UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended ~~September~~March 3031, ~~2014~~2015

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

	Securities registered pursuant to Section 12(b) of the Act: None
	Securities registered pursuant to Section 12(g) of the Act:
	Common Stock, $3.75 par value

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. Yes T No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes T No o

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



Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No T

All shares of outstanding common stock of Sierra Pacific Power Company are held by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of ~~October~~April 3130, ~~2014~~2015, 1,000 shares of common stock, $3.75 par value, were outstanding.

TABLE OF CONTENTS

PART I
Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	1213
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2119
Item 4.	Controls and Procedures	2119
PART II
Item 1.	Legal Proceedings	2220
Item 1A.	Risk Factors	2220
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	2220
Item 3.	Defaults Upon Senior Securities	2220
Item 4.	Mine Safety Disclosures	2220
Item 5.	Other Information	2220
Item 6.	Exhibits	2220
Signatures		2321
Exhibit Index		2422

Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 2 through 4, and Part II - Items 1 through 6, the following terms have the definitions indicated.

Sierra Pacific Power Company and Related Entities
Company		Sierra Pacific Power Company and its subsidiaries
BHE		Berkshire Hathaway Energy Company
NV Energy		NV Energy, Inc.
Berkshire Hathaway		Berkshire Hathaway Inc.
Clark Mountain Generating Station		132-megawatt generating facility in Nevada
Nevada Power		Nevada Power Company, an electric utility wholly owned by NV Energy
Fort Churchill Generating Station		226-megawatt generating facility in Nevada
Ft. Churchill Generating Station		226-megawatt generating facility in Nevada
Reid Gardner Generating Station		557-megawatt generating facility in Nevada
ON Line		500-kilovolt transmission line connecting the Company and Nevada Power
Tracy Generating Station		889-megawatt generating facility in Nevada
NV Energize		NV Energy project which includes advanced meter infrastructure, Smart Grid Technology and meter data management
Tracy Generating Station		753-megawatt generating facility in Nevada
Valmy Generating Station		522-megawatt generating facility in Nevada
Certain Industry Terms
AFUDC		Allowance for Funds Used During Construction
California ISO		California Independent System Operator Corporation
Dth		Decatherms
EEIR		Energy Efficiency Implementation Rate
EIM		Energy Imbalance Market
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
GWh		Gigawatt Hours
MW		Megawatts
MWh		Megawatt Hours
PUCN		Public Utilities Commission of Nevada

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 Company'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 the Company 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 reliability and safety standards, affecting the Company'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 generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;


•	the outcome of rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company's ability to recover costs in 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 distributed generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the Company's ability to obtain long-term contracts with customers and suppliers;

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


•	performance and availability of the Company's generating facilities, including the impacts of outages and repairs, transmission constraints, weather and operating conditions;


•	a high degree of variance between actual and forecasted load or generation that could impact the Company'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 effects of catastrophic and other unforeseen events, which may be caused by factors beyond the Company's control or by a breakdown or failure of the Company's operating assets, including storms, floods, fires, earthquakes, explosions, landslides, litigation, wars, terrorism and embargoes;


•	the financial condition and creditworthiness of the Company'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 the London Interbank Offered Rate, the base interest rate for the Company's credit facility;


•	changes in the Company's credit ratings;


•	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 Company's ability to recover such costs in rates;


•	increases in employee healthcare costs, including the implementation of the Affordable Care Act;


•	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 related to the Company's participation in NV Energy's benefit plans;


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


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

iii

• the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company's consolidated financial results; ~~and~~


•	the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the Company's control or by a breakdown or failure of the Company's operating assets, including storms, floods, fires, earthquakes, explosions, landslides, litigation, wars, terrorism and embargoes; and


•	other business or investment considerations that may be disclosed from time to time in the Company's filings with the United States Securities and Exchange Commission or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Company are described in ~~the Company's filings with the United States Securities and Exchange Commission, including Part II,~~ Item 1A and other discussions contained in this Form 10‑Q. The Company 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.

PART I

Item 1. Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Las Vegas, Nevada

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries (the "Company") as of ~~September~~March 3031, ~~2014~~2015, and the related consolidated statements of operations ~~for the three-month and nine-month periods ended September 30~~, ~~2014 and 2013, and of~~ changes in shareholder's equity and cash flows for the ~~nine~~three-month periods ended ~~September 30~~March 31, 2015 ~~2014~~ and ~~2013~~2014. These interim financial statements are the responsibility of the Company's management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Sierra Pacific Power Company and subsidiaries as of December 31, ~~2013~~ 2014, 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 ~~March~~February 3127, ~~2014~~2015, 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, 2014 ~~2013~~ is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

~~November~~May 71, ~~2014~~2015

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)

	As of
	September 30,			December 31,
	March 31,			December 31,
	2014			2013
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	~~131~~53		$	6722
Accounts receivable, net	~~122~~131			~~156~~127
Inventories	4340			4340
Regulatory assets	44—			1532
Deferred income taxes	3540			4842
Other current assets	2328			2320
Total current assets	~~398~~292			~~352~~283
Property, plant and equipment, net	2,~~587~~655			2,~~552~~640
Regulatory assets	~~409~~438			~~427~~444
Other assets	4919			3821
Total assets	$	3,~~443~~404		$	3,~~369~~388
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	~~125~~113		$	~~151~~127
Accrued interest	1516			15
Accrued property, income and other taxes	12			12
Accrued property and other taxes	12			12
Accrued employee expenses	11			7
Regulatory liabilities	38			39
Regulatory liabilities	46			37
Current portion of long-term debt	1			1
Customer deposits and other	23			16
Customer deposits	17			16
Total current liabilities	233			239
Other current liabilities	16			14
Total current liabilities	213			224
Long-term debt	1,199			1,199
Regulatory liabilities	~~252~~265			~~243~~262
Deferred income taxes	~~549~~575			~~525~~566
Other long-term liabilities	~~127~~135			~~147~~139
Total liabilities	2,~~360~~387			2,~~353~~390
Commitments and contingencies (Note 8)
Commitments and contingencies (Note 7)
Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	—			—
Other paid-in capital	1,111			1,111
Accumulated deficit	(2692		)	(93111		)
Accumulated other comprehensive loss, net	(2		)	(2		)
Total shareholder's equity	1,~~083~~017			~~1,016~~998
Total liabilities and shareholder's equity	$	3,~~443~~404		$	3,~~369~~388
The accompanying notes are an integral part of the consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)

	Three-Month Periods						~~Nine-Month Periods~~
	Ended September 30,						Ended September 30,
	Ended March 31,
	2014			2013			2014			2013
	2015			2014
Operating revenue:
Electric	$	233		$	213		$	589		$	559
Regulated electric	$	196		$	177
Natural gas	18			12			83			61
Regulated natural gas	50			44
Total operating revenue	~~251~~246			~~225~~221			~~672~~			~~620~~
Operating costs and expenses:
Cost of fuel, energy and capacity	~~103~~97			80			~~269~~			~~212~~
Natural gas purchased for resale	735			429			48			28
Operating and maintenance expense	47			52			120			148
Operating and maintenance	36			34
Depreciation and amortization	2728			26			79			78
Property and other taxes	7			6			19			19
Merger-related expenses	—			2			—			6
Total operating costs and expenses	203			175
Total operating costs and expenses	191			170			535			491
Operating income	43			46
Operating income	60			55			137			129
Other income (expense):
Other income (expense):
Interest expense	(15		)	(15		)
Interest expense, net of allowance for debt funds	(15		)	(15		)	(44		)	(47		)
Allowance for equity funds	1			1
Allowance for equity funds	1			1			3			2
Other, net	1			2
Other, net	3			1			8			8
Total other income (expense)	(13		)	(12		)
Total other income (expense)	(11		)	(13		)	(33		)	(37		)
Income before income tax expense	30			34
Income before income tax expense	49			42			104			92
Income tax expense	11			12
Income tax expense	18			13			37			30
Net income	$	19		$	22
Net income	$	31		$	29		$	67		$	62
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

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

(Amounts in millions, except shares)

