	$	(3	)	$	(167	)	$	(10	)	$	105		$	(75	)	$	(1	)	$	(180	)	$	(9	)	$	111		$	(79	)
Interest rate derivatives	—			(8		)	—			—			(8		)	—			(32		)	—			—			(32		)
	$	(3	)	$	(175	)	$	(10	)	$	105		$	(83	)	$	(1	)	$	(212	)	$	(9	)	$	111		$	(111	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of ~~$75~~$56 million and ~~$76~~$59 million as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017~~,2018, 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.

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. 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
	Ended September 30,						Ended September 30,						Ended March 31,
				Interest						Interest						Interest
	Commodity			Rate			Commodity			Rate			Commodity			Rate
	Derivatives			Derivatives			Derivatives			Derivatives			Derivatives			Derivatives
2018:
2019:
Beginning balance	$	83		$	17		$	94		$	9		$	99		$	10
Changes included in earnings	(1		)	54			3			140			(3		)	53
Changes in fair value recognized in OCI	1			—			1			—
Changes in fair value recognized in net regulatory assets	3			—			(11		)	—			(11		)	—
Purchases	1			—			2			—			1			—
Settlements	(3		)	(61		)	(5		)	(139		)	—			(45		)
Ending balance	$	84		$	10		$	84		$	10		$	86		$	18


2017:
2018:
Beginning balance	$	81		$	8		$	60		$	6		$	94		$	9
Changes included in earnings	7			34			19			100			—			30
Changes in fair value recognized in OCI	(1		)	—			(3		)	—			(1		)	—
Changes in fair value recognized in net regulatory assets	(3		)	—			(5		)	—			(9		)	—
Purchases	—			8			1			6			1			—
Settlements	2			(37		)	14			(99		)	(4		)	(23		)
Ending balance	$	86		$	13		$	86		$	13		$	81		$	16

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, 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



	As of March 31, 2019				As of December 31, 2018
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	37,916	$	42,154	$	36,250	$	38,874


(10)	Commitments and Contingencies

Commitments

During the ~~nine-month~~three-month period ended ~~September 30, 2018,~~March 31, 2019, PacifiCorp entered into non-cancelable agreements through ~~2045~~2020 totaling ~~$1.0 billion related to power purchase agreements to meet customer requests for renewable energy, $566~~$486 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.

During the nine-month period ended September 30, 2018, MidAmerican Energy entered into firm commitments totaling $563 million for the remainder of 2018 through 2020 related to the construction of wind-powered generating facilities.Washington.

Easements

During the ~~nine-month~~three-month period ended ~~September 30, 2018,~~March 31, 2019, MidAmerican Energy entered into non-cancelable easements with minimum payments totaling ~~$422~~$197 million through ~~2058~~2059 for land in Iowa on which some of its wind-powered generating facilities will be located.

Maintenance and Service Contracts

During the ~~nine-month~~three-month period ended ~~September 30, 2018,~~March 31, 2019, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling ~~$226~~$301 million through ~~2028.~~2029.

BHE Renewables' Counterparty Risk

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California ("PG&E Bankruptcy Filing"). The Company owns 100% of Topaz Solar Farm LLC ("Topaz") and owns a 49% interest in Agua Caliente Solar, LLC ("Agua Caliente"). Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until October 2039. As of March 31, 2019, the Company's consolidated balance sheet includes $1.1 billion of property, plant and equipment, net and $0.9 billion of non-recourse project debt related to Topaz. Agua Caliente is a 290-MW solar photovoltaic electric power generating facility located in Arizona. Agua Caliente sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until June 2039. As of March 31, 2019, the Company's equity investment in Agua Caliente totals $47 million and the project has $0.8 billion of non-recourse project debt owed to the United States Department of Energy. The PG&E Bankruptcy Filing is an event of default under the Topaz PPA ("PPA Default"). PG&E paid in full the invoices for December deliveries and all amounts invoiced to date for post-petition energy deliveries for both Topaz and Agua Caliente in 2019. PG&E has not paid for the power delivered from January 1 through January 28, 2019. The Company continues to perform on its obligations and deliver renewable energy to the PG&E Utility, and PG&E has publicly stated it will pay suppliers in full under normal terms for post-petition goods and services received. The Company maintains that, in light of the current facts and circumstances, the PPA Default could not reasonably be expected to result in a material adverse effect under the Topaz indenture and, therefore, no default has occurred under the Topaz indenture. The Company believes it is more likely than not that no impairment exists and current debt obligations will be met, as post-petition contractual revenue payments are expected to be paid by PG&E Utility to the Topaz and Agua Caliente projects. The Company will continue to monitor the situation, including continued receipt of future PG&E payments and the future risk of the PPAs being rejected or modified through the bankruptcy process.

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 climate change, renewable portfolio standards, 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 is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath ~~hydroelectric system is currently operating under annual licenses~~Hydroelectric Project. The KHSA does not guarantee dam removal. Instead, it establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of 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 license 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~~a third-party dam removal ~~should proceed, dam removal would begin no earlier than 2020.~~

Congress failed to pass legislation needed to implement the original KHSA. In April 2016, the principal parties to the KHSA (PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and Commerce) executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, in September 2016, PacifiCorp andentity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) PacifiCorp can operate the facilities for the benefit of customers until dam removal commences.

In September 2016, the KRRC and PacifiCorp filed a ~~private, independent nonprofit 501(c)(3) organization formed by certain signatories of the amended KSHA, jointly filed an~~joint application with the FERC to transfer the license for the four ~~mainstem~~main-stem Klamath ~~River hydroelectric generating facilities~~dams from PacifiCorp to the KRRC. ~~Also in September 2016,~~Over the past two years, the KRRC ~~filed an~~has been supplementing the application with additional information about its financial, technical and legal capacity to become the licensee. The KRRC is expected to provide the FERC ~~to surrender the license~~on July 29, 2019, with additional information, including updated cost estimates, and ~~decommission the same four facilities. The KRRC's license surrender application included a request for~~its insurance, bonding and liability transfer package. Based on that information, the FERC should be in a position to ~~refrain from acting on the surrender application until after the~~determine whether license transfer ~~of the license~~ to the KRRC is ~~effective. In March 2018,~~in the ~~FERC issued an order splitting~~public interest. That information should also allow PacifiCorp and 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 PacifiCorpStates to assess whether the KRRC ~~until some point in~~has the ~~future. PacifiCorp~~ability to satisfy its indemnification obligations under the KHSA, and whether there is ~~currently~~sufficient funding available under 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 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.

settlement. If certain conditions in the amended KHSA are not satisfied (e.g., inadequate funding or inability of KRRC to satisfy its indemnification obligation) and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.

The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, in January 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water quality certification authority over the Klamath hydroelectric project relicensing. This decision has the potential to limit the ability of the States to impose water quality conditions on new and relicensed projects. Environmental interests, supported by California, Oregon and other states, asked the court to rehear the case, which was denied.

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 from contracts with customers ("Customer 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																					For the Three-Month Period Ended March 31, 2019
	PacifiCorp			MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group			BHE Transmission		BHE Renewables		BHE and Other⁽¹⁾			Total		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
Retail electric																						$	1,186	$	443	$	527	$	—	$	—		$	—	$	—	$	—		$	2,156
Retail gas																						—		260		37		—		—			—		—		—			297
Wholesale⁽²⁾	(10		)	82		9		—		—			—		—		(1		)	80		28		110		18		—		—			—		—		—			156
Transmission and distribution	30			14		28		196		—			171		—		—			439		25		16		24		230		—			167		—		—			462
Interstate pipeline	—			—		—		—		283			—		—		(25		)	258		—		—		—		—		372			—		—		(37		)	335
Other	—			—		—		—		—			—		—		—			—		—		—		1		—		—			—		—		—			1
Total Regulated	1,343			826		1,052		196		283			171		—		(27		)	3,844		1,239		829		607		230		372			167		—		(37		)	3,407
Nonregulated	—			2		—		10		—			3		235		176			426		—		6		—		8		—			1		126		139			280
Total Customer Revenue	1,343			828		1,052		206		283			174		235		149			4,270		1,239		835		607		238		372			168		126		102			3,687
Other revenue⁽³⁾⁽²⁾	26			4		7		27		(24		)	—		85		24			149		20		7		7		25		(1		)	—		41		39			138
Total	$	1,369		$	832	$	1,059	$	233	$	259		$	174	$	320	$	173		$	4,419	$	1,259	$	842	$	614	$	263	$	371		$	168	$	167	$	141		$	3,825


	For the Nine-Month Period Ended September 30, 2018																				For the Three-Month Period Ended March 31, 2018
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group			BHE Transmission		BHE Renewables		BHE and Other⁽¹⁾			Total		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
Retail electric																					$	1,096	$	386	$	539	$	—	$	—	$	—	$	—	$	—		$	2,021
Retail gas																					—		246		40		—		—		—		—		—			286
Wholesale	21		262		26		—		—			—		—		(3		)	306		22		93		11		—		—		—		—		(1		)	125
Transmission and distribution	82		44		73		661		—			525		—		—			1,385		22		16		20		249		—		180		—		—			487
Interstate pipeline	—		—		—		—		893			—		—		(91		)	802		—		—		—		—		374		—		—		(41		)	333
Other	—		—		1		—		—			—		—		—			1		—		—		—		—		—		—		—		—			—
Total Regulated	3,637		2,272		2,404		661		893			525		—		(95		)	10,297		1,140		741		610		249		374		180		—		(42		)	3,252
Nonregulated	—		7		1		31		—			6		538		478			1,061		—		—		—		11		—		—		117		144			272
Total Customer Revenue	3,637		2,279		2,405		692		893			531		538		383			11,358		1,140		741		610		260		374		180		117		102			3,524
Other revenue⁽³⁾	109		18		21		65		(22		)	—		182		87			460		44		6		7		18		2		—		37		41			155
Total	$	3,746	$	2,297	$	2,426	$	757	$	871		$	531	$	720	$	470		$	11,818	$	1,184	$	747	$	617	$	278	$	376	$	180	$	154	$	143		$	3,679


(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~~Customer 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.



	HomeServices
	Three-Month Periods
	Ended March 31,
	2019		2018
Customer Revenue:
Brokerage	$	711	$	685
Franchise	14		15
Total Customer Revenue	725		700
Other revenue	60		61
Total	$	785	$	761

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,~~March 31, 2019, 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



	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	918	$	5,796	$	6,714


(12)	BHE Shareholders' Equity

~~Common Stock~~

For the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ BHE repurchased from certain family interests of Mr. Walter Scott, Jr. ~~177,381~~447,712 shares of its common stock for ~~$107~~$293 million and ~~35,000~~149,281 shares of its common stock for ~~$19~~$90 million, respectively.


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

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

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

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

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 )

~~For more information regarding the adoption of ASU 2016-01, refer to Note 5.~~



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

Balance, December 31, 2017	$	(383	)	$	(1,129	)	$	1,085		$	29		$	(398	)
Adoption of ASU 2016-01	—			—			(1,085		)	—			(1,085		)
Other comprehensive (loss) income	(3		)	73			—			(2		)	68
Balance, March 31, 2018	$	(386	)	$	(1,056	)	$	—		$	27		$	(1,415	)

Balance, December 31, 2018	$	(358	)	$	(1,623	)	$	—		$	36		$	(1,945	)
Other comprehensive (loss) income	(32		)	155			—			(8		)	115
Balance, March 31, 2019	$	(390	)	$	(1,468	)	$	—		$	28		$	(1,830	)


(14)	Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):


	Three-Month Periods				Nine-Month Periods				Three-Month Periods
	Ended September 30,				Ended September 30,				Ended March 31,
	2018		2017		2018		2017		2019		2018
Operating revenue:
PacifiCorp	$	1,369	$	1,430	$	3,746	$	3,956	$	1,259	$	1,184
MidAmerican Funding	832		815		2,297		2,170		842		747
NV Energy	1,059		1,047		2,426		2,384		614		617
Northern Powergrid	233		221		757		685		263		278
BHE Pipeline Group	259		193		871		700		371		376
BHE Transmission	174		182		531		506		168		180
BHE Renewables	320		283		720		647		167		154
HomeServices	1,218		961		3,252		2,502		785		761
BHE and Other⁽¹⁾	173		151		470		453		141		143
Total operating revenue	$	5,637	$	5,283	$	15,070	$	14,003	$	4,610	$	4,440


	Three-Month Periods					Nine-Month Periods						Three-Month Periods
	Ended September 30,					Ended September 30,						Ended March 31,
	2018			2017		2018			2017			2019			2018
Depreciation and amortization:
PacifiCorp	$	203		$	200	$	602		$	598		$	205		$	202
MidAmerican Funding	133			112		499			370			177			158
NV Energy	114			105		341			315			120			113
Northern Powergrid	62			55		189			156			63			63
BHE Pipeline Group	27			42		99			115			28			42
BHE Transmission	61			58		184			165			58			62
BHE Renewables	68			63		198			187			70			64
HomeServices	14			16		37			38			13			12
BHE and Other⁽¹⁾	(1		)	—		(2		)	(1		)	(1		)	—
Total depreciation and amortization	$	681		$	651	$	2,147		$	1,943		$	733		$	716


Operating income:
PacifiCorp	$	386		$	461		$	917		$	1,133		$	284		$	247
MidAmerican Funding	278			284			444			517			116			79
NV Energy	307			393			540			683			84			89
Northern Powergrid	102			106			360			346			129			147
BHE Pipeline Group	105			66			388			328			243			226
BHE Transmission	82			86			244			236			76			81
BHE Renewables	176			157			308			256			18			28
HomeServices	85			79			185			191			(21		)	(8		)
BHE and Other⁽¹⁾	2			8			(20		)	(38		)	(10		)	(18		)
Total operating income	1,523			1,640			3,366			3,652			919			871
Interest expense	(453		)	(464		)	(1,380		)	(1,379		)	(477		)	(466		)
Capitalized interest	17			14			44			34			16			12
Allowance for equity funds	30			24			75			59			32			21
Interest and dividend income	27			32			85			85			30			26
Gains (losses) on marketable securities, net	260			3			(336		)	8
Losses on marketable securities, net													(68		)	(209		)
Other, net	19			(17		)	50			8			35			30
Total income before income tax expense and equity income	$	1,423		$	1,232		$	1,904		$	2,467		$	487		$	285


Interest expense:
PacifiCorp	$	96	$	95	$	288	$	285	$	96	$	96
MidAmerican Funding	61		59		185		177		75		63
NV Energy	52		57		169		173		62		58
Northern Powergrid	34		34		107		98		34		37
BHE Pipeline Group	11		11		31		33		12		10
BHE Transmission	42		45		127		125		39		43
BHE Renewables	49		51		150		153		44		52
HomeServices	6		1		16		3		7		4
BHE and Other⁽¹⁾	102		111		307		332		108		103
Total interest expense	$	453	$	464	$	1,380	$	1,379	$	477	$	466


	Three-Month Periods				Nine-Month Periods				Three-Month Periods
	Ended September 30,				Ended September 30,				Ended March 31,
	2018		2017		2018		2017		2019		2018
Operating revenue by country:
United States	$	5,209	$	4,869	$	13,757	$	12,793	$	4,177	$	3,978
United Kingdom	232		221		754		685		263		277
Canada	174		182		531		506		168		180
Philippines and other	22		11		28		19		2		5
Total operating revenue by country	$	5,637	$	5,283	$	15,070	$	14,003	$	4,610	$	4,440


Income before income tax expense and equity income by country:
United States	$	1,290	$	1,113	$	1,501	$	2,065	$	336	$	118
United Kingdom	59		49		220		213		103		112
Canada	43		47		125		127		40		41
Philippines and other	31		23		58		62		8		14
Total income before income tax expense and equity income by country	$	1,423	$	1,232	$	1,904	$	2,467	$	487	$	285


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Assets:
PacifiCorp	$	23,501	$	23,086	$	24,211	$	23,478
MidAmerican Funding	19,499		18,444		20,845		20,029
NV Energy	14,078		13,903		14,105		14,119
Northern Powergrid	7,527		7,565		7,626		7,427
BHE Pipeline Group	5,285		5,134		5,579		5,511
BHE Transmission	8,863		9,009		8,567		8,424
BHE Renewables	8,590		7,687		8,654		8,666
HomeServices	2,860		2,722		3,427		2,797
BHE and Other⁽¹⁾	1,659		2,658		1,531		1,738
Total assets	$	91,862	$	90,208	$	94,545	$	92,189


(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~~three-month period ended ~~September 30, 2018~~March 31, 2019 (in millions):


												BHE Pipeline Group																													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
	PacifiCorp				NV Energy		Total				BHE Pipeline Group				BHE Transmission							HomeServices			Total			BHE Pipeline Group				MidAmerican Funding			NV Energy			Northern Powergrid					BHE Transmission			BHE Renewables			HomeServices
			MidAmerican Funding
December 31, 2017	$	1,129	$	2,102	$	2,369		Northern Powergrid		$				991			$	73	BHE Renewables			$	1,571			$	95					$	1,348
December 31, 2018																														$	1,129		$	2,102		$	2,369		$	952	$	73		$	1,448		$	95		$	1,427	$	9,595
Acquisitions																							70				70			—			—			—			—		—			—			—			23		23
Foreign currency translation								(24		)						(41		)									(65		)	—			—			—			14		—			31			—			—		45
September 30, 2018	$	1,129	$	2,102	$	2,369		$	967			$	73			$	1,530			$	95		$	1,418			$		9,683
March 31, 2019																														$	1,129		$	2,102		$	2,369		$	966	$	73		$	1,479		$	95		$	1,450	$	9,663


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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with the Company's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.

The Company's operations are organized 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~~BHE Canada (which primarily 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 investing in wind, solar, ~~wind,~~ geothermal and hydroelectric projects, the ~~second~~ largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States. 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~~First Quarter of 2019 and ~~First Nine Months of~~ 2018 ~~and 2017~~

Overview

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


	Third Quarter										First Nine Months											First Quarter
	2018		2017			Change					2018			2017			Change					2019			2018			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	270	$	263		$	7		3	%	$	603		$	618		$	(15	)	(2	)%	$	180		$	148		$	32		22	%
MidAmerican Funding	479		383			96			25		685			616			69			11		190			103			87			84
NV Energy	201		223			(22		)	(10	)	311			347			(36		)	(10	)	29			33			(4		)	(12	)
Northern Powergrid	44		39			5			13		169			174			(5		)	(3	)	80			84			(4		)	(5	)
BHE Pipeline Group	79		35			44			*		286			183			103			56		181			167			14			8
BHE Transmission	55		58			(3		)	(5	)	164			171			(7		)	(4	)	56			56			—			—
BHE Renewables	139		89			50			56		304			194			110			57		48			54			(6		)	(11	)
HomeServices	60		45			15			33		127			107			20			19		(22		)	(10		)	(12		)	*
BHE and Other	74		(67		)	141			*		(363		)	(212		)	(151		)	(71	)	(120		)	(122		)	2			2
Total net income attributable to BHE shareholders	$	1,401	$	1,068		$	333		31		$	2,286		$	2,198		$	88		4		$	622		$	513		$	109		21

* Not meaningful

Net income attributable to BHE shareholders increased ~~$333~~$109 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017 due to an after-tax~~2018. The first quarter of 2019 and 2018 included a pre-tax unrealized ~~gain~~loss of $79 million ($58 million after-tax) and $207 million ($149 million after-tax), respectively, on the Company's investment in BYD Company ~~Limited~~Limited. Excluding the impact of this item, adjusted net income attributable to BHE shareholders for the first quarter of 2019 was $680 million, an increase of $18 million compared to adjusted net income attributable to BHE shareholders in the first quarter of 2018 ~~totaling $182 million~~of $662 million.

In 2018, the Domestic Regulated Businesses began passing the benefits of lower income tax expense related to 2017 Tax Reform to customers through various regulatory mechanisms, including lower retail rates, higher depreciation expense and reductions to rate base. The increase in net income attributable to BHE shareholders was due to the ~~following factors:~~following:

PacifiCorp's net income increased $7$32 million primarily due to ~~a decrease in income tax expense~~higher utility margin of ~~$78~~$43 million ~~from a lower federal tax rate due to the impact~~and higher allowances for borrowed and equity funds used during construction of ~~the Tax Cuts and Jobs Act enacted on December 22, 2017 ("2017 Tax Reform"),~~$10 million, partially offset by ~~lower utility margin of $61 million and~~ higher operations and maintenance expense of ~~$12~~$6 million and higher depreciation and amortization expense of $3 million. Utility margin ~~decreased~~increased due to ~~lower~~higher retail customer volumes, higher average retail rates ~~including the impact~~and higher net deferrals of ~~a lower federal tax rate due to 2017 Tax Reform of $53 million,~~incurred net power costs in accordance with established adjustment mechanisms, partially offset by higher natural gas ~~costs, higher purchased electricity~~and coal costs and lower wholesale ~~revenue, partially offset by higher retail customer volumes and lower coal costs.~~revenue. Retail customer volumes increased ~~1.8%~~4.3% due to ~~higher customer usage, primarily from industrial, commercial and residential customers in Utah, and~~the favorable impact of weather, an increase in the average number of customers ~~across the service territory, offset by impacts of weather across the service territory.~~and higher customer usage.

MidAmerican Funding's net income increased ~~$96~~$87 million primarily due to ahigher electric utility margin of $67 million, higher income tax benefit of ~~$95~~$44 million ~~from~~driven by a ~~$53~~$38 million increase in recognized production tax credits, ~~and a lower federal tax rate~~$30 million of which was due to a change in the ~~impact~~method of ~~2017 Tax Reform,~~interim recognition, higher ~~electric utility margin~~income from corporate-owned life insurance policies of ~~$10~~$9 million, ~~and~~ higher allowances for borrowed and equity funds of $7 million partially offset by higher depreciation and amortization of $22 million from additional plant in-service and increases for Iowa revenue sharing. Electric utility margin increased due to higher retail customer volumes of 5.9%, primarily from industrial growth and the favorable impact of weather, higher electric wholesale revenue and higher 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 coal costs. Retail customer volumes decreased 0.9% due to the unfavorable impact of weather across the service territory and lower customer usage, primarily from industrial customers in Oregon and Utah, partially offset by higher commercial and irrigation customer usage in Utah, and an increase in the average number of customers across the service territory.

MidAmerican Funding's net income increased $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 $84 million, higher allowances for borrowed and equity funds of $19 million and higher natural gas utility margin of ~~$12~~$6 million, partially offset by higher depreciation and amortization of ~~$130~~$19 million, ~~from increases for Iowa revenue sharing~~higher operations and ~~additional plant in-service, higher wind-powered generation~~ maintenance expense of $17 million and higher ~~fossil-fueled generation maintenance~~interest expense of $12 ~~million and increases in other operations and maintenance expenses.~~million. Electric utility margin increased due to higher recoveries through bill riders, higher retail customer volumes of ~~6.9%~~4.7%, primarily from industrial growth and the favorable impact of weather, and higher 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 generation and purchased power costs.~~rates.

NV Energy's net income decreased ~~$36~~$4 million primarily due to ~~an increase in operations and maintenance expense~~lower electric utility margin of ~~$77~~$7 million ~~primarily~~ due to ~~earnings sharing of $42 million established in~~lower rates from a tax rate reduction rider effective April 1, 2018 ~~as part of~~and the Nevada Power 2017 regulatory rate review and higher political activity expenses, a decrease in electric utility margin of $38 million and an increase in 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,effective February 1, 2018, partially offset by higher retail customer volumes ~~of 1.1%, mainly~~and higher transmission revenue. Retail customer volumes increased 3.9% primarily due to the favorable ~~impact~~impacts of weather.

Northern Powergrid's net income decreased $5$4 million primarily due to ~~$22 million of~~ higher distribution-related operating and depreciation expenses of $8 million 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 ~~weaker~~stronger United States dollar of ~~$11~~$5 million, ~~higher distribution revenue of $10 million and higher smart meter net income of $3 million reflecting growth in that business. Distribution revenue increased mainly due to higher tariff rates,~~ partially offset by ~~unfavorable movements in regulatory provisions.~~lower overall pension expense of $6 million and lower income tax expense of $5 million.

BHE Pipeline Group's net income increased ~~$103~~$14 million primarily due to higher transportation revenue of ~~$102~~$20 million at Northern Natural Gas, and Kern River from higher volumes and rates due to unique market opportunities and colder temperatures and a decrease in income tax expense of $30 million from a lower federal tax rate due to the impact of 2017 Tax Reform, partially offset by ~~$49 million of~~ higher operations and maintenance expense ~~primarily~~of $3 million due to increased pipeline integrity ~~projects at Northern Natural Gas.~~projects.

BHE ~~Transmission's~~Renewables' net income decreased $7$6 million primarily due to lower solar earnings of $9 million due to lower insolation and a settlement received in 2018 related to Solar Star transformer issues in 2016 and lower earnings at CalEnergy Philippines of $4 million due to lower rainfall and financial asset balance, partially offset by higher wind earnings of $6 million due to new wind-powered generation offset by lower earnings from tax equity investments of $4 million and unfavorable changes in the valuations of interest rate swaps. Earnings from tax equity investments were unfavorable due to $13 million of higher equity losses from existing tax equity investments and $5 million of lower commitment fee income from new tax equity investments, partially offset by $12 million of favorable earnings from tax equity investments reaching commercial operation.

HomeServices' net loss increased $12 million primarily due to lower earnings at ~~BHE U.S. Transmission~~existing brokerage businesses largely from lower ~~equity earnings at Electric Transmission Texas, LLC due to the impacts of a regulatory rate order in March 2017.~~closed units, partially offset by lower operating expenses.

BHE ~~Renewables'~~and Other's net ~~income increased $110~~loss decreased $2 million primarily due to ~~$59 million of increased revenue from overall higher generation and pricing at existing projects, $20 million of net~~ income ~~from additional wind and solar capacity placed in-service, favorable earnings of $16 million from~~ tax equity investments, largely due to 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 premiums paid in 2017 due to early debt retirements and a settlement of $7 million receivedbenefits recognized in 2018 related to ~~transformer issues in 2016, partially offset by an unfavorable derivative valuation movement of $13 million.~~

HomeServices' net income increased $20 million primarily due to 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 margin and higher operating expenses at existing businesses and higher interest expense from increased borrowings related to acquisitions.

BHE and Other net loss increased $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~~the accrued repatriation tax on undistributed foreign earnings, lower federal income tax credits recognized on a consolidated ~~basis.~~basis and higher other operating expenses, partially offset by the change in the after-tax unrealized loss on the Company's investment in BYD Company Limited of $91 million and higher investment earnings.

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									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Operating revenue:
PacifiCorp	$	1,369	$	1,430	$	(61	)	(4	)%	$	3,746	$	3,956	$	(210	)	(5	)%	$	1,259	$	1,184	$	75		6	%
MidAmerican Funding	832		815		17			2		2,297		2,170		127			6		842		747		95			13
NV Energy	1,059		1,047		12			1		2,426		2,384		42			2		614		617		(3		)	—
Northern Powergrid	233		221		12			5		757		685		72			11		263		278		(15		)	(5	)
BHE Pipeline Group	259		193		66			34		871		700		171			24		371		376		(5		)	(1	)
BHE Transmission	174		182		(8		)	(4	)	531		506		25			5		168		180		(12		)	(7	)
BHE Renewables	320		283		37			13		720		647		73			11		167		154		13			8
HomeServices	1,218		961		257			27		3,252		2,502		750			30		785		761		24			3
BHE and Other	173		151		22			15		470		453		17			4		141		143		(2		)	(1	)
Total operating revenue	$	5,637	$	5,283	$	354		7		$	15,070	$	14,003	$	1,067		8		$	4,610	$	4,440	$	170		4


Operating income:
PacifiCorp	$	386	$	461	$	(75	)	(16	)%	$	917		$	1,133		$	(216	)	(19	)%	$	284		$	247		$	37		15	%
MidAmerican Funding	278		284		(6		)	(2	)	444			517			(73		)	(14	)	116			79			37			47
NV Energy	307		393		(86		)	(22	)	540			683			(143		)	(21	)	84			89			(5		)	(6	)
Northern Powergrid	102		106		(4		)	(4	)	360			346			14			4		129			147			(18		)	(12	)
BHE Pipeline Group	105		66		39			59		388			328			60			18		243			226			17			8
BHE Transmission	82		86		(4		)	(5	)	244			236			8			3		76			81			(5		)	(6	)
BHE Renewables	176		157		19			12		308			256			52			20		18			28			(10		)	(36	)
HomeServices	85		79		6			8		185			191			(6		)	(3	)	(21		)	(8		)	(13		)	*
BHE and Other	2		8		(6		)	(75)		(20		)	(38		)	18			47		(10		)	(18		)	8			44
Total operating income	$	1,523	$	1,640	$	(117	)	(7	)	$	3,366		$	3,652		$	(286	)	(8	)	$	919		$	871		$	48		6

PacifiCorp

Operating revenue ~~decreased $61~~increased $75 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 due to ~~lower~~higher retail revenue of ~~$40~~$95 million, ~~and~~partially offset by lower wholesale and other revenue of ~~$21 million. Retail revenue decreased $59~~$20 million due to lower wholesale volumes and average ~~rates, including the impact of a lower federal tax rate~~prices. Retail revenue increased due to higher customer volumes of $56 million and higher average retail rates of $39 million due to lower net tax deferrals associated with the 2017 Tax Reform ~~of $53 million, partially offset by $19 million from higher volumes.~~and product mix. Retail customer volumes increased ~~1.8%~~4.3% due to ~~higher usage, primarily from industrial, commercial and residential customers in Utah, and~~the favorable impact of weather, an increase in the average number of residential and commercial customers across the service territory, ~~offset by impacts of weather across the service territory. Wholesale~~higher industrial usage in Wyoming and ~~other revenue decreased primarily due to lower wholesale market prices,~~Washington, higher residential and commercial usage in Utah and higher commercial usage in Oregon, partially offset by ~~higher wholesale sales volumes.~~lower industrial usage in Idaho and Utah and lower commercial usage in Washington and Idaho.

