PACIFICORP /OR/ - Quarter Report: 2019 March (Form 10-Q)

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 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 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 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 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 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 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 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	150
Item 4.	Controls and Procedures	150

PART II



Item 1.	Legal Proceedings	151
Item 1A.	Risk Factors	151
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	151
Item 3.	Defaults Upon Senior Securities	151
Item 4.	Mine Safety Disclosures	151
Item 5.	Other Information	151
Item 6.	Exhibits	151
Signatures		154

Definition of Abbreviations and Industry Terms

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



Berkshire Hathaway Energy Company and Related Entities
BHE		Berkshire Hathaway Energy Company
Berkshire Hathaway		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
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
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
BHE Transmission		Consists of BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada		BHE Canada Holdings Corporation
AltaLink		AltaLink, L.P.
BHE U.S. Transmission		BHE U.S. Transmission, LLC
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
Domestic Regulated Businesses		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		Decatherm
EBA		Energy Balancing Account
ECAM		Energy Cost Adjustment Mechanism
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States of America
GEMA		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		Megawatt
MWh		Megawatt Hour
Ofgem		Office of Gas and Electric Markets
OPUC		Oregon Public Utility Commission
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;


•	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 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		51
Consolidated Balance Sheets		52
Consolidated Statements of Operations		54
Consolidated Statements of Changes in Shareholders' Equity		55
Consolidated Statements of Cash Flows		56
Notes to Consolidated Financial Statements		57
MidAmerican Energy Company
Report of Independent Registered Public Accounting Firm		74
Balance Sheets		75
Statements of Operations		77
Statements of Changes in Shareholder's Equity		78
Statements of Cash Flows		79
Notes to Financial Statements		80
MidAmerican Funding, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm		89
Consolidated Balance Sheets		90
Consolidated Statements of Operations		92
Consolidated Statements of Changes in Member's Equity		93
Consolidated Statements of Cash Flows		94
Notes to Consolidated Financial Statements		95
Nevada Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm		109
Consolidated Balance Sheets		110
Consolidated Statements of Operations		111
Consolidated Statements of Changes in Shareholder's Equity		112
Consolidated Statements of Cash Flows		113
Notes to Consolidated Financial Statements		114
Sierra Pacific Power Company
Report of Independent Registered Public Accounting Firm		130
Balance Sheets		131
Statements of Operations		132
Statements of Changes in Shareholder's Equity		133
Statements of Cash Flows		134
Notes to Financial Statements		135


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



Berkshire Hathaway Energy Company and its subsidiaries		28
PacifiCorp and its subsidiaries		67
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company		99
Nevada Power Company and its subsidiaries		123
Sierra Pacific Power Company		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 March 31, 2019, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for the three-month periods ended March 31, 2019 and 2018, 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, 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 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, 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

May 3, 2019

BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	March 31,		December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	1,661	$	627
Restricted cash and cash equivalents	181		227
Trade receivables, net	1,898		2,038
Inventories	785		844
Mortgage loans held for sale	506		468
Other current assets	1,080		943
Total current assets	6,111		5,147

Property, plant and equipment, net	68,948		68,087
Goodwill	9,663		9,595
Regulatory assets	2,898		2,896
Investments and restricted cash and cash equivalents and investments	4,877		4,903
Other assets	2,048		1,561

Total assets	$	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
	March 31,			December 31,
	2019			2018
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,434		$	1,809
Accrued interest	522			469
Accrued property, income and other taxes	475			599
Accrued employee expenses	316			275
Short-term debt	2,214			2,516
Current portion of long-term debt	1,078			2,081
Other current liabilities	1,358			1,021
Total current liabilities	7,397			8,770

BHE senior debt	8,228			8,577
BHE junior subordinated debentures	100			100
Subsidiary debt	28,510			25,492
Regulatory liabilities	7,347			7,346
Deferred income taxes	9,080			9,047
Other long-term liabilities	3,721			3,134
Total liabilities	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	6,355			6,371
Long-term income tax receivable	(457		)	(457		)
Retained earnings	25,968			25,624
Accumulated other comprehensive loss, net	(1,830		)	(1,945		)
Total BHE shareholders' equity	30,036			29,593
Noncontrolling interests	126			130
Total equity	30,162			29,723

Total liabilities and equity	$	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
	Ended March 31,
	2019			2018
Operating revenue:
Energy	$	3,825		$	3,679
Real estate	785			761
Total operating revenue	4,610			4,440

Operating expenses:
Energy:
Cost of sales	1,214			1,168
Operations and maintenance	802			785
Depreciation and amortization	720			704
Property and other taxes	149			143
Real estate	806			769
Total operating expenses	3,691			3,569

Operating income	919			871

Other income (expense):
Interest expense	(477		)	(466		)
Capitalized interest	16			12
Allowance for equity funds	32			21
Interest and dividend income	30			26
Losses on marketable securities, net	(68		)	(209		)
Other, net	35			30
Total other income (expense)	(432		)	(586		)

Income before income tax benefit and equity (loss) income	487			285
Income tax benefit	(148		)	(221		)
Equity (loss) income	(10		)	12
Net income	625			518
Net income attributable to noncontrolling interests	3			5
Net income attributable to BHE shareholders	$	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
	Ended March 31,
	2019			2018

Net income	$	625		$	518

Other comprehensive income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(7) and $(4)	(32		)	(3		)
Foreign currency translation adjustment	155			73
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	740			586
Comprehensive income attributable to noncontrolling interests	3			5
Comprehensive income attributable to BHE shareholders	$	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
							Long-term						Accumulated
				Additional			Income						Other
	Common			Paid-in			Tax			Retained			Comprehensive			Noncontrolling			Total
	Shares	Stock		Capital			Receivable			Earnings			Loss, Net			Interests			Equity

Balance, December 31, 2017	77	$	—	$	6,368		$	—		$	22,206		$	(398	)	$	132		$	28,308
Adoption of ASU 2016-01	—	—		—			—			1,085			(1,085		)	—			—
Net income	—	—		—			—			513			—			4			517
Other comprehensive income	—	—		—			—			—			68			—			68
Common stock purchases	—	—		(5		)	—			(85		)	—			—			(90		)
Distributions	—	—		—			—			—			—			(9		)	(9		)
Balance, March 31, 2018	77	$	—	$	6,363		$	—		$	23,719		$	(1,415	)	$	127		$	28,794

Balance, December 31, 2018	77	$	—	$	6,371		$	(457	)	$	25,624		$	(1,945	)	$	130		$	29,723
Net income	—	—		—			—			622			—			3			625
Other comprehensive income	—	—		—			—			—			115			—			115
Common stock purchases	—	—		(16		)	—			(277		)	—			—			(293		)
Distributions	—	—		—			—			—			—			(7		)	(7		)
Other equity transactions	—	—		—			—			(1		)	—			—			(1		)
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)



	Three-Month Periods
	Ended March 31,
	2019			2018
Cash flows from operating activities:
Net income	$	625		$	518
Adjustments to reconcile net income to net cash flows from operating activities:
Losses on marketable securities, net	68			209
Depreciation and amortization	733			716
Allowance for equity funds	(32		)	(21		)
Equity loss (income), net of distributions	26			(5		)
Changes in regulatory assets and liabilities	(52		)	94
Deferred income taxes and amortization of investment tax credits	(21		)	(166		)
Other, net	1			19
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	144			250
Derivative collateral, net	(3		)	(14		)
Pension and other postretirement benefit plans	(21		)	(21		)
Accrued property, income and other taxes, net	(48		)	(60		)
Accounts payable and other liabilities	68			(40		)
Net cash flows from operating activities	1,488			1,479

Cash flows from investing activities:
Capital expenditures	(1,393		)	(1,075		)
Acquisitions, net of cash acquired	(26		)	—
Purchases of marketable securities	(159		)	(155		)
Proceeds from sales of marketable securities	153			132
Equity method investments	(7		)	(156		)
Other, net	17			31
Net cash flows from investing activities	(1,415		)	(1,223		)

Cash flows from financing activities:
Proceeds from BHE senior debt	—			2,176
Common stock purchases	(293		)	(90		)
Proceeds from subsidiary debt	2,945			687
Repayments of subsidiary debt	(1,420		)	(550		)
Net repayments of short-term debt	(311		)	(1,873		)
Other, net	(21		)	(14		)
Net cash flows from financing activities	900			336

Effect of exchange rate changes	1			1

Net change in cash and cash equivalents and restricted cash and cash equivalents	974			593
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	883			1,283
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	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 ("BHE Canada") (which primarily consists of AltaLink, L.P. ("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, geothermal and hydroelectric projects, the 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 March 31, 2019 and for the three-month periods ended March 31, 2019 and 2018. The results of operations for the three-month period ended 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, 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 three-month period ended March 31, 2019.


(2)	Property, Plant and Equipment, Net

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



		As of
	Depreciable	March 31,			December 31,
	Life	2019			2018
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	77,659		$	76,707
Interstate natural gas pipeline assets	3-80 years	7,547			7,524
		85,206			84,231
Accumulated depreciation and amortization		(26,253		)	(25,894		)
Regulated assets, net		58,953			58,337

Nonregulated assets:
Independent power plants	5-30 years	6,844			6,826
Other assets	3-30 years	1,474			1,424
		8,318			8,250
Accumulated depreciation and amortization		(1,711		)	(1,610		)
Nonregulated assets, net		6,607			6,640

Net operating assets		65,560			64,977
Construction work-in-progress		3,388			3,110
Property, plant and equipment, net		$	68,948		$	68,087

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


(3)	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
	March 31,		December 31,
	2019		2018
Investments:
BYD Company Limited common stock	$	1,356	$	1,435
Rabbi trusts	394		371
Other	180		168
Total investments	1,930		1,974

Equity method investments:
BHE Renewables tax equity investments	1,627		1,661
Electric Transmission Texas, LLC	529		527
Bridger Coal Company	97		99
Other	158		153
Total equity method investments	2,411		2,440

Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	545		504
Restricted cash and cash equivalents	196		256
Total restricted cash and cash equivalents and investments	741		760

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

Reflected as:
Current assets	$	205	$	271
Noncurrent assets	4,877		4,903
Total investments and restricted cash and cash equivalents and investments	$	5,082	$	5,174

Investments

Losses on marketable securities, net recognized during the period consists of the following (in millions):



	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	)

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 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 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	$	1,661	$	627
Restricted cash and cash equivalents	181		227
Investments and restricted cash and cash equivalents and investments	15		29
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,857	$	883

(4) Leases

Adoption

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 on 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. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. The Company 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.

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".


(5)	Recent Financing Transactions

Long-Term Debt

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

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 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 $500 million 7.125% General and Refunding Mortgage Notes, Series V, maturing in March 2019.

In January 2019, MidAmerican Energy issued $600 million of its 3.65% First Mortgage Bonds due 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 November 1, 2017 to 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.


(6)	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
	Ended March 31,
	2019		2018

Federal statutory income tax rate	21	%	21	%
Income tax credits	(29	)	(45	)
State income tax, net of federal income tax benefit	(17	)	(30	)
Income tax effect of foreign income	(3	)	(16	)
Effects of ratemaking	(3	)	(8	)
Equity income	(1	)	1
Other, net	2		(1	)
Effective income tax rate	(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 the majority of all of its currently payable or receivable income tax is remitted to or received from Berkshire Hathaway. For the three-month periods ended March 31, 2019 and 2018, the Company did not receive or make any cash payments for federal income taxes from or to Berkshire Hathaway.