									Accumulated
				Other					Other			Total
	Common Stock			Paid-in		Accumulated			Comprehensive			Shareholder's
	Shares	Amount		Capital		Deficit			Loss, Net			Equity
Balance at December 31, 2012	1,000	$	—	$	1,111	$	(71	)	$	(1	)	$	1,039
Balance, December 31, 2013	1,000	$	—	$	1,111	$	(93	)	$	(2	)	$	1,016
Net income	—	—		—		6222			—			6222
Dividends declared	—	—		—		(40		)	—			(40		)
Other	—	—		—		—			1			1
Balance at September 30, 2013	1,000	$	—	$	1,111	$	(49	)	$	(1	)	$	1,061
Balance, March 31, 2014	1,000	$	—	$	1,111	$	(71	)	$	(1	)	$	1,039
Balance at December 31, 2013	1,000	$	—	$	1,111	$	(93	)	$	(2	)	$	1,016
Balance, December 31, 2014	1,000	$	—	$	1,111	$	(111	)	$	(2	)	$	998
Net income	—	—		—		6719			—			6719
Balance at September 30, 2014	1,000	$	—	$	1,111	$	(26	)	$	(2	)	$	1,083
Balance, March 31, 2015	1,000	$	—	$	1,111	$	(92	)	$	(2	)	$	1,017
The accompanying notes are an integral part of these consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)

	Nine-Month Periods
	Three-Month Periods
	Ended September 30,
	Ended March 31,
	2014			2013
	2015			2014
Cash flows from operating activities:
Net income	$	6719		$	6222
Adjustments to reconcile net income to net cash flows from operating activities:
Loss on nonrecurring items	14			—
Depreciation and amortization	28			26
Depreciation and amortization	79			78
Allowance for equity funds	—			(1		)
Allowance for equity funds	(3		)	(2		)
Deferred income taxes and amortization of investment tax credits	11			12
Deferred income taxes and amortization of investment tax credits	37			33
Amortization of deferred energy	12			1
Amortization of other regulatory assets	43			16
Deferred energy	26			(22		)
Other, net	(19		)	10
Amortization of other regulatory assets	(1		)	12
Other, net	(8		)	5
Changes in other operating assets and liabilities:
Accounts receivable and other assets	(1011		)	~~(11~~19		)
Inventories	—			10(5		)
Accounts payable and other liabilities	~~(27~~—		)	(401		)
Net cash flows from operating activities	~~181~~76			~~156~~68
Cash flows from investing activities:
Capital expenditures	(~~117~~48		)	(9055		)
Net cash flows from investing activities	(117		)	(90		)
Contributions in aid of construction and customer advances	1			2
Cash flows from financing activities:
Other, net	2			—
Proceeds from issuance of long-term debt	—			248
Net cash flows from investing activities	(45		)	(53		)
Repayment of long-term debt	—			(251		)
Net change in cash and cash equivalents	31			15
Dividends paid	—			(40		)
Cash and cash equivalents at beginning of period	22			67
Net cash flows from financing activities	—			(43		)
Cash and cash equivalents at end of period	$	53		$	82
Net change in cash and cash equivalents	64			23
Cash and cash equivalents at beginning of period	67			61
Cash and cash equivalents at end of period	$	131		$	84
The accompanying notes are an integral part of these consolidated financial statements.

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Organization and Operations

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

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September~~March 3031, ~~2014~~2015 and for the three- ~~and nine-~~month periods ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014. Certain amounts in the prior periods Consolidated Statement of Operations have been reclassified to conform to the current period's presentation. Such reclassifications did not impact previously reported net income. The results of operations for the three- ~~and nine-~~month ~~periods~~period ended ~~September~~March 3031, ~~2014~~2015 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2014 ~~2013~~ describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the ~~nine~~three-month period ended ~~September~~March 3031, ~~2014~~2015.

(2) New Accounting Pronouncements

In ~~May 2014~~April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. ~~2014~~2015-0903, which ~~creates~~amends FASB Accounting Standards Codification ("ASC") ~~Topic~~Subtopic ~~606~~835-30, "~~Revenue~~Interest ~~from~~- ~~Contracts~~Imputation ~~with~~of ~~Customers" and supersedes ASC Topic 605, "Revenue Recognition~~Interest." The ~~guidance~~amendments ~~replaces~~in ~~industry-specific~~this guidance ~~and~~require ~~establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is~~ that andebt ~~entity~~issuance ~~should~~costs ~~recognize~~related ~~revenue upon transfer of control of promised goods or services~~ to ~~customers~~a inrecognized andebt ~~amount~~liability ~~that reflects the consideration to which an entity expects to~~ be ~~entitled~~presented in ~~exchange for those goods or services. Additionally,~~ the ~~guidance~~balance ~~requires~~sheet ~~the~~as ~~entity~~a todirect ~~disclose~~deduction ~~further~~from ~~quantitative and qualitative information regarding~~ the ~~nature~~carrying ~~and~~ amount of ~~revenues~~that ~~arising~~debt ~~from contracts with customers~~liability, asinstead ~~well~~of as ~~other~~an ~~information about the significant judgments and estimates used in recognizing revenues from contracts with customers~~asset. This guidance is effective for interim and annual reporting periods beginning after December 15, ~~2016.~~2015, ~~Early~~with ~~application~~early isadoption ~~not~~ permitted. This guidance ~~may~~must be adopted retrospectively, orwherein ~~under~~the abalance ~~modified~~sheet ~~retrospective~~of ~~method~~each ~~where~~period ~~the~~presented ~~cumulative~~should ~~effect~~be isadjusted ~~recognized~~to atreflect the ~~date~~new ~~of initial application~~guidance. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

In ~~February 2013~~May 2014, the FASB issued ASU No. ~~2013~~2014-0409, which ~~amends~~creates FASB ASC Topic ~~405~~606, "~~Liabilities."~~Revenue ~~The~~from ~~amendments~~Contracts inwith ~~this~~Customers" ~~guidance~~and ~~require~~supersedes anASC ~~entity~~Topic to605, ~~measure~~"Revenue ~~obligations~~Recognition." ~~resulting~~The ~~from~~guidance ~~joint~~replaces industry-specific guidance and ~~several~~establishes ~~liability~~a ~~arrangements~~single ~~for~~five-step ~~which~~model ~~the~~to ~~total~~identify ~~amount~~and recognize revenue. The core principle of the ~~obligation~~guidance is ~~fixed~~that atan ~~the~~entity ~~reporting~~should ~~date~~recognize asrevenue ~~the~~upon ~~amount~~transfer ~~the~~of ~~reporting~~control ~~entity~~of ~~agreed~~promised goods or services to ~~pay~~customers ~~plus~~in ~~any~~an ~~additional~~amount ~~amounts~~that reflects the ~~reporting~~consideration to which an entity expects to ~~pay~~be onentitled ~~behalf~~in ofexchange ~~its~~for ~~co-obligor~~those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of ~~the~~revenues ~~obligation~~arising from contracts with customers, as well as other information about ~~those~~the ~~obligations.~~significant ~~The~~judgments ~~Company~~and ~~adopted~~estimates ~~this~~used in recognizing revenues from contracts with customers. This guidance onis ~~January~~effective for interim and annual reporting periods beginning after December 115, ~~2014~~2016. ~~The~~Early ~~adoption~~application ofis ~~this~~not permitted. This guidance ~~did~~may ~~not~~be ~~have~~adopted retrospectively or under a ~~material~~modified ~~impact~~retrospective onmethod where the cumulative effect is recognized at the date of initial application. The Company's is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.

(3) Property, Plant and Equipment, Net

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

	~~As of~~		As of
	September 30,				December 31,
	Depreciable Life		March 31,				December 31,
	2014				2013
			2015				2014
Utility plant in-service:
Electric generation	$40-125 years	~~1,054~~	$	1,077	$	~~1,070~~	$	1,036
Electric distribution	~~1,314~~20-70 years		1,337		~~1,289~~		1,321
Electric transmission	~~718~~50-70 years		723		~~685~~		719
Electric intangible plant	~~127~~5-65 years		127		~~138~~		123
Natural gas distribution	~~361~~40-70 years		366		~~357~~		366
Natural gas intangible plant	138-10 years		13		13		13
Common general	~~235~~5-65 years		241		~~212~~		234
Utility plant in-service	~~3,822~~		3,884		~~3,764~~		3,812
Accumulated depreciation and amortization	~~(1,334~~		)(1,316		~~(1,301~~)		)(1,300		)
Utility plant in-service, net	~~2,488~~		2,568		~~2,463~~		2,512
Construction work-in-progress	99		87		89		128
Property, plant and equipment, net	$	~~2,587~~	$	2,655	$	~~2,552~~	$	2,640