Operating income ~~decreased $75~~increased $37 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~lower~~higher utility margin of ~~$61~~$43 million, ~~and~~partially offset by higher operations and maintenance expense of ~~$12~~$6 million and higher depreciation and amortization of $3 million. Utility margin ~~decreased~~increased due to ~~lower~~higher retail customer volumes, higher average retail rates ~~including the impact of a lower federal tax rate due to 2017 Tax Reform of $53 million, higher natural gas costs from higher generation volumes, higher purchased electricity costs from higher prices~~ and ~~volumes and lower wholesale revenue, partially offset by~~ higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by higher ~~retail customer volumes~~natural gas and ~~lower~~ coal costs largely from ~~favorable prices.~~higher volumes and lower wholesale revenue.

Operating revenue decreased $210 million for the first nine months of 2018 compared to 2017 due to lower 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 and higher natural gas costs from higher generation volumes offset by lower prices, partially offset by higher net deferrals of incurred net power costs and lower coal costs from lower generation volumes and prices.

MidAmerican Funding

Operating revenue increased ~~$17~~$95 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to higher electric operating revenue of $20 million. Electric operating revenue increased due to higher wholesale and other revenue of $18 million and higher retail revenue of $2 million. Electric wholesale and other revenue increased primarily due to an increase in wholesale volumes of $17 million. Electric retail revenue increased $29 million from industrial growth and higher customer usage, $4 million from higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense) and $2 million from the impact of weather in 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 5.9% primarily from industrial growth and the favorable impact of weather.

Operating income decreased $6 million for the third quarter of 2018 compared to 2017 primarily due to higher depreciation and amortization of $22 million and higher wind-powered generation maintenance of $6 million, partially offset by higher electric utility margin of $10 million, net of a decrease in electric demand-side management program revenue of $2 million (offset in operations and maintenance expense), higher natural gas utility margin of $4 million and decreases in other operations and maintenance expenses. 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 due to higher retail customer volumes, higher wholesale revenue and higher recoveries through bill riders, partially offset by lower average retail rates, higher generation and purchased power costs and lower transmission revenue. Natural gas utility margin increased due to higher retail sales volumes, partially offset by lower average rates from the impact of a lower federal tax rate due to 2017 Tax Reform.

~~Operating revenue increased $127 million for the first nine months of 2018 compared to 2017 primarily due to higher electric operating revenue of $108~~$73 million and higher natural gas ~~operating~~ revenue of $20 million. Electric operating revenue increased due to higher retail revenue of ~~$96~~$55 million and higher wholesale and other revenue of ~~$12~~$18 million. Electric retail revenue increased ~~$91~~$38 million from higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense), ~~$58~~$21 million from industrial growth and higher customer usage ~~including higher industrial sales volumes,~~ and ~~$33~~$5 million from the impact of weather in ~~2018,~~2019, partially offset by lower average rates of ~~$86 million predominantly from~~$9 million. The increase in recoveries through bill rider is substantially due to the energy adjustment clause and a favorable outcome in 2018 of the ratemaking treatment for the impact of ~~a lower federal tax rate due to~~ 2017 Tax Reform. Electric retail customer volumes increased ~~6.9%~~4.7% primarily from industrial growth and the favorable impact of weather. Electric wholesale and other revenue increased $18 million due to ~~higher average per-unit prices of $7 million and~~ a ~~0.2% growth~~27.7% increase in ~~sales~~wholesale volumes. Natural gas operating revenue increased primarily due to ~~22.3%~~9.2% higher retail sales volumes from the impact of weather in ~~2018~~2019 and industrial growth ~~partially offset by~~and a ~~lower average per-unit price~~favorable outcome in 2018 of ~~$27 million (offset in cost of gas purchased~~the ratemaking treatment for ~~resale and other) and other usage and rate factors, including the impact of a lower federal tax rate due to~~ 2017 Tax Reform.

Operating income ~~decreased $73~~increased $37 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to higher depreciation and amortization of $130 million, 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~~$67 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~~$6 million, partially offset by higher depreciation and amortization ~~reflects increases for Iowa revenue sharing~~ of ~~$83~~$19 million ~~and $47 million related to additional~~from new wind generation and other plant ~~placed in-service.~~additions and higher operations and maintenance expense of $17 million primarily due to increased wind-powered generation costs and higher emergency outage and tree-trimming costs. 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.~~rates. Natural gas utility margin increased due to higher retail sales volumes ~~from colder temperatures, partially offset by lower average rates partially from~~and the ~~impact~~favorable outcome in 2018 of ~~a lower federal tax rate due to~~the ratemaking treatment for 2017 Tax Reform.

NV Energy

Operating revenue ~~increased $12~~decreased $3 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~higher electric~~lower natural gas operating revenue of ~~$12 million. Electric operating revenue increased due to higher electric retail revenue of $6~~$4 million, and 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 volumes of $18 million, primarily due to the impacts of weather, and customer growth of $6 million, partially offset by a decrease from the impact of a lower federal tax rate due to 2017 Tax Reform of $30 million and lower rates from the Nevada Power 2017 regulatory rate review of $16 million. Electric retail customer volumes, including distribution only service customers, increased 4.7% compared to 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~~$2 million. ~~Energy costs increased due to higher purchased power costs of $29 million.~~

Operating revenue increased $42 million for the first nine months of 2018 compared to 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 wholesale and other revenue of $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 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~~decreased due to a ~~higher~~lower average per-unit price (offset in cost of natural gas purchased for resale) of ~~$10~~$7 million, partially offset by 14.9% higher customer volumes. Electric operating revenue increased due to higher wholesale and other revenue of $12 million, primarily due to increases in wholesale revenue of $7 million and transmission revenue of $3 million, partially offset by lower ~~volumes.~~

~~Operating income~~electric retail revenue of $10 million. Electric retail revenue 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~~the tax rate reduction rider effective April 1, 2018 of ~~$42~~$17 million, ~~established in 2018 as part of~~lower rates from the Nevada Power 2017 regulatory rate review effective February 1, 2018 of $3 million and lower energy rates (offset in cost of fuel and energy) of $2 million, partially offset by higher ~~political activity expenses, a decrease in~~customer volumes of $10 million. Electric retail customer volumes, including distribution only service customers, increased 3.9% compared to the first quarter of 2018 primarily due to the impacts of weather.

Operating income decreased $5 million for the first quarter of 2019 compared to 2018 primarily due to lower electric 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.~~$7 million. Electric utility margin decreased as higher energy costs of ~~$72~~$9 million were offset by higher electric operating revenue of ~~$34~~$2 million. Energy costs increased due to a higher ~~net deferred power costs~~average cost of ~~$103~~fuel for generation of $45 million and higher purchased power costs of ~~$21~~$17 million, partially offset by a lower ~~average cost of fuel for generation~~net deferred power costs of $53 million.

Northern Powergrid

Operating revenue ~~increased $12~~decreased $15 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to the stronger United States dollar of $18 million and lower distributed units of $13 million, partially offset by higher distribution tariff rates of $10 million and higher smart meter revenue of $8$5 million from ~~additional~~increased smart meter ~~assets placed in-service and higher distribution revenue of $6 million mainly due to higher tariff rates.~~asset additions. Operating income decreased $4$18 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to the stronger United States dollar of $9 million, higher distribution-related operations and maintenance expense and higher depreciation expense related to additional distribution network and smart meter ~~and distribution assets placed in-service, partially offset by the increase in operating revenue.~~

Operating revenue increased $72 million for the first nine months of 2018 compared to 2017 primarily due to the weaker United States dollar of $45 million, higher smart meter revenue of $21 million from additional smart meter assets placed in-service and higher distribution revenue of $11 million. Distribution revenue increased mainly due to higher tariff rates of $17 million, partially offset by unfavorable movements in regulatory provisions of $5 million. Operating income increased $14 million for the first nine months of 2018 compared to 2017 primarily due to the increase in operating revenue and the weaker United States dollar of $24 million, partially offset by higher distribution-related operations and maintenance expense and higher depreciation expense related to additional smart meter and distribution assets placed in-service.investments.

BHE Pipeline Group

Operating revenue ~~increased $66~~decreased $5 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~higher~~lower transportation ~~revenues of $58 million~~revenue at ~~Northern Natural Gas and~~ Kern River ~~from higher volumes~~related to the impact of period two rates for the 2003 expansion group of $19 million (largely offset in depreciation and ~~rates due to unique market opportunities~~amortization) and ~~higher~~lower gas sales of ~~$10~~$14 million related to system balancing activities at Northern Natural Gas (largely offset in cost of sales), partially offset by higher transportation revenue of $20 million at Northern Natural Gas. Operating income increased ~~$39~~$17 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to the ~~increase in~~higher transportation revenue ~~and lower depreciation expense~~ at ~~Kern River,~~Northern Natural Gas, partially offset by higher operations and maintenance expense ~~primarily~~of $3 million due to increased pipeline integrity ~~projects at Northern Natural Gas.~~projects.

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 Transmission

Operating revenue decreased $8$12 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~lower operating revenue at AltaLink from a~~the stronger United States dollar of $9 million and ~~the release~~$4 million from recovery of ~~contingent liabilities in 2017, partially offset by additional assets placed in-service and higher non-regulated revenue.~~lower costs. Operating income decreased $4$5 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to the ~~lower operating revenue, partially offset by lower non-regulated operating costs at AltaLink.~~

~~Operating revenue increased $25 million for the first nine months of 2018 compared to 2017 primarily due to higher operating revenue at AltaLink from a weaker~~stronger United States dollar ~~additional assets placed in-service and higher non-regulated revenue, partially offset by the release~~ of contingent liabilities in 2017. Operating income increased $8 million for the first nine months of 2018 compared to 2017 primarily due to the higher operating revenue from additional assets placed in-service.$4 million.

BHE Renewables

Operating revenue increased ~~$37~~$13 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~overall~~ higher ~~generation and favorable pricing~~wind revenues of ~~$35~~$17 million ~~at existing~~largely from new projects and ~~$10~~higher geothermal revenues of $6 million ~~from additional solar and wind capacity placed in-service,~~due to higher pricing, partially offset by ~~an unfavorable derivative valuation movement~~lower solar revenues of ~~$8 million.~~$7 million due to lower insolation and lower hydro revenues of $3 million due to lower rainfall. Operating income ~~increased $19~~decreased $10 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to higher costs related to new wind-powered generation of $12 million, the lower solar and hydro revenues and higher geothermal maintenance costs of $6 million primarily due to the ~~increase in operating revenue,~~timing of overhauls, partially offset by ~~higher operations and maintenance expense of $14 million and higher depreciation expense of $6 million, primarily related to additional solar and wind capacity placed in-service.~~

~~Operating revenue increased $73 million for~~ the ~~first nine months of 2018 compared to 2017 due to overall~~ higher ~~generation and pricing of $59 million at existing projects and $27 million from additional~~ wind and solar capacity placed 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 of $14 million and higher depreciation expense of $11 million, primarily related to additional solar and wind capacity placed in-service.geothermal revenues.

HomeServices

Operating revenue increased ~~$257~~$24 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to an increase from acquired businesses of ~~$273 million. Operating income increased $6~~$80 million, ~~for the third quarter of 2018 compared to 2017 primarily due to higher earnings from acquired businesses of $21 million,~~partially offset by lower brokerage ~~segment earnings~~revenue at existing businesses of ~~$10~~$53 million ~~mainly due to lower margin and higher operating expenses.~~

largely from an 11% decrease in closed units. Operating ~~revenue~~loss increased ~~$750~~$13 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017 due to an increase from acquired businesses of $769 million. Operating income decreased $6 million for the first nine months of~~ 2018 ~~compared to 2017~~ primarily due to lower ~~brokerage segment~~ earnings at existing brokerage businesses ~~of $30 million, mainly~~primarily due to lower ~~margin and higher operating expenses, and a gain on the collection of receivables in 2017 in the franchise segment,~~closed units, partially offset by ~~higher earnings from acquired businesses of $47 million.~~lower operating expenses.

BHE and Other

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

~~Operating revenue increased $17~~$2 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~higher~~lower electricity ~~and natural gas~~ volumes at MidAmerican Energy Services, LLC. Operating loss ~~improved $18~~decreased $8 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 due to ~~higher margin at MidAmerican Energy Services, LLC and~~ lower other operating ~~costs.~~expenses.

Consolidated Other Income and Expense Items

Interest expense

Interest expense is summarized as follows (in millions):


	Third Quarter									First Nine Months									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change

Subsidiary debt	$	347	$	354	$	(7	)	(2	)%	$	1,062	$	1,045	$	17		2	%	$	368	$	360	$	8	2	%
BHE senior debt and other	105		106		(1		)	(1	)	314		317		(3		)	(1	)	108		105		3		3
BHE junior subordinated debentures	1		4		(3		)	(75	)	4		17		(13		)	(76	)	1		1		—		—
Total interest expense	$	453	$	464	$	(11	)	(2	)	$	1,380	$	1,379	$	1		—		$	477	$	466	$	11	2

Interest expense ~~decreased~~increased $11 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~repayments of~~debt issuances at BHE, ~~junior subordinated debentures of $944 million in 2017,~~MidAmerican Energy, BHE Pipeline Group and HomeServices, partially offset by scheduled maturities and principal payments and ~~early redemptions~~$4 million from the impact of ~~subsidiary debt, partially offset by debt issuances at BHE, MidAmerican Funding, BHE Renewables and HomeServices.~~foreign currency exchange rate movements.

Capitalized interest

Capitalized interest increased ~~$3 million for the third quarter of 2018 compared to 2017 and $10~~$4 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to higher construction work-in-progress balances at PacifiCorp and MidAmerican ~~Energy and BHE Renewables.~~Energy.

Allowance for equity funds

Allowance for equity funds increased ~~$6 million for the third quarter of 2018 compared to 2017 and $16~~$11 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to higher construction work-in-progress balances at PacifiCorp and MidAmerican Energy.

Interest and dividend income

Interest and dividend income ~~decreased $5~~increased $4 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~lower financial asset income from the~~higher cash balances at PacifiCorp, MidAmerican Energy and NV Energy, partially offset by a lower financial asset balance at ~~BHE Renewables and~~ the ~~timing of dividends from the Company's investment in BYD Company Limited.~~

Casecnan project.

~~Gains (losses)~~Losses on marketable securities, net

~~Gains (losses)~~Losses on marketable securities, net ~~increased $257~~decreased $141 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to anthe change in the unrealized ~~gain~~loss on the Company's investment in BYD Company Limited ~~totaling $252~~of $128 million. The Company had losses on marketable securities for the first nine months of 2018 of $336 million compared to gains on marketable securities in 2017 of $8 million primarily due to an unrealized loss in 2018 on the Company's investment in BYD Company Limited totaling $346 million in the first nine months of 2018.

Other, net

Other, net was income of $19 million for the third quarter of 2018 compared to 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 and 2018 at Northern Powergrid.

~~Other, net~~ increased ~~$42~~$5 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due ~~to costs incurred in 2017 associated with the early redemption of subsidiary long-term debt, favorable changes in the valuations of interest rate swap derivatives of $8~~higher investment earnings, partially offset by a $7 million ~~and a~~ settlement received in 2018 related to transformer related outages at the Solar Star projects in ~~2016.~~2016, unfavorable changes of $6 million in the valuations of interest rate swap derivatives and $5 million of lower commitment fee income from new tax equity investments.

Income tax ~~expense (benefit)~~benefit

Income tax ~~expense~~benefit decreased ~~$161~~$73 million, for the third quarter of 2018 compared to 2017 and the effective tax rate was 2% for 2018 and 15% 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, the favorable impacts of ratemaking and higher production tax credits recognized of $35 million, partially offset by income tax expense of $70including $37 million related to ~~an unrealized gain on~~ the ~~Company's investment~~change 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~~Limited, for the first ~~nine months~~quarter of ~~2017,~~2019 compared to 2018 and the ~~Company had an income~~effective tax ~~expense~~rate was (30)% for the first quarter of ~~$319 million.~~2019 and (78)% for the first quarter of 2018. The effective tax rate ~~was (19)% for 2018 and 13% for 2017. The effective tax rate decreased~~increased primarily due to ~~the reduction~~benefits recognized in ~~the United States federal corporate income tax rate from 35%~~2018 of $31 million related to ~~21%, effective January 1, 2018, lower consolidated state income tax expense, including a reduction to the state provision~~foreign earnings and $25 million for the accrued repatriation tax ~~of $45 million,~~on undistributed foreign earnings, partially offset by higher production tax credits recognized of ~~$97~~$22 million ~~lower United States income tax on foreign earnings~~ and the favorable impacts of ~~rate making.~~ratemaking of $8 million.

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 ~~2018~~2019 were ~~$529~~$137 million, or ~~$97~~$22 million higher than ~~2017,~~2018, while production tax credits earned in ~~2018~~2019 were ~~$413~~$186 million, or ~~$67~~$27 million higher than ~~2017.~~2018. The difference between production tax credits recognized and earned of ~~$116~~$49 million as of ~~September 30, 2018, primarily at MidAmerican Energy,~~March 31, 2019 will be reflected in earnings over the remainder of ~~2018.~~2019.

Equity (loss) income

~~Equity income decreased $21 million for the third quarter~~The Company had equity losses of ~~2018 compared to 2017 and $45~~$10 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~equity income of $12 million for the first quarter of 2018 primarily due to ~~lower~~higher pre-tax equity ~~earnings~~losses from tax equity investments at BHE ~~Renewables and lower equity earnings at Electric Transmission Texas, LLC due to the impacts of new retail rates effective March 2017.~~Renewables.

~~Net income attributable to noncontrolling interests~~

Net income attributable to noncontrolling interests decreased $2 million for the third quarter of 2018 compared to 2017 and $11 million for the first nine months of 2018 compared to 2017 primarily due to the April 2018 purchase of a redeemable noncontrolling interest at 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 1716 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, ~~2017~~2018 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of ~~September 30, 2018~~March 31, 2019, the Company's total net liquidity was as follows (in millions):


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

Cash and cash equivalents	$	92		$	308		$	115		$	148		$	36		$	59		$	258		$	1,016		$	65		$	669		$	433		$	131		$	31		$	53		$	279		$	1,661

Credit facilities⁽¹⁾⁽²⁾	3,500			1,200			909			650			202			1,026			1,635			9,122			3,500			1,200			909			650			221			655			1,635			8,770
Less:
Short-term debt	(508		)	—			—			—			(43		)	(380		)	(853		)	(1,784		)	(912		)	—			—			—			(103		)	(239		)	(960		)	(2,214		)
Tax-exempt bond support and letters of credit	—			(89		)	(370		)	(80		)	—			(5		)	—			(544		)	—			(256		)	(370		)	(80		)	—			(5		)	—			(711		)
Net credit facilities	2,992			1,111			539			570			159			641			782			6,794			2,588			944			539			570			118			411			675			5,845

Total net liquidity	$	3,084		$	1,419		$	654		$	718		$	195		$	700		$	1,040		$	7,810		$	2,653		$	1,613		$	972		$	701		$	149		$	464		$	954		$	7,506
Credit facilities:
Maturity dates⁽¹⁾	2021			2021			2019, 2021			2021			2020			2018, 2022			2018, 2019, 2022						2021			2021			2019, 2021			2021			2020			2023			2019, 2020, 2022


⁽¹⁾	Refer to Note 65 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$25 million at Northern Powergrid.

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$5.0~~$1.49 billion and ~~$5.1~~$1.48 billion, respectively. The ~~decrease~~increase was primarily due to ~~a reduction in income tax receipts,~~improved operating results, 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 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 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 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 the published rate in 2017, at 60% of the published rate in 2018, and 40% of 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). The Company's cash flows from operations are expected to benefit from PATH due to bonus depreciation on qualifying assets 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 Company believes property acquired on or before September 27, 2017 will remain subject to PATH.

Investing Activities

Net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$(4.5)~~$(1.4) billion and ~~$(4.4)~~$(1.2) billion, respectively. The change was primarily due to higher capital expenditures of ~~$1.0 billion,~~$318 million, partially offset by lower ~~cash paid for acquisitions, net~~funding of ~~cash acquired, of $997 million.~~tax equity investments. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

~~Acquisitions~~

Financing Activities

Net cash flows from financing activities for the ~~nine-month~~three-month period ended ~~September 30, 2018~~March 31, 2019 was ~~$(392)~~$900 million. Sources of cash totaled $2.9 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled ~~$5.9~~$2.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.4 billion, 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~~$311 million and ~~the purchase of redeemable noncontrolling interest of $131~~common stock repurchases totaling $293 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 65 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~~three-month period ended ~~September 30, 2017~~March 31, 2018 was ~~$(330)~~$336 million. Sources of cash totaled $2.8 billion and consisted of proceeds from BHE senior debt issuances totaling $2.2 billion and proceeds from subsidiary debt issuances totaling $687 million. Uses of cash totaled ~~$2.3~~$2.5 billion and consisted mainly of net repayments of ~~BHE senior~~short-term debt ~~and junior subordinated debentures~~ totaling ~~$1.3~~$1.9 billion and repayments of subsidiary debt totaling ~~$834~~$550 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.~~

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 regulatory approvals, 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; 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		Three-Month Periods				Annual
	Ended September 30,				Forecast		Ended March 31,				Forecast
	2017		2018		2018		2018		2019		2019
Capital expenditures by business:
PacifiCorp	$	553	$	713	$	1,198	$	236	$	337	$	2,268
MidAmerican Funding	1,165		1,466		2,365		365		573		2,629
NV Energy	333		342		545		109		165		729
Northern Powergrid	434		446		535		170		126		583
BHE Pipeline Group	174		251		480		53		72		756
BHE Transmission	255		203		269		71		61		247
BHE Renewables	239		741		868		59		46		122
HomeServices	18		34		49		11		10		49
BHE and Other	8		7		11		1		3		10
Total	$	3,179	$	4,203	$	6,320	$	1,075	$	1,393	$	7,393


Capital expenditures by type:
Wind generation	$	804	$	1,696	$	2,658	$	107	$	255	$	2,502
Electric transmission	267		118		194		21		97		675
Other growth	495		504		706		149		113		748
Operating	1,613		1,885		2,762		798		928		3,468
Total	$	3,179	$	4,203	$	6,320	$	1,075	$	1,393	$	7,393

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

•Wind generation includes the following:

◦

Construction of wind-powered generating facilities at MidAmerican Energy totaling ~~$704~~$159 million and ~~$455~~$16 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. MidAmerican Energy anticipates costs for wind-powered generating facilities will total an additional ~~$550~~$1,237 million for ~~2018. In August 2016, the IUB issued an order approving ratemaking principles related~~2019. MidAmerican Energy has approval to ~~MidAmerican Energy's construction of~~construct up to ~~2,000~~2,591 MW (nominal ratings) of wind-powered generating facilities expected to be placed in-service in 2017 through ~~2019,~~2020, including ~~334~~1,151 MW (nominal ratings) placed in-service ~~in 2017. The ratemaking principles establish a cost cap~~as 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 in effect prior to 2018. The revised sharing mechanism, which was effective January 1, 2018, will be triggered each year by actual equity returns exceeding a weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases.March 31, 2019. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of production tax credits available.

◦

Repowering certain existing wind-powered generating facilities at MidAmerican Energy totaling $27 million and $70 million for the three-month periods ended March 31, 2019 and 2018. The repowering projects entail the replacement of significant components of older turbines. MidAmerican Energy anticipate costs for these activities will total an additional $106 million for 2019. Of the 1,479 MWs of current repowering projects not in-service as of March 31, 2019, 303 MWs are currently expected to qualify for 100% of the federal production tax credits available for ten years following each facility's return to service, 769 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.


◦	The energy production from such repowered facilities is expected to qualify for federal production tax credits available for ten years following each facility's return to service.

◦

Construction of wind-powered generating facilities at PacifiCorp totaling $5$55 million and $4$1 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. PacifiCorp anticipates costs for these activities will total an additional ~~$62~~$311 million for ~~2018.~~2019. 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~~$4 million and ~~$276~~$1 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively. PacifiCorp ~~and MidAmerican Energy~~ anticipate costs for these activities will total an additional ~~$297~~$592 million for ~~2018.~~2019. 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.

◦

Construction of wind-powered generating facilities at BHE Renewables totaling ~~$684~~$11 million and ~~$69~~$18 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ 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 will total an additional $51 million in 2018 for development and construction of up to 212 MW of wind-powered generating facilities.

Electric transmission includes PacifiCorp's costs ~~associated with main grid reinforcement and~~for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission ~~Expansion Program,~~expansion program expected to be placed in service in 2020, 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.

Other growth includes ~~investments in solar generation for the construction of 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.~~connections and investments in solar generation.

Operating includes ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, investments in routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand and environmental spending relating to emissions control equipment and the management of coal combustion residuals.

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 $698 million, $403 million and $584 million in 2018, 2017 and ~~$170 million in 2017,~~ 2016, ~~and 2015,~~ respectively. Additionally, the Company has ~~made contributions of $252 million through September 30, 2018, and has~~ commitments as of ~~September 30, 2018,~~March 31, 2019, subject to satisfaction of certain specified conditions, to provide equity contributions of ~~$540~~$1,033 million for the remainder of ~~2018~~2019 and ~~$348~~$350 million in ~~2019~~2020 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, 2018~~March 31, 2019, 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, ~~2017~~2018 other than the recent financing transactions and the renewable tax equity investments previously discussed.

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, 2018, and new regulatory matters occurring in 2019.

PacifiCorp

During 2018, the PacifiCorp Retirement Plan incurred a settlement charge of $22 million as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018. In December 2018, PacifiCorp submitted filings with the UPSC, the OPUC, the WPSC and the WUTC seeking approval to recover the settlement charge. Also in December 2018, an advice letter was filed with the CPUC requesting a memo account to record the costs associated with pension and postretirement settlements and curtailments. In April 2019, WUTC approved PacifiCorp's request.

2017 Tax Reform

2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the United States federal corporate income tax rate from 35% to 21%. In 2018, PacifiCorp agreed to refund or defer the impact of the tax law change with each of its state regulatory commissions. The status of the remaining 2017 Tax Reform proceedings are noted in the applicable state section below.

Utah

In March 2018, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover $3 million, or 0.1%, in deferred net power costs from customers for the period January 1, 2017 through December 31, 2017, reflecting the difference between base and actual net power costs in the 2017 deferral period. The rate change was approved by the UPSC effective May 1, 2018 on an interim basis. A hearing was held in February 2019, and final approval was issued March 2019.

In March 2019, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover $24 million, or 1.1%, in deferred net power costs from customers for the period January 1, 2018 through December 31, 2018, reflecting the difference between base and actual net power costs in the 2018 deferral period. The rate change was approved by the UPSC effective May 1, 2019 on an interim basis, and the hearing on final approval is scheduled for February 2020.

Oregon

In December 2018, PacifiCorp proposed to reduce customer rates to reflect the lower annual current income tax expense in Oregon resulting from 2017 Tax Reform. PacifiCorp reached an all-party settlement on the amortization of the current income tax expense benefits and the deferral of the decision regarding the ratemaking treatment of excess deferred income tax balances until PacifiCorp's next general rate proceeding. The settlement, which results in a rate reduction of $48 million, or 3.7%, effective February 1, 2019, was approved by the OPUC in January 2019.

In December 2018, PacifiCorp filed an application requesting recovery of $37 million, or a 2.8% increase in rates, associated with repowering of approximately 900 MWs of company-owned and installed wind facilities. In March 2019, the application was updated to request recovery of $32 million, or a 2.5% increase in rates. A decision is expected from the OPUC in September 2019.

In April 2019, PacifiCorp submitted its annual TAM filing in Oregon requesting an annual decrease of $15 million, or an average price decrease of 1.2%, based on forecasted net power costs and loads for calendar year 2020. The filing includes the customer benefits of repowering resulting in an increase in production tax credits and reduced power costs.