(7)	Employee Benefit Plans

Domestic Operations

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



	Three-Month Periods
	Ended March 31,
	2019			2018
Pension:
Service cost	$	4		$	5
Interest cost	27			26
Expected return on plan assets	(38		)	(41		)
Net amortization	9			8
Net periodic benefit cost (credit)	$	2		$	(2	)

Other postretirement:
Service cost	$	2		$	2
Interest cost	6			6
Expected return on plan assets	(10		)	(10		)
Net amortization	(2		)	(3		)
Net periodic benefit credit	$	(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 $13 million and $1 million, respectively, during 2019. As of March 31, 2019, $3 million and $- 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
	Ended March 31,
	2019			2018

Service cost	$	4		$	5
Interest cost	13			14
Expected return on plan assets	(25		)	(27		)
Net amortization	9			15
Net periodic benefit cost	$	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 £44 million during 2019. As of March 31, 2019, £11 million, or $14 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 December 31, 2018
Assets:
Commodity derivatives	$	1		$	91		$	108		$	(52	)	$	148
Interest rate derivatives	1			13			10			—			24
Mortgage loans held for sale	—			468			—			—			468
Money market mutual funds⁽²⁾	409			—			—			—			409
Debt securities:
United States government obligations	187			—			—			—			187
International government obligations	—			4			—			—			4
Corporate obligations	—			46			—			—			46
Municipal obligations	—			2			—			—			2
Agency, asset and mortgage-backed obligations	—			1			—			—			1
Equity securities:
United States companies	256			—			—			—			256
International companies	1,441			—			—			—			1,441
Investment funds	128			—			—			—			128
	$	2,423		$	625		$	118		$	(52	)	$	3,114
Liabilities:
Commodity derivatives	$	(1	)	$	(180	)	$	(9	)	$	111		$	(79	)
Interest rate derivatives	—			(32		)	—			—			(32		)
	$	(1	)	$	(212	)	$	(9	)	$	111		$	(111	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $56 million and $59 million as of March 31, 2019 and December 31, 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
	Ended March 31,
				Interest
	Commodity			Rate
	Derivatives			Derivatives
2019:
Beginning balance	$	99		$	10
Changes included in earnings	(3		)	53
Changes in fair value recognized in net regulatory assets	(11		)	—
Purchases	1			—
Settlements	—			(45		)
Ending balance	$	86		$	18



2018:
Beginning balance	$	94		$	9
Changes included in earnings	—			30
Changes in fair value recognized in OCI	(1		)	—
Changes in fair value recognized in net regulatory assets	(9		)	—
Purchases	1			—
Settlements	(4		)	(23		)
Ending balance	$	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 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 three-month period ended March 31, 2019, PacifiCorp entered into non-cancelable agreements through 2020 totaling $486 million related to repowering certain existing wind facilities in Wyoming and Washington.

Easements

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

Maintenance and Service Contracts

During the three-month period ended March 31, 2019, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling $301 million through 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, emissions performance standards, 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 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") license to a third-party dam removal entity, 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 joint application with the FERC to transfer the license for the four main-stem Klamath dams from PacifiCorp to the KRRC. Over the past two years, the KRRC 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 on July 29, 2019, with additional information, including updated cost estimates, and its insurance, bonding and liability transfer package. Based on that information, the FERC should be in a position to determine whether license transfer to the KRRC is in the public interest. That information should also allow PacifiCorp and the States to assess whether the KRRC has the ability to satisfy its indemnification obligations under the KHSA, and whether there is sufficient funding available under the 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

Energy Products and Services

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 March 31, 2019
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group			BHE Transmission		BHE Renewables		BHE and Other⁽¹⁾			Total
Customer Revenue:
Regulated:
Retail electric	$	1,186	$	443	$	527	$	—	$	—		$	—	$	—	$	—		$	2,156
Retail gas	—		260		37		—		—			—		—		—			297
Wholesale	28		110		18		—		—			—		—		—			156
Transmission and distribution	25		16		24		230		—			167		—		—			462
Interstate pipeline	—		—		—		—		372			—		—		(37		)	335
Other	—		—		1		—		—			—		—		—			1
Total Regulated	1,239		829		607		230		372			167		—		(37		)	3,407
Nonregulated	—		6		—		8		—			1		126		139			280
Total Customer Revenue	1,239		835		607		238		372			168		126		102			3,687
Other revenue⁽²⁾	20		7		7		25		(1		)	—		41		39			138
Total	$	1,259	$	842	$	614	$	263	$	371		$	168	$	167	$	141		$	3,825



	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
Customer Revenue:
Regulated:
Retail electric	$	1,096	$	386	$	539	$	—	$	—	$	—	$	—	$	—		$	2,021
Retail gas	—		246		40		—		—		—		—		—			286
Wholesale	22		93		11		—		—		—		—		(1		)	125
Transmission and distribution	22		16		20		249		—		180		—		—			487
Interstate pipeline	—		—		—		—		374		—		—		(41		)	333
Other	—		—		—		—		—		—		—		—			—
Total Regulated	1,140		741		610		249		374		180		—		(42		)	3,252
Nonregulated	—		—		—		11		—		—		117		144			272
Total Customer Revenue	1,140		741		610		260		374		180		117		102			3,524
Other revenue	44		6		7		18		2		—		37		41			155
Total	$	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 derivative contracts at BHE Pipeline Group.

Real Estate Services

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



	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 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	$	918	$	5,796	$	6,714


(12)	BHE Shareholders' Equity

For the three-month periods ended March 31, 2019 and 2018, BHE repurchased from certain family interests of Mr. Walter Scott, Jr. 447,712 shares of its common stock for $293 million and 149,281 shares of its common stock for $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, 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
	Ended March 31,
	2019		2018
Operating revenue:
PacifiCorp	$	1,259	$	1,184
MidAmerican Funding	842		747
NV Energy	614		617
Northern Powergrid	263		278
BHE Pipeline Group	371		376
BHE Transmission	168		180
BHE Renewables	167		154
HomeServices	785		761
BHE and Other⁽¹⁾	141		143
Total operating revenue	$	4,610	$	4,440



	Three-Month Periods
	Ended March 31,
	2019			2018
Depreciation and amortization:
PacifiCorp	$	205		$	202
MidAmerican Funding	177			158
NV Energy	120			113
Northern Powergrid	63			63
BHE Pipeline Group	28			42
BHE Transmission	58			62
BHE Renewables	70			64
HomeServices	13			12
BHE and Other⁽¹⁾	(1		)	—
Total depreciation and amortization	$	733		$	716



Operating income:
PacifiCorp	$	284		$	247
MidAmerican Funding	116			79
NV Energy	84			89
Northern Powergrid	129			147
BHE Pipeline Group	243			226
BHE Transmission	76			81
BHE Renewables	18			28
HomeServices	(21		)	(8		)
BHE and Other⁽¹⁾	(10		)	(18		)
Total operating income	919			871
Interest expense	(477		)	(466		)
Capitalized interest	16			12
Allowance for equity funds	32			21
Interest and dividend income	30			26
Losses on marketable securities, net	(68		)	(209		)
Other, net	35			30
Total income before income tax expense and equity income	$	487		$	285



Interest expense:
PacifiCorp	$	96	$	96
MidAmerican Funding	75		63
NV Energy	62		58
Northern Powergrid	34		37
BHE Pipeline Group	12		10
BHE Transmission	39		43
BHE Renewables	44		52
HomeServices	7		4
BHE and Other⁽¹⁾	108		103
Total interest expense	$	477	$	466



	Three-Month Periods
	Ended March 31,
	2019		2018
Operating revenue by country:
United States	$	4,177	$	3,978
United Kingdom	263		277
Canada	168		180
Philippines and other	2		5
Total operating revenue by country	$	4,610	$	4,440



Income before income tax expense and equity income by country:
United States	$	336	$	118
United Kingdom	103		112
Canada	40		41
Philippines and other	8		14
Total income before income tax expense and equity income by country	$	487	$	285



	As of
	March 31,		December 31,
	2019		2018
Assets:
PacifiCorp	$	24,211	$	23,478
MidAmerican Funding	20,845		20,029
NV Energy	14,105		14,119
Northern Powergrid	7,626		7,427
BHE Pipeline Group	5,579		5,511
BHE Transmission	8,567		8,424
BHE Renewables	8,654		8,666
HomeServices	3,427		2,797
BHE and Other⁽¹⁾	1,531		1,738
Total assets	$	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 three-month period ended March 31, 2019 (in millions):



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

December 31, 2018	$	1,129	$	2,102	$	2,369	$	952	$	73	$	1,448	$	95	$	1,427	$	9,595
Acquisitions	—		—		—		—		—		—		—		23		23
Foreign currency translation	—		—		—		14		—		31		—		—		45
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 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, geothermal and hydroelectric projects, the 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 First Quarter of 2019 and 2018

Overview

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



	First Quarter
	2019			2018			Change
Net income attributable to BHE shareholders:
PacifiCorp	$	180		$	148		$	32		22	%
MidAmerican Funding	190			103			87			84
NV Energy	29			33			(4		)	(12	)
Northern Powergrid	80			84			(4		)	(5	)
BHE Pipeline Group	181			167			14			8
BHE Transmission	56			56			—			—
BHE Renewables	48			54			(6		)	(11	)
HomeServices	(22		)	(10		)	(12		)	*
BHE and Other	(120		)	(122		)	2			2
Total net income attributable to BHE shareholders	$	622		$	513		$	109		21

* Not meaningful

Net income attributable to BHE shareholders increased $109 million for the first quarter of 2019 compared to 2018. The first quarter of 2019 and 2018 included a pre-tax unrealized 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. 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 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:

•

PacifiCorp's net income increased $32 million primarily due to higher utility margin of $43 million and higher allowances for borrowed and equity funds used during construction of $10 million, partially offset by higher operations and maintenance expense of $6 million and higher depreciation and amortization expense of $3 million. Utility margin increased due to higher retail customer volumes, higher average retail rates and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by higher natural gas and coal costs and lower wholesale revenue. Retail customer volumes increased 4.3% due to the favorable impact of weather, an increase in the average number of customers and higher customer usage.

•

MidAmerican Funding's net income increased $87 million primarily due to higher electric utility margin of $67 million, higher income tax benefit of $44 million driven by a $38 million increase in recognized production tax credits, $30 million of which was due to a change in the method of interim recognition, higher income from corporate-owned life insurance policies of $9 million, higher allowances for borrowed and equity funds of $7 million and higher natural gas utility margin of $6 million, partially offset by higher depreciation and amortization of $19 million, higher operations and maintenance expense of $17 million and higher interest expense of $12 million. Electric utility margin increased due to higher recoveries through bill riders, higher retail customer volumes of 4.7%, primarily from industrial growth and the favorable impact of weather, and higher electric wholesale revenue, partially offset by lower average retail rates.

•

NV Energy's net income decreased $4 million primarily due to lower electric utility margin of $7 million due to lower rates from a tax rate reduction rider effective April 1, 2018 and the Nevada Power 2017 regulatory rate review effective February 1, 2018, partially offset by higher retail customer volumes and higher transmission revenue. Retail customer volumes increased 3.9% primarily due to the favorable impacts of weather.


•	Northern Powergrid's net income decreased $4 million primarily due to higher distribution-related operating and depreciation expenses of $8 million and the stronger United States dollar of $5 million, partially offset by lower overall pension expense of $6 million and lower income tax expense of $5 million.