(4) Regulatory Matters

~~Energy~~Deferred ~~Efficiency Implementation Rates~~Energy

~~The Public Utilities Commission of~~ Nevada's ~~("PUCN")~~statutes ~~final~~permit ~~order~~regulated ~~approving~~utilities the merger between BHE and NV Energy stipulated that the Company will not seek recovery of any lost revenue for calendar year 2014 in an amount that exceeds 50% of the lost revenue that the Company could otherwise request. In February 2014, the Company filed an application with the PUCN to ~~reset~~adopt ~~the~~deferred energy ~~efficiency~~accounting ~~implementation rate~~procedures. InThe ~~June~~intent ~~2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate, as~~ of ~~July~~these 1,procedures ~~2014,~~is to ~~collect~~ease ~~50% of~~ the ~~estimated~~effect lost revenue that the Company would otherwise be allowed to recover for the 2014 calendar year. The energy efficiency implementation rate will be effective from July through December 2014 and will reset on ~~January~~customers 1,of ~~2015~~fluctuations ~~and remain~~ in ~~effect through September 2015. To~~ the ~~extent~~cost ~~the Company's earned rate~~ of ~~return~~purchased ~~exceeds~~natural ~~the rate of return used to set base general rates~~gas, ~~the~~fuel ~~Company~~and iselectricity ~~required~~and toare ~~refund~~subject to ~~customers~~annual ~~energy~~prudency ~~efficiency~~review ~~implementation~~by ~~rate revenue collected. As a result,~~ the ~~Company~~Public ~~has~~Utilities ~~deferred~~Commission ~~recognition~~ of ~~energy~~Nevada ~~efficiency implementation rate revenue collected and has recorded a liability of $3 million on the Consolidated Balance Sheets as of September 30, 2014~~("PUCN").

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

InEnergy ~~connection~~Efficiency ~~with~~Implementation ~~Nevada~~Rates ~~Power's general rate case filing in May 2014, as required by the PUCN, the Company made a "companion filing" for the purpose of documenting the costs~~ and ~~benefits~~Energy ofEfficiency ~~the~~Program Company's investment in the advanced service delivery program. In October 2014, the PUCN issued an order in the companion filing issued with the general rate case order that, among other things, provided for the implementation of new rates effective January 1, 2015 to begin recovery of costs associated with advance service delivery. The recovery costs will increase annual revenue approximately $10 million. As a result of the PUCN order in the companion filing issued with the Nevada Power general rate case order, the Company recorded $7 million in asset impairments related to property, plant and equipment and $1 million of regulatory asset impairments, which are included in operating and maintenance expense on the Consolidated Statements of Operations for the three- and nine-month periods ended September 30, 2014.Rates

~~2013~~In ~~Federal~~July ~~Energy~~2010, ~~Regulatory~~regulations ~~Commission~~were ~~Transmission~~adopted ~~Rate~~by ~~Case~~the PUCN that authorizes an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN through energy efficiency implementation rates ("EEIR"). As a result, the Company files annually in March to adjust energy efficiency program rates and EEIR for over- or under-collected balances, which are effective in October of the same year.

InThe ~~May~~PUCN's ~~2013,~~final order approving the BHE Merger stipulated that the Company, ~~along~~would ~~with~~not ~~Nevada~~seek ~~Power,~~recovery ~~filed~~of anany ~~application~~lost ~~with~~revenue ~~the~~for ~~Federal~~calendar ~~Energy~~year ~~Regulatory~~2014 ~~Commission~~in ~~("FERC")~~an toamount ~~establish~~that ~~single~~exceeded ~~system~~50% ~~transmission~~of ~~and~~the ~~ancillary~~lost ~~service~~revenue ~~rates.~~that ~~The~~the ~~combined~~Company ~~filing~~could ~~requested~~otherwise ~~incremental~~request. In ~~rate~~February 2014, ~~relief~~the ofCompany ~~$17~~filed ~~million~~an ~~annually~~application with the PUCN to bereset ~~effective~~the ~~January 1,~~EEIR ~~2014~~and energy efficiency program rates. In ~~August~~June ~~2013~~2014, the ~~FERC~~PUCN ~~granted~~accepted ~~the~~a ~~companies'~~stipulation ~~request~~to ~~for~~adjust athe ~~rate~~EEIR, ~~effective~~as ~~date~~ of ~~January~~July 1, 2014, ~~subject~~ to ~~refund,~~collect ~~and~~50% ~~set~~of the ~~case~~estimated lost revenue that the Company would otherwise be allowed to recover for ~~hearing~~the or2014 ~~settlement~~calendar ~~discussions~~year. OnThe EEIR was effective from July through December 2014, set on January 1, ~~2014,~~2015 and remains in effect through September 2015. To the extent the Company's ~~implemented~~earned rate of return exceeds the ~~filed~~rate of return used to set base general rates, inthe ~~this~~Company ~~case~~is ~~subject~~required to refund asto ~~set~~customers ~~forth~~EEIR revenue collected. As a result, the Company has deferred recognition of EEIR revenue collected and has recorded a liability of $2 million, which is included in current regulatory liabilities on the ~~FERC's~~Consolidated ~~order~~Balance Sheets as of March 31, 2015.

InGeneral ~~September~~Rate 2014, the Company, along with Nevada Power, filed an unopposed settlement offer with the FERC on behalf of NV Energy and the intervening parties providing rate relief of $4 million. The settlement offer would resolve all outstanding issues related to this case. In addition, a preliminary order from the administrative law judge granting the motion for interim rate relief was issued, which authorizes the Company to institute the interim rates effective September 1, 2014, and begin billing transmission customers under the settlement rates for service provided on and after that date. These will remain in effect pending the FERC's approval. As of September 30, 2014, the Company accrued $2 million for amounts subject to rate refund, which is included in customer deposits and other on the Consolidated Balance Sheets. In October 2014, the FERC judge certified the settlement and referred to the FERC for final approval. Once the FERC approves the Offer of Settlement, the Company will refund amounts that were billed to the FERC transmission customers subject to refund.Case

~~(5) Recent~~In ~~Financing~~connection ~~Transactions~~with Nevada Power's general rate case filing in May 2014, as required by the PUCN, the Company made a "companion filing" for the purpose of documenting the costs and benefits of the Company's investment in the advanced service delivery program. In October 2014, the PUCN issued an order in the companion filing issued with the general rate case order that, among other things, provided for the implementation of new rates effective January 1, 2015 to begin recovery of costs associated with advance service delivery. The recovery of advanced service delivery costs will increase annual revenue approximately $10 million. As a result of the PUCN order in the companion filing issued with the Nevada Power general rate case order, the Company recorded $7 million in asset impairments related to property, plant and equipment and $1 million of regulatory asset impairments, which are included in operating and maintenance on the Consolidated Statements of Operations for the year ended December 31, 2014.

~~Credit~~2013 ~~Facility~~Federal Energy Regulatory Commission ("FERC") Transmission Rate Case

In ~~June 2014~~May 2013, the Company, ~~amended~~along ~~its~~with ~~$250~~Nevada ~~million~~Power, ~~secured~~filed ~~credit~~an ~~facility~~application ~~expiring~~with inthe ~~March~~FERC ~~2017,~~to ~~extending~~establish ~~the~~single ~~maturity~~system ~~date~~transmission toand ~~March~~ancillary ~~2018~~service rates. The ~~amended~~combined ~~facility~~filing ~~has~~requested aincremental ~~variable interest~~ rate ~~based~~relief onof ~~the~~$17 ~~London~~million ~~Interbank~~annually ~~Offered~~to ~~Rate~~be oreffective aJanuary 1, 2014. ~~base~~In ~~rate~~August 2013, atthe FERC granted the ~~Company~~companies's ~~option,~~request ~~plus~~for a ~~spread~~rate ~~that~~effective ~~varies~~date ~~based~~of ~~upon~~January ~~the~~1, ~~Company's~~2014 ~~secured~~subject ~~debt~~to ~~credit~~refund, ~~rating.~~and ~~The~~set ~~amended~~the ~~facility~~case ~~requires~~for ~~that~~hearing ~~the~~or ~~Company's~~settlement ~~ratio~~discussions. ofOn ~~consolidated~~January ~~debt~~1, ~~including~~2014, ~~current~~the ~~maturities,~~Company toimplemented ~~total~~the ~~capitalization not~~filed ~~exceed~~rates ~~0.68~~in this case subject to ~~1.0~~refund as ofset ~~the~~forth ~~last~~in ~~day~~the ofFERC's ~~each quarter~~order.