Wyoming

In April 2018, PacifiCorp filed a partial settlement related to the impact of 2017 Tax Reform with the WPSC 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, PacifiCorp filed reports with the WPSC with the calculation of the full impact of the tax law change on revenue requirement of $28 million annually, comprised of $20 million in current tax savings and $8 million for the amortization of excess deferred income tax. In March 2019, the WPSC issued a written order approving the continued annual rate reduction of $23 million until base rates are reset in the next general rate proceeding. An additional $4 million is currently being offset against PacifiCorp's 2018 ECAM rates. The order reflected the $20 million of current tax savings and was updated to reflect a projection of $7 million for amortization of excess deferred income tax.

In February 2019, PacifiCorp filed a certificate of public convenience and necessity application with the WPSC requesting to repower the existing Foote Creek I wind facility, which was approved without conditions in April 2019.

In April 2019, PacifiCorp filed its annual ECAM and RRA application with the WPSC. The filing requests approval to recover from customers $7 million, or approximately 1.0%, in deferred net power costs for the period January 1, 2018 through December 31, 2018. The rate change will go into effect on an interim basis June 15, 2019. PacifiCorp has proposed to offset this increase with other rate credits proposed to go into effect on June 15, 2019, including the use of deferred 2017 Tax Reform benefits.

Idaho

In May 2018, the IPUC approved a rate reduction of $6 million, or 2.2%, effective June 1, 2018 through May 31, 2019, to pass back a portion of the benefits associated with 2017 Tax Reform. In March 2019 an all-party settlement resolving the treatment of the remaining tax savings was filed with the IPUC. Effective June 1, 2019, the rate reduction will be adjusted to $7 million. Remaining 2017 Tax Reform benefits will be used to offset future rate increases.

In March 2019, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $15 million, or 0.4%, for deferred costs in 2018. 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 Mine investment and changes in production tax credits and renewable energy credits. Rates are proposed to go into effect June 1, 2019.

California

In April 2018, PacifiCorp filed a general rate case with the CPUC for an overall rate increase of $1 million, or 0.9%, effective January 1, 2019. A CPUC decision is pending.

On September 21, 2018, California's governor signed legislation to strengthen California's ability to prevent and recover from catastrophic wildfires, including Senate Bill 901 ("SB 901"). SB 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp filed its wildfire mitigation plan with the CPUC on February 6, 2019. The wildfire mitigation plan incorporates the requirements outlined in SB 901, including situational awareness, system hardening, vegetation management and procedures for proactive de-energization in certain high risk areas during times of extreme danger. A workshop was held February 13, 2019, at which time PacifiCorp briefly described its wildfire mitigation plan as filed. Intervenors filed comments on the wildfire mitigation plans on March 13, 2019 and the respondents filed reply comments on March 22, 2019. A proposed decision was released April 29, 2019 by the CPUC which will be considered for final action no sooner than May 30, 2019, and is subject to comments by parties of record to the proceeding.

NV Energy (Nevada Power and Sierra Pacific)

2017 Tax Reform

In February 2018, the Nevada Utilities made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the 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, 2018. Subsequently, the Nevada Utilities filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, the Nevada Utilities filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review.

Optional Pricing Program

In November 2018, the Nevada Utilities made filings with the PUCN to implement the Optional Pricing Program ("OPP"). The Nevada Utilities have designed the OPP to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option that is based on renewable resources. The OPP provides for an energy rate that would replace the base tariff energy rate and deferred energy accounting adjustment. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding.

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.

Since 2016, five fully bundled retail customers have transitioned to distribution only service and are acquiring energy from an energy supplier other than the Nevada Utilities. The total estimated peak demand of these customers was approximately 400 MWs, as of the date their applications were filed with the PUCN, which represents approximately 5% of the annual hourly peak demand on the Nevada Utilities’ electric system in 2018. The PUCN has imposed cumulative impact fees of $155 million on these customers which includes impact fee credits of $20 million established by the PUCN subsequent to the initial application approvals.

As of April 2019, the Nevada Utilities have an estimated 122 fully bundled retail customers that are eligible to file Chapter 704B applications. The PUCN has approved the applications of three fully bundled retail customers whose total estimated peak demand is approximately 55 MWs, as of the date their applications were filed with the PUCN. The PUCN has imposed impact fees of $18 million on these customers. Subsequent to approval, one customer with an estimated peak demand of 5 MWs and imposed impact fees of $2 million has withdrawn their application. The PUCN has also approved the applications of three pending customers not yet receiving service. These five customers have not yet become distribution only service customers.

As of April 2019, the Nevada Utilities have also received communications from eleven additional fully bundled or pending customers, three of which provided a letter of intent to file an application with the PUCN and eight of which filed an application with the PUCN to purchase energy from another energy supplier and become distribution only service customers. One applicant has subsequently withdrawn their application.

The Nevada Utilities are addressing further Chapter 704B activity by evaluating options that include implementing alternative pricing plans such as the OPP, educating current customers on the value of the Nevada Utilities' fully bundled service, evaluating legislative or administrative changes to the Chapter 704B process and participating in current and future Chapter 704B proceedings.

Northern Powergrid Distribution Companies

GEMA, through the Ofgem, published its RIIO-2 sector methodology consultation in December 2018, continuing the process of developing the next set of price control arrangements that will be implemented for transmission and gas distribution networks in Great Britain. Ofgem explicitly states that this consultation does not set out proposals for Northern Powergrid's next price control, which will begin in April 2023. However, it also states that some of the proposals may be capable of application to that price control. Regarding allowed return on capital, Ofgem has stated that it currently considers that a cost of equity of 4.0% (plus inflation calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs) would be appropriate for energy networks, which is approximately 2.5 percentage points lower than the current comparable cost of equity. This cost of equity assumption is based on a proposed debt capitalization assumption for the next price control of 60%, which is five percentage points lower than the 65% debt capitalization assumption for the current price control. The next significant milestone in the process will be Ofgem's decision on the methodology, due in May 2019, followed by an initial consultation for the next electricity distribution price control, due in late 2019.

BHE Pipeline Group

Northern Natural Gas

In July 2018, the FERC issued a final rule adopting procedures for determining whether natural gas pipelines were 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. On January 16, 2019, FERC initiated a Section 5 investigation to determine whether the rates currently charged by Northern Natural Gas are just and reasonable. As required by the FERC order, Northern Natural Gas filed a full cost and revenue study on April 1, 2019. Northern Natural Gas expects to file a general Section 4 rate case, as soon as July 1, 2019, which would supersede a Section 5 rate action to address Northern Natural Gas' significant investment. Northern Natural Gas believes a rate increase will result from the Section 4 rate case and higher rates would be implemented subject to refund in early 2020.

BHE Transmission

AltaLink

General Tariff Application

In August 2018, AltaLink filed its 2019-2021 GTA with the 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 a new salvage recovery approach and continuing the use of the flow-through income tax method. In addition, similar to the refund approved by the AUC for the 2017-2018 GTA of C$31 million, AltaLink proposes to provide a further tariff reduction over the three years by refunding previously collected accumulated depreciation surplus of an additional C$31 million.

AltaLink provided responses to information requests in November 2018 and additional responses in December 2018 and April 2019. In April 2019, AltaLink filed an update to its 2019-2021 GTA application primarily to reflect its 2018 actual results and the impact of the AUC decision on AltaLink's 2014-2015 deferral account reconciliation application. The application update also included AltaLink's request for additional capital expenditures and operating expenses to enhance its current practices, operations and maintenance program to reduce the risk of transmission system operation caused fire ignition. The updated application requests the approval of revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021 respectively, which are lower than the approved 2018 revenue requirement of C$904 million. The forecast revenue requirement is based on an 8.5% return on equity and 37% deemed equity approved by the AUC for 2019 and 2020 and assumes the same for 2021 as placeholders. In November 2018, the AUC approved the 2019 interim refundable transmission tariff at C$74.0 million per month effective January 2019.

2021 Generic Cost of Capital Proceeding

In December 2018, the AUC initiated a Generic Cost of Capital ("GCOC") proceeding to consider returning to a formula-based approach to determining the return on equity for a given year, starting with 2021. On April 4, 2019, after receiving comments from interested parties, the AUC expanded the scope of the proceeding to include a traditional non-formulaic GCOC inquiry as well as the consideration of returning to a formula-based approach. The AUC also issued a process timeline for the proceeding to commence in January 2020, with a hearing scheduled in April 2020.

Deferral Account Reconciliation Application

In April 2017, AltaLink filed its application with the AUC with respect to AltaLink's 2014 projects and deferral accounts and specific 2015 projects. The application 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 December 2017, AltaLink amended its application to include the remaining capital projects completed in 2015. The amended 2014 and 2015 deferral account reconciliation application includes 110 completed projects with total gross capital additions, excluding AFUDC, of C$3.8 billion. An oral hearing was held in September 2018 after the completion of an extensive information request process earlier in the year.

In December 2018 and January 2019 the AUC issued decisions approving C$3,833 million out of the C$4,017 million capital project additions, including AFUDC, included in the application. Project costs of C$155 million were deferred to a future hearing. The AUC disallowed capital additions of approximately C$30 million including applicable AFUDC, pending receipt of additional requested supporting documentation for certain specific items. In February 2019, AltaLink filed its 2014-2015 deferral accounts reconciliation application compliance filing to reflect the findings, conclusions and directions arising from this decision. In its compliance filing, AltaLink requested approval of interest in the amount of C$10 million on total outstanding amount of C$110 million to be recovered through a one-time payment from the AESO, upon AUC approval. In addition, the AUC ruled that it will put in placeholder amounts for the approved costs of the assets in the 2014-2015 DACDA proceeding until the AUC-initiated proceeding to consider the issue of transmission asset utilization.

In March 2019, AltaLink responded to information requests from the AUC. A decision from the AUC is expected in the second quarter of 2019.

First Nations Asset Transfer Application

In November 2018, the AUC approved, with conditions, AltaLink's application filed in April 2017 to sell and transfer approximately C$91 million of transmission assets located on reserve lands to new limited partnerships with First Nations. The transfers are part of the agreement which allowed AltaLink to route the Southwest Project on reserve land.

In December 2018, AltaLink filed an application with the Alberta Court of Appeal for permission to appeal the conditions imposed by the AUC decision. In January 2019, AltaLink filed an application for review and variance with the AUC.

BHE Renewables' Counterparty Risk

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California ("PG&E Bankruptcy Filing"). The Company owns 100% of Topaz and owns a 49% interest in Agua Caliente. Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale power purchase agreement ("PPA") that is in effect until October 2039. As of March 31, 2019, the Company's consolidated balance sheet includes $1.1 billion of property, plant and equipment, net and $0.9 billion of non-recourse project debt related to Topaz. Agua Caliente is a 290-MW solar photovoltaic electric power generating facility located in Arizona. Agua Caliente sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until June 2039. As of March 31, 2019, the Company's equity investment in Agua Caliente totals $47 million and the project has $0.8 billion of non-recourse project debt owed to the United States Department of Energy. The PG&E Bankruptcy Filing is an event of default under the Topaz PPA ("PPA Default"). PG&E paid in full the invoices for December deliveries and all amounts invoiced to date for post-petition energy deliveries for both Topaz and Agua Caliente in 2019. PG&E has not paid for the power delivered from January 1 through January 28, 2019. The Company continues to perform on its obligations and deliver renewable energy to the PG&E Utility, and PG&E has publicly stated it will pay suppliers in full under normal terms for post-petition goods and services received. The Company maintains that, in light of the current facts and circumstances, the PPA Default could not reasonably be expected to result in a material adverse effect under the Topaz indenture and, therefore, no default has occurred under the Topaz indenture. The Company believes it is more likely than not that no impairment exists and current debt obligations will be met, as post-petition contractual revenue payments are expected to be paid by PG&E Utility to the Topaz and Agua Caliente projects. The Company will continue to monitor the situation, including continued receipt of future PG&E payments and the future risk of the PPAs being rejected or modified through the bankruptcy process.

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 zero emission credit program violates certain provisions of the ~~U.S.~~United States Constitution. Both complaints argue that the Illinois zero emission credit program will distort the FERC's energy and capacity market auction system of setting wholesale prices. As majority owner and operator of Quad Cities Station, Exelon Generation intervened and filed motions to dismiss in both matters. On July 14, 2017,lawsuits were dismissed at the Northern District of Illinois, ~~granted the motions to dismiss. On July 17, 2017, the plaintiffs filed appeals with~~and the United States Court of Appeals for the Seventh Circuit ~~("Seventh Circuit").~~affirmed the dismissals. On ~~May 29, 2018,~~April 15, 2019, plaintiffs' petition seeking United States Supreme Court review of the U.S. Department of Justice and the 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 Illinois' ruling concluding that Illinois' ZEC program does not violate the Federal Power Act and is thus constitutional.

case was denied.

On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Offer Price Rule ("MOPR") provisions to apply to existing resources receiving zero emission credit compensation. If successful, an 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~~FERC has not yet issued a decision on the ~~FERC's decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.~~requests.

~~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~~On April 10, 2019, PJM Interconnection, L.L.C. ("PJM") notified the FERC of ~~each Registrant's Annual Report on Form 10-K for the year ended~~ ~~December 31, 2017, and new regulatory matters occurring in 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 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. 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 settlement supports 950 MWs of owned wind resources and the 200 MW purchase power agreement. Hearings were held by the UPSC and IPUC 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 the projected costs. PacifiCorp can seek recovery of any actual costs in excess of the 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 sought approval of PacifiCorp's resource decision to upgrade or "repower" existing wind resources, as prudent and in the public interest. PacifiCorp estimates the wind repowering project will cost approximately $1 billion. Applications filed in Utah, Idaho and Wyoming seek approval for the proposed rate-making treatment associated with the projects, 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 choosesits intent to proceed with ~~this project,~~ the ~~project will be subject~~next capacity auction in August 2019 under the existing market rules and asked the FERC to ~~a standard prudence review~~clarify that it would not require the PJM to re-run the auction in ~~future general rate cases. The WPSC approved an all-party settlement agreement~~the event the FERC alters those market rules in its decision on the MOPR complaint. It is too early to ~~repower wind facilities in a bench decision in June 2018. In~~predict the ~~decision,~~final outcome of each of these proceedings or their potential impact on the ~~WPSC specifically removed the Leaning Juniper project, located in Oregon, from the agreement and the approval, consistent with the treatment in Utah.~~continued operation of Quad Cities Station.

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 2018, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover from customers $3 million in deferred net power costs for the period January 1, 2017 through December 31, 2017, reflecting the difference between base and actual net power costs in the 2017 deferral period. The rate change was approved by the UPSC effective May 1, 2018 on an interim basis. A hearing on final approval is scheduled for February 2019.

In March 2018, PacifiCorp filed its annual REC balancing account application with the UPSC seeking to recover $1 million from customers for the period January 1, 2017 through December 31, 2017 for the difference in base and actual RECs. The rate change became effective on an interim basis June 1, 2018, with final approval received in August 2018.

~~Oregon~~

In March 2018, PacifiCorp submitted its filing for the annual TAM filing in Oregon requesting an annual increase of $17 million, or an average price increase of 1.3%, based on forecasted net power costs and loads for calendar year 2019. The filing includes an update of the impact of expiring production tax credits, which accounts for $11 million of the total rate 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 $1 million. The OPUC approved the all-parties partial stipulation and resolved all issues in the proceeding in an order issued in October 2018. The filing will be updated for changes in contracts and market conditions again in November 2018, before final rates become effective in January 2019.

~~Wyoming~~

In April 2018, PacifiCorp filed its annual ECAM and RRA application with the WPSC. The filing requests approval to refund to customers $3 million in deferred net power costs for the period January 1, 2017 through December 31, 2017. The rate change was approved by the WPSC on an interim basis, effective July 1, 2018. PacifiCorp expects the interim rates to become final in the 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 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 amortize the balance over 24 months effective January 1, 2019. The WUTC denied PacifiCorp's petition and ordered PacifiCorp to submit a compliance filing with tariffs supporting a 12-month amortization period effective November 1, 2018.

In June 2018, PacifiCorp filed with WUTC a proposal to decrease the System Benefits Charge ("SBC") collection rate by $2 million. In July 2018, the WUTC approved the proposed rates to go into effect August 1, 2018.

~~Idaho~~

In March 2018, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $8 million for deferred costs in 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 deferred costs, which resulted in a rate reduction of $2 million, or 0.8% effective June 1, 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 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 April 2018, PacifiCorp filed a general rate case with the CPUC for an overall rate increase of $1 million, or 0.9%, 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 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 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. 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.

2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the U.S. federal corporate income tax rate from 35% to 21%. In February 2018, the Nevada Utilities made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. The filings supported an annual rate reduction of $59 million and $25 million for Nevada Power and Sierra Pacific, respectively. In March 2018, the PUCN issued an order approving the 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, 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~~

In October 2016, Wynn Las Vegas, LLC ("Wynn"), became a distribution only service customer 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 September 2018, the PUCN granted relief requiring Nevada Power to credit $3 million as an offset against 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 equal monthly installments through December 2022.

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 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 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 Committee on Energy Choice in which the Nevada Utilities have representation. The Nevada Utilities have been engaged in the legislative process before the Governor's committee and related proceedings before the PUCN and the legislature. 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 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 decision the PUCN issued denying Nevada Power's proposed purchase of the South Point Energy Center, citing the unknown outcomes of the Energy Choice Initiative as one of the factors considered in their decision.

~~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 Application~~

In August 2018, ALP filed its 2019-2021 general tariff application ("GTA") with the 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 a new salvage recovery approach and continuing the use of the flow-through income tax method. In addition, similar to the refund approved by the AUC for the 2017-2018 GTA of C$31 million, ALP proposes to provide a further tariff reduction over the three years by refunding previously collected accumulated depreciation surplus of an additional C$31 million. The application requests the approval of revenue requirements of C$885 million, C$887 million and C$889 million for 2019, 2020 and 2021 respectively, which are lower than the approved 2018 revenue requirement of C$904 million. The forecast revenue requirement is based on an 8.5% return on equity and 37% deemed equity approved by the AUC for 2019 and 2020 and assumes the same for 2021 as placeholders.

~~2018 Generic Cost of Capital Proceeding~~

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

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 return on equity recommended by the intervenors ranges from 6.3% to 7.75%. The equity ratio recommended by the intervenors for ALP ranges from 35% to 37%.

In March 2018, an oral hearing 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 2018, 2019 and 2020.

~~Deferral Account Reconciliation Application~~

In April 2017, ALP filed its application with the AUC with respect to ALP's 2014 projects and deferral accounts and specific 2015 projects. The application 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 December 2017, ALP amended its application to include the remaining capital projects completed in 2015. The amended 2014 and 2015 deferral account reconciliation application includes 110 completed projects with total gross capital additions, excluding AFUDC, of C$3.8 billion. An oral hearing was held in September 2018 after the completion of an extensive information request process earlier in the year. Following written arguments in October 2018, a 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 climate change, RPS, air and water quality, ~~RPS,~~ emissions performance standards, ~~climate change,~~ coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. ~~Refer to "Liquidity and Capital Resources" of each respective Registrant in 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, ~~2017,~~2018, and new environmental matters occurring in ~~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 Colorado regional haze SIP requires selective catalytic reduction ("SCR") controls at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are either already in service or currently being constructed. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR controls to retire Unit 1 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 agreement were approved by the Colorado Air Quality Board in December 2016. The terms of the agreement were incorporated into an amended Colorado regional haze SIP in 2017 and were submitted to the EPA for its review and approval. The EPA's approval of the amended Colorado regional haze SIP was published in the Federal Register July 5, 2018, with an effective date of 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.2019.

Climate Change

In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce greenhouse gas emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global greenhouse gas emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. Under the terms of the Paris Agreement, ratifying countries are bound for a three-year period and must provide one-year's notice of their intent to withdraw. On June 1, 2017, President Trump announced the United States would withdraw from the Paris Agreement. Under the terms of the agreement, the withdrawal would be effective in November 2020. The cornerstone of the United States' commitment was the Clean Power Plan which was finalized by the EPA in 2015 but has since been proposed for repeal by the EPA.

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are ~~co-fired~~co-fueled with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the United States Court of Appeals for the District of Columbia Circuit ("D.C. ~~Circuit~~Circuit") and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. EPA accepted comment on the proposal through March 18, 2019. Until such time as the EPA undertakes further action ~~to reconsider~~on the ~~new source performance standards~~proposed reconsideration or the court takes action, any new fossil-fueled generating facilities constructed by the relevant Registrants will be required to meet the GHG new source performance standards.

Clean Air Act Regulations

~~Clean Power Plan~~Mercury and Air Toxics Standards

In ~~June 2014,~~March 2011, the EPA ~~released~~ proposed ~~regulations to address GHG emissions from existing fossil-fueled~~a rule that requires coal-fueled generating facilities ~~referred~~ to asreduce mercury emissions and other hazardous air pollutants through the ~~Clean Power Plan, under Section 111(d)~~establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015 with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the ~~Clean Air Act.~~Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The ~~EPA's proposal calculated state-specific~~relevant Registrants have completed emission ~~rate targets~~reduction projects to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The compliance period would have begun in 2022, with three interim periods of compliance andcomply with the final ~~goal~~rule's standards for acid gases and non-mercury metallic hazardous air pollutants.

MidAmerican Energy retired certain coal-fueled generating units as the least-cost alternative to ~~be achieved by 2030~~comply with the MATS. Walter Scott, Jr. Energy Center Units 1 and 2 were retired in 2015, and George Neal Energy Center Units 1 and 2 were retired in April 2016. A fifth unit, Riverside Generating Station, was ~~expected~~limited to ~~reduce carbon dioxide emissions~~natural gas combustion in March 2015.

Numerous lawsuits have been filed in the ~~power sector to 32% below 2005 levels by 2030. On February 9, 2016,~~D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the United States Supreme Court ~~ordered~~agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. Oral argument in the case was held before the United States Supreme Court in March 2015, and a decision was issued by the United States Supreme Court in June 2015, which reversed and remanded the MATS rule to the D.C. Circuit for further action. The United States Supreme Court held that the ~~EPA's emission guidelines for existing sources~~EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be ~~stayed pending the disposition~~considered before deciding whether regulation is necessary and appropriate. The United States Supreme Court's decision did not vacate or stay implementation of the MATS rule. In December 2015, the D.C. Circuit issued an order remanding the rule to the EPA, without vacating the rule. As a result, the relevant Registrants continue to have a legal obligation under the MATS rule and the respective permits issued by the states in which each respective Registrant operates to comply with the MATS rule, including operating all emissions controls or otherwise complying with the MATS requirements.

On December 27, 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. EPA proposes to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112; however, EPA proposes to retain the emission standards and other requirements of the MATS rule, because EPA is not proposing to remove coal- and oil-fueled power plants from the list of sources regulated under Section 112. The public comment period on the proposal closed April 17, 2019. Until EPA takes final action on the rule, the relevant Registrants cannot fully determine the impacts of the proposed changes to the MATS rule.

Regional Haze

The state of Utah issued a regional haze SIP requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to nitrogen oxides controls and require the installation of selective catalytic reduction ("SCR") controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the CAMX air quality dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis.

The state of Wyoming issued two regional haze SIPs requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the sulfur dioxide SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the nitrogen oxides and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the nitrogen oxides and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-nitrogen oxides burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-nitrogen oxides burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility ("Wyodak Facility"), requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on the Wyodak Facility in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for the Wyodak Facility, pending further action by the Tenth Circuit in the appeal. A stay remains in place and the case has not yet been set for oral argument. In June 2014, the Wyoming Department of Environmental Quality issued a revised BART permit allowing Naughton Unit 3 to operate on coal through 2017 and providing for natural gas conversion of the unit in 2018; in October 2016, an application was filed with the Wyoming Department of Environmental Quality requesting a revision of the dates for the end of coal firing and the start of gas firing for Naughton Unit 3 to align with the requirements of the Wyoming SIP. The Wyoming Department of Environmental Quality approved a change to the requirements for Naughton Unit 3, extending the requirement to cease coal firing to no later than January 30, 2019, and complete the gas conversion by June 30, 2019. On March 17, 2017, Wyoming Department of Environmental Quality issued an extension to operate the unit as a coal-fueled unit through January 30, 2019. The Wyoming Department of Environmental Quality submitted a proposed revision to the Wyoming SIP, including a change to the Naughton Unit 3 compliance date, to the EPA for approval on November 28, 2017. On November 7, 2018, the EPA published its proposed approval of the Wyoming SIP relative to the Naughton 3 gas conversion. The comment period closed December 7, 2018 and the EPA has not taken final action. PacifiCorp removed the unit from coal-fueled service on January 30, 2019, and is evaluating the economic benefits of converting it to a natural gas-fueled generation resource. On February 5, 2019, PacifiCorp submitted a reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of selective catalytic reduction, to be replaced with a permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. The proposal will be open for public comment May 31, 2019 through June 30, 2019, and the state of Wyoming will hold public hearings on July 1, 2019 to consider the proposal and public input.

The state of Arizona issued a regional haze SIP requiring, among other things, the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions requiring SCR controls on Cholla Unit 4. PacifiCorp filed an appeal in the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it relates to their interests. The Ninth Circuit issued an order in February 2015, holding the matter in abeyance while the parties pursued an alternate compliance approach for Cholla Unit 4. The Arizona Department of Environmental Quality's revision of the draft permit and revision to the Arizona regional haze SIP were approved by the EPA through final action published in the Federal Register on March 27, 2017, with an effective date of April 26, 2017. The final action allows Cholla Unit 4 to utilize coal until April 30, 2025 and convert to gas or otherwise cease burning coal by June 30, 2025.

The state of Colorado regional haze SIP requires SCR controls at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are either already in service or currently being constructed. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021 with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016. The terms of the agreement were incorporated into an amended Colorado regional haze SIP in 2017 and were submitted to the EPA for its review and approval. The EPA's approval of the amended Colorado regional haze SIP was published in the Federal Register on July 5, 2018, with an effective date of 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. The EPA issued a final FIP on August 8, 2014 adopting, with limited changes, the Navajo Generating Station proposal as a "better than BART" determination. Nevada Power filed the ERCR Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019, which was approved by the PUCN. In February 2017, the non-federal owners of the Navajo Generating Station announced the facility will shut down on or before December 23, 2019, unless new owners can be found. All current owners have since approved a lease extension with the Navajo Nation to allow operations to continue through 2019. On March 21, 2019, the Navajo Nation Council voted to end efforts to transition ownership and extend facility operations. The plant will cease operations by the end of 2019. Ownership transfer negotiations and closure preparations are ongoing and, until concluded, the relevant Registrant cannot determine whether additional action may be required.

Water Quality Standards

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

In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions has changed the effluent discharged from coal- and natural gas-fueled generating facilities. Under the originally-promulgated guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal with the new limits to be met as soon as possible, beginning November 1, 2018 and fully implemented by December 31, 2023. On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with the EPA. The EPA granted the request for reconsideration on April 12, 2017, imposed an immediate administrative stay of compliance dates in the rule that had not passed judicial review and requested the court stay the pending litigation over the rule until September 12, 2017. On June 6, 2017, the EPA proposed to extend many of the compliance deadlines that would otherwise occur in 2018 and on September 18, 2017, the EPA issued a final rule extending certain compliance dates for flue gas desulfurization wastewater and bottom ash transport water limits until November 1, 2020. In a separate action, on April 12, 2019, the Fifth Circuit Court of Appeal vacated two aspects of the final effluent limitation guidelines, concerning discharge limits for (1) legacy wastewater from ash transport or treatment systems and (2) combustion residual leachate from landfills or settling ponds. The Firth Circuit found that EPA's own data did not support the agency's conclusion that impoundments were the best technology available for these two waste streams. EPA must now complete a new effluent limitation guideline for these discharge limits. While most of the issues raised by effluent limitation guidelines 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 and remand actions are complete and any judicial review is conducted.

In April 2014, the EPA and the United States Army Corps of Engineers issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but is currently under appeal in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. The EPA plans to undertake a two-step process, with the first step to repeal the 2015 rule and the second step to carry out a notice-and-comment rulemaking in which a substantive re-evaluation of the ~~D.C. Circuit and any action on a writ~~definition of ~~certiorari before~~ the ~~U.S. Supreme Court. Oral argument was heard before~~"waters of the ~~D.C. Circuit on September~~United States" will be undertaken. On July 27, ~~2016. The court has not yet issued its decision. On October 10,~~ 2017, the EPA and the Corps of Engineers issued a proposal to repeal the ~~Clean Power Plan~~final rule and recodify the pre-existing rules pending issuance of a new rule and on November 16, 2017, the agencies proposed to extend the implementation day of the "waters of the United States" rule to 2020; neither of the proposals has been finalized. On January 22, 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extension of the compliance deadline. On December 11, 2018, the EPA and the ~~EPA took comments on~~Corps of Engineers proposed a revised definition of "waters of the ~~proposed repeal until April 26, 2018. In addition, the EPA published~~United States" that is intended further clarify jurisdictional questions, eliminate case-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion 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.~~Rapanos v. United States. The public comment period 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 were due October 31, 2018.closed April 15, 2019. Until the ~~proposed~~ rule is ~~finalized~~fully litigated and ~~state plans are developed, the full impacts on~~finalized, the Registrants cannot ~~be determined. However, PacifiCorp, MidAmerican Energy, Nevada Power~~determine whether projects that include construction and ~~Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements,~~demolition will face more complex permitting issues, higher costs or increased ~~diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advanced customer energy efficiency programs.~~

~~GHG Litigation~~

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

Coal Combustion Byproduct Disposal

In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts under the RCRA. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and was effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of coal combustion residuals. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. The final rule requires regulated entities to post annual groundwater monitoring and corrective action reports. The first of these reports ~~were~~was posted to the respective Registrant's coal combustion rule compliance data and information websites ~~prior to~~in March 2, 2018. Based on the results in those reports, additional ~~monitoring and~~ action may be required under the rule.