•	BHE Pipeline Group's net income increased $14 million primarily due to higher transportation revenue of $20 million at Northern Natural Gas, partially offset by higher operations and maintenance expense of $3 million due to increased pipeline integrity projects.

•

BHE Renewables' net income decreased $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 existing brokerage businesses largely from lower closed units, partially offset by lower operating expenses.

•

BHE and Other's net loss decreased $2 million primarily due to income tax benefits recognized in 2018 related to foreign earnings and the accrued repatriation tax on undistributed foreign earnings, lower federal income tax credits recognized on a consolidated 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):



	First Quarter
	2019		2018		Change
Operating revenue:
PacifiCorp	$	1,259	$	1,184	$	75		6	%
MidAmerican Funding	842		747		95			13
NV Energy	614		617		(3		)	—
Northern Powergrid	263		278		(15		)	(5	)
BHE Pipeline Group	371		376		(5		)	(1	)
BHE Transmission	168		180		(12		)	(7	)
BHE Renewables	167		154		13			8
HomeServices	785		761		24			3
BHE and Other	141		143		(2		)	(1	)
Total operating revenue	$	4,610	$	4,440	$	170		4



Operating income:
PacifiCorp	$	284		$	247		$	37		15	%
MidAmerican Funding	116			79			37			47
NV Energy	84			89			(5		)	(6	)
Northern Powergrid	129			147			(18		)	(12	)
BHE Pipeline Group	243			226			17			8
BHE Transmission	76			81			(5		)	(6	)
BHE Renewables	18			28			(10		)	(36	)
HomeServices	(21		)	(8		)	(13		)	*
BHE and Other	(10		)	(18		)	8			44
Total operating income	$	919		$	871		$	48		6

PacifiCorp

Operating revenue increased $75 million for the first quarter of 2019 compared to 2018 due to higher retail revenue of $95 million, partially offset by lower wholesale and other revenue of $20 million due to lower wholesale volumes and average 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 and product mix. Retail customer volumes increased 4.3% due to the favorable impact of weather, 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 lower industrial usage in Idaho and Utah and lower commercial usage in Washington and Idaho.

Operating income increased $37 million for the first quarter of 2019 compared to 2018 primarily due to higher utility margin of $43 million, partially offset by higher operations and maintenance expense of $6 million and higher depreciation and amortization of $3 million. Utility margin increased due to higher retail customer volumes, higher average retail rates and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by higher natural gas and coal costs largely from higher volumes and lower wholesale revenue.

MidAmerican Funding

Operating revenue increased $95 million for the first quarter of 2019 compared to 2018 primarily due to higher electric operating revenue of $73 million and higher natural gas revenue of $20 million. Electric operating revenue increased due to higher retail revenue of $55 million and higher wholesale and other revenue of $18 million. Electric retail revenue increased $38 million from higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense), $21 million from industrial growth and higher customer usage and $5 million from the impact of weather in 2019, partially offset by lower average rates of $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 2017 Tax Reform. Electric retail customer volumes increased 4.7% primarily from industrial growth and the favorable impact of weather. Electric wholesale and other revenue increased $18 million due to a 27.7% increase in wholesale volumes. Natural gas operating revenue increased primarily due to 9.2% higher retail sales volumes from the impact of weather in 2019 and industrial growth and a favorable outcome in 2018 of the ratemaking treatment for 2017 Tax Reform.

Operating income increased $37 million for the first quarter of 2019 compared to 2018 primarily due to higher electric utility margin of $67 million and higher natural gas utility margin of $6 million, partially offset by higher depreciation and amortization of $19 million from new wind generation and other plant 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. Natural gas utility margin increased due to higher retail sales volumes and the favorable outcome in 2018 of the ratemaking treatment for 2017 Tax Reform.

NV Energy

Operating revenue decreased $3 million for the first quarter of 2019 compared to 2018 primarily due to lower natural gas operating revenue of $4 million, partially offset by higher electric operating revenue of $2 million. Natural gas operating revenue decreased due to a lower average per-unit price (offset in cost of natural gas purchased for resale) of $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 electric retail revenue of $10 million. Electric retail revenue decreased primarily due to the tax rate reduction rider effective April 1, 2018 of $17 million, 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 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 $7 million. Electric utility margin decreased as higher energy costs of $9 million were offset by higher electric operating revenue of $2 million. Energy costs increased due to a higher average cost of fuel for generation of $45 million and higher purchased power costs of $17 million, partially offset by lower net deferred power costs of $53 million.

Northern Powergrid

Operating revenue decreased $15 million for the first quarter of 2019 compared to 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 $5 million from increased smart meter asset additions. Operating income decreased $18 million for the first quarter of 2019 compared to 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 investments.

BHE Pipeline Group

Operating revenue decreased $5 million for the first quarter of 2019 compared to 2018 primarily due to lower transportation revenue at Kern River related to the impact of period two rates for the 2003 expansion group of $19 million (largely offset in depreciation and amortization) and lower gas sales of $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 $17 million for the first quarter of 2019 compared to 2018 primarily due to the higher transportation revenue at Northern Natural Gas, partially offset by higher operations and maintenance expense of $3 million due to increased pipeline integrity projects.

BHE Transmission

Operating revenue decreased $12 million for the first quarter of 2019 compared to 2018 primarily due to the stronger United States dollar of $9 million and $4 million from recovery of lower costs. Operating income decreased $5 million for the first quarter of 2019 compared to 2018 primarily due to the stronger United States dollar of $4 million.

BHE Renewables

Operating revenue increased $13 million for the first quarter of 2019 compared to 2018 primarily due to higher wind revenues of $17 million largely from new projects and higher geothermal revenues of $6 million due to higher pricing, partially offset by lower solar revenues of $7 million due to lower insolation and lower hydro revenues of $3 million due to lower rainfall. Operating income decreased $10 million for the first quarter of 2019 compared to 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 timing of overhauls, partially offset by the higher wind and geothermal revenues.

HomeServices

Operating revenue increased $24 million for the first quarter of 2019 compared to 2018 primarily due to an increase from acquired businesses of $80 million, partially offset by lower brokerage revenue at existing businesses of $53 million largely from an 11% decrease in closed units. Operating loss increased $13 million for the first quarter of 2019 compared to 2018 primarily due to lower earnings at existing brokerage businesses primarily due to lower closed units, partially offset by lower operating expenses.

BHE and Other

Operating revenue decreased $2 million for the first quarter of 2019 compared to 2018 primarily due to lower electricity volumes at MidAmerican Energy Services, LLC. Operating loss decreased $8 million for the first quarter of 2019 compared to 2018 due to lower other operating expenses.

Consolidated Other Income and Expense Items

Interest expense

Interest expense is summarized as follows (in millions):



	First Quarter
	2019		2018		Change

Subsidiary debt	$	368	$	360	$	8	2	%
BHE senior debt and other	108		105		3		3
BHE junior subordinated debentures	1		1		—		—
Total interest expense	$	477	$	466	$	11	2

Interest expense increased $11 million for the first quarter of 2019 compared to 2018 primarily due to debt issuances at BHE, MidAmerican Energy, BHE Pipeline Group and HomeServices, partially offset by scheduled maturities and principal payments and $4 million from the impact of foreign currency exchange rate movements.

Capitalized interest

Capitalized interest increased $4 million for the first quarter of 2019 compared to 2018 primarily due to higher construction work-in-progress balances at PacifiCorp and MidAmerican Energy.

Allowance for equity funds

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

Interest and dividend income

Interest and dividend income increased $4 million for the first quarter of 2019 compared to 2018 primarily due to higher cash balances at PacifiCorp, MidAmerican Energy and NV Energy, partially offset by a lower financial asset balance at the Casecnan project.

Losses on marketable securities, net

Losses on marketable securities, net decreased $141 million for the first quarter of 2019 compared to 2018 primarily due to the change in the unrealized loss on the Company's investment in BYD Company Limited of $128 million.

Other, net

Other, net increased $5 million for the first quarter of 2019 compared to 2018 primarily due higher investment earnings, partially offset by a $7 million settlement received in 2018 related to transformer related outages at the Solar Star projects in 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 benefit

Income tax benefit decreased $73 million, including $37 million related to the change in the unrealized loss on the Company's investment in BYD Company Limited, for the first quarter of 2019 compared to 2018 and the effective tax rate was (30)% for the first quarter of 2019 and (78)% for the first quarter of 2018. The effective tax rate increased primarily due to benefits recognized in 2018 of $31 million related to foreign earnings and $25 million for the accrued repatriation tax on undistributed foreign earnings, partially offset by higher production tax credits recognized of $22 million and the favorable impacts of 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 2019 were $137 million, or $22 million higher than 2018, while production tax credits earned in 2019 were $186 million, or $27 million higher than 2018. The difference between production tax credits recognized and earned of $49 million as of March 31, 2019 will be reflected in earnings over the remainder of 2019.

Equity (loss) income

The Company had equity losses of $10 million for the first quarter of 2019 compared to equity income of $12 million for the first quarter of 2018 primarily due to higher pre-tax equity losses from tax equity investments at BHE Renewables.

Liquidity and Capital Resources

Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. 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 16 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, 2018 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

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



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

Cash and cash equivalents	$	65		$	669		$	433		$	131		$	31		$	53		$	279		$	1,661

Credit facilities⁽¹⁾⁽²⁾	3,500			1,200			909			650			221			655			1,635			8,770
Less:
Short-term debt	(912		)	—			—			—			(103		)	(239		)	(960		)	(2,214		)
Tax-exempt bond support and letters of credit	—			(256		)	(370		)	(80		)	—			(5		)	—			(711		)
Net credit facilities	2,588			944			539			570			118			411			675			5,845

Total net liquidity	$	2,653		$	1,613		$	972		$	701		$	149		$	464		$	954		$	7,506
Credit facilities:
Maturity dates⁽¹⁾	2021			2021			2019, 2021			2021			2020			2023			2019, 2020, 2022


⁽¹⁾	Refer to Note 5 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 $25 million at Northern Powergrid.

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2019 and 2018 were $1.49 billion and $1.48 billion, respectively. The increase was primarily due to 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.

Investing Activities

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

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2019 was $900 million. Sources of cash totaled $2.9 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $2.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.4 billion, net repayments of short-term debt totaling $311 million and common stock repurchases totaling $293 million.

For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the three-month period ended March 31, 2018 was $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 $2.5 billion and consisted mainly of net repayments of short-term debt totaling $1.9 billion and repayments of subsidiary debt totaling $550 million.

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):



	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2018		2019		2019
Capital expenditures by business:
PacifiCorp	$	236	$	337	$	2,268
MidAmerican Funding	365		573		2,629
NV Energy	109		165		729
Northern Powergrid	170		126		583
BHE Pipeline Group	53		72		756
BHE Transmission	71		61		247
BHE Renewables	59		46		122
HomeServices	11		10		49
BHE and Other	1		3		10
Total	$	1,075	$	1,393	$	7,393



Capital expenditures by type:
Wind generation	$	107	$	255	$	2,502
Electric transmission	21		97		675
Other growth	149		113		748
Operating	798		928		3,468
Total	$	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 $159 million and $16 million for the three-month periods ended March 31, 2019 and 2018, respectively. MidAmerican Energy anticipates costs for wind-powered generating facilities will total an additional $1,237 million for 2019. MidAmerican Energy has approval to construct up to 2,591 MW (nominal ratings) of wind-powered generating facilities expected to be placed in-service in 2017 through 2020, including 1,151 MW (nominal ratings) placed in-service as of 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 $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 ten years once the equipment is placed in-service.