~~(6) Employee~~In ~~Benefit~~September ~~Plans~~2014, the Company, along with Nevada Power, filed an unopposed settlement offer with the FERC on behalf of NV Energy and the intervening parties providing rate relief of $4 million. The settlement offer would resolve all outstanding issues related to this case. In addition, a preliminary order from the administrative law judge granting the motion for interim rate relief was issued, which authorizes the Company to institute the interim rates effective September 1, 2014, and begin billing transmission customers under the settlement rates for service provided on and after that date. In January 2015, the FERC approved the settlement and refunds were issued.

~~The Company is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan~~ (~~"Qualified Pension Plan"~~5) Employee 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 the Company. Amounts attributable to the Company 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 income.

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

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

	As of
	September 30,				December 31,
	March 31,			December 31,
	2014				2013
	2015			2014
Qualified Pension Plan:
Qualified Pension Plan -
Other assets	$	15			$	18
Other long-term liabilities	(13	)		(13	)
Non-Qualified Pension Plans:
Accrued employee expenses	(1		)		(1		)
Other current liabilities	(1	)		(1	)
Other long-term liabilities	(10	)	)	(10	~~(11~~)		)
Other Postretirement Plans:
Other Postretirement Plans -
Other long-term liabilities	(3934	)	)	(33	~~(38~~)		)

(7) Fair Value Measurements

• 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.


(6)	Fair Value Measurements

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

As of September 30, 2014

As of December 31, 2013

As of March 31, 2015

As of December 31, 2014

Carrying

Fair

Carrying

Fair

Value

Long-term debt

1,174

1,~~293~~309

1,~~176~~174

1,~~270~~301

(87) Commitments and Contingencies

Environmental Laws and Regulations

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

Valmy ~~Generating~~Generation Station

In June 2009, the Company received a request for information from the Environmental Protection Agency Region 9 under Section 114 of the Clean Air Act requesting current and historical operations and capital project information for the Company's Valmy Generating Station, ~~a 522-megawatt generating facility~~ located in Valmy, Nevada. The Company co-owns ~~50%~~ and operates this coal-fueled generating facility. ~~while~~ Idaho Power Company owns the ~~other~~remaining 50% ~~interest~~. The Environmental Protection Agency's Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the Environmental Protection Agency relating to the plant. The Company completed its ~~response~~responses to the Environmental Protection Agency in December 2009 and will continue to monitor developments relating to this Section 114 request. At this time, the Company cannot predict the impact, if any, associated with this information request.

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.

Newmont Nevada Energy Investment - TS Power Plant

Newmont Nevada Energy Investment, LLC ("Newmont") owns a 203 megawatt coal-fueled power plant facility located in Eureka County, Nevada (the "TS Power Plant") that is interconnected to the Company's transmission system. As a result of system modifications required for a 500-kilovolt transmission line connecting the Company and Nevada Power ("ON Line"), Newmont will need to install certain protection equipment at its TS Power Plant. Newmont brought suit against the Company in the Second Judicial District of Nevada seeking declaratory relief and to enjoin the operation at full capacity of certain equipment to be installed by the Company for the ON Line project, until such time as Newmont completes the design, fabrication and installation of protection equipment at its power plant to protect its generator from potential adverse effects caused by the operation of the Company's equipment at full capacity. In addition, Newmont's complaint asserted a claim under the parties' interconnection agreement seeking to recover the cost of making the necessary modifications to the TS Power Plant.

A hearing on Newmont's motion for a preliminary injunction was held during the week of August 12, 2013, after which the trial court concluded that it would enter an order enjoining the Company from operating its equipment at full capacity from January 1, 2014 until approximately April 8, 2014, and from approximately June 1, 2014 to June 30, 2014 (or the time Newmont has completed the installation of its protection equipment), so as to allow installation and testing of protection equipment at the TS Power Plant. The district court issued the order in December 2013. Newmont posted the required $1 million bond and subsequently filed a complaint with the FERC to address the issue of who will pay for the protection equipment and its installation at the TS Power Plant. In April 2014, the FERC issued an order directing the Company to pay the costs of studies relating to subsynchronous resonance conducted by Newmont and the installation of the protection equipment at the TS Power Plant. The costs are a component of the ON Line construction costs and are shared between the Company and Nevada Power at 5% and 95%, respectively. The protection equipment has been installed at the TS Power Plant and the Sierra Pacific facilities are now operating at full capacity. Accordingly, the $1 million bond posted by Newmont has been released. Newmont is also seeking recovery of legal fees associated with litigating this matter. The parties have finalized a settlement in this matter and final documents dismissing the claims are being filed with the court. The terms of the settlement will not have a material impact to the Company.

Caughlin Fire

On November 18, 2011, a fire was reported in the hills near Reno, Nevada (the "Caughlin Fire"). In January 2012, the Reno Fire Department issued a report in which they opined that "this fire was most likely the result of an electrical event in the area," and that "something such as a tree branch hitting the power-line" was a likely cause of the fire. The Company is continuing its investigation in the matter.

ToSubrogation ~~date, six subrogation~~ lawsuits and ~~two~~ individual claimant lawsuits have been filed against the Company in relation to the Caughlin Fire. The subrogation lawsuits have been brought by various insurance companies, and involve similar causes of action (negligence, inverse condemnation, trespass, nuisance, subrogation and strict liability). ~~One~~The ~~of the~~ individual ~~claimant~~ lawsuits ~~identifies~~mostly ~~six~~alleged ~~plaintiffs,~~similar ~~while~~causes ~~the~~of ~~other~~action ~~individual~~as ~~claimant~~outlined ~~lawsuit~~in ~~purports~~the tosubrogation beclaims. ~~brought~~The onCompany ~~behalf~~reached ofsettlement ~~a class~~ of ~~similarly~~all ~~affected individuals within~~ the ~~fire~~subrogation ~~perimeter~~lawsuits ~~who~~in ~~suffered~~July ~~damage~~2014, orwhich ~~loss~~did ofnot ~~use~~have ~~of their property as~~ a ~~result~~material ofimpact ~~the~~to ~~Caughlin Fire and~~ the ~~evacuation order associated with it~~Company.

~~All~~In ofFebruary ~~the remaining cases have been consolidated before a single judge in Washoe County~~2015, ~~Nevada.~~all Inbut ~~July~~one ~~2014,~~of the ~~Company~~remaining ~~reached~~individual ~~a settlement with the~~ plaintiffs inentered ~~the~~into ~~six~~a ~~subrogation~~settlement ~~lawsuits~~agreement. ~~identified~~This ~~above,~~settlement ~~which~~agreement did not have a material impact toon the Company. AtThe ~~this~~Company ~~time,~~plans ~~management~~to vigorously defend the remaining lawsuit. The Company cannot assess or predict ~~what~~ the ~~impact or~~ outcome of the ~~two~~remaining ~~individual~~lawsuit ~~claimant lawsuits may be,~~ or ~~what,~~ if any, other litigation may be brought on this matter.

~~(9) Segment~~Touch ~~Information~~America Holdings

~~The~~In ~~Company~~January ~~has~~2015, ~~identified~~Brent ~~two~~Williams ~~reportable~~as ~~operating~~Trustee ~~segments:~~of ~~electric~~Touch ~~and~~America ~~natural~~Holdings ~~gas.~~("Touch ~~The~~America") ~~electric~~filed ~~segment~~a ~~derives~~complaint ~~most~~in ofthe ~~its~~United ~~revenue~~States ~~from~~Bankruptcy ~~retail~~Court ~~sales~~for the District of ~~electricity~~Delaware toagainst ~~residential,~~the ~~commercial,~~Company ~~and~~alleging ~~industrial~~Touch ~~customers~~America ~~and~~owns ~~from~~certain ~~wholesale~~underground ~~sales.~~communications ~~The~~conduit ~~natural~~located ~~gas~~at ~~segment~~various ~~derives~~places ~~most~~in ofthe ~~its~~western ~~revenue~~United ~~from~~States ~~retail~~that ~~sales~~the ofCompany ~~natural~~also ~~gas~~claims to ~~residential,~~own. ~~commercial,~~The ~~and~~conduit ~~industrial~~at ~~customers~~issue ~~and~~is ~~also~~believed ~~obtains~~to ~~revenue~~be bylocated ~~transporting~~between ~~natural~~Reno, ~~gas~~Nevada ~~owned~~and bySpanish ~~others~~Fork, ~~through~~Utah ~~its~~as ~~distribution~~part of a larger duct bank system. ~~Pricing~~In ~~for~~March 2015, ~~electric~~the ~~and~~Company ~~natural~~filed ~~gas~~a ~~sales~~response ~~are~~to ~~established~~the ~~separately~~complaint byand ~~the~~asserted ~~PUCN;~~a ~~therefore,~~counterclaim ~~management~~to ~~also~~the ~~reviews~~conduit. ~~each~~The ~~segment~~Company ~~separately~~plans to ~~make~~vigorously ~~decisions~~defend ~~regarding~~the ~~allocation~~matter. The Company cannot assess or predict the outcome of ~~resources~~the ~~and~~case inat ~~evaluating~~this ~~performance~~time.