At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston Generating Station were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017 and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated ten evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule. Refer to Note 13 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for discussion of the impacts on asset retirement obligations as a result of the final rule.

Additional substantive revisions to the rule are expected to be finalized by the EPA by December 2019 but have not yet been released for public comment. If adopted, certain elements of the proposal have the potential to reduce costs of compliance. The D.C. Circuit issued a decision on 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, the impacts on the Registrants cannot be determined.

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. Oral argument was held by the D.C. Circuit on November 20, 2017 over certain portions of the 2015 rule that had not been settled or otherwise remanded. On August 21, 2018, the D.C. Circuit issued its opinion in Utility Solid Waste Activities Group v. EPA, finding it was arbitrary and capricious for EPA to allow unlined ash ponds to continue operating until some unknown point in the future when groundwater contamination could be detected. The D.C. Circuit vacated the closure section of the CCR rule and remanded the issue of unlined ponds to EPA for reconsideration with specific instructions to consider harm to the environment, not just to human health. The D.C. Circuit also held EPA's decision to not regulate legacy ponds was arbitrary and capricious. While the D.C. Circuit's decision was pending, the EPA, on March 15, 2018, ~~the EPA~~ issued a proposal to address provisions of the final coal combustion rule that were remanded back to the agency on 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 or are otherwise subject to oversight through a permit program administered by the EPA. The EPA published the first phase of the coal combustion rule amendments on July 30, 2018, with an effective date of August 28, ~~2018. Additional substantive revisions~~2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, EPA extended the ~~rule are expected~~deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to ~~be finalized by~~October 31, 2020. Following submittal of competing motions from environmental groups and the EPA ~~by December~~to stay or remand this deadline extension, on March 13, 2019, ~~but have not yet been released for public comment. If adopted, certain elements of the proposal have the potential to reduce costs of compliance. The U.S. Court of Appeals for~~ the D.C. Circuit ~~issued a decision August 21, 2018, vacating several elements of~~granted EPA's request to remand the rule, ~~including closure provisions~~without vacatur, leaving the October 31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for ~~unlined surface impoundments,~~initiating closure. Until the rule is fully litigated 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, the impacts onfinalized, the Registrants cannot determine whether additional action may be ~~determined.~~required.

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 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, two surface 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 by December 2018 and April 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 removed eight surface impoundments from service and commenced closure. Two surface impoundments and 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 and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of the Form 10-K for the year ended December 31, 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.~~United States 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, ~~2017~~2018. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, ~~2017~~2018.

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

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of ~~September 30, 2018,~~March 31, 2019, the related consolidated statements of operations, ~~for the three-month and nine-month periods ended September 30, 2018 and 2017, of~~ changes in shareholders' equity and of cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ and 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 PacifiCorp as of December 31, ~~2017,~~2018, 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,~~22, 2019, 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,~~2018, 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 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.

/s/ Deloitte & Touche LLP

Portland, Oregon

~~November 2, 2018~~May 3, 2019

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	308	$	14	$	669	$	77
Accounts receivable, net	761		684
Trade receivables, net					591		640
Other receivables, net					114		92
Inventories	429		433		406		417
Prepaid expenses	59		73
Other current assets	55		111		152		133
Total current assets	1,612		1,315		1,932		1,359

Property, plant and equipment, net	19,338		19,203		19,698		19,570
Regulatory assets	1,028		1,030		1,090		1,076
Other assets	358		372		329		308

Total assets	$	22,336	$	21,920	$	23,049	$	22,313

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,			March 31,			December 31,
	2018			2017			2019			2018
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	438		$	453		$	583		$	597
Accrued interest	106			115			105			114
Accrued property, income and other taxes	219			66			142			75
Accrued employee expenses	126			70			108			79
Short-term debt	—			80
Current portion of long-term debt and capital lease obligations	352			588
Current portion of long-term debt							—			350
Regulatory liabilities							83			77
Other current liabilities	245			245			196			223
Total current liabilities	1,486			1,617			1,217			1,515

Long-term debt and capital lease obligations	6,682			6,437
Long-term debt							7,656			6,665
Regulatory liabilities	3,151			2,996			2,989			2,978
Deferred income taxes	2,560			2,582			2,551			2,543
Other long-term liabilities	700			733			786			767
Total liabilities	14,579			14,365			15,199			14,468

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

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	3,291			3,089			3,381			3,377
Accumulated other comprehensive loss, net	(15		)	(15		)	(12		)	(13		)
Total shareholders' equity	7,757			7,555			7,850			7,845

Total liabilities and shareholders' equity	$	22,336		$	21,920		$	23,049		$	22,313

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
	Ended September 30,							Ended September 30,						Ended March 31,
		2018			2017			2018			2017				2019			2018

Operating revenue		$	1,369		$	1,430		$	3,746		$	3,956			$	1,259		$	1,184

Operating expenses:
Cost of fuel and energy		465			465			1,300			1,305				465			433
Operations and maintenance		266			254			777			771				256			250
Depreciation and amortization		203			200			602			598				205			202
Property and other taxes		49			50			150			149				49			52
Total operating expenses		983			969			2,829			2,823				975			937

Operating income		386			461			917			1,133				284			247

Other income (expense):
Interest expense		(96		)	(95		)	(288		)	(285		)		(96		)	(96		)
Allowance for borrowed funds		5			4			13			12				7			4
Allowance for equity funds		9			7			24			21				14			7
Other, net		14			12			36			30				12			11
Total other income (expense)		(68		)	(72		)	(215		)	(222		)		(63		)	(74		)

Income before income tax expense		318			389			702			911				221			173
Income tax expense		48			126			100			294				42			25
Net income		$	270		$	263		$	602		$	617			$	179		$	148

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

Balance, December 31, 2017	$	2	$	—	$	4,479	$	3,089		$	(15	)	$	7,555		$	2	$	—	$	4,479	$	3,089		$	(15	)	$	7,555
Net income	—		—		—		602			—			602			—		—		—		148			—			148
Common stock dividends declared	—		—		—		(400		)	—			(400		)	—		—		—		(250		)	—			(250		)
Balance, September 30, 2018	$	2	$	—	$	4,479	$	3,291		$	(15	)	$	7,757
Balance, March 31, 2018																$	2	$	—	$	4,479	$	2,987		$	(15	)	$	7,453

Balance, December 31, 2018																$	2	$	—	$	4,479	$	3,377		$	(13	)	$	7,845
Net income																—		—		—		179			—			179
Other comprehensive income																—		—		—		—			1			1
Common stock dividends declared																—		—		—		(175		)	—			(175		)
Balance, March 31, 2019																$	2	$	—	$	4,479	$	3,381		$	(12	)	$	7,850

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						Three-Month Periods
	Ended September 30,						Ended March 31,
	2018			2017			2019			2018
Cash flows from operating activities:
Net income	$	602		$	617		$	179		$	148
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	602			598			205			202
Allowance for equity funds	(24		)	(21		)	(14		)	(7		)
Changes in regulatory assets and liabilities	127			21			(35		)	60
Deferred income taxes and amortization of investment tax credits	(53		)	14			5			(28		)
Other, net	(1		)	1			(1		)	1
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(31		)	42
Trade receivables, other receivables and other assets							28			97
Inventories	4			(1		)	11			(12		)
Derivative collateral, net	4			(4		)	7			(3		)
Prepaid expenses	10			9
Accrued property, income and other taxes, net	204			145			68			83
Accounts payable and other liabilities	36			40			41			(8		)
Net cash flows from operating activities	1,480			1,461			494			533

Cash flows from investing activities:
Capital expenditures	(713		)	(553		)	(337		)	(236		)
Other, net	2			5			1			(1		)
Net cash flows from investing activities	(711		)	(548		)	(336		)	(237		)

Cash flows from financing activities:
Proceeds from long-term debt, net	593			—
Repayments of long-term debt and capital lease obligations	(588		)	(54		)
Net repayments of short-term debt	(80		)	(270		)
Proceeds from long-term debt							990			—
Repayments of long-term debt							(350		)	(86		)
Dividends paid	(400		)	(500		)	(175		)	(250		)
Other, net	—			(3		)	(31		)	43
Net cash flows from financing activities	(475		)	(827		)	434			(293		)

Net change in cash and cash equivalents and restricted cash and cash equivalents	294			86			592			3
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	29			33			92			29
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	323		$	119		$	684		$	32

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

PACIFICORP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	General

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

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September 30, 2018~~March 31, 2019 and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The results of operations for the ~~three- and nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 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, ~~2017~~2018 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, except as disclosed in Note 4, during the ~~nine-month~~three-month period ended ~~September 30, 2018.~~March 31, 2019.


(2)	~~New Accounting Pronouncements~~Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

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 consist substantially of funds representing escrow accounts for disputes, vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2019 and December 31, 2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):



	As of
	March 31,		December 31,
	2019		2018
Cash and cash equivalents	$	669	$	77
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	$	684	$	92


(3)	Property, Plant and Equipment, Net

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



		As of
		March 31,			December 31,
	Depreciable Life	2019			2018
Utility Plant:
Utility plant in-service	5-75 years	$	28,455		$	28,399
Accumulated depreciation and amortization		(10,105		)	(10,034		)
Utility plant in-service, net		18,350			18,365
Other non-regulated, net of accumulated depreciation and amortization	47 years	10			10
Plant, net		18,360			18,375
Construction work-in-progress		1,338			1,195
Property, plant and equipment, net		$	19,698		$	19,570

(4) Leases

Adoption

In ~~August 2018,~~February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. ~~2018-14,~~2016-02, which ~~amends~~creates 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 PacifiCorp's 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 inon 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,~~Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance ~~and provided optional transition practical expedients~~ for ASU No. 2016-02 ~~including~~but did not change the core principle of the guidance. PacifiCorp adopted this guidance for all applicable contracts in effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.

PacifiCorp has elected to utilize various practical expedients available to adopt ASU No. ~~2018-01 that allows companies to forgo evaluating~~2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements ~~if they~~that were not previously accounted for as leases under ASC Topic 840 ~~"Leases"~~are or contain a lease under ASC Topic 842.

Leases

Lessee

PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and ~~ASU No. 2018-11 that allows companies~~generating facilities and finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally require PacifiCorp to ~~apply~~pay for insurance, taxes and maintenance applicable to the ~~new guidance at~~leased property. Given the ~~adoption date~~capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the ~~cumulative-effect adjustment~~corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's accounting policy is to not recognize lease obligations and corresponding right-of-use assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with ASC 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

PacifiCorp's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

PacifiCorp's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and long-term debt, respectively, to conform to the ~~opening balance~~current period presentation. The following table summarizes PacifiCorp's leases recorded on the Consolidated Balance Sheet (in millions):



	As of
	March 31,
	2019
Right-of-use assets:
Operating leases	$	14
Finance leases	20
Total right-of-use assets	$	34

Lease liabilities:
Operating leases	$	14
Finance leases	20
Total lease liabilities	$	34

Cash payments associated with operating and finance lease liabilities approximated lease cost. The following table summarizes PacifiCorp's lease costs (in millions):



	Three-Month Period
	Ended March 31,
	2019

Variable	$	9
Operating	1
Finance:
Interest	1
Total lease costs	$	11

Weighted-average remaining lease term (years):
Operating leases	13.6
Finance leases	9.7

Weighted-average discount rate:
Operating leases	3.7		%
Finance leases	10.6		%

PacifiCorp has the following remaining lease commitments as of ~~retained earnings recognized~~(in millions):



	March 31, 2019									December 31, 2018⁽¹⁾
	Operating			Finance			Total			Operating		Capital		Total
2019	$	2		$	3		$	5		$	3	$	4	$	7
2020	2			3			5			3		4		7
2021	2			7			9			3		7		10
2022	2			3			5			2		3		5
2023	2			2			4			2		2		4
Thereafter	8			16			24			7		16		23
Total undiscounted lease payments	18			34			52			$	20	$	36	$	56
Less - amounts representing interest	(4		)	(14		)	(18		)
Lease liabilities	$	14		$	20		$	34

(1) Amounts included for comparability and accounted for in ~~the period of adoption. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018,~~accordance 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.ASC 840, "Leases".


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

~~Cash and Cash Equivalents and Restricted Cash and Cash Equivalents~~

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 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. PacifiCorp 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.


~~(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:
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~~

~~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)~~(5)	Recent Financing Transactions

Long-Term Debt

In ~~July 2018,~~March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its ~~4.125%~~4.15% First Mortgage Bonds due ~~2049.~~February 2050. PacifiCorp used a portion of the net proceeds to repay short-term debt that was partially incurred in January 2019 to repay all of PacifiCorp's ~~$500~~$350 million ~~5.65%~~5.50% First Mortgage Bonds due ~~July 2018~~January 2019 and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

Credit Facilities

In ~~April 2018,~~March 2019, PacifiCorp ~~amended and restated, its existing $400~~completed a re-offering of variable rate tax-exempt bond obligations totaling $168 million, ~~unsecured~~involving the cancellation, at PacifiCorp's request, of $170 million of letters of credit support by the issuing banks. As a result, PacifiCorp's 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 amended and restated, its existing $600 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.support for outstanding variable rate tax-exempt bond obligations increased by $168 million.


~~(7)~~(6)	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 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				Three-Month Periods
	Ended September 30,				Ended September 30,				Ended March 31,
	2018		2017		2018		2017		2019		2018

Federal statutory income tax rate	21	%	35	%	21	%	35	%	21	%	21	%
State income tax, net of federal income tax benefit	4		3		4		3		3		4
Federal income tax credits	(5	)	(5	)	(5	)	(5	)	(4	)	(5	)
Effects of ratemaking	(4	)	1		(4	)	1		(1	)	(4	)
Other	(1	)	(2	)	(2	)	(2	)	—		(2	)
Effective income tax rate	15	%	32	%	14	%	32	%	19	%	14	%

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


	Three-Month Periods				Nine-Month Periods				Three-Month Periods
	Ended September 30,				Ended September 30,				Ended March 31,
	2018		2017		2018		2017		2019			2018
Pension:
Service cost	—		—		—		—		$	—		$	—
Interest cost	11		12		32		37		11			11
Expected return on plan assets	(18	)	(18	)	(54	)	(54	)	(17		)	(18		)
Net amortization	3		3		10		10		3			3
Net periodic benefit credit	(4	)	(3	)	(12	)	(7	)	$	(3	)	$	(4	)

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

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 $4 million and $- million, respectively, during ~~2018~~2019. As of ~~September 30, 2018, $3~~March 31, 2019, $1 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.


~~(9)~~(8)	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 109 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, 2018
As of March 31, 2019
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	10		$	4	$	6		$	—		$	20		$	37		$	8		$	6		$	1		$	52
Commodity liabilities	(6		)	2		(47		)	(74		)	(125		)	(8		)	—			(59		)	(64		)	(131		)
Total	4			6		(41		)	(74		)	(105		)	29			8			(53		)	(63		)	(79		)

Total derivatives	4			6		(41		)	(74		)	(105		)	29			8			(53		)	(63		)	(79		)
Cash collateral receivable	—			—		18			52			70
Cash collateral (payable) receivable															(3		)	—			16			39			52
Total derivatives - net basis	$	4		$	6	$	(23	)	$	(22	)	$	(35	)	$	26		$	8		$	(37	)	$	(24	)	$	(27	)

As of December 31, 2017
As of December 31, 2018
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	11		$	1	$	1		$	—		$	13		$	36		$	4		$	10		$	1		$	51
Commodity liabilities	(3		)	—		(32		)	(82		)	(117		)	(9		)	(1		)	(67		)	(71		)	(148		)
Total	8			1		(31		)	(82		)	(104		)	27			3			(57		)	(70		)	(97		)

Total derivatives	8			1		(31		)	(82		)	(104		)	27			3			(57		)	(70		)	(97		)
Cash collateral receivable	—			—		17			57			74
Cash collateral (payable) receivable															(2		)	—			16			45			59
Total derivatives - net basis	$	8		$	1	$	(14	)	$	(25	)	$	(30	)	$	25		$	3		$	(41	)	$	(25	)	$	(38	)


(1)	PacifiCorp's commodity derivatives are generally included in rates and as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, a regulatory asset of ~~$102~~$78 million and ~~$101~~$96 million, respectively, was recorded related to the net derivative liability of ~~$105~~$79 million and ~~$104~~$97 million, respectively.

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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018

Beginning balance	$	116		$	95		$	101		$	73		$	96		$	101
Changes in fair value recognized in net regulatory assets	14			6			48			36
Changes in fair value													(54		)	28
Net (losses) gains reclassified to operating revenue	(36		)	(5		)	(30		)	8			(22		)	7
Net gains (losses) reclassified to cost of fuel and energy	8			1			(17		)	(20		)	58			(14		)
Ending balance	$	102		$	97		$	102		$	97		$	78		$	122

Derivative Contract Volumes

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

Unit of September 30, December 31,
Measure 2018 2017

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



	Unit of	March 31,		December 31,
	Measure	2019		2018

Electricity sales, net	Megawatt hours	(4	)	(6	)
Natural gas purchases	Decatherms	110		117

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, 2018,~~March 31, 2019, PacifiCorp's credit ratings ~~from the three recognized~~for its senior secured debt and its issuer credit ~~rating agencies~~ratings for senior unsecured debt by Moody's Investor Service and Standard & Poor's Rating Services were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled ~~$108~~$101 million and ~~$110~~$113 million as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, respectively, for which PacifiCorp had posted collateral of ~~$70~~$55 million and ~~$74~~$61 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, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, PacifiCorp would have been required to post ~~$26~~$32 million and ~~$34~~$35 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.


~~(10)~~(9)	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, 2018
As of March 31, 2019
Assets:
Commodity derivatives	$	—	$	20		$	—	$	(10	)	$	10		$	—	$	52		$	—	$	(18	)	$	34
Money market mutual funds⁽²⁾	310		—			—		—			310			468		—			—		—			468
Investment funds	26		—			—		—			26			24		—			—		—			24
	$	336	$	20		$	—	$	(10	)	$	346		$	492	$	52		$	—	$	(18	)	$	526

Liabilities - Commodity derivatives	$	—	$	(125	)	$	—	$	80		$	(45	)	$	—	$	(131	)	$	—	$	70		$	(61	)

As of December 31, 2017
As of December 31, 2018
Assets:
Commodity derivatives	$	—	$	13		$	—	$	(4	)	$	9		$	—	$	51		$	—	$	(23	)	$	28
Money market mutual funds⁽²⁾	21		—			—		—			21			69		—			—		—			69
Investment funds	21		—			—		—			21			24		—			—		—			24
	$	42	$	13		$	—	$	(4	)	$	51		$	93	$	51		$	—	$	(23	)	$	121

Liabilities - Commodity derivatives	$	—	$	(117	)	$	—	$	78		$	(39	)	$	—	$	(148	)	$	—	$	82		$	(66	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of ~~$70~~$52 million and ~~$74~~$59 million as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, 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 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 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 98 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. 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, 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



	As of March 31, 2019				As of December 31, 2018
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	7,656	$	8,763	$	7,015	$	7,833


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

Commitments

During the ~~nine-month~~three-month period ended ~~September 30,~~March 31, ~~2018~~2019, PacifiCorp entered into non-cancelable agreements through ~~2045~~2020 totaling $~~1.0 billion~~486 million 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.Washington.

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 climate change, renewable portfolio standards, 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

In September 2016, the KRRC and PacifiCorp filed a ~~private, independent nonprofit 501(c)(3) organization formed by certain signatories of the amended KSHA, jointly filed an~~joint application with the FERC to transfer the license for the four ~~mainstem~~main-stem Klamath ~~River hydroelectric generating facilities~~dams from PacifiCorp to the KRRC. ~~Also in September 2016,~~Over the past two years, the KRRC ~~filed an~~has been supplementing the application with additional information about its financial, technical, and legal capacity to become the licensee. The KRRC is expected to provide the FERC ~~to surrender the license~~on July 29, 2019, with additional information, including updated cost estimates, and ~~decommission the same four facilities. The KRRC's license surrender application included a request for~~its insurance, bonding and liability transfer package. Based on that information, the FERC should be in a position to ~~refrain from acting on the surrender application until after the~~determine whether license transfer ~~of the license~~ to the KRRC is ~~effective. In March 2018,~~in the ~~FERC issued an order splitting~~public interest. That information should also allow PacifiCorp and 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 PacifiCorpStates to assess whether the KRRC ~~until some point in~~has the ~~future. PacifiCorp~~ability to satisfy its indemnification obligations under the KHSA, and whether there is ~~currently~~sufficient funding available under 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.

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)~~(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~~following table summarizes PacifiCorp's 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 t~~he ~~three-month period endedSeptember 30, 2018, PacifiCorp financially settled certain non-derivative forward contracts for energy sales by making net payments to counterparties.~~



	Three-Month Periods
	Ended March 31,
	2019		2018
Customer Revenue:
Retail:
Residential	$	489	$	441
Commercial	360		342
Industrial	292		269
Other retail	29		25
Total retail	1,170		1,077
Wholesale	28		22
Transmission	25		22
Other Customer Revenue	16		19
Total Customer Revenue	1,239		1,140
Other revenue	20		44
Total operating revenue	$	1,259	$	1,184

~~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.


~~(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 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. For the nine-month periods ended September 30, 2018 and 2017, PacifiCorp made net cash payments for federal and state income tax to BHE totaling $21 million and $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~~First Quarter ~~and First Nine Months~~ of ~~2018~~2019 and ~~2017~~2018

Overview

Net income for the ~~third~~first quarter of ~~2018~~2019 was ~~$270~~$179 million, an increase of $7$31 million, or 3%21%, compared to ~~2017.~~2018. Net income increased primarily due to ~~a decrease in income tax expense~~higher utility margins of ~~$78~~$43 million ~~from a lower federal tax rate due to the impact~~and higher allowances for borrowed and equity funds used during construction of ~~the Tax Cuts and Jobs Act enacted on December 22, 2017 ("2017 Tax Reform"),~~$10 million, partially offset by ~~lower utility margin of $61 million and~~ higher operations and maintenance expense of ~~$12~~$6 million and higher depreciation and amortization expense of $3 million. Utility margin ~~decreased~~increased due to lower ~~average~~purchased electricity volumes, higher retail ~~and wholesale rates, including $53 million of refund accruals related to~~revenue mainly from higher retail customer volumes, lower net tax deferrals associated with the 2017 Tax Reform ~~higher natural gas costs from higher volumes~~and product mix, and higher ~~purchased electricity from higher prices,~~net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by higher ~~retail~~purchased electricity prices, higher gas and coal-fueled generation costs, and lower wholesale revenue from lower volumes and ~~lower coal~~average prices. Retail customer volumes increased 2%4.3%, due to ~~higher customer usage, primarily from industrial, commercial~~favorable impact of weather and ~~residential customers in Utah, and an~~ increase in the average number of residential and commercial customers across the service territory, higher industrial usage in Wyoming and Washington, higher residential and commercial usage in Utah and higher commercial usage in Oregon, partially offset by ~~impacts of weather across the service territory.~~lower industrial usage in Idaho and Utah, and lower commercial usage in Washington and Idaho. Energy generated increased 7%10% for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to higher natural gas and ~~wind-powered generation, offset by lower~~ coal-fueled ~~and hydroelectric generation. Wholesale electricity sales volumes increased 33% and purchased electricity volumes decreased 17%.~~

Net income for the first nine months of 2018 was $602 million, a decrease of $15 million, or 2%, compared to 2017. Net income decreased primarily due to lower utility margin of $205 million, and higher operations and maintenance expenses of $6 million, partially offset by lower 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 retail revenue from lower average retail rates, including $159 million of refund accruals related to 2017 Tax Reform, and lower retail volumes, higher purchased electricity from higher prices and volumes, lower average wholesale prices, and higher natural gas generation volumes, partially offset by higher wholesale volumes, lower coal costs from lower volumes and prices, and lower average natural gas prices. Retail customer volumes decreased 1% due to the unfavorable impact of weather across the service territory, and lower customer usage, primarily from industrial customers in Oregon and Utah, partially offset by higher commercial and irrigation customer usage in Utah and an increase in the average number of customers across the service territory. Energy generated increased 2% for the first nine months of 2018 compared to 2017 primarily due to higher natural gas and wind-powered generation, offset by lower hydroelectric and ~~coal-fueled~~wind-powered generation. Wholesale electricity sales volumes ~~increased 37%~~decreased 23% and purchased electricity volumes ~~increased 4%~~decreased 30%.

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,~~utility margin, to help evaluate results of operations. Utility ~~Margin~~margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

PacifiCorp's cost of fuel and energy is directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes ~~Utility Margin~~utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of ~~Utility Margin~~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~~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 operating income (in millions):


	Third Quarter									First Nine Months									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Utility margin:
Operating revenue	$	1,369	$	1,430	$	(61	)	(4	)%	$	3,746	3,956		$	(210	)	(5	)%	$	1,259	$	1,184	$	75		6	%
Cost of fuel and energy	465		465		—			—		1,300		1,305		(5		)	—		465		433		32			7
Utility margin	904		965		(61		)	(6	)	2,446		2,651		(205		)	(8	)	794		751		43			6
Operations and maintenance	266		254		12			5		777		771		6			1		256		250		6			2
Depreciation and amortization	203		200		3			2		602		598		4			1		205		202		3			1
Property and other taxes	49		50		(1		)	(2	)	150		149		1			1		49		52		(3		)	(6	)
Operating income	$	386	$	461	$	(75	)	(16	)	$	917	$	1,133	$	(216	)	(19	)	$	284	$	247	$	37		15

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


	Third Quarter									First Nine Months									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Utility margin (in millions):
Operating revenue	$	1,369	$	1,430	$	(61	)	(4	)%	$	3,746	$	3,956	$	(210	)	(5	)%	$	1,259	$	1,184	$	75		6	%
Cost of fuel and energy	465		465		—			—		1,300		1,305		(5		)	—		465		433		32			7
Utility margin	$	904	$	965	$	(61	)	(6	)	$	2,446	$	2,651	$	(205	)	(8	)	$	794	$	751	$	43		6

Sales (GWh):
Residential	4,347		4,372		(25		)	(1	)%	11,996		12,410		(414		)	(3	)%	4,608		4,191		417			10	%
Commercial	4,941		4,783		158			3		13,530		13,303		227			2		4,445		4,298		147			3
Industrial, irrigation and other	5,823		5,683		140			2		15,889		16,061		(172		)	(1	)	4,710		4,706		4			—
Total retail	15,111		14,838		273			2		41,415		41,774		(359		)	(1	)	13,763		13,195		568			4
Wholesale	1,802		1,350		452			33		5,963		4,362		1,601			37		1,887		2,448		(561		)	(23	)
Total sales	16,913		16,188		725			4		47,378		46,136		1,242			3		15,650		15,643		7			—

Average number of retail customers
(in thousands)	1,902		1,868		34			2	%	1,896		1,863		33			2	%	1,921		1,890		31			2	%

Average revenue per MWh:
Retail	$	86.29	$	90.58	$	(4.29	)	(5	)%	$	83.92	$	88.41	$	(4.49	)	(5	)%	$	85.08	$	81.54	$	3.54		4	%
Wholesale	$	9.12	$	28.74	$	(19.62	)	(68	)%	$	21.62	$	29.55	$	(7.93	)	(27	)%	$	24.26	$	26.92	$	(2.66	)	(10	)%

Heating degree days	208		304		(96		)	(32	)%	5,655		6,472		(817		)	(13	)%	5,092		4,336		756			17	%
Cooling degree days	1,532		1,804		(272		)	(15	)%	1,980		2,342		(362		)	(15	)%

Sources of energy (GWh)⁽¹⁾:
Coal	10,510		10,764		(254		)	(2	)%	26,231		27,120		(889		)	(3	)%	9,486		8,642		844			10	%
Natural gas	3,841		2,486		1,355			55		7,770		5,647		2,123			38		3,061		1,948		1,113			57
Hydroelectric⁽²⁾	467		641		(174		)	(27	)	2,640		3,598		(958		)	(27	)	717		1,136		(419		)	(37	)
Wind and other⁽²⁾	569		460		109			24		2,353		2,030		323			16		760		1,069		(309		)	(29	)
Total energy generated	15,387		14,351		1,036			7		38,994		38,395		599			2		14,024		12,795		1,229			10
Energy purchased	2,506		3,023		(517		)	(17	)	11,279		10,845		434			4		2,836		4,055		(1,219		)	(30	)
Total	17,893		17,374		519			3		50,273		49,240		1,033			2		16,860		16,850		10			—

Average cost of energy per MWh:
Energy generated⁽³⁾	$	19.45	$	19.89	$	(0.44	)	(2	)%	$	18.96	$	19.21	$	(0.25	)	(1	)%	$	21.09	$	18.48	$	2.61		14	%
Energy purchased	$	70.75	$	53.34	$	17.41		33	%	$	44.43	$	42.20	$	2.23		5	%	$	57.89	$	40.20	$	17.69		44	%


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


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


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

Utility margin ~~decreased $61~~increased $43 million, or 6%, for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to:

$5956 million of higher retail revenue from higher volumes. Retail volumes increased 4% due to favorable impact of weather and increase in the average number of residential and commercial customers across the service territory, higher industrial usage in Wyoming and Washington, higher residential and commercial usage in Utah and higher commercial usage in Oregon, partially offset by lower industrial usage in Idaho and Utah, and lower commercial usage in Washington and Idaho;

$39 million of higher retail revenue primarily due to lower ~~average retail rates, including~~net tax deferrals associated with the ~~impact of a lower federal tax rate due to~~ 2017 Tax Reform ~~of $53 million;~~

~~$30 million of lower wholesale revenues from lower average prices;~~

~~$23 million of~~and higher ~~natural gas costs~~prices due to ~~higher volumes;~~product mix; and

~~$16 million of higher purchased electricity costs due to higher prices and volumes.~~

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

$31 million of higher net deferrals of incurred net power costs in accordance with established adjustment ~~mechanisms;~~mechanisms.