◦

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 anticipate costs for these activities will total an additional $592 million for 2019. 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 BHE Renewables totaling $11 million and $18 million for the three-month periods ended March 31, 2019 and 2018, respectively.

•

Electric transmission includes PacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission 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 projects to deliver power and services to new markets, new customer connections, enhancements to existing customer 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 2016, respectively. Additionally, the Company has commitments as of March 31, 2019, subject to satisfaction of certain specified conditions, to provide equity contributions of $1,033 million for the remainder of 2019 and $350 million in 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 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, 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 United States Constitution. Both lawsuits were dismissed at the Northern District of Illinois, and the United States Court of Appeals for the Seventh Circuit affirmed the dismissals. On April 15, 2019, plaintiffs' petition seeking United States Supreme Court review of the 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 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 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 on the MOPR complaint. It is too early to predict the final outcome of each of these proceedings or their potential impact on the continued operation of Quad Cities Station.

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, emissions performance standards, 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. 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 environmental matters occurring in 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-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") 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 on the 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

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.

Mercury and Air Toxics Standards

In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015 with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.

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

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

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

The state of Utah issued a regional haze SIP requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides and particulate matter portions. 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 definition of the "waters of the United States" will be undertaken. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule and on November 16, 2017, the agencies proposed to extend the implementation day of the "waters of the United States" rule to 2020; neither of the proposals has been finalized. On January 22, 2018, the 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 Corps of Engineers proposed a revised definition of "waters of the 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 Rapanos v. United States. The public comment period closed April 15, 2019. Until the rule is fully litigated and finalized, the Registrants cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs or increased requirements for compensatory mitigation.

Coal Combustion Byproduct Disposal

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

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

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, 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 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, EPA extended the 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 October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted EPA's request to remand the rule, without vacatur, leaving the October 31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. Until the rule is fully litigated and finalized, the Registrants cannot determine whether additional action may be required.

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 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.

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, 2018. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 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 March 31, 2019, the related consolidated statements of operations, changes in shareholders' equity and cash flows for the three-month periods ended March 31, 2019 and 2018, 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, 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 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, 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

May 3, 2019

PACIFICORP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	March 31,		December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	669	$	77
Trade receivables, net	591		640
Other receivables, net	114		92
Inventories	406		417
Other current assets	152		133
Total current assets	1,932		1,359

Property, plant and equipment, net	19,698		19,570
Regulatory assets	1,090		1,076
Other assets	329		308

Total assets	$	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
	March 31,			December 31,
	2019			2018
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	583		$	597
Accrued interest	105			114
Accrued property, income and other taxes	142			75
Accrued employee expenses	108			79
Current portion of long-term debt	—			350
Regulatory liabilities	83			77
Other current liabilities	196			223
Total current liabilities	1,217			1,515

Long-term debt	7,656			6,665
Regulatory liabilities	2,989			2,978
Deferred income taxes	2,551			2,543
Other long-term liabilities	786			767
Total liabilities	15,199			14,468

Commitments and contingencies (Note 10)

Shareholders' equity:
Preferred stock	2			2
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding	—			—
Additional paid-in capital	4,479			4,479
Retained earnings	3,381			3,377
Accumulated other comprehensive loss, net	(12		)	(13		)
Total shareholders' equity	7,850			7,845

Total liabilities and shareholders' equity	$	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
	Ended March 31,
		2019			2018

Operating revenue		$	1,259		$	1,184

Operating expenses:
Cost of fuel and energy		465			433
Operations and maintenance		256			250
Depreciation and amortization		205			202
Property and other taxes		49			52
Total operating expenses		975			937

Operating income		284			247

Other income (expense):
Interest expense		(96		)	(96		)
Allowance for borrowed funds		7			4
Allowance for equity funds		14			7
Other, net		12			11
Total other income (expense)		(63		)	(74		)

Income before income tax expense		221			173
Income tax expense		42			25
Net income		$	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
					Additional					Other			Total
	Preferred		Common		Paid-in		Retained			Comprehensive			Shareholders'
	Stock		Stock		Capital		Earnings			Loss, Net			Equity

Balance, December 31, 2017	$	2	$	—	$	4,479	$	3,089		$	(15	)	$	7,555
Net income	—		—		—		148			—			148
Common stock dividends declared	—		—		—		(250		)	—			(250		)
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)



	Three-Month Periods
	Ended March 31,
	2019			2018
Cash flows from operating activities:
Net income	$	179		$	148
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	205			202
Allowance for equity funds	(14		)	(7		)
Changes in regulatory assets and liabilities	(35		)	60
Deferred income taxes and amortization of investment tax credits	5			(28		)
Other, net	(1		)	1
Changes in other operating assets and liabilities:
Trade receivables, other receivables and other assets	28			97
Inventories	11			(12		)
Derivative collateral, net	7			(3		)
Accrued property, income and other taxes, net	68			83
Accounts payable and other liabilities	41			(8		)
Net cash flows from operating activities	494			533

Cash flows from investing activities:
Capital expenditures	(337		)	(236		)
Other, net	1			(1		)
Net cash flows from investing activities	(336		)	(237		)

Cash flows from financing activities:
Proceeds from long-term debt	990			—
Repayments of long-term debt	(350		)	(86		)
Dividends paid	(175		)	(250		)
Other, net	(31		)	43
Net cash flows from financing activities	434			(293		)

Net change in cash and cash equivalents and restricted cash and cash equivalents	592			3
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	92			29
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	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 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 March 31, 2019 and for the three-month periods ended March 31, 2019 and 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-month periods ended March 31, 2019 and 2018 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 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 three-month period ended March 31, 2019.


(2)	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 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 on 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. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 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. 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

PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally require PacifiCorp 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. 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 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 (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 accordance with ASC 840, "Leases".


(5)	Recent Financing Transactions

Long-Term Debt

In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its 4.15% First Mortgage Bonds due 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 $350 million 5.50% First Mortgage Bonds due January 2019 and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

Credit Facilities

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.


(6)	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
	Ended March 31,
	2019		2018

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


(7)	Employee Benefit Plans

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



	Three-Month Periods
	Ended March 31,
	2019			2018
Pension:
Service cost	$	—		$	—
Interest cost	11			11
Expected return on plan assets	(17		)	(18		)
Net amortization	3			3
Net periodic benefit credit	$	(3	)	$	(4	)

Other postretirement:
Service cost	$	—		$	—
Interest cost	3			3
Expected return on plan assets	(5		)	(5		)
Net amortization	—			(1		)
Net periodic benefit credit	$	(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 2019. As of March 31, 2019, $1 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.


(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 9 for additional information on derivative contracts.

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



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

As of March 31, 2019
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	37		$	8		$	6		$	1		$	52
Commodity liabilities	(8		)	—			(59		)	(64		)	(131		)
Total	29			8			(53		)	(63		)	(79		)

Total derivatives	29			8			(53		)	(63		)	(79		)
Cash collateral (payable) receivable	(3		)	—			16			39			52
Total derivatives - net basis	$	26		$	8		$	(37	)	$	(24	)	$	(27	)

As of December 31, 2018
Not designated as hedging contracts⁽¹⁾:
Commodity assets	$	36		$	4		$	10		$	1		$	51
Commodity liabilities	(9		)	(1		)	(67		)	(71		)	(148		)
Total	27			3			(57		)	(70		)	(97		)

Total derivatives	27			3			(57		)	(70		)	(97		)
Cash collateral (payable) receivable	(2		)	—			16			45			59
Total derivatives - net basis	$	25		$	3		$	(41	)	$	(25	)	$	(38	)


(1)	PacifiCorp's commodity derivatives are generally included in rates and as of March 31, 2019 and December 31, 2018, a regulatory asset of $78 million and $96 million, respectively, was recorded related to the net derivative liability of $79 million and $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
	Ended March 31,
	2019			2018

Beginning balance	$	96		$	101
Changes in fair value	(54		)	28
Net (losses) gains reclassified to operating revenue	(22		)	7
Net gains (losses) reclassified to cost of fuel and energy	58			(14		)
Ending balance	$	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	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 March 31, 2019, PacifiCorp's credit ratings for its senior secured debt and its issuer credit 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 $101 million and $113 million as of March 31, 2019 and December 31, 2018, respectively, for which PacifiCorp had posted collateral of $55 million and $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 March 31, 2019 and December 31, 2018, PacifiCorp would have been required to post $32 million and $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.


(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
	Level 1		Level 2			Level 3		Other⁽¹⁾			Total
As of March 31, 2019
Assets:
Commodity derivatives	$	—	$	52		$	—	$	(18	)	$	34
Money market mutual funds⁽²⁾	468		—			—		—			468
Investment funds	24		—			—		—			24
	$	492	$	52		$	—	$	(18	)	$	526

Liabilities - Commodity derivatives	$	—	$	(131	)	$	—	$	70		$	(61	)

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

Liabilities - Commodity derivatives	$	—	$	(148	)	$	—	$	82		$	(66	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $52 million and $59 million as of March 31, 2019 and December 31, 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 8 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 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


(10)	Commitments and Contingencies

Commitments

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, emissions performance standards, 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 joint application with the FERC to transfer the license for the four main-stem Klamath dams from PacifiCorp to the KRRC. Over the past two years, the KRRC 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 on July 29, 2019, with additional information, including updated cost estimates, and its insurance, bonding and liability transfer package. Based on that information, the FERC should be in a position to determine whether license transfer to the KRRC is in the public interest. That information should also allow PacifiCorp and the States to assess whether the KRRC has the ability to satisfy its indemnification obligations under the KHSA, and whether there is sufficient funding available under the 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.

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.


(11)	Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):



	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


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 First Quarter of 2019 and 2018

Overview

Net income for the first quarter of 2019 was $179 million, an increase of $31 million, or 21%, compared to 2018. Net income increased primarily due to higher utility margins of $43 million and higher allowances for borrowed and equity funds used during construction of $10 million, partially offset by higher operations and maintenance expense of $6 million and higher depreciation and amortization expense of $3 million. Utility margin increased due to lower purchased electricity volumes, higher retail revenue mainly from higher retail customer volumes, lower net tax deferrals associated with the 2017 Tax Reform and product mix, and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased electricity prices, higher gas and coal-fueled generation costs, and lower wholesale revenue from lower volumes and average prices. Retail customer volumes increased 4.3%, 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. Energy generated increased 10% for the first quarter of 2019 compared to 2018 primarily due to higher natural gas and coal-fueled generation, offset by lower hydroelectric and wind-powered generation. Wholesale electricity sales volumes decreased 23% and purchased electricity volumes 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, to help evaluate results of operations. Utility 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 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 provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

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



	First Quarter
	2019		2018		Change
Utility margin:
Operating revenue	$	1,259	$	1,184	$	75		6	%
Cost of fuel and energy	465		433		32			7
Utility margin	794		751		43			6
Operations and maintenance	256		250		6			2
Depreciation and amortization	205		202		3			1
Property and other taxes	49		52		(3		)	(6	)
Operating income	$	284	$	247	$	37		15

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



	First Quarter
	2019		2018		Change
Utility margin (in millions):
Operating revenue	$	1,259	$	1,184	$	75		6	%
Cost of fuel and energy	465		433		32			7
Utility margin	$	794	$	751	$	43		6

Sales (GWh):
Residential	4,608		4,191		417			10	%
Commercial	4,445		4,298		147			3
Industrial, irrigation and other	4,710		4,706		4			—
Total retail	13,763		13,195		568			4
Wholesale	1,887		2,448		(561		)	(23	)
Total sales	15,650		15,643		7			—

Average number of retail customers
(in thousands)	1,921		1,890		31			2	%

Average revenue per MWh:
Retail	$	85.08	$	81.54	$	3.54		4	%
Wholesale	$	24.26	$	26.92	$	(2.66	)	(10	)%

Heating degree days	5,092		4,336		756			17	%

Sources of energy (GWh)⁽¹⁾:
Coal	9,486		8,642		844			10	%
Natural gas	3,061		1,948		1,113			57
Hydroelectric⁽²⁾	717		1,136		(419		)	(37	)
Wind and other⁽²⁾	760		1,069		(309		)	(29	)
Total energy generated	14,024		12,795		1,229			10
Energy purchased	2,836		4,055		(1,219		)	(30	)
Total	16,860		16,850		10			—

Average cost of energy per MWh:
Energy generated⁽³⁾	$	21.09	$	18.48	$	2.61		14	%
Energy purchased	$	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 increased $43 million, or 6%, for the first quarter of 2019 compared to 2018 primarily due to:

•

$56 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 net tax deferrals associated with the 2017 Tax Reform and higher prices due to product mix; and


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

The increases above were partially offset by:


•	$59 million of higher gas and coal-fueled generation costs from higher volumes and prices;


•	$20 million of lower wholesale revenues from lower average volumes and prices; and


•	$1 million of higher purchased electricity costs due to $105 million of higher average market prices, offset by $104 million of lower volumes.