~~Operating~~(8) Segment ~~revenue,~~Information cost of fuel, energy and capacity and natural gas purchased for resale are key drivers of the Company's results of operations as they encompass retail and wholesale electricity and natural gas revenue and the direct costs associated with providing electricity and natural gas to customers. The Company believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale, is therefore meaningful.

The Company 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 Company believes presenting gross margin allows the reader to assess the impact of the Company's regulatory treatment and its overall regulatory environment on a consistent basis and is meaningful. Gross margin is calculated as operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale. The following tables provide information on a reportable segment basis (in millions):

		Three-Month Period								Nine-Month Period
	For the three-month period ended
		Ended September 30, 2014								Ended September 30, 2014
	March 31,			March 31,
					Natural							Natural
	2015			2014
		Electric			Gas		Total			Electric		Gas		Total
Operating revenue:
Operating revenue		$	233		$	18	$	251		$	589	$	83	$	672
Regulated electric	$	196		$	177
Cost of fuel, energy and capacity		103			—		103			269		—		269
Regulated gas	50			44
Natural gas purchased for resale		—			7		7			—		48		48
Total operating revenue	$	246		$	221
Gross margin		$	130		$	11	141			$	320	$	35	355
Cost of sales:
Operating and maintenance expense							47							120
Regulated electric	$	97		$	80
Depreciation and amortization							27							79
Regulated gas	35			29
Property and other taxes							7							19
Total cost of sales	$	132		$	109
Interest expense, net of allowance for debt funds							15							44
Gross margin:
Allowance for equity funds							(1		)					(3		)
Regulated electric	$	99		$	97
Other, net							(3		)					(8		)
Regulated gas	15			15
Income before income tax expense							$	49						$	104
Total gross margin	$	114		$	112
Operating and maintenance:
Regulated electric	$	32		$	29
Regulated gas	4			5
Total operating and maintenance	$	36		$	34
Depreciation and amortization:
Regulated electric	$	24		$	22
Regulated gas	4			4
Total depreciation and amortization	$	28		$	26
Operating income:
Regulated electric	$	37		$	41
Regulated gas	6			5
Total operating income	$	43		$	46
Interest expense, net of allowance for borrowed funds:
Regulated electric	$	14		$	14
Regulated gas	1			1
Total interest expense, net of allowance for borrowed funds	$	15		$	15
Income tax (benefit) expenses:
Regulated electric	$	9		$	10
Regulated gas	2			2
Total income tax (benefit) expense	$	11		$	12

	Three-Month Period							Nine-Month Period
	Ended September 30, 2013							Ended September 30, 2013
			Natural							Natural
	Electric		Gas		Total			Electric		Gas		Total
Operating revenue	$	213	$	12	$	225		$	559	$	61	$	620
Cost of fuel, energy and capacity	80		—		80			212		—		212
Natural gas purchased for resale	—		4		4			—		28		28
Gross margin(1)	$	133	$	8	141			$	347	$	33	380
Operating and maintenance expenses					52							148
Depreciation and amortization					26							78
Property and other taxes					6							19
Merger-related expenses					2							6
Interest expense, net of allowance for debt funds					15							47
Allowance for equity funds					(1		)					(2		)
Other, net					(1		)					(8		)
Income before income tax expense					$	42						$	92

(1) Energy efficiency program costs were reclassified from gross margin to operating and maintenance expenses for presentation purposes.

	As of
	September 30,		December 31,
	2014		2013
Total assets:
Electric	$	2,976	$	2,957
Natural gas	329		335
Other(1)	138		77
Total assets	$	3,443	$	3,369

(1) Consists principally of cash and cash equivalents.



	For the three-month period ended
	March 31,		March 31,
	2015		2014
Capital expenditures:
Regulated electric	$	43	$	50
Regulated gas	5		5
Total capital expenditures	$	48	$	55

	As of
	March 31,		December 31,
	2015		2014
Total assets:
Regulated electric	$	3,008	$	3,031
Regulated gas	337		327
Regulated common assets⁽¹⁾	59		30
Total assets	$	3,404	$	3,388


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

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

General

The Company'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. The Company 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 the Company. 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 the Company.

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 Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.

Results of Operations for the ~~Third~~First Quarter ~~and First Nine Months~~ of ~~2014~~2015 and ~~2013~~2014

Net income for the ~~third~~first quarter of ~~2014~~2015 was $31 19 million, ana ~~increase~~decrease of $2 3 million, or 714%, compared to ~~2013~~2014 due to ~~reductions~~an toincrease ~~income~~in ~~from~~regulatory ~~energy~~amortizations, ~~efficiency~~lower ~~implementation~~revenue ~~rate~~due ~~revenue~~to ~~adjustments~~a ~~recorded~~FERC inrate ~~2013~~change ~~and~~effective ~~higher~~September 1, 2014 ~~natural~~and ~~gas~~increased ~~margins,~~maintenance costs; partially offset by ~~impairment~~increased ~~costs~~revenues ~~resulting~~for ~~from~~ the ~~settlement~~recovery of ~~the~~costs ~~companion~~associated ~~filing made in conjunction~~ with ~~Nevada~~advanced ~~Power's~~service ~~2014 general rate case and lower revenue in 2014 as a result of reduced customer rates from the 2013 general rate case~~delivery.

Net income for the first nine months of 2014 was $67 million, an increase of $5 million, or 8%, compared to 2013 due primarily to lower compensation and office costs, higher regulatory credits, merger-related expenses in 2013 and reductions to income from energy efficiency implementation rate revenue adjustments recorded in 2013, partially offset by lower revenue in 2014 as a result of reduced customer rates from the 2013 general rate case and impairment costs resulting from the settlement of the companion filing made in conjunction with Nevada Power's 2014 general rate case.13

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

Electric Gross Margin

	Third Quarter									First Nine Months
	First Quarter
	2014		2013		Change					2014		2013		Change
	2015		2014		Change
Gross margin (in millions):
Operating revenue	$	233	$	213	$	20		9	%	$	589	$	559	$	30		5	%
Operating electric revenue	$	196	$	177	$	19		11	%
Cost of fuel, energy and capacity	~~103~~97		80		2317			2921		~~269~~		~~212~~		57			27
Gross margin	$	~~130~~99	$	~~133~~97	$	(32	)	(2	)	$	~~320~~	$	~~347~~	$	~~(27~~	)	(8	)
Sales (GWh):
GWh sold:
Residential	~~668~~591		~~671~~594		(3		)	—(1	)%	~~1,746~~		~~1,794~~		~~(48~~		)	(3	)%
Commercial	~~855~~666		~~851~~652		414			—2		~~2,268~~		~~2,268~~		—			—
Industrial	~~728~~717		~~701~~687		2730			4		~~2,145~~		~~2,092~~		53			3
Other	4		4		—			—		12		12		—			—
Total retail	21,~~255~~978		21,~~227~~937		2841			12		~~6,171~~		~~6,166~~		5			—
Wholesale	~~138~~182		~~182~~210		(4428		)	(2413	)	~~481~~		~~654~~		~~(173~~		)	~~(26~~	)
Total sales	2,393		2,409		(16		)	(1	)	6,652		6,820		(168		)	(2	)
Total GWh sold	2,160		2,147		13			1
Average number of retail customers (in thousands)	331		328		3			1	%	330		327		3			1	%
Average number of retail customers (in thousands):
Average retail revenue per MWh	$	97.32	$	88.74	$	8.58		10	%	$	88.07	$	83.40	$	4.67		6	%
Residential	287		284		3			1	%
Heating degree days	53		85		(32		)	(38	)%	2,372		2,859		(487		)	(17	)%
Commercial	46		46		—			—
Cooling degree days	947		914		33			4	%	1,206		1,177		29			2	%
Total	333		330		3			1
Sources of energy (GWh):
Average retail revenue per MWh	$	91.86	$	82.85	$	9.01		11	%
Coal	461		411		50			12	%	1,408		1,061		347			33	%
Heating degree days	1,668		1,860		(192		)	(10	)%
Natural gas	1,213		1,170		43			4		3,107		2,768		339			12
Sources of energy (GWh)(1):
Total energy generated	1,674		1,581		93			6		4,515		3,829		686			18
Coal	340		455		(115		)	(25	)%
Energy purchased	793		916		(123		)	(13	)	2,274		3,170		(896		)	(28	)
Natural gas	978		909		69			8
Total	2,467		2,497		(30		)	(1	)	6,789		6,999		(210		)	(3	)
Total energy generated	1,318		1,364		(46		)	(3	)
Energy purchased	927		810		117			14
Total	2,245		2,174		71			3

13(1) GWh amounts are net of energy used by the related generating facilities.