The increases above were partially offset by:

$1959 million of higher ~~retail revenue~~gas and coal-fueled generation costs 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;~~prices;

$820 million of lower ~~coal costs~~wholesale revenues from lower average volumes and prices; and

$81 million of higher ~~wholesale revenues from~~purchased electricity costs due to $105 million of higher ~~volumes~~.

average market prices, offset by $104 million of lower volumes.

Operations and maintenance increased ~~$12~~$6 million, or 5%2%, for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~reserves accrued for 2018 wildfires~~increased vegetation management, overhead line expenses and ~~higher labor costs.~~increased overtime largely due to storm restoration activities, partially offset by decreased maintenance expense.

Depreciation and amortization increased $3 million, or 2%1%, for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to higher plant-in-service.

~~Income tax expense~~Property and other taxes decreased ~~$78~~$3 million, or ~~62%,~~6% for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017. The effective tax rate was 15% for~~ 2018 ~~and 32% for 2017. The effective tax rate decreased~~ primarily ~~as a result of the reduction~~due to lower property taxes primarily 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. Washington.

~~Utility margin~~Allowance for borrowed and equity funds ~~decreased $205~~increased $10 million, or 8%91%, for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017 primarily due to:~~

~~$184 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 $159 million;~~

~~$44 million of higher purchased electricity costs due to higher prices and volumes;~~

~~$36 million of lower wholesale revenue from lower average prices;~~

~~$34 million of higher natural gas costs due to higher volumes; and~~

$33 million of lower retail revenue from lower retail customer volumes. Retail volumes decreased 1% due to the unfavorable impacts of weather across the service territory, and lower customer usage, primarily from industrial customers in Oregon and Utah, partially offset by higher commercial and irrigation customer usage in Utah and an increase in the average number of customers across the service territory.

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

~~$55 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms;~~

~~$36 million of higher wholesale revenue due to higher volumes;~~

~~$20 million of lower coal costs due to lower volumes and prices; and~~

~~$12 million of lower natural gas costs from lower average prices.~~

~~Operations and maintenance~~ ~~increased $6 million, or 1%, for the first nine months of~~ 2018 ~~compared to 2017 primarily due to reserves accrued for 2018 wildfires, partially offset by lower labor costs.~~

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

Income tax expense ~~decreased $194~~increased $17 million, or ~~66%~~68%, for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017.~~2018. The effective tax rate was 19% for 2019 and 14% for ~~2018 and 32% for 2017.~~2018. The effective tax rate ~~decreased~~increased primarily ~~as a result~~due to the effects of rate making and impacts 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. 2017 Tax Reform settlements.

Liquidity and Capital Resources

As of ~~September 30, 2018,~~March 31, 2019, PacifiCorp's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	308		$	669

Credit facilities	1,200			1,200
Less:
Short-term debt	-
Tax-exempt bond support	(89		)	(256		)
Net credit facilities	1,111			944

Total net liquidity	$	1,419		$	1,613

Credit facilities:
Maturity dates	2021			2021

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$1,480~~$494 million and ~~$1,461~~$533 million, respectively. The change was primarily due to ~~lower current year income tax paid~~increased fuel payments and ~~higher current year collections from wholesale customers, primarily due to timing, partially offset by higher current year purchased power costs and~~ lower ~~current year~~ collections from retail customers, ~~primarily due to the 2017 Tax Reform.~~

including 2017 Tax Reform ~~reduced the federal corporate tax rate from 35% to 21% effective January 1, 2018,~~refunds, and eliminated bonus depreciation on qualifying regulated utility assets 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. wholesale customers.

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~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$(711)~~$(336) million and ~~$(548)~~$(237) million, respectively. The change is ~~primarily the result of a current year~~mainly due to an increase in capital expenditures of ~~$160~~$101 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the ~~nine-month~~three-month period ended ~~September 30, 2018~~March 31, 2019 was ~~$(475)~~$434 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $990 million. Uses of cash consisted substantially of ~~$586~~$350 million for the repayment of long term debt, ~~$400~~$175 million for common stock dividends paid to PPW Holdings LLC and ~~$80~~$30 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~~three-month period ended ~~September 30, 2017~~March 31, 2018 was ~~$(827)~~$(293) million. Uses of cash consisted substantially of ~~$270 million for the repayment of short-term debt, $500~~$250 million for common stock dividends paid to PPW Holdings LLC and ~~$50~~$86 million for the repayment of long-term debt, offset by $44 million net proceeds from short-term debt.

Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of ~~September 30, 2018,~~March 31, 2019, PacifiCorp had no short-term debt outstanding. As of December 31, ~~2017,~~2018, PacifiCorp had ~~$80~~$30 million of short-term debt outstanding at a weighted average interest rate of ~~1.83%~~2.85%.

Long-term Debt

In ~~July 2018,~~March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its ~~4.125%~~4.15% First Mortgage Bonds due ~~January 2049.~~February 2050. PacifiCorp used a portion of the net proceeds to repay the short-term debt that was partially incurred in January 2019 to repay all of PacifiCorp's ~~$500~~$350 million ~~5.65%~~of its 5.50% First Mortgage Bonds due ~~July 2018 and~~January 2019. PacifiCorp intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

In March 2019, PacifiCorp completed a re-offering of variable rate tax-exempt bond obligations totaling $168 million, involving the cancellation, at PacifiCorp's request, of $170 million of letters of credit support by the issuing banks. As a result, PacifiCorp's credit facility support for outstanding variable rate tax-exempt bond obligations increased by $168 million.

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional ~~$725 million~~$1 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance.

~~As of September 30, 2018,~~ PacifiCorp had $170 million of letters of credit providing credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling $168 million plus interest. These letters of credit were fully available as of September 30, 2018 and expire periodicallycurrently has an effective shelf registration statement with the SEC to issue up to $1 billion additional first mortgage bonds through ~~March 2019.~~October 2021.

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 regulatory approvals, 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; 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		Three-Month Periods				Annual
	Ended September 30,				Forecast		Ended March 31,				Forecast
	2017		2018		2018		2018		2019		2019

Transmission system investment	$	75	$	34	$	66	$	9	$	73	$	511
Wind investment	8		76		384		2		59		962
Advanced meter infrastructure	20		44		74
Operating and other	450		559		674		225		205		795
Total	$	553	$	713	$	1,198	$	236	$	337	$	2,268

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

Transmission system investment primarily reflects initial costs for the 140-mile ~~500 kV~~500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program expected to be placed in-service in 2020. Planned spending for the Aeolus-Bridger/Anticline line totals ~~$45~~$399 million in ~~2018.~~2019.

~~Construction of wind-powered generating facilities at PacifiCorp totaling $5 million and $4 million for~~Wind investment includes 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.following:

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.

◦

Construction of wind-powered generating facilities at PacifiCorp totaling $55 million and $1 million for the three-month periods ended March 31, 2019 and 2018, respectively. PacifiCorp anticipates costs for these activities will total an additional $311 million for 2019. 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 10 years once the equipment is placed in-service.

Advanced meter infrastructure ("AMI") includes costs for customer meter replacements and installation of 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 planned in Oregon, California, Utah and Idaho in 2018.

◦

Repowering certain existing wind-powered generating facilities at PacifiCorp totaling $4 million and $1 million for the three-month periods ended March 31, 2019 and 2018, respectively. PacifiCorp anticipates costs for these activities will total an additional $592 million for 2019. 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 10 years following each facility's return to service.

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

Integrated Resource ~~Plan~~Planning

~~In April 2017,~~As required by certain state regulations, PacifiCorp ~~filed~~uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its ~~2017 Integrated Resource Plan ("IRP")~~customers while maintaining compliance with ~~its state commissions. The IRP, which includes~~existing and evolving environmental laws and regulations. As part of 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. The OPUC acknowledged PacifiCorp's 2017 IRP in December 2017, the UPSC acknowledged the 2017 IRP in March 2018, the IPUC acknowledged the 20172019 IRP, in April ~~2018, and~~2019, PacifiCorp released an economic study of the ~~WUTC acknowledged~~coal fleet which will inform how PacifiCorp will meet the ~~2017~~long-term energy needs of its customers. While no resource decision will be made ahead of completion of the 2019 IRP, ~~in May 2018. PacifiCorp~~expected to be filed ~~its 2017 IRP Update with its state commissions, except~~by August 2019, the study identified potential benefits 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.~~customers through retirement of some coal units as early as 2022.

~~Request~~

Requests 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 RFP with the UPSC in June 2017 and with the OPUC in August 2017. The UPSC and the OPUC approved PacifiCorp's 2017R RFP in September 2017. The 2017R RFP ~~was subsequently released to the market on September 27, 2017. The 2017R RFP~~ sought up to approximately 1,270 MWMWs of new wind resources that can interconnect to PacifiCorp's transmission system in Wyoming once a proposed high-voltage transmission line is constructed. The 2017R RFP also 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 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~~plans to ~~acquire energy and capacity~~deliver 1,150 MWs from three new wind facilities ~~totaling 1,150~~under various commercial structures including a power purchase agreement, a build-transfer agreement, and traditional self-build agreements. PacifiCorp has finalized a 200-MW power purchase agreement and a 200-MW build-transfer agreement for one of three new wind facilities. PacifiCorp has also secured agreements for safe harbor wind turbine equipment, acquisition of development assets and balance-of-plant construction for the two remaining projects; one providing 250 MWs ~~consisting~~and a second providing 500 MWs. Agreements for acquisition of ~~950 MWs owned and 200 MWs as a power-purchase agreement.~~follow-on wind turbine equipment for the final two projects was completed in 2019.

Contractual Obligations

As of ~~September 30, 2018,~~March 31, 2019, 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, ~~2017.~~2018, except as disclosed in Note 10.

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~~local regulations regarding climate change, RPS, 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~~local. All such laws and regulations ~~although many~~ are subject to a range of interpretation, ~~that~~which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results. ~~Refer to "Liquidity~~PacifiCorp believes it is in material compliance with all applicable laws and ~~Capital Resources" for discussion of PacifiCorp's forecast environmental-related capital expenditures.~~regulations.

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, ~~2017.~~2018. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, ~~2017.~~2018.

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

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of ~~September 30, 2018,~~March 31, 2019, the related statements of operations, ~~for the three-month and nine-month periods ended September 30, 2018 and 2017, and of~~ changes in shareholder's equity and cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ and 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 balance sheet of MidAmerican Energy as of December 31, ~~2017,~~2018, 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,~~22, 2019, 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,~~2018, 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.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 2, 2018~~May 3, 2019

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	115	$	172	$	432	$	—
Accounts receivable, net	384		344
Trade receivables, net					377		367
Income tax receivable	150		51		19		—
Inventories	205		245		149		204
Other current assets	104		134		94		90
Total current assets	958		946		1,071		661

Property, plant and equipment, net	15,233		14,207		16,545		16,157
Regulatory assets	230		204		260		273
Investments and restricted investments	756		728		761		708
Other assets	211		233		95		121

Total assets	$	17,388	$	16,318	$	18,732	$	17,920

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,		March 31,		December 31,
	2018		2017		2019		2018
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	348	$	452	$	350	$	575
Accrued interest	55		48		69		53
Accrued property, income and other taxes	155		132		162		300
Short-term debt					—		240
Current portion of long-term debt	500		350		—		500
Other current liabilities	153		128		163		122
Total current liabilities	1,211		1,110		744		1,790

Long-term debt	4,880		4,692		6,341		4,879
Regulatory liabilities	1,645		1,661		1,597		1,620
Deferred income taxes	2,322		2,237		2,372		2,322
Asset retirement obligations	546		528		735		552
Other long-term liabilities	325		326		304		311
Total liabilities	10,929		10,554		12,093		11,474

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	5,898		5,203		6,078		5,885
Total shareholder's equity	6,459		5,764		6,639		6,446

Total liabilities and shareholder's equity	$	17,388	$	16,318	$	18,732	$	17,920

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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Regulated electric	$	727		$	707		$	1,785		$	1,677		$	542		$	469
Regulated natural gas and other	105			106			510			489			300			277
Total operating revenue	832			813			2,295			2,166			842			746

Operating expenses:
Cost of fuel and energy	140			130			366			342			114			108
Cost of natural gas purchased for resale and other	50			54			296			288			195			179
Operations and maintenance	201			204			598			561			207			190
Depreciation and amortization	133			111			499			369			177			158
Property and other taxes	30			30			92			90			34			32
Total operating expenses	554			529			1,851			1,650			727			667

Operating income	278			284			444			516			115			79

Other income (expense):
Interest expense	(56		)	(54		)	(170		)	(160		)	(69		)	(58		)
Allowance for borrowed funds	6			4			14			9			6			4
Allowance for equity funds	16			11			39			25			15			10
Other, net	13			9			34			27			20			9
Total other income (expense)	(21		)	(30		)	(83		)	(99		)	(28		)	(35		)

Income before income tax benefit	257			254			361			417			87			44
Income tax benefit	(226		)	(131		)	(334		)	(207		)	(106		)	(62		)

Net income	$	483		$	385		$	695		$	624		$	193		$	106

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		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity		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	$	—	$	561	$	5,203	$	5,764
Net income	—		—		695		695		—		—		106		106
Balance, September 30, 2018	$	—	$	561	$	5,898	$	6,459
Balance, March 31, 2018									$	—	$	561	$	5,309	$	5,870

Balance, December 31, 2018									$	—	$	561	$	5,885	$	6,446
Net income									—		—		193		193
Balance, March 31, 2019									$	—	$	561	$	6,078	$	6,639

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						Three-Month Periods
	Ended September 30,						Ended March 31,
	2018			2017			2019			2018
Cash flows from operating activities:
Net income	$	695		$	624		$	193		$	106
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	499			369			177			158
Amortization of utility plant to other operating expenses	26			25			8			8
Allowance for equity funds	(39		)	(25		)	(15		)	(10		)
Deferred income taxes and amortization of investment tax credits	(35		)	64			31			19
Other, net	13			5			3			2
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(46		)	(29		)
Trade receivables and other assets							(30		)	15
Inventories	40			29			55			37
Derivative collateral, net	—			3			—			(2		)
Contributions to pension and other postretirement benefit plans, net	(10		)	(8		)	(3		)	(3		)
Accrued property, income and other taxes, net	(77		)	98			(159		)	(82		)
Accounts payable and other liabilities	(38		)	18			18			(18		)
Net cash flows from operating activities	1,028			1,173			278			230

Cash flows from investing activities:
Capital expenditures	(1,466		)	(1,162		)	(573		)	(365		)
Purchases of marketable securities	(224		)	(126		)	(71		)	(95		)
Proceeds from sales of marketable securities	198			127			68			74
Other, net	29			(10		)	1			15
Net cash flows from investing activities	(1,463		)	(1,171		)	(575		)	(371		)

Cash flows from financing activities:
Proceeds from long-term debt	687			842			1,460			687
Repayments of long-term debt	(350		)	(255		)	(500		)	(350		)
Net repayments of short-term debt	—			(99		)	(240		)	—
Other, net	(1		)	—
Net cash flows from financing activities	336			488			720			337

Net change in cash and cash equivalents and restricted cash and cash equivalents	(99		)	490			423			196
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	282			26			56			282
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	183		$	516		$	479		$	478

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~~that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of ~~September 30, 2018,~~March 31, 2019, and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2019 and 2018. The results of operations for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018,~~March 31, 2019, 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, ~~2017,~~2018, 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~~three-month period ended ~~September 30, 2018.~~March 31, 2019.


(2)	~~New Accounting Pronouncements~~Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

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 March 31, 2019 and December 31, 2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2019 and December 31, 2018, as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):



	As of
	March 31,		December 31
	2019		2018

Cash and cash equivalents	$	432	$	—
Restricted cash and cash equivalents in other current assets	47		56
Total cash and cash equivalents and restricted cash and cash equivalents	$	479	$	56


(3)	Property, Plant and Equipment, Net

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



		As of
		March 31,			December 31,
	Depreciable Life	2019			2018
Utility plant in service, net:
Generation	20-70 years	$	14,092		$	13,727
Transmission	52-75 years	1,946			1,934
Electric distribution	20-75 years	3,732			3,672
Natural gas distribution	29-75 years	1,734			1,724
Utility plant in service		21,504			21,057
Accumulated depreciation and amortization		(6,076		)	(5,941		)
Utility plant in service, net		15,428			15,116
Nonregulated property, net:
Nonregulated property gross	20-50 years	7			7
Accumulated depreciation and amortization		(1		)	(1		)
Nonregulated property, net		6			6
		15,434			15,122
Construction work-in-progress		1,111			1,035
Property, plant and equipment, net		$	16,545		$	16,157


(4)	Leases

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which 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 inon 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,~~Following the issuance of ASU No. 2016-02, 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~~but did not ~~previously accounted~~change the core principle of the guidance. MidAmerican Energy adopted this guidance 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~~all applicable contracts in-effect as 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 usingJanuary 1, 2019 under a modified retrospective ~~approach. MidAmerican Energy plans to adopt this guidance effective January 1, 2019~~method, and ~~is currently in~~ the ~~process~~adoption did not have a cumulative effect impact at the date of ~~evaluating the~~initial adoption nor a material impact on ~~its~~MidAmerican Energy's Financial Statements and disclosures included within Notes to Financial Statements.


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

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 and December 31, 2017, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. 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 Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):

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,~~February 2019, MidAmerican Energy ~~repaid $350~~redeemed $500 million of its ~~5.30% Senior Notes~~2.40% First Mortgage Bonds due in March ~~2018.~~2019 at a redemption price of 100% of the principal amount plus accrued interest.

~~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				Three-Month Periods
	Ended September 30,				Ended September 30,				Ended March 31,
	2018		2017		2018		2017		2019		2018

Federal statutory income tax rate	21	%	35	%	21	%	35	%	21	%	21	%
Income tax credits	(95	)	(74	)	(97	)	(74	)	(113	)	(137	)
State income tax, net of federal income tax benefit	(10	)	(10	)	(9	)	(7	)	(21	)	(9	)
Effects of ratemaking	(4	)	(2	)	(7	)	(4	)	(8	)	(18	)
Other, net	—		(1	)	(1	)	—		(1	)	2
Effective income tax rate	(88	)%	(52	)%	(93	)%	(50	)%	(122	)%	(141	)%

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.

Due to a combination of declines in pre-tax income and increases in production tax credits in recent years and changes in estimates for these values throughout the year, the volatility of the effective tax rate used to determine the recognition of income tax expense each quarter has similarly increased. MidAmerican Energy concluded that, due to such increased volatility, it was no longer able to reasonably estimate an annual effective tax rate for this purpose. Accordingly, beginning January 1, 2019, production tax credits are recognized in the Statement of Operations as they are earned, and excluded in the determination of the effective tax rate used in the recognition of all other income tax expense. Production tax credits recognized in income for the three-month periods ended March 31, 2019 and 2018 were $98 million and $60 million, respectively, with $30 million of the difference related to the change in the method of interim recognition in 2019.

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~~$14 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 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. MidAmerican Energy adopted this guidance January 1, 2018 prospectively for the capitalization of the service cost component in the Balance Sheets and retrospectively for the presentation of the service cost component and the other components of net benefit cost in the Statements of Operations, applying the practical expedient to use the amounts previously disclosed in the Notes to Financial Statements as the estimation basis for applying the retrospective presentation requirement. As a result, for the three- and nine-month periods ended September 30, 2017, amounts other than the 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 participating subsidiaries, of which $4 million and $14 million, respectively, relates to MidAmerican Energy.

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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Pension:
Service cost	$	2		$	2		$	6		$	7		$	2		$	2
Interest cost	7			8			21			23			7			7
Expected return on plan assets	(11		)	(11		)	(33		)	(33		)	(10		)	(11		)
Net amortization	1			—			2			1			—			1
Net periodic benefit credit	$	(1	)	$	(1	)	$	(4	)	$	(2	)	$	(1	)	$	(1	)

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

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$7 million and $1 million, respectively, during ~~2018.~~2019. As of ~~September 30, 2018, $5~~March 31, 2019, $2 million and $- 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 initiated analysis of additional actions to be taken. As a result of that analysis, MidAmerican Energy will remove all CCR material located below the water table and cap the material 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~~In the first quarter of 2019, ~~with any necessary adjustments to~~MidAmerican Energy increased by $237 million the ~~related~~ asset retirement ~~obligations recognized at that time.~~obligation ("ARO") for the cost of this closure activity. Closure activity on the six existing surface impoundments is estimated to extend through 2023.

The following table presents MidAmerican Energy's ARO liabilities by asset type (in millions):



	As of
	March 31,		December 31,
	2019		2018

Quad Cities Station	$	348	$	345
Fossil-fueled generating facilities	328		93
Wind-powered generating facilities	125		123
Other	1		1
	$	802	$	562

The following table reconciles the beginning and ending balances of MidAmerican Energy's ARO liabilities for the three-month period ended March 31, 2019 (in millions):



Beginning balance	$	562
Change in estimated costs	234
Accretion	6
Ending balance	$	802

Reflected as:
Other current liabilities	$	67
Asset retirement obligations	735
	$	802


(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, 2018:
As of March 31, 2019:
Assets:
Commodity derivatives	$	—	$	4		$	1		$	(2	)	$	3		$	—	$	1		$	—		$	—	$	1
Money market mutual funds⁽²⁾	88		—			—			—			88			410		—			—			—		410
Debt securities:
United States government obligations	183		—			—			—			183			190		—			—			—		190
International government obligations	—		4			—			—			4			—		4			—			—		4
Corporate obligations	—		47			—			—			47			—		47			—			—		47
Municipal obligations	—		2			—			—			2			—		2			—			—		2
Agency, asset and mortgage-backed obligations															—		1			—			—		1
Equity securities:
United States companies	300		—			—			—			300			292		—			—			—		292
International companies	6		—			—			—			6			7		—			—			—		7
Investment funds	21		—			—			—			21			19		—			—			—		19
	$	598	$	57		$	1		$	(2	)	$	654		$	918	$	55		$	—		$	—	$	973

Liabilities - commodity derivatives	$	—	$	(7	)	$	(2	)	$	3		$	(6	)	$	—	$	(3	)	$	(1	)	$	1	$	(3	)


	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, 2017:
As of December 31, 2018:
Assets:
Commodity derivatives	$	—	$	3		$	4		$	(2	)	$	5		$	—	$	4		$	2		$	(3	)	$	3
Money market mutual funds⁽²⁾	133		—			—			—			133			2		—			—			—			2
Debt securities:
United States government obligations	176		—			—			—			176			187		—			—			—			187
International government obligations	—		5			—			—			5			—		4			—			—			4
Corporate obligations	—		36			—			—			36			—		46			—			—			46
Municipal obligations	—		2			—			—			2			—		2			—			—			2
Agency, asset and mortgage-backed obligations															—		1			—			—			1
Equity securities:
United States companies	288		—			—			—			288			256		—			—			—			256
International companies	7		—			—			—			7			6		—			—			—			6
Investment funds	15		—			—			—			15			10		—			—			—			10
	$	619	$	46		$	4		$	(2	)	$	667		$	461	$	57		$	2		$	(3	)	$	517

Liabilities - commodity derivatives	$	—	$	(9	)	$	(1	)	$	2		$	(8	)	$	—	$	(4	)	$	(2	)	$	3		$	(3	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $1 million and $- million as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, 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.~~value, with debt securities primarily accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

The following table reconciles the beginning and ending balances of MidAmerican Energy's 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
Ended September 30, Ended September 30,
2018 2017 2018 2017

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

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, 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



	As of March 31, 2019				As of December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	6,341	$	6,929	$	5,379	$	5,644


(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

MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, 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. MidAmerican Energy believes it is in material compliance with all applicable 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 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, 2018,~~March 31, 2019, has accrued a $10 million liability for refunds under the second complaint of amounts collected under the higher ROE from 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.


(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~~following table summarizes MidAmerican Energy's 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 summarizes MidAmerican Energy's revenue~~ by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 12, (in millions):


	For the Three-Month Period Ended September 30, 2018								For the Three-Month Period Ended March 31, 2019
	Electric		Natural Gas		Other		Total		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	233	$	54	$	—	$	287	$	171	$	175	$	—	$	346
Commercial	100		17		—		117		75		66		—		141
Industrial	268		3		—		271		163		6		—		169
Natural gas transportation services	—		8		—		8		—		12		—		12
Other retail	46		1		—		47		35		1		—		36
Total retail	647		83		—		730		444		260		—		704
Wholesale	62		20		—		82		76		34		—		110
Multi-value transmission projects	14		—		—		14		16		—		—		16
Other Customer Revenue	—		—		2		2		—		—		5		5
Total Customer Revenue	723		103		2		828		536		294		5		835
Other revenue	4		—		—		4		6		1		—		7
Total operating revenue	$	727	$	103	$	2	$	832	$	542	$	295	$	5	$	842


	For the Nine-Month Period Ended September 30, 2018								For the Three-Month Period Ended March 31, 2018
	Electric		Natural Gas		Other		Total		Electric		Natural Gas			Other		Total
Customer Revenue:
Retail:
Residential	$	567	$	287	$	—	$	854	$	161	$	168		$	—	$	329
Commercial	251		100		—		351		71		62			—		133
Industrial	608		13		—		621		145		5			—		150
Natural gas transportation services	—		27		—		27		—		13			—		13
Other retail	113		1		—		114		10		(6		)	—		4
Total retail	1,539		428		—		1,967		387		242			—		629
Wholesale	187		75		—		262		62		32			—		94
Multi-value transmission projects	43		—		—		43		15		—			—		15
Other Customer Revenue	—		—		5		5		—		—			2		2
Total Customer Revenue	1,769		503		5		2,277		464		274			2		740
Other revenue	16		2		—		18		5		1			—		6
Total operating revenue	$	1,785	$	505	$	5	$	2,295	$	469	$	275		$	2	$	746

~~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.