Operations and maintenance increased $6 million, or 2%, for the first quarter of 2019 compared to 2018 primarily due to increased vegetation management, overhead line expenses and increased overtime largely due to storm restoration activities, partially offset by decreased maintenance expense.

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

Property and other taxes decreased $3 million, or 6% for the first quarter of 2019 compared to 2018 primarily due to lower property taxes primarily in Washington.

Allowance for borrowed and equity funds increased $10 million, or 91%, for the first quarter of 2019 compared to 2018 primarily due to higher qualified construction work-in-progress balances.

Income tax expense increased $17 million, or 68%, for the first quarter of 2019 compared to 2018. The effective tax rate was 19% for 2019 and 14% for 2018. The effective tax rate increased primarily due to the effects of rate making and impacts of the 2017 Tax Reform settlements.

Liquidity and Capital Resources

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



Cash and cash equivalents	$	669

Credit facilities	1,200
Less:
Tax-exempt bond support	(256		)
Net credit facilities	944

Total net liquidity	$	1,613

Credit facilities:
Maturity dates	2021

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2019 and 2018 were $494 million and $533 million, respectively. The change was primarily due to increased fuel payments and lower collections from retail customers, including 2017 Tax Reform refunds, and 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.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2019 and 2018 were $(336) million and $(237) million, respectively. The change is mainly due to an increase in capital expenditures of $101 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2019 was $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 $350 million for the repayment of long term debt, $175 million for common stock dividends paid to PPW Holdings LLC and $30 million for the repayment of short-term debt.

Net cash flows from financing activities for the three-month period ended March 31, 2018 was $(293) million. Uses of cash consisted substantially of $250 million for common stock dividends paid to PPW Holdings LLC and $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 March 31, 2019, PacifiCorp had no short-term debt outstanding. As of December 31, 2018, PacifiCorp had $30 million of short-term debt outstanding at a weighted average interest rate of 2.85%.

Long-term Debt

In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its 4.15% First Mortgage Bonds due 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 $350 million of its 5.50% First Mortgage Bonds due January 2019. PacifiCorp intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue up to $1 billion additional first mortgage bonds through 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):



	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2018		2019		2019

Transmission system investment	$	9	$	73	$	511
Wind investment	2		59		962
Operating and other	225		205		795
Total	$	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 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 $399 million in 2019.


•	Wind investment includes the following:

◦

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 Planning

As required by certain state regulations, PacifiCorp 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 customers while maintaining compliance with existing and evolving environmental laws and regulations. As part of the 2019 IRP, in April 2019, PacifiCorp released an economic study of the coal fleet which will inform how PacifiCorp will meet the long-term energy needs of its customers. While no resource decision will be made ahead of completion of the 2019 IRP, expected to be filed by August 2019, the study identified potential benefits for customers through retirement of some coal units as early as 2022.

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 sought up to approximately 1,270 MWs 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. PacifiCorp finalized its bid-selection process and established a final shortlist in February 2018. PacifiCorp plans to deliver 1,150 MWs from three new wind facilities 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 and a second providing 500 MWs. Agreements for acquisition of follow-on wind turbine equipment for the final two projects was completed in 2019.

Contractual Obligations

As of 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, 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 and local regulations regarding climate change, RPS, air and water quality, emissions performance standards, 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 and local. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results. PacifiCorp believes it is in material compliance with all applicable laws and 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.

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, 2018. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 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 March 31, 2019, the related statements of operations, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2019 and 2018, 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, 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 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, 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

May 3, 2019

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	March 31,		December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	432	$	—
Trade receivables, net	377		367
Income tax receivable	19		—
Inventories	149		204
Other current assets	94		90
Total current assets	1,071		661

Property, plant and equipment, net	16,545		16,157
Regulatory assets	260		273
Investments and restricted investments	761		708
Other assets	95		121

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

Long-term debt	6,341		4,879
Regulatory liabilities	1,597		1,620
Deferred income taxes	2,372		2,322
Asset retirement obligations	735		552
Other long-term liabilities	304		311
Total liabilities	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
Retained earnings	6,078		5,885
Total shareholder's equity	6,639		6,446

Total liabilities and shareholder's equity	$	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
	Ended March 31,
	2019			2018
Operating revenue:
Regulated electric	$	542		$	469
Regulated natural gas and other	300			277
Total operating revenue	842			746

Operating expenses:
Cost of fuel and energy	114			108
Cost of natural gas purchased for resale and other	195			179
Operations and maintenance	207			190
Depreciation and amortization	177			158
Property and other taxes	34			32
Total operating expenses	727			667

Operating income	115			79

Other income (expense):
Interest expense	(69		)	(58		)
Allowance for borrowed funds	6			4
Allowance for equity funds	15			10
Other, net	20			9
Total other income (expense)	(28		)	(35		)

Income before income tax benefit	87			44
Income tax benefit	(106		)	(62		)

Net income	$	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

Balance, December 31, 2017	$	—	$	561	$	5,203	$	5,764
Net income	—		—		106		106
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)



	Three-Month Periods
	Ended March 31,
	2019			2018
Cash flows from operating activities:
Net income	$	193		$	106
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	177			158
Amortization of utility plant to other operating expenses	8			8
Allowance for equity funds	(15		)	(10		)
Deferred income taxes and amortization of investment tax credits	31			19
Other, net	3			2
Changes in other operating assets and liabilities:
Trade receivables and other assets	(30		)	15
Inventories	55			37
Derivative collateral, net	—			(2		)
Contributions to pension and other postretirement benefit plans, net	(3		)	(3		)
Accrued property, income and other taxes, net	(159		)	(82		)
Accounts payable and other liabilities	18			(18		)
Net cash flows from operating activities	278			230

Cash flows from investing activities:
Capital expenditures	(573		)	(365		)
Purchases of marketable securities	(71		)	(95		)
Proceeds from sales of marketable securities	68			74
Other, net	1			15
Net cash flows from investing activities	(575		)	(371		)

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

Net change in cash and cash equivalents and restricted cash and cash equivalents	423			196
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	56			282
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	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 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 March 31, 2019, and for the three-month periods ended March 31, 2019 and 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-month periods ended 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, 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 three-month period ended March 31, 2019.


(2)	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 on 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. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. MidAmerican Energy 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 nor a material impact on MidAmerican Energy's Financial Statements and disclosures included within Notes to Financial Statements.


(5)	Recent Financing Transactions

Long-Term Debt

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.


(6)	Income Taxes

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



	Three-Month Periods
	Ended March 31,
	2019		2018

Federal statutory income tax rate	21	%	21	%
Income tax credits	(113	)	(137	)
State income tax, net of federal income tax benefit	(21	)	(9	)
Effects of ratemaking	(8	)	(18	)
Other, net	(1	)	2
Effective income tax rate	(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 $- million and $14 million for the three-month periods ended March 31, 2019 and 2018, respectively.


(7)	Employee Benefit Plans

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

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



	Three-Month Periods
	Ended March 31,
	2019			2018
Pension:
Service cost	$	2		$	2
Interest cost	7			7
Expected return on plan assets	(10		)	(11		)
Net amortization	—			1
Net periodic benefit credit	$	(1	)	$	(1	)

Other postretirement:
Service cost	$	1		$	1
Interest cost	2			2
Expected return on plan assets	(3		)	(3		)
Net amortization	(1		)	(1		)
Net periodic benefit credit	$	(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 $7 million and $1 million, respectively, during 2019. As of 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, 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 ("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
	Level 1		Level 2			Level 3			Other⁽¹⁾		Total
As of March 31, 2019:
Assets:
Commodity derivatives	$	—	$	1		$	—		$	—	$	1
Money market mutual funds⁽²⁾	410		—			—			—		410
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	7		—			—			—		7
Investment funds	19		—			—			—		19
	$	918	$	55		$	—		$	—	$	973

Liabilities - commodity derivatives	$	—	$	(3	)	$	(1	)	$	1	$	(3	)



	Input Levels for Fair Value Measurements
	Level 1		Level 2			Level 3			Other⁽¹⁾			Total
As of December 31, 2018:
Assets:
Commodity derivatives	$	—	$	4		$	2		$	(3	)	$	3
Money market mutual funds⁽²⁾	2		—			—			—			2
Debt securities:
United States government obligations	187		—			—			—			187
International government obligations	—		4			—			—			4
Corporate obligations	—		46			—			—			46
Municipal obligations	—		2			—			—			2
Agency, asset and mortgage-backed obligations	—		1			—			—			1
Equity securities:
United States companies	256		—			—			—			256
International companies	6		—			—			—			6
Investment funds	10		—			—			—			10
	$	461	$	57		$	2		$	(3	)	$	517

Liabilities - commodity derivatives	$	—	$	(4	)	$	(2	)	$	3		$	(3	)


(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $1 million and $- million as of March 31, 2019 and December 31, 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.

MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair 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.

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 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

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, 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 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.