Electric gross margin decreased $3 million, or 2%, for the third quarter of 2014 compared to 2013 due to:

• $5 million in lower revenue in 2014 as a result of reduced customer rates from the 2013 general rate case effective January 1, 2014;

• $1 million in lower energy efficiency program rate revenue, which is offset in operating and maintenance expense; and

• $1 million in lower transmission revenue.

The decrease in gross margin was partially offset by:

• $4 million provision for refund of energy efficiency implementation rate revenue recorded in 2013.

Electric gross margin decreased $27 million, or 8%, for the first nine months of 2014 compared to 2013 due to:

• $25 million in lower revenue in 2014 as a result of reduced customer rates from the 2013 general rate case effective January 1, 2014;

• $4 million in lower net residential usage primarily due to a decrease in heating degree days; and

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

The decrease in gross margin was partially offset by:

• $3 million in higher wholesale revenue due to higher natural gas prices and

• $2 million due to customer growth.

Natural Gas Gross Margin

	Third Quarter									First Nine Months
	2014		2013		Change					2014		2013		Change
Gross margin (in millions):
Operating revenue	$	18	$	12	$	6		50	%	$	83	$	61	$	22		36	%
Natural gas purchased for resale	7		4		3			75		48		28		20			71
Gross margin	$	11	$	8	$	3		38		$	35	$	33	$	2		6
Sales (000's Dth):
Residential	687		698		(11		)	(2	)%	5,219		6,039		(820		)	(14	)%
Commercial	396		400		(4		)	(1	)	2,777		3,086		(309		)	(10	)
Industrial	181		189		(8		)	(4	)	969		986		(17		)	(2	)
Total retail	1,264		1,287		(23		)	(2	)	8,965		10,111		(1,146		)	(11	)
Average number of retail customers (in thousands)	156		154		2			1	%	156		154		2			1	%
Average revenue per retail Dth sold	$	13.54	$	8.91	$	4.63		52	%	$	9.04	$	5.84	$	3.20		55	%
Average cost of natural gas per retail Dth sold	$	6.06	$	5.73	$	0.33		6	%	$	7.00	$	6.16	$	0.84		14	%
Combined retail and wholesale average cost of natural gas per Dth sold	$	6.07	$	3.15	$	2.92		93	%	$	5.40	$	2.75	$	2.65		96	%
Heating degree days	53		85		(32		)	(38	)%	2,372		2,859		(487		)	(17	)%

Natural gas gross margin increased $3 million, or 38%, for the third quarter and $2 million, or 6%, for the first nine months of 2014 compared to 2013 due to rate increases from the general rate case effective January 1, 2014. The first nine months of 2014 are partially offset by a decrease in heating degree days.

~~Operating~~Natural ~~and~~Gas ~~maintenance~~Gross ~~expense decreased $5 million, or 10%, for the third quarter of 2014 compared to 2013 primarily due to:~~Margin

• $5 million in costs for the disallowance of energy efficiency implementation rate revenue in 2013;



	First Quarter
	2015		2014		Change
Gross margin (in millions):
Operating natural gas revenue	$	50	$	44	$	6		14	%
Natural gas purchased for resale	35		29		6			21
Gross margin	$	15	$	15	$	—		—

Dth sold:
Residential	3,215		3,299		(84		)	(3	)%
Commercial	1,615		1,759		(144		)	(8	)
Industrial	525		507		18			4
Total retail	5,355		5,565		(210		)	(4	)

Average number of retail customers (in thousands)	158		156		2			1	%
Average revenue per retail Dth sold	$	9.15	$	7.75	$	1.40		18	%
Average cost of natural gas per retail Dth sold	$	6.48	$	5.29	$	1.19		22	%
Heating degree days	1,668		1,860		(192		)	(10	)%

•Electric gross margin increased $42 million, inor ~~lower~~2%, ~~demand-side~~for ~~management~~the ~~program~~first ~~amortization;~~quarter of 2015 compared to 2014 due to:

• $3 million infrom ~~lower~~recovery ~~compensation~~of ~~and~~costs ~~insurance~~associated ~~costs;~~with advanced service delivery and

• $31 million ofin higher ~~regulatory~~energy ~~credits~~efficiency ~~related~~program torate ~~advanced~~revenue, ~~meter~~which ~~technology~~is ~~and~~offset ~~other~~in ~~regulatory~~operating ~~amortizations;~~and maintenance expense.

•The $1increase ~~million~~ in ~~lower~~gross ~~maintenance~~margin ~~costs~~was atpartially ~~the~~offset ~~generating stations; and~~by:

• $12 million in lower ~~energy~~revenue ~~efficiency~~due ~~program~~to ~~costs,~~a ~~which~~FERC ~~are~~rate ~~fully~~change ~~recovered~~effective inSeptember ~~operating~~1, ~~revenue~~2014 and improved energy efficiency measures.

~~The~~Natural ~~decrease~~gas ingross ~~operating~~margin ~~and~~remained ~~maintenance~~constant ~~expense~~for ~~was~~the ~~offset~~first ~~by:~~quarter of 2015 compared to 2014.

•Operating and maintenance increased $82 million, or 6%, for the first quarter of ~~impairment~~2015 ~~costs~~compared ~~resulting~~to ~~from~~2014 ~~the~~due ~~settlement~~to ofenergy ~~the~~efficiency ~~companion~~program ~~filing~~costs, ~~made~~which inare ~~conjunction~~fully ~~with~~recovered ~~Nevada~~in ~~Power's~~operating ~~2014~~revenue; ~~general~~planned ~~rate~~maintenance ~~case~~costs and outside service fees. The increase was partially offset by lower compensation costs.

•Depreciation and amortization increased $32 million, ~~related~~or to8%, anfor ~~impairment~~the ~~charge~~first ~~related~~quarter toof ~~the~~2015 ~~recovery~~compared ofto ~~certain~~2014 ~~assets~~primarily ~~not~~due ~~currently~~to inregulatory ~~rates~~amortizations.

~~Operating~~Income ~~and~~tax ~~maintenance~~ expense decreased $281 million, or 198%, for the first ~~nine~~quarter ~~months~~ of ~~2014~~2015 compared to ~~2013~~2014 and the effective tax rates were 37% for 2015 and 35% for 2014. The decrease in income tax expense is primarily due to: lower income before income tax expense.

• $11 million in lower compensation and office costs;

• $8 million in higher regulatory credits related to advanced meter technology and other regulatory amortizations;

• $8 million in lower demand-side management program amortization;

• $5 million in costs for the disallowance of energy efficiency implementation rate revenue in 2013;

• $4 million in lower maintenance costs at the generating stations;

• $3 million in lower energy efficiency program costs, which are fully recovered in operating revenues;

• $2 million in lower regulatory costs and amortization; and

• $1 million in lower costs associated with outside consulting services.

The decrease in operating and maintenance expense was partially offset by:

• $8 million of impairment costs resulting from the settlement of the companion filing made in conjunction with Nevada Power's 2014 general rate case;

• $3 million in higher costs related to relinquishing an insurance claim for a previously sold asset; and

• $3 million related to an impairment charge related to the recovery of certain assets not currently in rates.

Depreciation and amortization increased $1 million, or 4%, for the third quarter and $1 million, or 1%, for the first nine months of 2014 compared to 2013 primarily due to plant in-service additions.

Merger-related expense decreased $2 million for the third quarter and $6 million for the first nine months of 2014 compared to 2013 due to costs incurred related to the merger of BHE and NV Energy in 2013.

Interest expense, net of allowance for debt funds decreased $3 million, or 6%, for the first nine months of 2014 compared to 2013 as a result of using the proceeds from issuing lower cost debt in August 2013 to repay higher cost debt, partially offset by higher interest expense on regulatory items.