(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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Regulated electric	$	727		$	707		$	1,785		$	1,677		$	542		$	469
Regulated natural gas	103			103			505			485			295			275
Other	2			3			5			4			5			2
Total operating revenue	$	832		$	813		$	2,295		$	2,166		$	842		$	746

Operating income:
Regulated electric	$	278		$	287		$	392		$	475		$	66		$	36
Regulated natural gas	1			(3		)	52			41			48			43
Other	(1		)	—			—			—			1			—
Total operating income	278			284			444			516			115			79
Interest expense	(56		)	(54		)	(170		)	(160		)	(69		)	(58		)
Allowance for borrowed funds	6			4			14			9			6			4
Allowance for equity funds	16			11			39			25			15			10
Other, net	13			9			34			27			20			9
Income before income tax benefit	$	257		$	254		$	361		$	417		$	87		$	44


	As of				As of
	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Assets:
Regulated electric	$	16,066	$	14,914	$	17,373	$	16,511
Regulated natural gas	1,322		1,403		1,357		1,406
Other	—		1		2		3
Total assets	$	17,388	$	16,318	$	18,732	$	17,920

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

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, 2018,~~March 31, 2019, the related consolidated statements of operations, ~~for the three-month and nine-month periods ended September 30, 2018 and 2017, and of~~ changes in member's equity and cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ and 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) 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,~~2018, 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,~~22, 2019, 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,~~2018, 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 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.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

~~November 2, 2018~~May 3, 2019

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	115	$	172	$	433	$	1
Accounts receivable, net	385		348
Trade receivables, net					377		365
Income tax receivable	150		64		19		—
Inventories	205		245		149		204
Other current assets	104		134		94		89
Total current assets	959		963		1,072		659

Property, plant and equipment, net	15,246		14,221		16,557		16,169
Goodwill	1,270		1,270		1,270		1,270
Regulatory assets	230		204		260		273
Investments and restricted investments	758		730		763		710
Other assets	208		233		95		121

Total assets	$	18,671	$	17,621	$	20,017	$	19,202

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,		March 31,		December 31,
	2018		2017		2019		2018
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	348	$	451	$	350	$	575
Accrued interest	57		53		70		58
Accrued property, income and other taxes	155		133		161		300
Note payable to affiliate	158		164		167		156
Short-term debt					—		240
Current portion of long-term debt	500		350		—		500
Other current liabilities	153		128		164		122
Total current liabilities	1,371		1,279		912		1,951

Long-term debt	5,120		4,932		6,581		5,119
Regulatory liabilities	1,645		1,661		1,597		1,620
Deferred income taxes	2,319		2,235		2,369		2,319
Asset retirement obligations	546		528		735		552
Other long-term liabilities	325		326		304		312
Total liabilities	11,326		10,961		12,498		11,873

Commitments and contingencies (Note 10)

Member's equity:
Paid-in capital	1,679		1,679		1,679		1,679
Retained earnings	5,666		4,981		5,840		5,650
Total member's equity	7,345		6,660		7,519		7,329

Total liabilities and member's equity	$	18,671	$	17,621	$	20,017	$	19,202

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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Regulated electric	$	727		$	707		$	1,785		$	1,677		$	542		$	469
Regulated natural gas and other	105			108			512			493			300			278
Total operating revenue	832			815			2,297			2,170			842			747

Operating expenses:
Cost of fuel and energy	140			130			366			342			114			108
Cost of natural gas purchased for resale and other	50			54			297			289			194			180
Operations and maintenance	201			206			599			563			207			190
Depreciation and amortization	133			111			499			369			177			158
Property and other taxes	30			30			92			90			34			32
Total operating expenses	554			531			1,853			1,653			726			668

Operating income	278			284			444			517			116			79

Other income (expense):
Interest expense	(61		)	(59		)	(185		)	(177		)	(75		)	(63		)
Allowance for borrowed funds	6			4			14			9			6			4
Allowance for equity funds	16			11			39			25			15			10
Other, net	12			10			35			28			21			10
Total other income (expense)	(27		)	(34		)	(97		)	(115		)	(33		)	(39		)

Income before income tax benefit	251			250			347			402			83			40
Income tax benefit	(228		)	(133		)	(338		)	(214		)	(107		)	(63		)

Net income	$	479		$	383		$	685		$	616		$	190		$	103

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		Total Member's Equity		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	$	1,679	$	4,981	$	6,660
Net income	—		685		685		—		103		103
Balance, September 30, 2018	$	1,679	$	5,666	$	7,345
Balance, March 31, 2018							$	1,679	$	5,084	$	6,763

Balance, December 31, 2018							$	1,679	$	5,650	$	7,329
Net income							—		190		190
Balance, March 31, 2019							$	1,679	$	5,840	$	7,519

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						Three-Month Periods
	Ended September 30,						Ended March 31,
	2018			2017			2019			2018
Cash flows from operating activities:
Net income	$	685		$	616		$	190		$	103
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	499			369			177			158
Amortization of utility plant to other operating expenses	26			25			8			8
Allowance for equity funds	(39		)	(25		)	(15		)	(10		)
Deferred income taxes and amortization of investment tax credits	(35		)	64			31			19
Other, net	17			4			4			3
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(42		)	(32		)
Trade receivables and other assets							(33		)	19
Inventories	40			29			55			37
Derivative collateral, net	—			3			—			(2		)
Contributions to pension and other postretirement benefit plans, net	(10		)	(8		)	(3		)	(3		)
Accrued property, income and other taxes, net	(65		)	96			(160		)	(83		)
Accounts payable and other liabilities	(41		)	13			14			(21		)
Net cash flows from operating activities	1,035			1,154			268			228

Cash flows from investing activities:
Capital expenditures	(1,466		)	(1,162		)	(573		)	(365		)
Purchases of marketable securities	(224		)	(126		)	(71		)	(95		)
Proceeds from sales of marketable securities	198			127			68			74
Other, net	29			(13		)	—			15
Net cash flows from investing activities	(1,463		)	(1,174		)	(576		)	(371		)

Cash flows from financing activities:
Proceeds from long-term debt	687			842			1,460			687
Repayments of long-term debt	(350		)	(255		)	(500		)	(350		)
Net change in note payable to affiliate	(6		)	21			11			2
Net repayments of short-term debt	—			(99		)	(240		)	—
Other, net	(2		)	—
Net cash flows from financing activities	329			509			731			339

Net change in cash and cash equivalents and restricted cash and cash equivalents	(99		)	489			423			196
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	282			27			57			282
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	183		$	516		$	480		$	478

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

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September 30, 2018,~~March 31, 2019, and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2019 and 2018. The results of operations for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018,~~March 31, 2019, 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, ~~2017,~~2018, 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~~three-month period ended ~~September 30, 2018.~~March 31, 2019.


(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

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~~March 31, 2019 and December 31, ~~2017,~~2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of				As of
	September 30		December 31		March 31		December 31
	2018		2017		2019		2018

Cash and cash equivalents	$	115	$	172	$	433	$	1
Restricted cash and cash equivalents in other current assets	68		110		47		56
Total cash and cash equivalents and restricted cash and cash equivalents	$	183	$	282	$	480	$	57


~~(4)~~(3)	Property, Plant and Equipment, Net

Refer to Note 43 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, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, nonregulated property gross of $24 million and related accumulated depreciation and amortization of ~~$11~~$12 million, ~~and $10 million, respectively,~~ which consisted primarily of a corporate aircraft owned by MHC.


(4)	Leases

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


(5)	Recent Financing Transactions

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


(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
	Ended September 30,				Ended September 30,				Ended March 31,
	2018		2017		2018		2017		2019		2018

Federal statutory income tax rate	21	%	35	%	21	%	35	%	21	%	21	%
Income tax credits	(97	)	(76	)	(101	)	(76	)	(118	)	(151	)
State income tax, net of federal income tax benefit	(10	)	(10	)	(10	)	(8	)	(22	)	(10	)
Effects of ratemaking	(5	)	(2	)	(7	)	(4	)	(9	)	(20	)
Other, net									(1	)	2
Effective income tax rate	(91	)%	(53	)%	(97	)%	(53	)%	(129	)%	(158	)%

Due to a combination of declines in pre-tax income and increases in production tax credits in recent years and changes in estimates for these values throughout the year, the volatility of the effective tax rate used to determine the recognition of income tax expense each quarter has similarly increased. MidAmerican Energy concluded that, due to such increased volatility, it was no longer able to reasonably estimate an annual effective tax rate for this purpose. Accordingly, beginning January 1, 2019, production tax credits are recognized in the Statement of Operations as they are earned, and excluded in the determination of the effective tax rate used in the recognition of all other income tax expense. Production tax credits recognized in income for the three-month periods ended March 31, 2019 and 2018 were $98 million and $60 million, respectively with $30 million of the difference related to the change in the method of interim recognition in 2019.

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Funding received net cash payments for income tax from BHE totaling ~~$248~~$- million and ~~$386~~$14 million for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively.


(7)	Employee Benefit Plans

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


(8)	Asset Retirement Obligations

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


(9)	Fair Value Measurements

Refer to Note 9 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, 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



	As of March 31, 2019				As of December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	6,581	$	7,236	$	5,619	$	5,941


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


(11)	Revenue from Contracts with Customers

Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had $- million and $2$1 million of other Accounting Standards Codification Topic 606 revenue for the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2019 and 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						Three-Month Periods
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Regulated electric	$	727		$	707		$	1,785		$	1,677		$	542		$	469
Regulated natural gas	103			103			505			485			295			275
Other	2			5			7			8			5			3
Total operating revenue	$	832		$	815		$	2,297		$	2,170		$	842		$	747

Operating income:
Regulated electric	$	278		$	287		$	392		$	475		$	66		$	36
Regulated natural gas	1			(3		)	52			41			48			43
Other	(1		)	—			—			1			2			—
Total operating income	278			284			444			517			116			79
Interest expense	(61		)	(59		)	(185		)	(177		)	(75		)	(63		)
Allowance for borrowed funds	6			4			14			9			6			4
Allowance for equity funds	16			11			39			25			15			10
Other, net	12			10			35			28			21			10
Income before income tax benefit	$	251		$	250		$	347		$	402		$	83		$	40


	As of				As of
	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Assets⁽¹⁾:
Regulated electric	$	17,257	$	16,105	$	18,564	$	17,702
Regulated natural gas	1,401		1,482		1,436		1,485
Other	13		34		17		15
Total assets	$	18,671	$	17,621	$	20,017	$	19,202



(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~~First Quarter of 2019 and ~~First Nine Months of~~ 2018 ~~and 2017~~

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the ~~third~~first quarter of ~~2018~~2019 was ~~$483~~$193 million, an increase of ~~$98~~$87 million, or ~~25%~~82%, compared to ~~2017~~2018 primarily due to ahigher electric utility margin of $67 million, higher income tax benefit of ~~$95~~$44 million ~~from~~driven by a ~~$53~~$38 million increase in recognized production tax credits, ~~and a lower federal tax rate~~$30 million of which was due to a change in the ~~impact~~method of ~~2017 Tax Reform,~~interim recognition, higher ~~electric utility margin~~income from corporate-owned life insurance policies of ~~$10~~$9 million, higher allowances for borrowed and equity funds of $7 million ~~due to higher construction balances for wind-powered generation,~~ and higher natural gas utility margin of $4$6 million, partially offset by higher depreciation and amortization of ~~$22~~$19 million from additional plant in-service and Iowa revenue sharing. Electric utility margin increased due to higher retail customer volumes of 6% primarily from industrial growth and the favorable impact of weather, higher wholesale volumes of 37% and higher 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.

MidAmerican Energy's net income for the first nine months of 2018 was $695 million, an increase of $71 million, or 11%, compared to 2017 primarily due to a higher income tax benefit of $127 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 $84 million, higher allowances for borrowed and equity funds of $19 million due to higher construction balances fornew wind-powered generation and other plant additions, higher ~~natural gas utility margin of $12 million, partially offset by higher depreciation~~operations and ~~amortization of $130 million from Iowa revenue sharing and additional plant in-service, higher wind-powered generation~~ maintenance expense of $17 million and higher ~~fossil-fueled generation maintenance~~interest expense of ~~$12 million and increases in other operating expenses.~~$11 million. Electric utility margin increased due to higher recoveries through bill riders, higher retail customer volumes of 7%4.7%, primarily from industrial growth and the favorable impact of weather, and higher electric wholesale ~~revenues from higher average prices,~~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 generation and purchased power costs.~~rates.

MidAmerican Funding -

MidAmerican Funding's net income for the ~~third~~first quarter of ~~2018~~2019 was ~~$479~~$190 million, an increase of ~~$96~~$87 million, or ~~25%~~84%, compared to ~~2017. MidAmerican Funding's net income for the first nine months of 2018 was $685 million, an increase of $69 million, or 11%, compared to 2017.~~2018. 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~~electric utility margin and ~~Natural Gas Utility Margin,~~natural gas utility margin, to help evaluate results of operations. Electric ~~Utility Margin~~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~~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~~generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in ~~MidAmerican Energy's~~those expenses result in comparable changes to revenue from the related recovery ~~mechanisms are comparable to changes in such expenses.~~mechanisms. As such, management believes ~~Electric Utility Margin~~electric utility margin and ~~Natural Gas Utility Margin~~natural gas utility margin more appropriately and concisely ~~explains~~explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of ~~Electric Utility Margin~~electric utility margin and ~~Natural Gas Utility Margin~~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~~utility margin and ~~Natural Gas Utility Margin is~~natural gas utility margin are not ~~a measure~~measures 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									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Electric utility margin:
Regulated electric operating revenue	$	727	$	707	$	20		3	%	$	1,785	$	1,677	$	108		6	%	$	542	$	469	$	73	16	%
Cost of fuel and energy	140		130		10			8		366		342		24			7		114		108		6		6
Electric utility margin	587		577		10			2		1,419		1,335		84			6		428		361		67		19
																	��
Natural gas utility margin:
Regulated natural gas operating revenue	103		103		—			—	%	505		485		20			4		295		275		20		7	%
Cost of natural gas purchased for resale	50		54		(4		)	(7	)	296		288		8			3		193		179		14		8
Natural gas utility margin	53		49		4			8		209		197		12			6		102		96		6		6

Utility margin	640		626		14			2	%	1,628		1,532		96			6		530		457		73		16	%

Other operating revenue	2		3		(1		)	(33	)	5		4		1			25		5		2		3		150
Other cost of sales																			2		—		2		*
Operations and maintenance	201		204		(3		)	(1	)%	598		561		37			7		207		190		17		9	%
Depreciation and amortization	133		111		22			20		499		369		130			35		177		158		19		12
Property and other taxes	30		30		—			—		92		90		2			2		34		32		2		6

Operating income	$	278	$	284	$	(6	)	(2	)%	$	444	$	516	$	(72	)	(14	)	$	115	$	79	$	36	46	%

Regulated Electric Utility Margin

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


	Third Quarter									First Nine Months								First Quarter
	2018		2017		Change					2018		2017		Change				2019		2018		Change
Electric utility margin (in millions):
Operating revenue	$	727	$	707	$	20		3	%	$	1,785	$	1,677	$	108	6	%	$	542	$	469	$	73		16	%
Cost of fuel and energy	140		130		10			8		366		342		24		7		114		108		6			6
Electric utility margin	$	587	$	577	$	10		2		$	1,419	$	1,335	$	84	6		$	428	$	361	$	67		19

Electricity Sales (GWh):
Residential	1,952		1,790		162			9	%	5,307		4,753		554		12	%	1,885		1,786		99			6	%
Commercial	1,025		987		38			4		2,944		2,796		148		5		1,040		985		55			6
Industrial	3,550		3,366		184			5		10,158		9,621		537		6		3,271		3,125		146			5
Other	415		411		4			1		1,218		1,185		33		3		399		403		(4		)	(1	)
Total retail	6,942		6,554		388			6		19,627		18,355		1,272		7		6,595		6,299		296			5
Wholesale	2,160		1,571		589			37		7,179		7,162		17		—		3,276		2,565		711			28
Total sales	9,102		8,125		977			12		26,806		25,517		1,289		5		9,871		8,864		1,007			11

Average number of retail customers (in thousands)	780		771		9			1	%	778		769		9		1	%	785		777		8			1	%

Average revenue per MWh:
Retail	$	93.39	$	98.15	$	(4.76	)	(5	)%	$	78.63	$	78.62	$	0.01	—	%	$	67.22	$	61.66	$	5.56		9	%
Wholesale	$	27.19	$	25.57	$	1.62		6	%	$	25.09	$	23.90	$	1.19	5	%	$	23.37	$	22.66	$	0.71		3	%

Heating degree days	91		44		47			*		4,126		3,203		923		29	%	3,601		3,335		266			8	%
Cooling degree days	784		752		32			4	%	1,295		1,098		197		18	%

Sources of energy (GWh)⁽¹⁾:
Coal	4,559		4,354		205			5	%	11,293		11,019		274		2	%	3,903		3,329		574			17	%
Nuclear	990		961		29			3		2,838		2,820		18		1		916		891		25			3
Natural gas	275		257		18			7		549		274		275		100		18		45		(27		)	(60	)
Wind and other⁽²⁾	2,428		1,929		499			26		9,693		9,129		564		6		4,344		3,985		359			9
Total energy generated	8,252		7,501		751			10		24,373		23,242		1,131		5		9,181		8,250		931			11
Energy purchased	1,054		812		242			30		3,010		2,756		254		9		849		788		61			8
Total	9,306		8,313		993			12		27,383		25,998		1,385		5		10,030		9,038		992			11


*	~~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 utility margin increased ~~$10~~$67 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 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$51 million due to -

an increase of ~~$25~~$36 million, net of fuel costs, from higher recoveries through bill riders (substantially offset in operations and maintenance expense and income tax benefit);

an increase of $20 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~~$9 million in average revenue 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 utility margin of $69 million due to -~~

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

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

~~an increase of $30 million from the impact of 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 $22 million from higher retail energy costs due to higher generation and purchased power costs;~~mix;


(2)	Higher wholesale ~~gross~~utility margin of ~~$16~~$15 million due to higher margins per unit, ~~from~~reflecting lower costs, and higher ~~market prices~~sales volumes; and ~~lower fuel costs; partially offset by~~


(3)	~~Lower MVP~~Higher Multi-Value Projects ("MVP") transmission revenue of $1 ~~million due to refund accruals.~~million.

Regulated Natural Gas Utility Margin

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


	Third Quarter									First Nine Months									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Natural gas utility margin (in millions):
Operating revenue	$	103	$	103	$	—		—	%	$	505	$	485	$	20		4	%	$	295	$	275	$	20		7	%
Cost of natural gas purchased for resale	50		54		(4		)	(7	)	296		288		8			3		193		179		14			8
Natural gas utility margin	$	53	$	49	$	4		8		$	209	$	197	$	12		6		$	102	$	96	$	6		6

Natural gas throughput (000's Dth):
Residential	2,773		2,773		—			—	%	36,493		29,442		7,051			24	%	28,569		26,079		2,490			10	%
Commercial	1,651		1,788		(137		)	(8	)	17,661		14,797		2,864			19		13,284		12,253		1,031			8
Industrial	985		717		268			37		3,690		3,070		620			20		1,546		1,416		130			9
Other	3		2		1			50		33		29		4			14		35		22		13			59
Total retail sales	5,412		5,280		132			3		57,877		47,338		10,539			22		43,434		39,770		3,664			9
Wholesale sales	7,569		8,815		(1,246		)	(14	)	27,940		29,111		(1,171		)	(4	)	11,555		11,176		379			3
Total sales	12,981		14,095		(1,114		)	(8	)	85,817		76,449		9,368			12		54,989		50,946		4,043			8
Natural gas transportation service	21,876		19,784		2,092			11		73,968		65,431		8,537			13		30,543		29,460		1,083			4
Total natural gas throughput	34,857		33,879		978			3		159,785		141,880		17,905			13		85,532		80,406		5,126			6

Average number of retail customers (in thousands)	754		746		8			1	%	755		747		8			1	%	763		757		6			1	%
Average revenue per retail Dth sold	$	13.90	$	13.33	$	0.57		4	%	$	6.95	$	7.93	$	(0.98	)	(12)	%	$	5.72	$	5.81	$	(0.09	)	(2)	%
Average cost of natural gas per retail Dth sold	$	5.48	$	5.56	$	(0.08	)	(1)	%	$	3.81	$	4.33	$	(0.52	)	(12)	%	$	3.65	$	3.70	$	(0.05	)	(1)	%

Combined retail and wholesale average cost of natural gas per Dth sold	$	3.86	$	3.82	$	0.04		1	%	$	3.44	$	3.76	$	(0.32	)	(9)	%	$	3.50	$	3.51	$	(0.01	)	—	%

Heating degree days	92		45		47			*		4,269		3,406		863			25	%	3,726		3,443		283			8	%


*	~~Not meaningful.~~

Regulated natural gas utility margin increased $4$6 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 due to:


(1)	An increase of $5$4 million from rate and non-weather-related usage ~~factors, including~~factors;


(2)	An increase of $2 million from lower tax reform revenue reduction;


(3)	An increase of $1 million from the impact of ~~a lower federal tax rate due to 2017 Tax Reform;~~weather; partially offset by


~~(2)~~(4)	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 $13 million from higher retail sales volumes due to the impact of colder temperatures;~~


~~(2)~~	~~An increase of $1 million from higher natural gas transportation services; partially offset by~~


~~(3)~~	~~A decrease of $2 million from rate and non-weather-related usage factors, including the impact of a lower federal tax rate due to 2017 Tax Reform.~~

Operating Expenses

MidAmerican Energy -

Operations and maintenance ~~decreased $3~~increased $17 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to higher wind-powered generation operations and maintenance of $10 million due to additional wind turbines and easements and higher electric distribution operation and maintenance of $4 million from emergency outage and tree-trimming costs and higher nonregulated operations costs of $4 million, partially offset by lower DSM program expense of $3 million, which is recoverable in bill riders and offset in operating revenue, lower fossil-fueled generation maintenance of $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 $5 million.

~~Operations and maintenance~~ increased $37 million for the first nine months of 2018 compared to 2017 primarily due to higher wind-powered generation maintenance from additional wind turbines of $17 million, higher fossil-fueled generation maintenance of $12 million from planned outages, higher DSM program expense of $9 million and higher 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 operations and maintenance expense of $4 million.revenue.

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

~~Depreciation and amortization~~ ~~increased $130~~$19 million for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 due ~~to higher accruals for Iowa revenue sharing of $83 million and $47 million related~~ to wind-powered generating facilities and other plant placed in-service.

Other Income (Expense)

MidAmerican Energy -

Interest expense increased ~~$2 million and $10~~$11 million for the ~~third~~first quarter ~~and first nine months~~ of ~~2018, respectively,~~2019 compared to ~~2017~~2018 primarily due to higher interest expense from the issuance of ~~$700~~$1.5 billion of first mortgage bonds in January 2019, partially offset by the redemption of $500 million of first mortgage bonds in February 2018, partially offset by the redemption of $350 million of senior notes in March 2018, and additionally for the first nine months comparison, the issuance of $850 million of first mortgage bonds in February 2017.2019.

Allowance for borrowed and equity funds increased $7 million ~~and $19 million~~ for the ~~third~~first quarter ~~and first nine months~~ of ~~2018, respectively,~~2019 compared to ~~2017~~2018 primarily due to higher construction work-in-progress balances related to wind-powered generation.

Other, net increased ~~$4 million and $7~~$11 million for the ~~third~~first quarter ~~and~~ ~~first nine months~~ of ~~2018~~2019~~, respectively,~~ compared to ~~2017~~2018 primarily due to higher returns on corporate-owned life insurance 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 ~~$95~~$44 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017,~~2018, and the effective tax rate was ~~(88)~~(122)% for ~~2018~~2019 and ~~(52)~~(141)% for 2017. For the first nine months of 2018 compared to 2017, MidAmerican Energy's income tax benefit increased $127 million in 2018 compared to 2017, and the effective tax rate was (93)% for 2018 and (50)% for 2017.2018. The ~~changes~~change in the effective tax rates for ~~2018~~2019 compared to ~~2017~~2018 were substantially due to the ~~reduction in 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.~~credits.

~~Production tax credits are recognized in earnings for interim periods based on the application of an estimated annual effective tax rate to pretax earnings.~~ Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for the credits for 10 years from the date the qualifying generating facilities were placed in-service. Due to a combination of declines in pre-tax income and increases in production tax credits in recent years and changes in estimates for these values throughout the year, the volatility of the effective tax rate used to determine the recognition of income tax expense each quarter has similarly increased. MidAmerican Energy concluded that, due to such increased volatility, it was no longer able to reasonably estimate an annual effective tax rate for this purpose. Accordingly, beginning January 1, 2019, production tax credits are recognized in the Statement of Operations as they are earned, and excluded in the determination of the effective tax rate used in the recognition of all other income tax expense. Production tax credits recognized in income for the ~~first nine months of~~three-month periods ended March 31, 2019 and 2018 were ~~$349~~$98 million ~~or $43~~and $60 million, ~~higher than~~respectively, with $30 million of the ~~first nine months of 2017, while production tax credits earned~~difference related to the change in the ~~first nine months~~method of ~~2018 were $220 million, or $20 million higher than the first nine months of 2017 primarily due to wind-powered generation placed in-service~~interim recognition in late 2017, partially offset by facilities no longer eligible to earn production tax credits. The difference between production tax credits recognized and earned of $129 million as of September 30, 2018, will be reflected in earnings over the remainder of 2018.2019.

MidAmerican Funding -

MidAmerican Funding's income tax benefit increased ~~$95~~$44 million for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017,~~2018, and the effective tax rate was ~~(91)~~(129)% for ~~2018~~2019 and ~~(53)~~(158)% for 2017. For the first nine months of 2018 compared to 2017, MidAmerican Funding's income tax benefit increased $124 million of 2018 compared to 2017, and the effective tax rate was (97)% for 2018 and (53)% for 2017.2018. 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, 2018,~~March 31, 2019, MidAmerican Energy's and MidAmerican Funding's total net liquidity 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~~



MidAmerican Energy:
Cash and cash equivalents	$	432

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

MidAmerican Energy total net liquidity	$	967

MidAmerican Funding:
MidAmerican Energy total net liquidity	$	967
Cash and cash equivalents	1
MHC, Inc. credit facility, maturing 2019	4
MidAmerican Funding total net liquidity	$	972

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ were ~~$1,028~~$278 million and ~~$1,173~~$230 million, respectively. MidAmerican Funding's net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ were ~~$1,035~~$268 million and ~~$1,154~~$228 million, respectively. Cash flows from operating activities ~~decreased~~increased primarily due to ~~the timing of MidAmerican Energy's income tax cash flows with BHE and greater payments to vendors, partially offset by~~ higher cash ~~gross margin~~margins for MidAmerican Energy's regulated electric ~~business. MidAmerican Energy's income tax cash flows with BHE totaled net cash receipts in 2018~~wholesale business and ~~2017 of $232 million and $381 million, respectively.~~ lower payments to vendors.

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 2017, 2017 Tax Reform was enacted which, among other items, reduced the federal corporate tax rate from 35% to 21% effective January 1, 2018 and eliminated bonus depreciation on qualifying regulated utility assets 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 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 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 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~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ were ~~$(1,463)~~$(575) million and ~~$(1,171)~~$(371) million, respectively. MidAmerican Funding's net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ were ~~$(1,463)~~$(576) million and ~~$(1,174)~~$(371) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures, which increased due to higher wind-powered generating facility construction expenditures. Purchases and proceeds related to marketable securities ~~primarily~~substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning ~~trust.~~trust and other trust investments.

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$336~~$720 million and ~~$488~~$337 million, respectively. MidAmerican Funding's net cash flows from financing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017,~~ were ~~$329~~$731 million and ~~$509~~$339 million, respectively. In January 2019, MidAmerican Energy issued $700 million of its 3.65% First Mortgage Bonds due 2029 and $900 million of its 4.25% First Mortgage Bonds due 2049.

In February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest. 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 March 2018, MidAmerican Energy repaid $350 million 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 2027 and $475 million of its 3.95% First Mortgage Bonds due 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 $250 million of its 5.95% Senior Notes due July 2017. Through its commercial paper program, MidAmerican Energy made payments totaling ~~$99~~$240 million in ~~2017.~~2019. MidAmerican Funding ~~repaid $6~~received $11 million and ~~received $21~~$2 million in ~~2018~~2019 and ~~2017,~~2018, respectively, through its note payable with BHE.

Debt Authorizations and Related Matters

MidAmerican Energy has authority from the FERC to issue, through July 31, 2020, commercial paper and bank notes aggregating $1.3 billion at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of 400 basis points. MidAmerican Energy has a $900 million unsecured credit facility expiring in June 2021 for which MidAmerican Energy may request that the banks extend the credit facility up to 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 SEC to issue an indeterminate amount of long-term debt securities through 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 $1.5 billion at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points and~~ from the 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 $1.5 billion, of which $500 million expires March 15, 2019, and $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, 2018, MidAmerican Energy's common equity ratio was 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 regulatory approvals, their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

MidAmerican Energy 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; 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		Three-Month Periods				Annual
	Ended September 30,				Forecast		Ended March 31,				Forecast
	2017		2018		2018		2018		2019		2019

Wind-powered generation	$	455	$	704	$	1,254	$	16	$	159	$	1,396
Wind-powered generation repowering	272		233		284		70		27		133
Transmission Multi-Value Projects	18		33		52
Other	417		496		775		279		387		1,100
Total	$	1,162	$	1,466	$	2,365	$	365	$	573	$	2,629

MidAmerican Energy's forecast capital expenditures for ~~2018~~2019 include the following:

The construction of wind-powered generating facilities in Iowa. MidAmerican Energy currently has two wind-powered generation construction projects in progress under ratemaking principles approved by the IUB.

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 ("Wind XI") expected to be placed in service in 2017 through 2019, including ~~334~~a total of 1,151 MW (nominal ratings) placed in-service ~~in 2017. The~~through March 31, 2019. Wind XI ratemaking principles ~~establish~~established 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 in effect prior to 2018. The revised sharing mechanism, which was effective January 1, 2018, will be triggered each year by actual equity returns exceeding a weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of production tax credits available.