(11)	Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer 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 March 31, 2019
	Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential	$	171	$	175	$	—	$	346
Commercial	75		66		—		141
Industrial	163		6		—		169
Natural gas transportation services	—		12		—		12
Other retail	35		1		—		36
Total retail	444		260		—		704
Wholesale	76		34		—		110
Multi-value transmission projects	16		—		—		16
Other Customer Revenue	—		—		5		5
Total Customer Revenue	536		294		5		835
Other revenue	6		1		—		7
Total operating revenue	$	542	$	295	$	5	$	842



	For the Three-Month Period Ended March 31, 2018
	Electric		Natural Gas			Other		Total
Customer Revenue:
Retail:
Residential	$	161	$	168		$	—	$	329
Commercial	71		62			—		133
Industrial	145		5			—		150
Natural gas transportation services	—		13			—		13
Other retail	10		(6		)	—		4
Total retail	387		242			—		629
Wholesale	62		32			—		94
Multi-value transmission projects	15		—			—		15
Other Customer Revenue	—		—			2		2
Total Customer Revenue	464		274			2		740
Other revenue	5		1			—		6
Total operating revenue	$	469	$	275		$	2	$	746


(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
	Ended March 31,
	2019			2018
Operating revenue:
Regulated electric	$	542		$	469
Regulated natural gas	295			275
Other	5			2
Total operating revenue	$	842		$	746

Operating income:
Regulated electric	$	66		$	36
Regulated natural gas	48			43
Other	1			—
Total operating income	115			79
Interest expense	(69		)	(58		)
Allowance for borrowed funds	6			4
Allowance for equity funds	15			10
Other, net	20			9
Income before income tax benefit	$	87		$	44



	As of
	March 31, 2019		December 31, 2018
Assets:
Regulated electric	$	17,373	$	16,511
Regulated natural gas	1,357		1,406
Other	2		3
Total assets	$	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 March 31, 2019, the related consolidated statements of operations, changes in member's equity and cash flows for the three-month periods ended March 31, 2019 and 2018, 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, 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 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, 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

May 3, 2019

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)



	As of
	March 31,		December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	433	$	1
Trade receivables, net	377		365
Income tax receivable	19		—
Inventories	149		204
Other current assets	94		89
Total current assets	1,072		659

Property, plant and equipment, net	16,557		16,169
Goodwill	1,270		1,270
Regulatory assets	260		273
Investments and restricted investments	763		710
Other assets	95		121

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

Long-term debt	6,581		5,119
Regulatory liabilities	1,597		1,620
Deferred income taxes	2,369		2,319
Asset retirement obligations	735		552
Other long-term liabilities	304		312
Total liabilities	12,498		11,873

Commitments and contingencies (Note 10)

Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	5,840		5,650
Total member's equity	7,519		7,329

Total liabilities and member's equity	$	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
	Ended March 31,
	2019			2018
Operating revenue:
Regulated electric	$	542		$	469
Regulated natural gas and other	300			278
Total operating revenue	842			747

Operating expenses:
Cost of fuel and energy	114			108
Cost of natural gas purchased for resale and other	194			180
Operations and maintenance	207			190
Depreciation and amortization	177			158
Property and other taxes	34			32
Total operating expenses	726			668

Operating income	116			79

Other income (expense):
Interest expense	(75		)	(63		)
Allowance for borrowed funds	6			4
Allowance for equity funds	15			10
Other, net	21			10
Total other income (expense)	(33		)	(39		)

Income before income tax benefit	83			40
Income tax benefit	(107		)	(63		)

Net income	$	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

Balance, December 31, 2017	$	1,679	$	4,981	$	6,660
Net income	—		103		103
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)



	Three-Month Periods
	Ended March 31,
	2019			2018
Cash flows from operating activities:
Net income	$	190		$	103
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	177			158
Amortization of utility plant to other operating expenses	8			8
Allowance for equity funds	(15		)	(10		)
Deferred income taxes and amortization of investment tax credits	31			19
Other, net	4			3
Changes in other operating assets and liabilities:
Trade receivables and other assets	(33		)	19
Inventories	55			37
Derivative collateral, net	—			(2		)
Contributions to pension and other postretirement benefit plans, net	(3		)	(3		)
Accrued property, income and other taxes, net	(160		)	(83		)
Accounts payable and other liabilities	14			(21		)
Net cash flows from operating activities	268			228

Cash flows from investing activities:
Capital expenditures	(573		)	(365		)
Purchases of marketable securities	(71		)	(95		)
Proceeds from sales of marketable securities	68			74
Other, net	—			15
Net cash flows from investing activities	(576		)	(371		)

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

Net change in cash and cash equivalents and restricted cash and cash equivalents	423			196
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	57			282
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	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 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 March 31, 2019, and for the three-month periods ended March 31, 2019 and 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-month periods ended 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, 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 three-month period ended March 31, 2019.


(2)	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 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	$	433	$	1
Restricted cash and cash equivalents in other current assets	47		56
Total cash and cash equivalents and restricted cash and cash equivalents	$	480	$	57


(3)	Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had as of March 31, 2019 and December 31, 2018, nonregulated property gross of $24 million and related accumulated depreciation and amortization of $12 million, 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

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
	Ended March 31,
	2019		2018

Federal statutory income tax rate	21	%	21	%
Income tax credits	(118	)	(151	)
State income tax, net of federal income tax benefit	(22	)	(10	)
Effects of ratemaking	(9	)	(20	)
Other, net	(1	)	2
Effective income tax rate	(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 $- million and $14 million for the three-month periods ended March 31, 2019 and 2018, 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 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 $1 million of other Accounting Standards Codification Topic 606 revenue for the three-month periods ended 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
	Ended March 31,
	2019			2018
Operating revenue:
Regulated electric	$	542		$	469
Regulated natural gas	295			275
Other	5			3
Total operating revenue	$	842		$	747

Operating income:
Regulated electric	$	66		$	36
Regulated natural gas	48			43
Other	2			—
Total operating income	116			79
Interest expense	(75		)	(63		)
Allowance for borrowed funds	6			4
Allowance for equity funds	15			10
Other, net	21			10
Income before income tax benefit	$	83		$	40



	As of
	March 31, 2019		December 31, 2018
Assets⁽¹⁾:
Regulated electric	$	18,564	$	17,702
Regulated natural gas	1,436		1,485
Other	17		15
Total assets	$	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 First Quarter of 2019 and 2018

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the first quarter of 2019 was $193 million, an increase of $87 million, or 82%, compared to 2018 primarily due to higher electric utility margin of $67 million, higher income tax benefit of $44 million driven by a $38 million increase in recognized production tax credits, $30 million of which was due to a change in the method of interim recognition, higher income from corporate-owned life insurance policies of $9 million, higher allowances for borrowed and equity funds of $7 million and higher natural gas utility margin of $6 million, partially offset by higher depreciation and amortization of $19 million from new wind-powered generation and other plant additions, higher operations and maintenance expense of $17 million and higher interest expense of $11 million. Electric utility margin increased due to higher recoveries through bill riders, higher retail customer volumes of 4.7%, primarily from industrial growth and the favorable impact of weather, and higher electric wholesale revenue, partially offset by lower average retail rates.

MidAmerican Funding -

MidAmerican Funding's net income for the first quarter of 2019 was $190 million, an increase of $87 million, or 84%, compared to 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 and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.

MidAmerican Energy's cost of fuel and energy and regulated cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in those expenses result in comparable changes to revenue from the related recovery mechanisms. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely 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 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):



	First Quarter
	2019		2018		Change
Electric utility margin:
Regulated electric operating revenue	$	542	$	469	$	73	16	%
Cost of fuel and energy	114		108		6		6
Electric utility margin	428		361		67		19

Natural gas utility margin:
Regulated natural gas operating revenue	295		275		20		7	%
Cost of natural gas purchased for resale	193		179		14		8
Natural gas utility margin	102		96		6		6

Utility margin	530		457		73		16	%

Other operating revenue	5		2		3		150
Other cost of sales	2		—		2		*
Operations and maintenance	207		190		17		9	%
Depreciation and amortization	177		158		19		12
Property and other taxes	34		32		2		6

Operating income	$	115	$	79	$	36	46	%

100

Regulated Electric Utility Margin

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



	First Quarter
	2019		2018		Change
Electric utility margin (in millions):
Operating revenue	$	542	$	469	$	73		16	%
Cost of fuel and energy	114		108		6			6
Electric utility margin	$	428	$	361	$	67		19

Electricity Sales (GWh):
Residential	1,885		1,786		99			6	%
Commercial	1,040		985		55			6
Industrial	3,271		3,125		146			5
Other	399		403		(4		)	(1	)
Total retail	6,595		6,299		296			5
Wholesale	3,276		2,565		711			28
Total sales	9,871		8,864		1,007			11

Average number of retail customers (in thousands)	785		777		8			1	%

Average revenue per MWh:
Retail	$	67.22	$	61.66	$	5.56		9	%
Wholesale	$	23.37	$	22.66	$	0.71		3	%

Heating degree days	3,601		3,335		266			8	%

Sources of energy (GWh)⁽¹⁾:
Coal	3,903		3,329		574			17	%
Nuclear	916		891		25			3
Natural gas	18		45		(27		)	(60	)
Wind and other⁽²⁾	4,344		3,985		359			9
Total energy generated	9,181		8,250		931			11
Energy purchased	849		788		61			8
Total	10,030		9,038		992			11


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


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

101

Regulated electric utility margin increased $67 million for the first quarter of 2019 compared to 2018 primarily due to:


(1)	Higher retail utility margin of $51 million due to -


•	an increase of $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 the impact of weather; partially offset by


•	a decrease of $9 million in average revenue rates due to sales mix;


(2)	Higher wholesale utility margin of $15 million due to higher margins per unit, reflecting lower costs, and higher sales volumes; and


(3)	Higher Multi-Value Projects ("MVP") transmission revenue of $1 million.

Regulated Natural Gas Utility Margin

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



	First Quarter
	2019		2018		Change
Natural gas utility margin (in millions):
Operating revenue	$	295	$	275	$	20		7	%
Cost of natural gas purchased for resale	193		179		14			8
Natural gas utility margin	$	102	$	96	$	6		6

Natural gas throughput (000's Dth):
Residential	28,569		26,079		2,490			10	%
Commercial	13,284		12,253		1,031			8
Industrial	1,546		1,416		130			9
Other	35		22		13			59
Total retail sales	43,434		39,770		3,664			9
Wholesale sales	11,555		11,176		379			3
Total sales	54,989		50,946		4,043			8
Natural gas transportation service	30,543		29,460		1,083			4
Total natural gas throughput	85,532		80,406		5,126			6

Average number of retail customers (in thousands)	763		757		6			1	%
Average revenue per retail Dth sold	$	5.72	$	5.81	$	(0.09	)	(2)	%
Average cost of natural gas per retail Dth sold	$	3.65	$	3.70	$	(0.05	)	(1)	%

Combined retail and wholesale average cost of natural gas per Dth sold	$	3.50	$	3.51	$	(0.01	)	—	%

Heating degree days	3,726		3,443		283			8	%

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


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


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


(3)	An increase of $1 million from the impact of weather; partially offset by


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

102

Operating Expenses

MidAmerican Energy -

Operations and maintenance increased $17 million for the first quarter of 2019 compared to 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.

Depreciation and amortization increased $19 million for the first quarter of 2019 compared to 2018 due to wind-powered generating facilities and other plant placed in-service.

Other Income (Expense)

MidAmerican Energy -

Interest expense increased $11 million for the first quarter of 2019 compared to 2018 primarily due to higher interest expense from the issuance of $1.5 billion of first mortgage bonds in January 2019, partially offset by the redemption of $500 million of first mortgage bonds in February 2019.

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

Other, net increased $11 million for the first quarter of 2019 compared to 2018 primarily due to higher returns on corporate-owned life insurance policies and higher interest income from favorable cash positions.

Income Tax Benefit

MidAmerican Energy -

MidAmerican Energy's income tax benefit increased $44 million for the first quarter of 2019 compared to 2018, and the effective tax rate was (122)% for 2019 and (141)% for 2018. The change in the effective tax rates for 2019 compared to 2018 were substantially due to the recognition of production tax credits.

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 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.

MidAmerican Funding -

MidAmerican Funding's income tax benefit increased $44 million for the first quarter of 2019 compared to 2018, and the effective tax rate was (129)% for 2019 and (158)% for 2018. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.