Allowance for equity funds increased $1 million, or 50%, for the first nine months of 2014 compared to 2013 primarily due to an increase in construction activity.

Other, net increased $2 million for the third quarter of 2014 compared to 2013 due to $2 million in higher carrying charges related to the 2013 general rate case, partially offset by $1 million in gains recognized in 2013 related to the sale of property.

Income tax expense increased $5 million, or 38%, for the third quarter of 2014 compared to 2013 and the effective tax rates were 37% for 2014 and 31% for 2013. The increase in income tax expense and change in effective tax rate is primarily due to higher pre-tax earnings and effects of ratemaking.

Income tax expense increased $7 million, or 23%, for the first nine months of 2014 compared to 2013 and the effective tax rates were 36% for 2014 and 33% for 2013. The increase in income tax expense is primarily due to higher pre-tax earnings.

Liquidity and Capital Resources

As of ~~September~~March 3031, ~~2014~~2015, the Company's total net liquidity was $~~381~~303 million consisting of $~~131~~53 million in cash and cash equivalents and $250 million of revolving credit facility availability.

Operating Activities

Net cash flows from operating activities for the ~~nine~~three-month periods ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014 were $~~181~~76 million and $~~156~~68 million, respectively. The change was primarily due to ~~refunds~~higher tocollections ~~customers~~ for deferred energy costs, ina ~~2013~~one-time ~~and~~bill ~~collection~~credit of ~~prior~~$5 ~~period~~million ~~deferred~~to ~~renewable~~retail ~~energy~~customers ~~program~~refunded ~~costs,~~in 2014 in connection with the BHE Merger and lower compensation payments. The increase is partially offset by ~~increased~~lower ~~rent~~collections ~~payments~~from ~~related~~customers, higher refunds to ~~the~~customers ONfor ~~Line~~conservation ~~transmission~~and ~~use~~renewable ~~agreement~~programs and higher property taxes in 2015.

Investing Activities

Net cash flows from investing activities for the ~~nine~~three-month periods ended ~~September~~March 3031, ~~2014~~2015 and ~~2013~~2014 were $(~~117~~45) million and $(9053) million, respectively. The change was primarily due to ~~higher~~decreased capital expenditures for various ~~base~~ capital projects ~~and reduced contributions in aid of construction~~.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2014 and 2013 were $– million and $(43) million, respectively. The change was due to repayment of long-term debt of $251 million in 2013 and a decrease in dividends paid of $40 million, partially offset by proceeds from issuance of long-term debt of $248 million 2013.

Ability to Issue Debt

The Company's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of ~~September~~March 3031, ~~2014~~2015, the Company has financing authority from the PUCN consisting of ~~authority~~the ability to: (1) issue additional long-term debt securities of up to $350 million; (2) refinance up to $348 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $600 million. The Company's revolving credit facility contains a financial maintenance covenant which the Company was in compliance with as of ~~September~~March 3031, ~~2014~~2015. In addition, certain financing agreements contain covenants which are currently suspended as the Company's senior secured debt is rated investment grade. However, if the Company's senior secured debt ratings fall below investment grade by either Moody's Investor Service or Standard & Poor's, the Company would be subject to limitations under these covenants.

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

Capital Expenditures

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

16Forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, for the year ended December 31, 2015 are as follows (in millions):

Forecasted capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items for the year ended December 31, 2014 are as follows (in millions):



	2015

Generation development	$	73
Distribution	118
Transmission system investment	14
Other	33
Total	$	238

	2014
Generation development	$	41
Distribution	95
Transmission system investment	15
Other	39
Total	$	190

Contractual Obligations

As of ~~September~~March 3031, ~~2014~~2015, 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, ~~2013~~ 2014.

Regulatory Matters

The Company is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2013~~ 2014, and new regulatory matters occurring in ~~2014~~2015.

The PUCN's final order approving the merger between BHE and NV Energy stipulated that the Company will not seek recovery of any lost revenue for calendar year 2014 in an amount that exceeds 50% of the lost revenue that the Company could otherwise request. In February 2014, the Company filed an application with the PUCN to reset the energy efficiency implementation rate. In June 2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate, as of July 1, 2014, to collect 50% of the estimated lost revenue that the Company would otherwise be allowed to recover for the 2014 calendar year. The energy efficiency implementation rate will be effective from July through December 2014 and will reset on January 1, 2015 and remain in effect through September 2015. To the extent the Company's earned rate of return exceeds the rate of return used to set base general rates, the Company is required to refund to customers energy efficiency implementation rate revenue collected. As a result, the Company has deferred recognition of energy efficiency implementation rate revenue collected and has recorded a liability of $3 million on the Consolidated Balance Sheets as of September 30, 2014.16

InState ~~connection~~Regulatory with Nevada Power's general rate case filing in May 2014, as required by the PUCN, the Company made a "companion filing" for the purpose of documenting the costs and benefits of the Company's investment in the advanced service delivery program. In October 2014, the PUCN issued an order in the companion filing issued with the general rate case order that, among other things, provided for the implementation of new rates effective January 1, 2015 to begin recovery of costs associated with advance service delivery. The recovery costs will increase annual revenue approximately $10 million. As a result of the PUCN order in the companion filing issued with the Nevada Power general rate case order, the Company recorded $7 million in asset impairments related to property, plant and equipment and $1 million of regulatory asset impairments, which are included in operating and maintenance expense on the Consolidated Statements of Operations for the three- and nine-month periods ended September 30, 2014.Matters

NVThe ~~Energy~~PUCN's ~~has~~final ~~announced~~order ~~plans~~approving ~~to join~~ the ~~energy~~BHE ~~imbalance~~Merger ~~market~~stipulated ~~("EIM")~~that inthe ~~October~~Company ~~2015.~~would ~~The~~not ~~EIM~~seek isrecovery ~~expected~~of toany ~~reduce~~lost ~~costs~~revenue tofor ~~serve~~calendar ~~customers~~year ~~through~~2014 ~~more~~in ~~efficient~~an ~~dispatch~~amount ofthat aexceeded ~~larger~~50% ~~and more diverse pool~~ of ~~resources,~~the ~~more~~lost ~~effectively~~revenue ~~integrate~~that ~~renewables~~the ~~and~~Company ~~enhance~~could ~~reliability~~otherwise ~~through improved situational awareness and responsiveness~~request. In ~~today's environment~~February 2014, ~~utilities in~~ the ~~west~~Company ~~outside~~filed ~~the~~an ~~California~~application ~~Independent~~with ~~System~~the ~~Operator~~PUCN ~~("California~~to ~~ISO")~~reset ~~rely~~the ~~upon~~EEIR aand ~~combination~~energy ofefficiency ~~automated~~program ~~and~~rates. ~~manual~~In ~~dispatch~~June ~~within~~2014, the ~~hour~~PUCN toaccepted ~~balance~~a ~~generation~~stipulation ~~and load~~ to ~~maintain~~adjust ~~reliable~~the ~~supply~~EEIR, ~~and~~as ~~have~~of ~~limited~~July ~~capability~~1, 2014, to ~~transact~~collect ~~within~~50% of the ~~hour~~estimated ~~outside~~lost ~~their~~revenue ~~own~~that ~~borders.~~the InCompany ~~contrast,~~would ~~the~~otherwise ~~EIM~~be ~~will~~allowed ~~optimize~~to ~~and~~recover ~~automate~~for ~~five-minute~~the ~~dispatch~~2014 ofcalendar ~~generation~~year. toThe ~~serve~~EEIR ~~load~~was ~~across~~effective ~~the~~from ~~state~~July ~~and~~through ~~the~~December ~~California~~2014, ~~ISO~~set ~~footprint.~~on ~~The~~January ~~EIM~~1, is2015 ~~voluntary~~ and ~~available~~remains ~~to all balancing authorities~~ in ~~the~~effect ~~Western~~through ~~United~~September ~~States~~2015. ~~Benefits~~To tothe ~~customers~~extent ~~are~~the ~~expected~~Company's toearned ~~increase~~rate asof ~~more~~return ~~entities~~exceeds ~~join and~~ the ~~footprint~~rate ~~grows~~of ~~bringing~~return ~~incremental~~used ~~generation~~to ~~and~~set ~~load~~base ~~diversity.~~general ~~In April 2014~~rates, the Company ~~filed~~is anrequired ~~application~~ to ~~amend~~refund ~~its~~to ~~portfolio~~customers ~~optimization~~EEIR ~~procedures~~revenue ~~contained~~collected. inAs ~~the~~a ~~PUCN-approved~~result, ~~energy supply plan for~~ the ~~remaining~~Company ~~action~~has ~~period~~deferred recognition of ~~2016.~~EEIR ~~The~~revenue ~~PUCN's~~collected ~~final order approving the merger between BHE~~ and NVhas ~~Energy~~recorded ~~stipulated~~a ~~that~~liability ~~the~~of ~~Company~~$2 ~~would~~million, ~~obtain~~which ~~PUCN~~is ~~authorization~~included ~~prior to participating~~ in ancurrent ~~EIM.~~regulatory ~~The~~liabilities ~~amendment~~on ~~reflects~~ the ~~Company's~~Consolidated ~~participation~~Balance inSheets ~~the~~as ~~EIM~~of ~~that~~March is31, ~~being established by the California ISO~~2015.