The repowering of certain existing wind-powered generating facilities in Iowa. This project entails the replacement of significant components of the oldest turbines in MidAmerican Energy's fleet. The energy production from such repowered facilities is expected to qualify for 100% of the federal production tax credits available for ten years following 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 started the construction of four MVPs located in Iowa and Illinois 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 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~~the revenue sharing mechanism that was effective in 2018. In December 2018, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's construction of up to 591 MWs (nominal ratings) of additional wind-powered generating facilities ("Wind XII") expected to be placed in-service by the end of 2020. Wind XII ratemaking principles establish a cost cap of $922 million, including AFUDC, establish 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 provide that all Iowa retail energy benefits from Wind XII will reduce rate base and be excluded from the Iowa energy adjustment ~~clause and, instead, will reduce rate base.~~clause. Additionally, the ~~settlement agreement modifies~~ratemaking principles modify the ~~current~~Wind XI 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 calculated each year-end and will be the ~~year-end~~ weighted average of equity returns ~~for rate base as~~ authorized via ratemaking principles ~~proceedings~~for certain rate base 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%..The cost caps established by ratemaking principles ensure that as long as total costs for each project are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of production tax credits available. Production tax credits from these projects are excluded from MidAmerican Energy's Iowa energy adjustment clause until these generation assets are reflected in base rates.

The repowering of the oldest of MidAmerican Energy's wind-powered generating facilities in Iowa. The repowering projects entail the replacement of significant components of the facilities, which is expected to qualify such facilities for the re-establishment of production tax credits for ten years following each facility's return to service at rates that depend upon the year in which construction begins. Of the 1,479 MWs of current repowering projects not in-service as of March 31, 2019, 303 MWs are currently expected to qualify for 100% of the federal production tax credits available for ten years following each facility's return to service, 769 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.

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

Contractual Obligations

As of ~~September 30, 2018,~~March 31, 2019, 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, ~~2017.~~2018.

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

On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Offer Price Rule ("MOPR") provisions to apply to existing resources receiving zero emission credit compensation. If successful, an 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~~FERC has not yet issued a decision on the requests.

On April 10, 2019, PJM Interconnection, L.L.C. ("PJM") notified the FERC of its intent to proceed with the ~~FERC's~~next capacity auction in August 2019 under the existing market rules and asked the FERC to clarify that it would not require the PJM to re-run the auction in the event the FERC alters those market rules in its decision ~~with respect~~on the MOPR complaint. It is too early to ~~both proceedings is currently unknown and~~predict the final outcome of each of these ~~matters is currently uncertain.~~proceedings or their potential impact on the continued operation of Quad Cities Station.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, RPS, 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, ~~2017.~~2018. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, ~~2017.~~2018.

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

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, 2018,~~March 31, 2019, the related consolidated statements of operations, ~~for the three-month and nine-month periods ended September 30, 2018 and 2017, and of~~ changes in shareholder's equity and cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ and 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 Nevada Power as of December 31, ~~2017,~~2018, 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,~~22, 2019, 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~~2018 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.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

~~November 2, 2018~~May 3, 2019

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of						As of
	September 30,			December 31,			March 31,			December 31,
	2018			2017			2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	80		$	57		$	51		$	111
Accounts receivable, net	368			238
Trade receivables, net							193			233
Inventories	58			59			63			61
Regulatory assets	16			28			72			39
Other current assets	79			44			64			75
Total current assets	601			426			443			519

Property, plant and equipment, net	6,830			6,877			6,443			6,418
Finance lease right of use assets, net							449			450
Regulatory assets	880			941			862			878
Other assets	41			35			60			37

Total assets	$	8,352		$	8,279		$	8,257		$	8,302

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	168		$	156		$	178		$	187
Accrued interest	33			50			35			38
Accrued property, income and other taxes	128			63			28			30
Current portion of long-term debt							—			500
Current portion of finance lease obligations							24			20
Regulatory liabilities	51			91			50			49
Current portion of long-term debt and financial and capital lease obligations	519			842
Customer deposits	64			73			76			67
Other current liabilities	43			16			38			29
Total current liabilities	1,006			1,291			429			920

Long-term debt and financial and capital lease obligations	2,297			2,233
Long-term debt							2,348			1,853
Finance lease obligations							438			443
Regulatory liabilities	1,123			1,030			1,156			1,137
Deferred income taxes	757			767			750			749
Other long-term liabilities	264			280			301			296
Total liabilities	5,447			5,601			5,422			5,398

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

Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—			—			—			—
Additional paid-in capital	2,308			2,308			2,308			2,308
Retained earnings	601			374			531			600
Accumulated other comprehensive loss, net	(4		)	(4		)	(4		)	(4		)
Total shareholder's equity	2,905			2,678			2,835			2,904

Total liabilities and shareholder's equity	$	8,352		$	8,279		$	8,257		$	8,302

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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018

Operating revenue	$	820		$	819		$	1,777		$	1,785		$	395		$	395

Operating expenses:
Cost of fuel and energy	331			318			740			721			173			170
Operations and maintenance	146			96			344			276			76			91
Depreciation and amortization	85			77			253			231			89			84
Property and other taxes	11			10			31			29			12			10
Total operating expenses	573			501			1,368			1,257			350			355

Operating income	247			318			409			528			45			40

Other income (expense):
Interest expense	(38		)	(44		)	(128		)	(132		)	(47		)	(45		)
Allowance for borrowed funds	—			1			1			1			1			—
Allowance for equity funds	1			—			2			1			1			1
Other, net	7			4			16			16			8			4
Total other income (expense)	(30		)	(39		)	(109		)	(114		)	(37		)	(40		)

Income before income tax expense	217			279			300			414			8			—
Income tax expense	53			103			72			151			2			—
Net income	$	164		$	176		$	228		$	263		$	6		$	—

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
				Additional					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, 2016	1,000	$	—	$	2,308	$	667		$	(3	)	$	2,972
Balance, December 31, 2017															1,000	$	—	$	2,308	$	374		$	(4	)	$	2,678
Net income															—	—		—		—			—			—
Balance, March 31, 2018															1,000	$	—	$	2,308	$	374		$	(4	)	$	2,678

Balance, December 31, 2018															1,000	$	—	$	2,308	$	600		$	(4	)	$	2,904
Net income	—	—		—		263			—			263			—	—		—		6			—			6
Dividends declared	—	—		—		(412		)	—			(412		)	—	—		—		(75		)	—			(75		)
Balance, September 30, 2017	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
Balance, March 31, 2019															1,000	$	—	$	2,308	$	531		$	(4	)	$	2,835

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						Three-Month Periods
	Ended September 30,						Ended March 31,
	2018			2017			2019			2018
Cash flows from operating activities:
Net income	$	228		$	263		$	6		$	—
Adjustments to reconcile net income to net cash flows from operating activities:
Gain on marketable securities	(1		)	—
Gain on nonrecurring items	—			(1		)
Depreciation and amortization	253			231			89			84
Allowance for equity funds	(2		)	(1		)	(1		)	(1		)
Changes in regulatory assets and liabilities	75			25			28			10
Deferred income taxes and amortization of investment tax credits	(7		)	61			2			(7		)
Deferred energy	12			(22		)	(33		)	—
Amortization of deferred energy	13			13			3			3
Other, net	9			(1		)	(5		)	—
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(138		)	(125		)
Trade receivables and other assets							48			57
Inventories	1			6			(2		)	1
Accrued property, income and other taxes, net	54			11
Accrued property, income and other taxes							(11		)	(1		)
Accounts payable and other liabilities	(11		)	9			11			(36		)
Net cash flows from operating activities	486			469			135			110

Cash flows from investing activities:
Capital expenditures	(203		)	(202		)	(113		)	(64		)
Acquisitions	—			(77		)
Other, net	1			4
Proceeds from sale of assets							2			—
Net cash flows from investing activities	(202		)	(275		)	(111		)	(64		)

Cash flows from financing activities:
Proceeds from long-term debt	573			91			495			—
Repayments of long-term debt and financial and capital lease obligations	(836		)	(86		)
Repayments of long-term debt							(500		)	—
Dividends paid	—			(412		)	(75		)	—
Other, net							(3		)	(5		)
Net cash flows from financing activities	(263		)	(407		)	(83		)	(5		)

Net change in cash and cash equivalents and restricted cash and cash equivalents	21			(213		)	(59		)	41
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	66			290			121			66
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	87		$	77		$	62		$	107

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

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(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 ~~and~~that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September 30, 2018~~March 31, 2019 and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The results of operations for the ~~three- and nine-month periods~~three-month period ended ~~September 30, 2018~~March 31, 2019 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, ~~2017~~2018 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, except as disclosed in Note 4, during the ~~nine-month~~three-month period ended ~~September 30, 2018.~~


~~(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.March 31, 2019.


(32)	Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

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~~March 31, 2019 and December 31, ~~2017,~~2018, consist of funds restricted by the Public Utilities Commission of Nevada ("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~~March 31, 2019 and December 31, ~~2017,~~2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Cash and cash equivalents	$	80	$	57	$	51	$	111
Restricted cash and cash equivalents included in other current assets	7		9		11		10
Total cash and cash equivalents and restricted cash and cash equivalents	$	87	$	66	$	62	$	121


~~(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,
2018 2017
Utility plant:
Generation 30 - 55 years $ 3,702
$ 3,707
Distribution 20 - 65 years 3,373
3,314
Transmission 45 - 70 years 1,864
1,860
General and intangible plant 5 - 65 years 820
793
Utility plant 9,759
9,674
Accumulated depreciation and amortization (3,026 ) (2,871 )
Utility plant, net 6,733
6,803
Other non-regulated, net of accumulated depreciation and amortization 45 years 1
1
Plant, net 6,734
6,804
Construction work-in-progress 96
73
Property, plant and equipment, net $ 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.



		As of
	Depreciable Life	March 31,			December 31,
	Depreciable Life	2019			2018
Utility plant:
Generation	30 - 55 years	$	3,725		$	3,720
Distribution	20 - 65 years	3,436			3,411
Transmission	45 - 70 years	1,441			1,439
General and intangible plant	5 - 65 years	710			716
Utility plant		9,312			9,286
Accumulated depreciation and amortization		(2,995		)	(2,966		)
Utility plant, net		6,317			6,320
Other non-regulated, net of accumulated depreciation and amortization	45 years	1			1
Plant, net		6,318			6,321
Construction work-in-progress		125			97
Property, plant and equipment, net		$	6,443		$	6,418


(4)	Leases

Adoption

Nevada Power has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842.

Leases

Lessee

Nevada Power has non-cancelable operating leases primarily for land, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities, office space and vehicles. These leases generally require Nevada Power to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Nevada Power does not include options in its lease calculations unless there is a triggering event indicating Nevada Power is reasonably certain to exercise the option. Nevada Power's accounting policy is to not recognize lease obligations and corresponding right-of-use assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with ASC Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

Nevada Power's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output

Nevada Power's operating right-of-use assets are recorded in other assets and the operating lease liabilities are recorded in current and long-term other liabilities accordingly. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and long-term debt, respectively, to conform to the current period presentation. The following table summarizes Nevada Power's leases recorded on the Consolidated Balance Sheet (in millions):



	As of
	March 31,
	2019
Right-of-use assets:
Operating leases	$	15
Finance leases	449
Total right-of-use assets	$	464

Lease liabilities:
Operating leases	$	18
Finance leases	462
Total lease liabilities	$	480

The following table summarizes Nevada Power's lease costs (in millions):



	Three-Month Period
	Ended March 31,
	2019

Variable	$	108
Operating	1
Finance:
Amortization	3
Interest	10
Total lease costs	$	122

Weighted-average remaining lease term (years):
Operating leases	8.1
Finance leases	31.3

Weighted-average discount rate:
Operating leases	4.5		%
Finance leases	8.7		%

The following table summarizes Nevada Power's supplemental cash flow information relating to leases (in millions):



	Three-Month Period
	Ended March 31,
	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	(1	)
Operating cash flows from finance leases	(11		)
Financing cash flows from finance leases	(3		)
Right-of-use assets obtained in exchange for lease liabilities:
Finance leases	$	1

Nevada Power has the following remaining lease commitments as of (in millions):



	March 31, 2019									December 31, 2018⁽¹⁾
	Operating			Finance			Total			Operating		Capital		Total
2019	$	2		$	46		$	48		$	3	$	59	$	62
2020	3			58			61			3		59		62
2021	3			62			65			3		61		64
2022	2			60			62			3		60		63
2023	2			50			52			2		50		52
Thereafter	10			711			721			10		709		719
Total undiscounted lease payments	22			987			1,009			$	24	$	998	$	1,022
Less - amounts representing interest	(4		)	(525		)	(529		)
Lease liabilities	$	18		$	462		$	480

(1) Amounts included for comparability and accounted for in accordance with ASC Topic 840, "Leases".


(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 and energy in future time periods.

~~Regulatory Rate Review~~2017 Tax Reform

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. Subsequently, Nevada Power filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, Nevada Power filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review.

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 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.

In June 2018, Station Casinos LLC ("Station"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from an alternative ~~providers of a new electric resource~~provider and become a distribution only service customer of Nevada Power. In October 2018, the PUCN approved ~~a stipulation~~an order allowing Station to purchase energy from ~~alternative providers~~another energy supplier subject to conditions, including paying an impact fee of $15 million. In November 2018, Station filed a petition for reconsideration with the PUCN to allow Station to pay its share of the Renewable Base Tariff Energy Rate in a single lump sum, receive a credit for a portion of impact fees previously paid by past 704B applicants and receive a credit for a portion of incremental transmission revenue associated with expected sales to others. In December 2018, the PUCN issued an order granting reconsideration and reaffirming the October 2018 order. In February 2019, the PUCN issued an order allowing Station to alter their expected transition date from December 1, 2018 to October 1, 2019.


(6)	Recent Financing Transactions

Long-Term Debt

In ~~April 2018,~~January 2019, Nevada Power issued ~~$575~~$500 million of its ~~2.75%~~3.70% General and Refunding Mortgage Notes, Series ~~BB,~~CC, due ~~April 2020.~~May 2029. Nevada Power used ~~a portion of~~ the net proceeds to repay all of Nevada Power's ~~$325~~$500 million ~~6.50%~~7.125% General and Refunding Mortgage Notes, Series O,V, 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.March 2019.

~~Credit Facilities~~

In April 2018, Nevada Power amended and restated its existing $400 million secured 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.


~~(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 elimination of the deduction for production activities and limitations on bonus depreciation for utility property.

~~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 3
—

3

—
Effects of ratemaking 1
—
—
—
Other (1 ) 2
—
1
Effective income tax rate 24 %
37 %
24 %
36 %

~~(8)~~(7) 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, 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 ~~receivable from (payable to)~~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,			March 31,		December 31,
	2018			2017			2019		2018
Qualified Pension Plan:
Qualified Pension Plan -
Other long-term liabilities	$	(4	)	$	(23	)	$	26	$	26

Non-Qualified Pension Plans:
Other current liabilities	(1		)	(1		)	1		1
Other long-term liabilities	(10		)	(10		)	9		9

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


~~(9)~~(8)	Fair Value Measurements

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

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

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

The following table presents Nevada Power's 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, 2018
As of March 31, 2019
Assets:
Commodity derivatives	$	—	$	—	$	1		$	1		$	—	$	—	$	4		$	4
Money market mutual funds⁽¹⁾	67		—		—			67			43		—		—			43
Investment funds	2		—		—			2			2		—		—			2
	$	69	$	—	$	1		$	70		$	45	$	—	$	4		$	49

Liabilities - commodity derivatives	$	—	$	—	$	(8	)	$	(8	)	$	—	$	—	$	(9	)	$	(9	)

As of December 31, 2017
Assets - investment funds	$	2	$	—	$	—		$	2
As of December 31, 2018
Assets:
Commodity derivatives											$	—	$	—	$	7		$	7
Money market mutual funds⁽¹⁾											104		—		—			104
Investment funds											1		—		—			1
											$	105	$	—	$	7		$	112

Liabilities - commodity derivatives	$	—	$	—	$	(3	)	$	(3	)	$	—	$	—	$	(4	)	$	(4	)


(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, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, 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.

Nevada Power's investments in money market mutual funds and equity securities 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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018

Beginning balance	$	(9	)	$	(4	)	$	(3	)	$	(14	)	$	3		$	(3	)
Changes in fair value recognized in regulatory assets	2			(1		)	(6		)	(3		)	(9		)	(5		)
Settlements	—			1			2			13			1			—
Ending balance	$	(7	)	$	(4	)	$	(7	)	$	(4	)	$	(5	)	$	(8	)

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, 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



	As of March 31, 2019				As of December 31, 2018
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	2,348	$	2,722	$	2,353	$	2,651


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

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, 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.

Legal Matters

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


~~(11)~~(10)	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~~following table summarizes Nevada Power's 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		Three-Month Periods
	Ended September 30,		Ended September 30,		Ended March 31,
	2018		2018		2019		2018
Customer Revenue:
Retail:
Residential	$	484	$	989	$	200	$	193
Commercial	135		340		90		95
Industrial	164		351		70		79
Other	7		18		5		6
Total fully bundled	790		1,698		365		373
Distribution only service	9		24		7		7
Total retail	799		1,722		372		380
Wholesale, transmission and other	15		38		17		10
Total Customer Revenue	814		1,760		389		390
Other revenue	6		17		6		5
Total revenue	$	820	$	1,777	$	395	$	395

~~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~~First Quarter of 2019 and ~~First Nine Months of~~ 2018 ~~and 2017~~

Overview

Net income for the ~~third~~first quarter of ~~2018~~2019 was ~~$164~~$6 million, ~~a decrease~~an increase of ~~$12~~$6 million ~~or 7%,~~ compared to ~~2017~~2018 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 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"), and $8 million in higher depreciation and amortization, primarily due to various regulatory-directed amortizations established in the Nevada Power 2017 regulatory rate review, partially offset by a decrease in income tax expense of $50 million, primarily from a lower federal tax rate due to the impact of 2017 Tax Reform, and $6 million of lower interest expense on long-term ~~debt.~~

~~Net income for the first nine months~~debt, $8 million of lower settlement costs associated with a personal injury claim in 2018 ~~was $228 million, a decrease of $35 million, or 13%, compared to 2017 primarily due to $68~~and $2 million of higher ~~operations and maintenance expense, mainly~~other income, net due to ~~an accrual for~~higher interest income, partially offset by $4 million of higher earnings sharing ~~established in 2018 as part of the Nevada Power 2017 regulatory rate review~~accrual and ~~increased political activity expenses, $27~~$3 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 2017 Tax Reform, and a $22 million increase in depreciation and amortization, primarily due to 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.margin.

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 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 energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's ~~revenue are~~expenses result in comparable changes to ~~changes in such expenses.~~revenue. 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 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 directly 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									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Utility margin:
Operating revenue	$	820	$	819	$	1		—	%	$	1,777	$	1,785	$	(8	)	—	%	$	395	$	395	$	—		—	%
Cost of fuel and energy	331		318		13			4		740		721		19			3		173		170		3			2
Utility margin	489		501		(12		)	(2	)	1,037		1,064		(27		)	(3	)	222		225		(3		)	(1	)
Operations and maintenance	146		96		50			52		344		276		68			25		76		91		(15		)	(16	)
Depreciation and amortization	85		77		8			10		253		231		22			10		89		84		5			6
Property and other taxes	11		10		1			10		31		29		2			7		12		10		2			20
Operating income	$	247	$	318	$	(71	)	(22	)	$	409	$	528	$	(119	)	(23	)	$	45	$	40	$	5		13

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


	Third Quarter									First Nine Months									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Utility margin (in millions):
Operating revenue	$	820	$	819	$	1		—	%	$	1,777	$	1,785	$	(8	)	—	%	$	395	$	395	$	—		—	%
Cost of fuel and energy	331		318		13			4		740		721		19			3		173		170		3			2
Utility margin	$	489	$	501	$	(12	)	(2	)	$	1,037	$	1,064	$	(27	)	(3	)	$	222	$	225	$	(3	)	(1	)

GWh sold:
GWhs sold:
Residential	4,213		3,899		314			8	%	8,299		7,899		400			5	%	1,608		1,482		126			9	%
Commercial	1,568		1,517		51			3		3,759		3,669		90			2		992		990		2			—
Industrial	1,631		1,783		(152		)	(9	)	4,281		4,870		(589		)	(12	)	1,160		1,234		(74		)	(6	)
Other	61		60		1			2		157		154		3			2		47		50		(3		)	(6	)
Total fully bundled⁽¹⁾	7,473		7,259		214			3		16,496		16,592		(96		)	(1	)	3,807		3,756		51			1
Distribution only service	775		617		158			26		1,938		1,367		571			42		528		492		36			7
Total retail	8,248		7,876		372			5		18,434		17,959		475			3		4,335		4,248		87			2
Wholesale	53		59		(6		)	(10	)	181		214		(33		)	(15	)	144		44		100			*
Total GWh sold	8,301		7,935		366			5		18,615		18,173		442			2
Total GWhs sold																			4,479		4,292		187			4

Average number of retail customers (in thousands):
Residential	828		813		15			2	%	823		809		14			2	%	834		813		21			3	%
Commercial	108		106		2			2		107		106		1			1		109		106		3			3
Industrial	2		2		—			—		2		2		—			—		2		2		—			—
Total	938		921		17			2		932		917		15			2		945		921		24			3

Average per MWh:
Revenue - fully bundled⁽¹⁾	$	105.82	$	109.85	$	(4.03	)	(4	)%	$	102.93	$	104.06	$	(1.13	)	(1	)%	$	95.87	$	99.29	$	(3.42	)	(3	)%
Total cost of energy⁽²⁾	$	41.93	$	42.46	$	(0.53	)	(1	)%	$	44.14	$	41.80	$	2.34		6	%
Wholesale																			$	42.27	$	56.29	$	(14.02	)	(25	)%
Total cost of energy⁽²⁾⁽³⁾																			$	43.32	$	44.60	$	(1.28	)	(3	)%

Heating degree days	—		—		—			—	%	839		791		48			6	%	1,083		816		267			33	%
Cooling degree days	2,580		2,319		261			11	%	4,072		3,808		264			7	%	12		19		(7		)	(37	)%

Sources of energy (GWh)⁽³⁾:
Sources of energy (GWhs)⁽³⁾⁽⁴⁾:
Natural gas	5,282		4,592		690			15	%	11,295		10,338		957			9	%	2,169		2,401		(232		)	(10	)%
Coal	403		367		36			10		891		1,182		(291		)	(25	)	342		249		93			37
Renewables	20		19		1			5		56		57		(1		)	(2	)	12		15		(3		)	(20	)
Total energy generated	5,705		4,978		727			15		12,242		11,577		665			6		2,523		2,665		(142		)	(5	)
Energy purchased	2,214		2,500		(286		)	(11	)	5,209		5,665		(456		)	(8	)	1,475		1,146		329			29
Total	7,919		7,478		441			6		17,451		17,242		209			1		3,998		3,811		187			5

* Not meaningful


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


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

(3)

The average total cost of energy per MWh and sources of energy excludes -81 and ~~39 GWh~~70 GWhs of coal and -497 and ~~481 GWh~~680 GWhs of gas generated energy that is purchased at cost by related parties for the ~~third quarter of~~three-month periods ended March 31, 2019 and 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)~~(4)	GWh amounts are net of energy used by the related generating facilities.

Utility margin decreased ~~$12~~$3 million, or 2%1%, for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to:

$2311 million in lower retail rates due to the tax rate reduction rider ~~as a result of 2017 Tax Reform;~~effective April 2018 and

$153 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.~~2018.

The decrease in utility margin was offset by:

$156 million in higher residential volumes primarily from the impacts of ~~weather;~~weather,

$43 million from higher transmission revenue and

$2 million due to residential customer ~~growth;~~

~~$3 million in higher other revenue primarily from impact fees and revenue relating to customers becoming distribution only service customers;~~

~~$2 million in higher energy efficiency program rate revenue, which is offset in operating and maintenance expense and~~

~~$2 million from higher transmission revenue.~~growth.

Operations and maintenance ~~increased $50~~decreased $15 million, or ~~52%~~16%, for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to anthe impacts of adopting ASC 842, "Leases"("ASC 842") and settlement costs associated with a personal injury claim in 2018, partially offset by a higher accrual for earnings ~~sharing established in 2018 as part of the Nevada Power 2017 regulatory rate review and higher political activity expenses.~~sharing.

Depreciation and amortization increased $8$5 million, or ~~10%~~6%, for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~various regulatory-directed amortizations and increased depreciation expense as a result~~the impacts of ~~the Nevada Power 2017 regulatory rate review.~~adopting ASC 842.

Other income (expense) is favorable $9$3 million, or ~~23%~~8%, for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to lower interest expense on long-term debt, higher interest income and higher ~~interest income.~~other income due to a licensing agreement with a third party, partially offset by the impacts of adopting ASC 842.

Income tax expense ~~decreased $50~~increased $2 million ~~or 49%,~~ for the ~~third~~first quarter of ~~2018~~2019 compared to ~~2017.~~2018 due to higher income before income tax expense. The effective tax rate was ~~24% in 2018 and 37% 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, partially offset by an increase in nondeductible expenses.~~

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

~~$39 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~~2019 and

~~$8 million in lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers.~~

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

~~$17 million in higher residential volumes primarily from the impacts of weather;~~

~~$8 million due to residential customer growth;~~

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

~~$3 million in higher energy efficiency program rate revenue, which is offset in operating and maintenance expense.~~

~~Operations and maintenance~~ ~~increased $68 million, or 25%,~~ 0% for the first ~~nine months~~quarter of ~~2018 compared to 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 $22 million, or 10%, for the first nine months 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 $5 million, or 4%, for the first nine months of 2018 compared to 2017 primarily due to lower interest expense on long-term debt.~~

~~Income tax expense~~ decreased $79 million, or 52%, for the first nine months of 2018 compared to 2017. The effective tax rate was 24% in 2018 and 36% 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, partially offset by an increase in nondeductible expenses.2018.

Liquidity and Capital Resources

As of ~~September 30, 2018,~~March 31, 2019, Nevada Power's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	80	$	51
Credit facility	400		400
Total net liquidity	$	480	$	451
Credit facility:
Maturity date	2021		2021

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$486~~$135 million and ~~$469~~$110 million, respectively. 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 2017, higher~~ payments for operating costs, increased collections of customer advances and ~~higher contributions to the pension plan.~~

~~Nevada Power's income tax cash flows benefited~~proceeds from a licensing agreement with a third party, partially offset by an increase in 2017 and 2016 from 50% bonus depreciation on qualifying assets placed in service and from investment tax credits earned on qualifying 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.fuel costs.

Investing Activities

Net cash flows from investing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$(202)~~$(111) million and ~~$(275)~~$(64) million, respectively. The change was primarily due to ~~the acquisition of the remaining 25% in the Silverhawk generating station in 2017.~~increased capital expenditures.

Financing Activities

Net cash flows from financing activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$(263)~~$(83) million and ~~$(407)~~$(5) million, respectively. The change was due to ~~greater proceeds from issuance~~higher repayments of long-term debt ~~in 2018~~ and dividends paid to NV Energy, Inc. of ~~$412~~$75 million, ~~in 2017 compared to no dividends paid in 2018,~~ partially offset by ~~higher repayments~~greater proceeds from issuance of long-term ~~debt in 2018.~~debt.

~~Ability to Issue~~Long-Term Debt

In January 2019, Nevada Power issued $500 million of its 3.70% General and Refunding Mortgage Notes, Series CC, due May 2029. Nevada Power used the net proceeds to repay all of Nevada Power's ~~ability to issue debt is primarily impacted by its financing authority from the PUCN. Following the April 2018 issuance of $575~~$500 million ~~of general~~7.125% General and ~~refunding mortgage securities,~~ Refunding Mortgage Notes, Series V, maturing in March 2018.

Debt Authorizations

Nevada Power currently 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 ~~$656~~$156 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, 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 regulatory approvals, 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~~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		Three-Month Periods				Annual
	Ended September 30,				Forecast		Ended March 31,				Forecast
	2017		2018		2018		2018		2019		2019

Distribution	41		93		155		27		43		197
Transmission system investment	6		6		19		2		4		40
Other	155		104		157		35		66		225
Total	$	202	$	203	$	331	$	64	$	113	$	462

Nevada Power's 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, 2018,~~March 31, 2019, 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, ~~2017.~~2018.

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 climate change, RPS, 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 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, ~~2017.~~2018. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, ~~2017.~~2018.