103

Liquidity and Capital Resources

As of March 31, 2019, MidAmerican Energy's and MidAmerican Funding's total net liquidity were as follows (in millions):



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 three-month periods ended March 31, 2019 and 2018, were $278 million and $230 million, respectively. MidAmerican Funding's net cash flows from operating activities for the three-month periods ended March 31, 2019 and 2018, were $268 million and $228 million, respectively. Cash flows from operating activities increased primarily due to higher cash margins for MidAmerican Energy's regulated electric wholesale business and 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.

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the three-month periods ended March 31, 2019 and 2018, were $(575) million and $(371) million, respectively. MidAmerican Funding's net cash flows from investing activities for the three-month periods ended March 31, 2019 and 2018, were $(576) million and $(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 substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments.

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the three-month periods ended March 31, 2019 and 2018 were $720 million and $337 million, respectively. MidAmerican Funding's net cash flows from financing activities for the three-month periods ended March 31, 2019 and 2018, were $731 million and $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. In March 2018, MidAmerican Energy repaid $350 million of its 5.30% Senior Notes due March 2018. Through its commercial paper program, MidAmerican Energy made payments totaling $240 million in 2019. MidAmerican Funding received $11 million and $2 million in 2019 and 2018, respectively, through its note payable with BHE.

104

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 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 from the ICC to issue preferred stock up to an aggregate of $500 million through November 1, 2020.

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):



	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2018		2019		2019

Wind-powered generation	$	16	$	159	$	1,396
Wind-powered generation repowering	70		27		133
Other	279		387		1,100
Total	$	365	$	573	$	2,629

105

MidAmerican Energy's forecast capital expenditures for 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 a total of 1,151 MW (nominal ratings) placed in-service through March 31, 2019. Wind XI ratemaking principles established a cost cap of $3.6 billion, including AFUDC, 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 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. Additionally, the ratemaking principles modify the 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 100% sharing. The threshold will be calculated each year-end and will be the weighted average of equity returns authorized via ratemaking principles 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 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, 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.

106

Quad Cities Generating Station Operating Status

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, 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 "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.

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, 2018. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2018.

107

Nevada Power Company and its subsidiaries

Consolidated Financial Section

108

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 March 31, 2019, the related consolidated statements of operations, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2019 and 2018 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, 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 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, 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

May 3, 2019

109

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	March 31,			December 31,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	51		$	111
Trade receivables, net	193			233
Inventories	63			61
Regulatory assets	72			39
Other current assets	64			75
Total current assets	443			519

Property, plant and equipment, net	6,443			6,418
Finance lease right of use assets, net	449			450
Regulatory assets	862			878
Other assets	60			37

Total assets	$	8,257		$	8,302

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	178		$	187
Accrued interest	35			38
Accrued property, income and other taxes	28			30
Current portion of long-term debt	—			500
Current portion of finance lease obligations	24			20
Regulatory liabilities	50			49
Customer deposits	76			67
Other current liabilities	38			29
Total current liabilities	429			920

Long-term debt	2,348			1,853
Finance lease obligations	438			443
Regulatory liabilities	1,156			1,137
Deferred income taxes	750			749
Other long-term liabilities	301			296
Total liabilities	5,422			5,398

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
Retained earnings	531			600
Accumulated other comprehensive loss, net	(4		)	(4		)
Total shareholder's equity	2,835			2,904

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

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

110

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods
	Ended March 31,
	2019			2018

Operating revenue	$	395		$	395

Operating expenses:
Cost of fuel and energy	173			170
Operations and maintenance	76			91
Depreciation and amortization	89			84
Property and other taxes	12			10
Total operating expenses	350			355

Operating income	45			40

Other income (expense):
Interest expense	(47		)	(45		)
Allowance for borrowed funds	1			—
Allowance for equity funds	1			1
Other, net	8			4
Total other income (expense)	(37		)	(40		)

Income before income tax expense	8			—
Income tax expense	2			—
Net income	$	6		$	—

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

111

NEVADA POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)



									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	$	—	$	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	—	—		—		6			—			6
Dividends declared	—	—		—		(75		)	—			(75		)
Balance, March 31, 2019	1,000	$	—	$	2,308	$	531		$	(4	)	$	2,835

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

112

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



	Three-Month Periods
	Ended March 31,
	2019			2018
Cash flows from operating activities:
Net income	$	6		$	—
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	89			84
Allowance for equity funds	(1		)	(1		)
Changes in regulatory assets and liabilities	28			10
Deferred income taxes and amortization of investment tax credits	2			(7		)
Deferred energy	(33		)	—
Amortization of deferred energy	3			3
Other, net	(5		)	—
Changes in other operating assets and liabilities:
Trade receivables and other assets	48			57
Inventories	(2		)	1
Accrued property, income and other taxes	(11		)	(1		)
Accounts payable and other liabilities	11			(36		)
Net cash flows from operating activities	135			110

Cash flows from investing activities:
Capital expenditures	(113		)	(64		)
Proceeds from sale of assets	2			—
Net cash flows from investing activities	(111		)	(64		)

Cash flows from financing activities:
Proceeds from long-term debt	495			—
Repayments of long-term debt	(500		)	—
Dividends paid	(75		)	—
Other, net	(3		)	(5		)
Net cash flows from financing activities	(83		)	(5		)

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

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

113

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 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 March 31, 2019 and for the three-month periods ended March 31, 2019 and 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-month period ended 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, 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 three-month period ended March 31, 2019.


(2)	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 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 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	$	51	$	111
Restricted cash and cash equivalents included in other current assets	11		10
Total cash and cash equivalents and restricted cash and cash equivalents	$	62	$	121

114


(3)	Property, Plant and Equipment, Net

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



		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

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 on 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. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. Nevada Power 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 to the opening balance of retained earnings at the date of initial 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.

115

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

116

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".

117


(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

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. 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 June 2018, Station Casinos LLC ("Station"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from an alternative provider and become a distribution only service customer of Nevada Power. In October 2018, the PUCN approved an order allowing Station to purchase energy from 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

118

(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. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

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



	As of
	March 31,		December 31,
	2019		2018
Qualified Pension Plan -
Other long-term liabilities	$	26	$	26

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

Other Postretirement Plans -
Other long-term liabilities	1		1


(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.

119

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



	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3			Total
As of March 31, 2019
Assets:
Commodity derivatives	$	—	$	—	$	4		$	4
Money market mutual funds⁽¹⁾	43		—		—			43
Investment funds	2		—		—			2
	$	45	$	—	$	4		$	49

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

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	$	—	$	—	$	(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 March 31, 2019 and December 31, 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.

120

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
	Ended March 31,
	2019			2018

Beginning balance	$	3		$	(3	)
Changes in fair value recognized in regulatory assets	(9		)	(5		)
Settlements	1			—
Ending balance	$	(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 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


(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, emissions performance standards, 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.

121


(10)	Revenue from Contracts with Customers

The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):



	Three-Month Periods
	Ended March 31,
	2019		2018
Customer Revenue:
Retail:
Residential	$	200	$	193
Commercial	90		95
Industrial	70		79
Other	5		6
Total fully bundled	365		373
Distribution only service	7		7
Total retail	372		380
Wholesale, transmission and other	17		10
Total Customer Revenue	389		390
Other revenue	6		5
Total revenue	$	395	$	395

122

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.

123

Results of Operations for the First Quarter of 2019 and 2018

Overview

Net income for the first quarter of 2019 was $6 million, an increase of $6 million compared to 2018 primarily due to $8 million of lower interest expense on long-term debt, $8 million of lower settlement costs associated with a personal injury claim in 2018 and $2 million of higher other income, net due to higher interest income, partially offset by $4 million of higher earnings sharing accrual and $3 million of lower utility 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 expenses result in comparable changes to 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):



	First Quarter
	2019		2018		Change
Utility margin:
Operating revenue	$	395	$	395	$	—		—	%
Cost of fuel and energy	173		170		3			2
Utility margin	222		225		(3		)	(1	)
Operations and maintenance	76		91		(15		)	(16	)
Depreciation and amortization	89		84		5			6
Property and other taxes	12		10		2			20
Operating income	$	45	$	40	$	5		13

124

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



	First Quarter
	2019		2018		Change
Utility margin (in millions):
Operating revenue	$	395	$	395	$	—		—	%
Cost of fuel and energy	173		170		3			2
Utility margin	$	222	$	225	$	(3	)	(1	)

GWhs sold:
Residential	1,608		1,482		126			9	%
Commercial	992		990		2			—
Industrial	1,160		1,234		(74		)	(6	)
Other	47		50		(3		)	(6	)
Total fully bundled⁽¹⁾	3,807		3,756		51			1
Distribution only service	528		492		36			7
Total retail	4,335		4,248		87			2
Wholesale	144		44		100			*
Total GWhs sold	4,479		4,292		187			4

Average number of retail customers (in thousands):
Residential	834		813		21			3	%
Commercial	109		106		3			3
Industrial	2		2		—			—
Total	945		921		24			3

Average per MWh:
Revenue - fully bundled⁽¹⁾	$	95.87	$	99.29	$	(3.42	)	(3	)%
Wholesale	$	42.27	$	56.29	$	(14.02	)	(25	)%
Total cost of energy⁽²⁾⁽³⁾	$	43.32	$	44.60	$	(1.28	)	(3	)%

Heating degree days	1,083		816		267			33	%
Cooling degree days	12		19		(7		)	(37	)%

Sources of energy (GWhs)⁽³⁾⁽⁴⁾:
Natural gas	2,169		2,401		(232		)	(10	)%
Coal	342		249		93			37
Renewables	12		15		(3		)	(20	)
Total energy generated	2,523		2,665		(142		)	(5	)
Energy purchased	1,475		1,146		329			29
Total	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.


(3)	The average total cost of energy per MWh and sources of energy excludes 81 and 70 GWhs of coal and 497 and 680 GWhs of gas generated energy that is purchased at cost by related parties for the three-month periods ended March 31, 2019 and 2018 respectively.


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

125

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


•	$11 million in lower retail rates due to the tax rate reduction rider effective April 2018 and


•	$3 million due to lower retail rates as a result of the 2017 regulatory rate review with rates effective February 2018.

The decrease in utility margin was offset by:


•	$6 million in higher residential volumes primarily from the impacts of weather,


•	$3 million from higher transmission revenue and


•	$2 million due to residential customer growth.

Operations and maintenance decreased $15 million, or 16%, for the first quarter of 2019 compared to 2018 primarily due to the 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.

Depreciation and amortization increased $5 million, or 6%, for the first quarter of 2019 compared to 2018 primarily due to the impacts of adopting ASC 842.

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

Income tax expense increased $2 million for the first quarter of 2019 compared to 2018 due to higher income before income tax expense. The effective tax rate was 21% for the first quarter of 2019 and 0% for the first quarter of 2018.

Liquidity and Capital Resources

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



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

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2019 and 2018 were $135 million and $110 million, respectively. Increases were due to lower payments for operating costs, increased collections of customer advances and proceeds from a licensing agreement with a third party, partially offset by an increase in fuel costs.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2019 and 2018 were $(111) million and $(64) million, respectively. The change was primarily due to increased capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month periods ended March 31, 2019 and 2018 were $(83) million and $(5) million, respectively. The change was due to higher repayments of long-term debt and dividends paid to NV Energy, Inc. of $75 million, partially offset by greater proceeds from issuance of long-term debt.

126

Long-Term Debt

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 $156 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion.

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

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.

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):



	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2018		2019		2019

Distribution	27		43		197
Transmission system investment	2		4		40
Other	35		66		225
Total	$	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 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, 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.

127

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, 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 "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.

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

128

Sierra Pacific Power Company

Financial Section

129

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 balance sheet of Sierra Pacific Power Company ("Sierra Pacific") as of March 31, 2019, the related statements of operations, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2019 and 2018 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 Sierra Pacific as of December 31, 2018, and the related 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 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, 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 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

May 3, 2019

130

SIERRA PACIFIC POWER COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)



	As of
	March 31,		December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	62	$	71
Trade receivables, net	95		100
Inventories	53		52
Regulatory assets	31		7
Other current assets	33		33
Total current assets	274		263

Property, plant and equipment, net	2,965		2,947
Regulatory assets	312		314
Other assets	66		45

Total assets	$	3,617	$	3,569

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	110	$	116
Accrued interest	11		13
Accrued property, income and other taxes	17		14
Regulatory liabilities	23		18
Customer deposits	21		18
Other current liabilities	23		18
Total current liabilities	205		197

Long-term debt	1,120		1,120
Regulatory liabilities	491		491
Deferred income taxes	338		331
Other long-term liabilities	177		166
Total liabilities	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
Retained earnings	175		153
Total shareholder's equity	1,286		1,264

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

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

131

SIERRA PACIFIC POWER COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)



	Three-Month Periods
	Ended March 31,
	2019			2018
Operating revenue:
Regulated electric	$	182		$	181
Regulated natural gas	37			41
Total operating revenue	219			222

Operating expenses:
Cost of fuel and energy	82			77
Cost of natural gas purchased for resale	19			23
Operations and maintenance	44			39
Depreciation and amortization	31			30
Property and other taxes	6			6
Total operating expenses	182			175

Operating income	37			47

Other income (expense):
Interest expense	(12		)	(10		)
Allowance for equity funds	1			1
Other, net	2			2
Total other income (expense)	(9		)	(7		)

Income before income tax expense	28			40
Income tax expense	6			6
Net income	$	22		$	34

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

132

SIERRA PACIFIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)



								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.

133

SIERRA PACIFIC POWER COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)



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

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

Cash flows from financing activities:
Net cash flows from financing activities	—			—

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

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

134

SIERRA PACIFIC POWER COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)


(1)	General

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

The unaudited 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 March 31, 2019 and for the three-month periods ended March 31, 2019 and 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-month period ended 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 Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2018 describes the most significant accounting policies used in the preparation of the unaudited 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 three-month period ended March 31, 2019.


(2)	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 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 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	$	62	$	71
Restricted cash and cash equivalents included in other current assets	6		5
Total cash and cash equivalents and restricted cash and cash equivalents	$	68	$	76

135


(3)	Property, Plant and Equipment, Net

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



		As of
	Depreciable Life	March 31,			December 31,
	Depreciable Life	2019			2018
Utility plant:
Electric generation	25 - 60 years	$	1,132		$	1,132
Electric distribution	20 - 100 years	1,588			1,568
Electric transmission	50 - 100 years	818			812
Electric general and intangible plant	5 - 70 years	174			185
Natural gas distribution	35 - 70 years	405			403
Natural gas general and intangible plant	5 - 70 years	14			14
Common general	5 - 70 years	318			321
Utility plant		4,449			4,435
Accumulated depreciation and amortization		(1,585		)	(1,583		)
Utility plant, net		2,864			2,852
Other non-regulated, net of accumulated depreciation and amortization	70 years	5			5
Plant, net		2,869			2,857
Construction work-in-progress		96			90
Property, plant and equipment, net		$	2,965		$	2,947


(4)	Leases

Adoption

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 on 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. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. Sierra Pacific 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.

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.

136

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

137

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".

138


(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 Statements of Operations but rather is deferred and recorded as a regulatory asset on the 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

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. 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. 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

(6) Recent Financing Transactions

Long-Term Debt

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 re-offering 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 re-offering for general corporate purposes.

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(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
	Ended March 31,
	2019		2018

Federal statutory income tax rate	21	%	21	%
Effects of ratemaking	—		(5	)
Other	—		(1	)
Effective income tax rate	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. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

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



	As of
	March 31,		December 31,
	2019		2018
Qualified Pension Plan -
Other long-term liabilities	$	19	$	19

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

Other Postretirement Plans -
Other long-term liabilities	13		13

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(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 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 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 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 Balance Sheets. The fair value of these money market mutual funds approximates cost.

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.

Sierra Pacific's long-term debt is carried at cost on the 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 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

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(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, emissions performance standards, 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 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

The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 12 (in millions):



	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

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(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
	Ended March 31,
	2019			2018
Operating revenue:
Regulated electric	$	182		$	181
Regulated natural gas	37			41
Total operating revenue	$	219		$	222

Operating income:
Regulated electric	$	29		$	37
Regulated natural gas	8			10
Total operating income	37			47
Interest expense	(12		)	(10		)
Allowance for equity funds	1			1
Other, net	2			2
Income before income tax expense	$	28		$	40



	As of
	March 31,		December 31,
	2019		2018
Assets:
Regulated electric	$	3,227	$	3,177
Regulated natural gas	316		314
Regulated common assets⁽¹⁾	74		78
Total assets	$	3,617	$	3,569


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

143

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's electric segment is summer peaking experiencing its highest retail energy sales in response to the demand for air 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 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 Financial Statements and Notes to 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.

144

Results of Operations for the First Quarter of 2019 and 2018

Overview

Net income for the first quarter of 2019 was $22 million, a decrease of $12 million, or 35%, compared to 2018 primarily due to $5 million of higher operations and maintenance expense, $4 million of lower electric utility margin, primarily due to lower retail rates related to the tax rate reduction rider effective April 2018 and $2 million of higher other expense, primarily due to 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 Statements of Operations.

Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely 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):



	First Quarter
	2019		2018		Change
Electric utility margin:
Electric operating revenue	$	182	$	181	$	1		1	%
Cost of fuel and energy	82		77		5			6
Electric utility margin	100		104		(4		)	(4	)

Natural gas utility margin:
Natural gas operating revenue	37		41		(4		)	(10	)%
Cost of natural gas purchased for resale	19		23		(4		)	(17	)
Natural gas utility margin	18		18		—			—

Utility margin	118		122		(4		)	(3	)%

Operations and maintenance	44		39		5			13	%
Depreciation and amortization	31		30		1			3
Property and other taxes	6		6		—			—
Operating income	$	37	$	47	$	(10	)	(21	)%

145

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

Electric Utility Margin



	First Quarter
	2019		2018		Change
Electric utility margin (in millions):
Electric operating revenue	$	182	$	181	$	1		1	%
Cost of fuel and energy	82		77		5			6
Electric utility margin	$	100	$	104	$	(4	)	(4	)

GWhs sold:
Residential	655		613		42			7	%
Commercial	700		697		3			—
Industrial	924		819		105			13
Other	4		4		—			—
Total fully bundled⁽¹⁾	2,283		2,133		150			7
Distribution only service	391		362		29			8
Total retail	2,674		2,495		179			7
Wholesale	219		171		48			28
Total GWhs sold	2,893		2,666		227			9

Average number of retail customers (in thousands):
Residential	303		298		5			2	%
Commercial	48		47		1			2
Total	351		345		6			2

Average per MWh:
Revenue - fully bundled⁽¹⁾	$	71.50	$	77.93	$	(6.43	)	(8	)%
Revenue - wholesale	$	52.52	$	49.51	$	3.01		6	%
Total cost of energy⁽²⁾	$	31.50	$	32.52	$	(1.02	)	(3	)%

Heating degree days	2,244		2,140		104			5	%

Sources of energy (GWhs)⁽³⁾:
Natural gas	1,094		1,057		37			4	%
Coal	340		—		340			*
Renewables⁽⁴⁾	5		6		(1		)	(17	)
Total energy generated	1,439		1,063		376			35
Energy purchased	1,179		1,306		(127		)	(10	)
Total	2,618		2,369		249			11

* 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.


(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.

146

Natural Gas Utility Margin



	First Quarter
	2019		2018		Change
Natural gas utility margin (in millions):
Natural gas operating revenue	$	37	$	41	$	(4	)	(10	)%
Cost of natural gas purchased for resale	19		23		(4		)	(17	)
Natural gas utility margin	$	18	$	18	$	—		—

Dths sold:
Residential	5,013		4,319		694			16	%
Commercial	2,497		2,112		385			18
Industrial	670		690		(20		)	(3	)
Total retail	8,180		7,121		1,059			15

Average number of retail customers (in thousands)	169		166		3			2	%
Average revenue per retail Dth sold	$	4.52	$	5.61	$	(1.09	)	(19	)%
Average cost of natural gas per retail Dth sold	$	2.32	$	3.20	$	(0.88	)	(28	)%
Heating degree days	2,244		2,140		104			5	%

Electric utility margin decreased $4 million, or 4%, for the first quarter of 2019 compared to 2018 primarily due to $6 million in lower retail rates due to the tax rate reduction rider effective April 2018, partially offset by $2 million in higher residential volumes primarily from the impacts of weather.

Operations and maintenance increased $5 million, or 13%, for the first quarter of 2019 compared to 2018 primarily due to higher transmission and distribution costs and higher generation plant costs, partially offset by the impacts of adopting ASC 842, "Leases" ("ASC 842").

Other income (expense) is unfavorable $2 million, or 29%, for the first quarter of 2019 compared to 2018 primarily due to higher pension expense and the impacts of adopting ASC 842.

Liquidity and Capital Resources

As of March 31, 2019, Sierra Pacific's total net liquidity was as follows (in millions):



Cash and cash equivalents	$	62

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

Total net liquidity	$	232
Credit facility:
Maturity date	2021

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2019 and 2018 were $44 million and $75 million, respectively. The change was due to an increase in fuel costs and higher payments for operating costs, partially offset by lower contributions to the pension plan.

147

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2019 and 2018 were $(52) million and $(45) million, respectively. The change was due to increased capital expenditures.

Long-Term Debt

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) establish debt issuances limited to a debt ceiling of $1.6 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.

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

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.

148

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):



	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2018		2019		2019

Distribution	$	31	$	34	$	174
Transmission system investment	1		2		22
Other	13		16		71
Total	$	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 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, 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.

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, 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 financial results. Sierra Pacific believes it is in material compliance with all applicable laws and 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 and regulations.

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

149


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, 2018. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2018. Refer to Note 8 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 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 March 31, 2019 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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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, 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.

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Exhibit No.	Description

BERKSHIRE HATHAWAY ENERGY


15.1	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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

PACIFICORP


15.2	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP


4.1	Thirtieth Supplemental Indenture, dated as of March 1, 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 March 1, 2019).


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

MIDAMERICAN ENERGY


15.3	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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

MIDAMERICAN FUNDING


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


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


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


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

NEVADA POWER


15.4	Awareness Letter of Independent Registered Public Accounting Firm.


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


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


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


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

152


Exhibit No.	Description

SIERRA PACIFIC


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


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


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


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

ALL REGISTRANTS

101

The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended 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.

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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: May 3, 2019	/s/ Patrick J. Goodman
	Patrick J. Goodman
	Executive Vice President and Chief Financial Officer
	(principal financial and accounting officer)

	PACIFICORP

Date: 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: 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: 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: May 3, 2019	/s/ Michael E. Cole
	Michael E. Cole
	Vice President and Chief Financial Officer
	(principal financial and accounting officer)

154