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

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, 2018,~~March 31, 2019, the related ~~consolidated~~ statements of operations, ~~for the three-month and nine-month periods ended September 30, 2018 and 2017, and of~~ changes in shareholder's equity and cash flows for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ and 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 Sierra Pacific as of December 31, ~~2017,~~2018, 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,~~22, 2019, 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~~2018 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.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

~~November 2, 2018~~May 3, 2019

SIERRA PACIFIC POWER COMPANY ~~AND SUBSIDIARIES~~

~~CONSOLIDATED~~ BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of						As of
	September 30,			December 31,			March 31,		December 31,
	2018			2017			2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	71		$	4		$	62	$	71
Accounts receivable, net	106			112
Trade receivables, net							95		100
Inventories	53			49			53		52
Regulatory assets	8			32			31		7
Other current assets	32			17			33		33
Total current assets	270			214			274		263

Property, plant and equipment, net	2,938			2,892			2,965		2,947
Regulatory assets	293			300			312		314
Other assets	15			7			66		45

Total assets	$	3,516		$	3,413		$	3,617	$	3,569

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	84		$	92		$	110	$	116
Accrued interest	11			14			11		13
Accrued property, income and other taxes	13			10			17		14
Regulatory liabilities	32			19			23		18
Current portion of long-term debt and financial and capital lease obligations	2			2
Customer deposits	19			15			21		18
Other current liabilities	25			12			23		18
Total current liabilities	186			164			205		197

Long-term debt and financial and capital lease obligations	1,153			1,152
Long-term debt							1,120		1,120
Regulatory liabilities	489			481			491		491
Deferred income taxes	333			330			338		331
Other long-term liabilities	107			114			177		166
Total liabilities	2,268			2,241			2,331		2,305

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	—			—			—		—
Additional paid-in capital	1,111			1,111			1,111		1,111
Retained earnings	138			62			175		153
Accumulated other comprehensive loss, net	(1		)	(1		)
Total shareholder's equity	1,248			1,172			1,286		1,264

Total liabilities and shareholder's equity	$	3,516		$	3,413		$	3,617	$	3,569

The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the financial statements.							The accompanying notes are an integral part of the 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
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Regulated electric	$	225		$	215		$	575		$	534		$	182		$	181
Regulated natural gas	14			15			74			66			37			41
Total operating revenue	239			230			649			600			219			222

Operating expenses:
Cost of fuel and energy	90			76			245			193			82			77
Cost of natural gas purchased for resale	4			4			35			26			19			23
Operations and maintenance	53			41			140			122			44			39
Depreciation and amortization	30			29			89			85			31			30
Property and other taxes	6			6			18			18			6			6
Total operating expenses	183			156			527			444			182			175

Operating income	56			74			122			156			37			47

Other income (expense):
Interest expense	(12		)	(11		)	(33		)	(33		)	(12		)	(10		)
Allowance for borrowed funds	—			1			1			1
Allowance for equity funds	1			1			3			2			1			1
Other, net	3			3			8			5			2			2
Total other income (expense)	(8		)	(6		)	(21		)	(25		)	(9		)	(7		)

Income before income tax expense	48			68			101			131			28			40
Income tax expense	13			24			25			46			6			6
Net income	$	35		$	44		$	76		$	85		$	22		$	34

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

SIERRA PACIFIC POWER COMPANY ~~AND SUBSIDIARIES~~

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

(Amounts in millions, except shares)

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

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

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.



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

Balance, December 31, 2017	1,000	$	—	$	1,111	$	62	$	(1	)	$	1,172
Net income	—	—		—		34		—			34
Balance, March 31, 2018	1,000	$	—	$	1,111	$	96	$	(1	)	$	1,206

Balance, December 31, 2018	1,000	$	—	$	1,111	$	153	$	—		$	1,264
Net income	—	—		—		22		—			22
Balance, March 31, 2019	1,000	$	—	$	1,111	$	175	$	—		$	1,286

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

SIERRA PACIFIC POWER COMPANY ~~AND SUBSIDIARIES~~

~~CONSOLIDATED~~ STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Nine-Month Periods						Three-Month Periods
	Ended September 30,						Ended March 31,
	2018			2017			2019			2018
Cash flows from operating activities:
Net income	$	76		$	85		$	22		$	34
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	89			85			31			30
Allowance for equity funds	(3		)	(2		)	(1		)	(1		)
Changes in regulatory assets and liabilities	32			9			11			12
Deferred income taxes and amortization of investment tax credits	9			46			5			6
Deferred energy	26			(23		)	(22		)	13
Amortization of deferred energy	(6		)	(43		)	(5		)	(4		)
Other, net							(1		)	—
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(3		)	11
Inventories	(5		)	(2		)
Accrued property, income and other taxes, net	(2		)	(2		)
Trade receivables and other assets							7			3
Accrued property, income and other taxes							(2		)	(2		)
Accounts payable and other liabilities	(5		)	(54		)	(1		)	(16		)
Net cash flows from operating activities	208			110			44			75

Cash flows from investing activities:
Capital expenditures	(139		)	(131		)	(52		)	(45		)
Net cash flows from investing activities	(139		)	(131		)	(52		)	(45		)

Cash flows from financing activities:
Repayments of long-term debt and financial and capital lease obligations	(2		)	(1		)
Dividends paid	—			(5		)
Net cash flows from financing activities	(2		)	(6		)	—			—

Net change in cash and cash equivalents and restricted cash and cash equivalents	67			(27		)	(8		)	30
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	8			60			76			8
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	75		$	33		$	68		$	38

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

SIERRA PACIFIC POWER COMPANY ~~AND SUBSIDIARIES~~

NOTES TO ~~CONSOLIDATED~~ FINANCIAL STATEMENTS

(Unaudited)


(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 ~~and~~that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited ~~Consolidated~~ Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited ~~Consolidated~~ Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited ~~Consolidated~~ Financial Statements as of ~~September 30, 2018~~March 31, 2019 and for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The ~~Consolidated~~ Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the ~~three- and nine-month~~three-month periods ended ~~September 30, 2018~~March 31, 2019 and ~~2017.~~2018. The results of operations for the ~~three- and nine-month periods~~three-month period ended ~~September 30, 2018~~March 31, 2019 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, ~~2017~~2018 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, except as disclosed in Note 4, during the ~~nine-month~~three-month period ended ~~September 30, 2018.~~


~~(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 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.March 31, 2019.


(32)	Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

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~~March 31, 2019 and December 31, ~~2017,~~2018, consist of funds restricted by the Public Utilities Commission of Nevada ("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~~March 31, 2019 and December 31, ~~2017,~~2018, as presented in the ~~Consolidated~~ Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the ~~Consolidated~~ Balance Sheets (in millions):


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Cash and cash equivalents	$	71	$	4	$	62	$	71
Restricted cash and cash equivalents included in other current assets	4		4		6		5
Total cash and cash equivalents and restricted cash and cash equivalents	$	75	$	8	$	68	$	76


~~(4)~~(3)	Property, Plant and Equipment, Net

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


		As of							As of
	Depreciable Life	September 30,			December 31,			Depreciable Life	March 31,			December 31,
		2018			2017				2019			2018
Utility plant:
Electric generation	25 - 60 years	$	1,144		$	1,144		25 - 60 years	$	1,132		$	1,132
Electric distribution	20 - 100 years	1,518			1,459			20 - 100 years	1,588			1,568
Electric transmission	50 - 100 years	817			786			50 - 100 years	818			812
Electric general and intangible plant	5 - 70 years	191			181			5 - 70 years	174			185
Natural gas distribution	35 - 70 years	398			390			35 - 70 years	405			403
Natural gas general and intangible plant	5 - 70 years	14			14			5 - 70 years	14			14
Common general	5 - 70 years	305			294			5 - 70 years	318			321
Utility plant		4,387			4,268				4,449			4,435
Accumulated depreciation and amortization		(1,573		)	(1,513		)		(1,585		)	(1,583		)
Utility plant, net		2,814			2,755				2,864			2,852
Other non-regulated, net of accumulated depreciation and amortization	70 years	5			5			70 years	5			5
Plant, net		2,819			2,760				2,869			2,857
Construction work-in-progress		119			132				96			90
Property, plant and equipment, net		$	2,938		$	2,892			$	2,965		$	2,947


(4)	Leases

Adoption

Sierra Pacific has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842.

Leases

Lessee

Sierra Pacific has non-cancelable operating leases primarily for transmission and delivery assets, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require Sierra Pacific to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Sierra Pacific does not include options in its lease calculations unless there is a triggering event indicating Sierra Pacific is reasonably certain to exercise the option. Sierra Pacific's accounting policy is to not recognize lease obligations and corresponding right-of-use assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with ASC Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

Sierra Pacific's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

Sierra Pacific's operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and long-term debt, respectively, to conform to the current period presentation. The following table summarizes Sierra Pacific's leases recorded on the Balance Sheet (in millions):



	As of
	March 31,
	2019
Right-of-use assets:
Operating leases	$	19
Finance leases	38
Total right-of-use assets	$	57

Lease liabilities:
Operating leases	$	19
Finance leases	39
Total lease liabilities	$	58

The following table summarizes Sierra Pacific's lease costs (in millions):



	Three-Month Period
	Ended March 31,
	2019

Variable	$	15
Operating	—
Finance:
Amortization	1
Interest	1
Total lease costs	$	17

Weighted-average remaining lease term (years):
Operating leases	25.7
Finance leases	23.8

Weighted-average discount rate:
Operating leases	4.9		%
Finance leases	7.3		%

The following table summarizes Sierra Pacific's supplemental cash flow information relating to leases (in millions):



	Three-Month Period
	Ended March 31,
	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from finance leases	$	(1	)

Sierra Pacific has the following remaining lease commitments as of (in millions):



	March 31, 2019									December 31, 2018⁽¹⁾
	Operating			Finance			Total			Operating		Capital		Total
2019	$	2		$	4		$	6		$	2	$	6	$	8
2020	2			5			7			2		4		6
2021	2			5			7			2		5		7
2022	1			4			5			1		4		5
2023	1			4			5			1		4		5
Thereafter	27			47			74			28		47		75
Total undiscounted lease payments	35			69			104			$	36	$	70	$	106
Less - amounts representing interest	(16		)	(30		)	(46		)
Lease liabilities	$	19		$	39		$	58

(1) Amounts included for comparability and accounted for in accordance with ASC Topic 840, "Leases".


(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 and energy in future time periods.

2017 Tax Reform

~~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 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 supports an annual rate reduction of $25 million.~~ In March 2018, the PUCN issued an order approving the rate reduction proposed by Sierra ~~Pacific,~~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. In September 2018, the PUCN issued an order directing Sierra Pacific 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. Subsequently, Sierra Pacific filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, Sierra Pacific filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review.

Chapter 704B Applications

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.

(6) Recent Financing Transactions

~~Credit Facilities~~Long-Term Debt

In April ~~2018,~~2019, Sierra Pacific ~~amended~~purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; and ~~restated~~$25 million of its ~~existing $250 million secured credit facility, expiring June 2020, extending~~variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036. Sierra Pacific purchased the ~~expiration date to June 2021~~Series 2016C, Series 2016D and ~~reducing from two to one,~~Series 2016E bonds as required by the ~~available one-year extension options, subject to lender consent.~~


~~(7)~~	~~Income Taxes~~

~~Tax Cuts and Jobs Act~~

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.April 2019, Sierra Pacific ~~has recorded the impacts of 2017 Tax Reform and believes all the impacts to be complete with the exception of interpretations~~entered into a re-offering of the ~~bonus depreciation rules.~~following series of bonds: $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; the Series 2016D bonds; the Series 2016E bonds; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; and $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Series 2016B and Series 2016G bonds were offered at a fixed rate of 1.85%. The Series 2016D, Series 2016E and Series 2016F bonds were offered at a fixed rate of 2.05%. Sierra Pacific ~~has determined~~previously purchased the ~~amounts recorded~~Series 2016B, Series 2016F and ~~the interpretations relating~~Series 2016G bonds on their date of issuance to ~~this items to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary additional information to complete the accounting.~~hold for its own account. Sierra Pacific ~~believes~~holds the Series 2016C bonds for its ~~interpretations for bonus depreciation to be reasonable, however, as the guidance is clarified estimates may change.~~own account and potential future outcomes of regulatory proceedings. Sierra Pacific ~~recorded a current tax benefit and deferred tax expense~~intends to use the net proceeds 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.re-offering for general corporate purposes.

(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				Three-Month Periods
	Ended September 30,				Ended September 30,				Ended March 31,
	2018		2017		2018		2017		2019		2018

Federal statutory income tax rate	21	%	35	%	21	%	35	%	21	%	21	%
Nondeductible expenses	5		—		4		—
Effects of ratemaking	1		—		—		—		—		(5	)
Other									—		(1	)
Effective income tax rate	27	%	35	%	25	%	35	%	21	%	15	%


(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 $6 million to the Qualified Pension Plan and $6 million to the Other Postretirement Plan for the nine-month period ended September 30, 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 ~~receivable from (payable to)~~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,			March 31,		December 31,
	2018			2017			2019		2018
Qualified Pension Plan:
Other assets	$	6		$	—
Qualified Pension Plan -
Other long-term liabilities	—			(2		)	$	19	$	19

Non-Qualified Pension Plans:
Other current liabilities	(1		)	(1		)	1		1
Other long-term liabilities	(8		)	(8		)	7		7

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


(9)	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 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, 2018
Assets - money market mutual funds⁽¹⁾
$ 18
$ —
$ —
$ 18

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

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



	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3			Total
As of March 31, 2019
Assets:
Commodity derivatives	$	—	$	—	$	2		$	2
Money market mutual funds⁽¹⁾	34		—		—			34
	$	34	$	—	$	2		$	36

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

As of December 31, 2018
Assets:
Commodity derivatives	$	—	$	—	$	2		$	2
Money market mutual funds⁽¹⁾	45		—		—			45
	$	45	$	—	$	2		$	47


(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 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, 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



	As of March 31, 2019				As of December 31, 2018
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,120	$	1,196	$	1,120	$	1,167


(10)	Commitments and Contingencies

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, 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. Sierra Pacific 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.


(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~~following table summarizes Sierra Pacific's 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.



	Three-Month Periods
	Ended March 31,
	2019						2018
	Electric		Gas		Total		Electric		Gas		Total
Customer Revenue:
Retail:
Residential	$	68	$	24	$	92	$	68	$	26	$	94
Commercial	54		10		64		57		11		68
Industrial	39		3		42		39		3		42
Other	2		—		2		2		—		2
Total fully bundled	163		37		200		166		40		206
Distribution only service	1		—		1		1		—		1
Total retail	164		37		201		167		40		207
Wholesale, transmission and other	17		—		17		13		—		13
Total Customer Revenue	181		37		218		180		40		220
Other revenue	1		—		1		1		1		2
Total revenue	$	182	$	37	$	219	$	181	$	41	$	222


(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.

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


	Three-Month Periods						Nine-Month Periods						Three-Month Periods
	Ended September 30,						Ended September 30,						Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Regulated electric	$	225		$	215		$	575		$	534		$	182		$	181
Regulated natural gas	14			15			74			66			37			41
Total operating revenue	$	239		$	230		$	649		$	600		$	219		$	222

Operating income:
Regulated electric	$	56		$	71		$	111		$	141		$	29		$	37
Regulated natural gas	—			3			11			15			8			10
Total operating income	56			74			122			156			37			47
Interest expense	(12		)	(11		)	(33		)	(33		)	(12		)	(10		)
Allowance for borrowed funds	—			1			1			1
Allowance for equity funds	1			1			3			2			1			1
Other, net	3			3			8			5			2			2
Income before income tax expense	$	48		$	68		$	101		$	131		$	28		$	40


	As of				As of
	September 30,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Assets:
Regulated electric	$	3,131	$	3,103	$	3,227	$	3,177
Regulated natural gas	300		300		316		314
Regulated common assets⁽¹⁾	85		10		74		78
Total assets	$	3,516	$	3,413	$	3,617	$	3,569


(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, natural gas and resources. Sierra ~~Pacific~~Pacific's electric segment is a summer peaking ~~utility~~ experiencing its highest retail energy sales in response to the demand for air ~~conditioning.~~conditioning and its natural gas segment is winter peaking due to sales in response to the demand for heating. 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~~First Quarter ~~and First Nine Months~~ of ~~2018~~2019 and ~~2017~~2018

Overview

Net income for the ~~third~~first quarter of ~~2018~~2019 was ~~$35~~$22 million, a decrease of $9$12 million, or ~~20%~~35%, compared to ~~2017~~2018 primarily due to ~~$12~~$5 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 income tax expense of $11 million, primarily from a lower federal tax rate due to the impact of 2017 Tax Reform.

Net income for the first nine months of 2018 was $76 million, a decrease of $9 million, or 11%, compared to 2017 primarily due to $18 million of higher operations and maintenance expense, primarily due to increased political activity expenses, and $11$4 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~~effective April 2018 and $2 million of ~~2017 Tax Reform, partially offset by a decrease in income tax~~higher other expense, ~~of $21 million,~~ primarily ~~from a lower federal tax rate~~ due to ~~the impact of 2017 Tax Reform.~~higher pension expense.

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 cost of natural gas purchased for resale are ~~directly~~generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's ~~revenue are~~expenses result in comparable changes to ~~changes in such expenses.~~revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely ~~explains~~explain 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 are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly 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									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Electric utility margin:
Electric operating revenue	$	225	$	215	$	10		5	%	$	575	$	534	$	41		8	%	$	182	$	181	$	1		1	%
Cost of fuel and energy	90		76		14			18		245		193		52			27		82		77		5			6
Electric utility margin	135		139		(4		)	(3	)	330		341		(11		)	(3	)	100		104		(4		)	(4	)

Natural gas utility margin:
Natural gas operating revenue	14		15		(1		)	(7	)%	74		66		8			12	%	37		41		(4		)	(10	)%
Cost of natural gas purchased for resale	4		4		—			—		35		26		9			35		19		23		(4		)	(17	)
Natural gas utility margin	10		11		(1		)	(9	)	39		40		(1		)	(3	)	18		18		—			—

Utility margin	145		150		(5		)	(3	)%	369		381		(12		)	(3	)%	118		122		(4		)	(3	)%

Operations and maintenance	53		41		12			29	%	140		122		18			15	%	44		39		5			13	%
Depreciation and amortization	30		29		1			3		89		85		4			5		31		30		1			3
Property and other taxes	6		6		—			—		18		18		—			—		6		6		—			—

Operating income	$	56	$	74	$	(18	)	(24	)%	$	122	$	156	$	(34	)	(22	)%	$	37	$	47	$	(10	)	(21	)%

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

Electric Utility Margin


	Third Quarter									First Nine Months									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Electric utility margin (in millions):
Electric operating revenue	$	225	$	215	$	10		5	%	$	575	$	534	$	41		8	%	$	182	$	181	$	1		1	%
Cost of fuel and energy	90		76		14			18		245		193		52			27		82		77		5			6
Electric utility margin	$	135	$	139	$	(4	)	(3	)	$	330	$	341	$	(11	)	(3	)	$	100	$	104	$	(4	)	(4	)

GWh sold:
GWhs sold:
Residential	737		736		1			—	%	1,877		1,904		(27		)	(1	)%	655		613		42			7	%
Commercial	874		850		24			3		2,282		2,271		11			—		700		697		3			—
Industrial	867		797		70			9		2,497		2,346		151			6		924		819		105			13
Other	4		4		—			—		12		12		—			—		4		4		—			—
Total fully bundled⁽¹⁾	2,482		2,387		95			4		6,668		6,533		135			2		2,283		2,133		150			7
Distribution only service	375		348		27			8		1,124		1,041		83			8		391		362		29			8
Total retail	2,857		2,735		122			4		7,792		7,574		218			3		2,674		2,495		179			7
Wholesale	109		103		6			6		391		392		(1		)	—		219		171		48			28
Total GWh sold	2,966		2,838		128			5		8,183		7,966		217			3
Total GWhs sold																			2,893		2,666		227			9

Average number of retail customers (in thousands):
Residential	300		295		5			2	%	299		295		4			1	%	303		298		5			2	%
Commercial	48		47		1			2		48		47		1			2		48		47		1			2
Total	348		342		6			2		347		342		5			1		351		345		6			2

Average per MWh:
Revenue - fully bundled⁽¹⁾	$	84.84	$	85.07	$	(0.23	)	—	%	$	80.02	$	75.89	$	4.13		5	%	$	71.50	$	77.93	$	(6.43	)	(8	)%
Revenue - wholesale	$	58.09	$	61.21	$	(3.12	)	(5	)%	$	49.92	$	52.92	$	(3.00	)	(6	)%	$	52.52	$	49.51	$	3.01		6	%
Total cost of energy⁽²⁾	$	36.76	$	28.53	$	8.23		29	%	$	34.57	$	26.07	$	8.50		33	%	$	31.50	$	32.52	$	(1.02	)	(3	)%

Heating degree days	14		118		(104		)	(88	)%	2,639		2,823		(184		)	(7	)%	2,244		2,140		104			5	%
Cooling degree days	1,043		1,070		(27		)	(3	)%	1,283		1,401		(118		)	(8	)%

Sources of energy (GWh)⁽³⁾:
Sources of energy (GWhs)⁽³⁾:
Natural gas	1,480		1,221		259			21	%	3,615		3,227		388			12	%	1,094		1,057		37			4	%
Coal	361		355		6			2		558		457		101			22		340		—		340			*
Renewables	12		12		—			—		30		31		(1		)	(3	)
Renewables⁽⁴⁾																			5		6		(1		)	(17	)
Total energy generated	1,853		1,588		265			17		4,203		3,715		488			13		1,439		1,063		376			35
Energy purchased	785		1,074		(289		)	(27	)	3,090		3,698		(608		)	(16	)	1,179		1,306		(127		)	(10	)
Total	2,638		2,662		(24		)	(1	)	7,293		7,413		(120		)	(2	)	2,618		2,369		249			11

* Not meaningful


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

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

(2)

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 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.costs.


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


(4)	Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.

Natural Gas Utility Margin


	Third Quarter									First Nine Months									First Quarter
	2018		2017		Change					2018		2017		Change					2019		2018		Change
Natural gas utility margin (in millions):
Natural gas operating revenue	$	14	$	15	$	(1	)	(7	)%	$	74	$	66	$	8		12	%	$	37	$	41	$	(4	)	(10	)%
Cost of natural gas purchased for resale	4		4		—			—		35		26		9			35		19		23		(4		)	(17	)
Natural gas utility margin	$	10	$	11	$	(1	)	(9	)	$	39	$	40	$	(1	)	(3	)	$	18	$	18	$	—		—

Dth sold:
Dths sold:
Residential	740		835		(95		)	(11	)%	6,520		6,866		(346		)	(5	)%	5,013		4,319		694			16	%
Commercial	464		494		(30		)	(6	)	3,364		3,522		(158		)	(4	)	2,497		2,112		385			18
Industrial	267		244		23			9		1,364		1,255		109			9		670		690		(20		)	(3	)
Total retail	1,471		1,573		(102		)	(6	)	11,248		11,643		(395		)	(3	)	8,180		7,121		1,059			15

Average number of retail customers (in thousands)	167		164		3			2	%	167		164		3			2	%	169		166		3			2	%
Average revenue per retail Dth sold	$	8.98	$	8.59	$	0.39		5	%	$	6.44	$	5.47	$	0.97		18	%	$	4.52	$	5.61	$	(1.09	)	(19	)%
Average cost of natural gas per retail Dth sold	$	2.69	$	2.53	$	0.16		6	%	$	3.11	$	2.20	$	0.91		41	%	$	2.32	$	3.20	$	(0.88	)	(28	)%
Heating degree days	14		118		(104		)	(88	)%	2,639		2,823		(184		)	(7	)%	2,244		2,140		104			5	%

Electric utility margin decreased $4 million, or ~~3%, for the third quarter of 2018 compared to 2017 primarily due to lower retail rates due to the tax rate reduction rider as a result of 2017 Tax Reform.~~

~~Operations and maintenance~~ ~~increased $12 million, or 29%, for the third quarter of 2018 compared to 2017 primarily due to increased political activity expenses and higher transmission and distribution costs.~~

~~Income tax expense~~ decreased $11 million, or 46%, for the third quarter of 2018 compared to 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 unfavorable effects of ratemaking.

~~Electric utility margin~~ ~~decreased $11 million, or 3%~~4%, for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due ~~to:~~

~~$12~~to $6 million in lower retail rates due to the tax rate reduction rider ~~as a result of 2017 Tax Reform and~~

$2effective April 2018, partially offset by $2 million in ~~lower customer~~higher residential volumes primarily from the impacts of weather.

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

~~$1 million due to customer growth.~~

Operations and maintenance increased ~~$18~~$5 million, or ~~15%~~13%, for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~increased political activity expenses and~~ higher transmission and distribution ~~costs.~~

~~Depreciation~~costs and ~~amortization~~higher generation plant costs, partially offset by the impacts of adopting ASC 842, "Leases"("ASC 842" ~~increased $4 million, or 5%, for the first nine months of 2018 compared to 2017 primarily due to higher plant placed in service.~~).

Other income (expense) is ~~favorable $4~~unfavorable $2 million, or ~~16%~~29%, for the first ~~nine months~~quarter of ~~2018~~2019 compared to ~~2017~~2018 primarily due to ~~lower~~higher pension ~~expense.~~

~~Income tax~~ expense ~~decreased $21 million, or 46%, for~~ and the ~~first nine months~~impacts of 2018 compared to 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 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.adopting ASC 842.

Liquidity and Capital Resources

As of ~~September 30, 2018,~~March 31, 2019, Sierra Pacific's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	71		$	62

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

Total net liquidity	$	241		$	232
Credit facility:
Maturity date	2021			2021

Operating Activities

Net cash flows from operating activities for the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$208~~$44 million and ~~$110~~$75 million, respectively. The change was due to ~~a decrease~~an increase in fuel costs and ~~increased collections from customers due to~~ higher ~~deferred energy rates,~~payments for operating costs, partially offset by ~~higher federal tax payments and higher~~lower contributions to the pension plan.

Sierra Pacific's income tax cash flows benefited in 2017 and 2016 from 50% bonus depreciation on qualifying assets placed in service. 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, 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~~three-month periods ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~ were ~~$(139)~~$(52) million and ~~$(131)~~$(45) million, respectively. The change was due to increased capital expenditures.

~~Financing Activities~~

Net cash flows from financing activities for the nine-month periods ended September 30, 2018 and 2017 were $(2) million and $(6) million, respectively. The change was primarily due to dividends paid to NV Energy, Inc. in 2017.

~~Ability to Issue~~Long-Term Debt

~~Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of September 30, 2018,~~In April 2019, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; and $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036. Sierra Pacific purchased the Series 2016C, Series 2016D and Series 2016E bonds as required by the bond indentures.

In April 2019, Sierra Pacific entered into a reoffering of the following series of bonds: $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; the Series 2016D bonds; the Series 2016E bonds; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; and $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Series 2016B and Series 2016G bonds were offered at a fixed rate of 1.85%. The Series 2016D, Series 2016E and Series 2016F bonds were offered at a fixed rate of 2.05%. Sierra Pacific previously purchased the Series 2016B, Series 2016F and Series 2016G bonds on their date of issuance to hold for its own account. Sierra Pacific holds the Series 2016C bonds for its own account and potential future outcomes of regulatory proceedings. Sierra Pacific intends to use the net proceeds of the reoffering for general corporate purposes.

Debt Authorizations

Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) ~~issue additional long-term~~establish debt ~~securities~~issuances limited to a debt ceiling of ~~up to $350 million;~~$1.6 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (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, 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 regulatory approvals, 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~~

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		Three-Month Periods				Annual
	Ended September 30,				Forecast		Ended March 31,				Forecast
	2017		2018		2018		2018		2019		2019

Distribution	$	61	$	101	$	158	$	31	$	34	$	174
Transmission system investment	9		3		5		1		2		22
Other	61		35		51		13		16		71
Total	$	131	$	139	$	214	$	45	$	52	$	267

Sierra Pacific's 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, 2018,~~March 31, 2019, 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, ~~2017.~~2018.

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 climate change, RPS, 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, ~~2017.~~2018. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, ~~2017.~~2018.


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, ~~2017~~2018. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, ~~2017~~2018. Refer to Note 98 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of ~~September 30, 2018~~March 31, 2019.


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, 2018~~March 31, 2019 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, ~~2017~~2018.


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 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~~Firm..


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


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


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


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

PACIFICORP


15.2	Awareness Letter of Independent Registered Public Accounting ~~Firm~~Firm..


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


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


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


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


~~Exhibit No.~~	~~Description~~

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP


~~4.3~~4.1	~~Twenty-Ninth~~Thirtieth Supplemental Indenture, dated as of ~~July~~March 1, ~~2018,~~2019, 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)1, 2019).


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

MIDAMERICAN ENERGY


15.3	Awareness Letter of Independent Registered Public Accounting ~~Firm~~Firm..


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


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


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


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


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


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


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


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


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


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


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


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


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


32.12	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002~~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,~~March 31, 2019, 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 2, 2018~~May 3, 2019	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Executive Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	PACIFICORP

Date: ~~November 2, 2018~~May 3, 2019	/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 2, 2018~~May 3, 2019	/s/ Thomas B. Specketer
	Thomas B. Specketer
	Vice President and Controller
	of MidAmerican Funding, LLC and
	Vice President and Chief Financial Officer
	of MidAmerican Energy Company
	(principal financial and accounting officer)

	NEVADA POWER COMPANY

Date: ~~November 2, 2018~~May 3, 2019	/s/ Michael E. Cole
	Michael E. Cole
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	SIERRA PACIFIC POWER COMPANY

Date: ~~November 2, 2018~~May 3, 2019	/s/ Michael E. Cole
	Michael E. Cole
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)

~~170~~154



Item 1.	Legal Proceedings	~~166~~151
Item 1A.	Risk Factors	~~166~~151
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	~~166~~151
Item 3.	Defaults Upon Senior Securities	~~166~~151
Item 4.	Mine Safety Disclosures	~~166~~151
Item 5.	Other Information	~~166~~151
Item 6.	Exhibits	~~166~~151
Signatures		~~170~~154