17Joint Dispatch Agreement Application

~~The~~In ~~filing~~May ~~requested~~2013, ~~the~~in ~~PUCN~~anticipation toof ~~determine~~ON ~~that~~Line's completion, the ~~amended~~Company ~~energy~~and ~~supply~~Nevada ~~plan~~Power ~~balances~~filed with the ~~objectives~~PUCN ofto ~~minimizing~~combine ~~the~~their ~~cost~~power of supply ~~and~~resources ~~retail~~for ~~price~~joint ~~volatility,~~dispatch ~~maximizes~~purposes ~~the~~and ~~reliability~~merge ofthe ~~supply~~two ~~over~~utilities ~~the~~into ~~remaining~~a ~~term~~single oflegal ~~the~~and ~~plan,~~jurisdictional ~~optimizes~~entity. ~~the~~That ~~value~~filing ofwas ~~the~~withdrawn ~~overall~~in ~~supply~~favor ~~portfolio~~ of ~~the~~continued ~~Company~~operation ~~for~~of the ~~benefit~~utilities ofas ~~bundled~~separate ~~retail~~legal ~~customers~~entities, ~~and~~who ~~does~~would ~~not~~conduct ~~contain~~joint ~~any~~dispatch ~~features~~of ortheir ~~mechanisms~~combined ~~that~~power ~~the~~supply ~~PUCN~~resources ~~finds~~utilizing ~~would~~ON ~~impair~~Line, ~~the~~governed ~~restoration~~by or the ~~creditworthiness~~terms of ~~the Company. The PUCN issued~~ an ~~order~~Interim inJoint ~~August~~Dispatch ~~2014~~Agreement ~~finding~~("Interim ~~that~~JDA"). itIn isseeking in the ~~public~~PUCN's ~~interest~~permission to ~~grant~~withdraw the ~~application~~May ~~and~~2013 ~~that~~filing, NVthe ~~Energy~~Company ~~met~~and ~~the~~Nevada ~~merger~~Power ~~stipulation~~committed ~~requirement~~to return to ~~obtain~~the PUCN ~~approval~~with ~~prior~~a tonew ~~participating in an EIM~~application. In ~~April~~March ~~2014~~2015, the ~~California~~Company ~~ISO~~and Nevada Power filed an application with the ~~Implementation~~PUCN ~~Agreement~~seeking ~~entered~~approval ~~into~~of byan ~~the~~indefinite ~~Company~~Joint ~~and~~Dispatch ~~the~~Agreement ~~California~~("Indefinite ~~ISO~~JDA"). The ~~Implementation~~Indefinite ~~Agreement~~JDA ~~provides~~is ~~the~~intended ~~mechanism~~to byreplace ~~which~~ the ~~Company~~currently ~~will~~effective ~~compensate~~Interim ~~the~~JDA, ~~California~~which ~~ISO~~terminates ~~for~~on ~~its~~December 31, 2015. ~~share~~Joint ofdispatch transactions addressed by the ~~costs~~proposed toIndefinite ~~upgrade~~JDA ~~systems~~include real-time, ~~software~~hourly ~~licenses~~ and ~~other~~daily ~~configuration activities~~transactions. The ~~Implementation~~Indefinite ~~Agreement~~JDA ~~was~~also ~~approved~~explicitly bygoverns joint dispatch transactions between the ~~FERC~~Company inand ~~June~~Nevada ~~2014~~Power and the California ISO utilizing the California ISO's EIM.

InThe ~~October~~primary ~~2014,~~differences between the ~~PUCN~~Interim ~~issued~~JDA anand ~~order~~the ~~directing~~Indefinite ~~the~~JDA ~~Company~~relate to ~~provide~~EIM ~~information~~transactions ~~relating~~with tothe ~~failures~~California inISO. ~~certain~~The ~~remote~~Indefinite ~~disconnect/reconnect~~JDA ~~electric~~establishes ~~meters~~Nevada Power as the ~~Company~~EIM ~~has~~scheduling ~~installed~~coordinator ~~after~~for ~~media~~both ~~reports~~the ~~were~~Company ~~published~~and ~~that~~Nevada ~~electric~~Power ~~meter~~and ~~failures~~recognizes ~~may~~that ~~have~~the ~~resulted~~joint indispatch ~~fire~~costs ~~events.~~and ~~The~~benefits ~~Company~~associated iswith ~~investigating~~EIM ~~and~~transactions ~~responding~~will tobe ~~this~~governed ~~and~~by ~~other~~the ~~federal,~~accounting ~~state~~protocols and ~~local~~allocations ~~inquiries relating~~set toforth ~~these~~in ~~events.~~the ~~Additionally~~Indefinite JDA, which are unchanged from those currently in ~~October~~effect ~~2014,~~under the ~~Nevada~~Interim ~~State~~JDA. ~~Fire~~The ~~Marshal~~Company ~~issued~~and aNevada ~~report~~Power ~~concluding~~requested ~~that~~ the ~~incidents~~PUCN ofto ~~electric~~act ~~arching~~on ~~fires~~this ~~continue~~application toby ~~decrease~~July 2015, in ~~Nevada~~time ~~and~~to atfile ~~this~~the ~~time~~Indefinite ~~there~~JDA iswith nothe ~~statewide~~FERC ~~fire~~and ~~problem~~obtain ~~related~~FERC approval prior to the ~~replacement~~"go oflive" ~~electric~~date ~~meters~~for EIM transactions, which is October 1, 2015. ~~Management~~The ~~cannot~~Indefinite ~~assess~~JDA orwill ~~predict~~continue ~~the~~in ~~outcome~~effect ofuntil ~~these~~terminated ~~inquires~~by atmutual ~~this~~consent ~~time~~of the parties.

Advanced Metering Infrastructure

In October 2014, the PUCN issued an order directing the Company to provide information relating to failures in certain remote disconnect/reconnect electric meters the Company has installed after media reports were published that electric meter failures may have resulted in fire events. The Company completed an internal review in response to this and other federal, state and local inquiries relating to these events. The information compiled and submitted indicates that no fire has resulted from the remote disconnect/reconnect electric meters. Additionally, in October 2014, the Nevada State Fire Marshal issued a report concluding that the incidents of electric arcing fires continue to decrease in Nevada and at this time there is no statewide fire problem related to the replacement of electric meters. In December 2014, the Company filed the requested information with the PUCN. In March 2015, the PUCN staff made additional requests and in May 2015, the Company will provide the follow up items. Analysis and internal investigation is continuing, but the Company does not believe this will have a material adverse impact on the Consolidated Financial Statements.

Environmental Laws and Regulations

The Company is subject to federal, state and local laws and regulations regarding air and water quality, ~~renewable portfolio standards~~RPS, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company'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 agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Refer to "Liquidity and Capital Resources" for discussion of the Company's ~~forecasted~~forecast environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2013~~ 2014.

Clean Air Act Regulations

~~The~~National ~~Clean~~Ambient Air ~~Act~~Quality is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in State Implementation Plans ("SIPs"), which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA.Standards

The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour sulfur dioxide standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2020 sulfur dioxide standard, and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of sulfur dioxide in 2012 or emitted more than 2,600 tons of sulfur dioxide and had an emission rate of at least 0.45 lbs/sulfur dioxide per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its' determinations and supporting information by the specified deadline of September 18, 2015. The EPA intends to promulgate final sulfur dioxide area designations no later than July 2, 2016.

Mercury and Air Toxics Standards

~~The~~Numerous ~~Clean~~lawsuits ~~Air~~have ~~Mercury~~been ~~Rule~~filed ~~("CAMR"), issued by the EPA~~ in ~~March 2005, was~~ the United States' first attempt to regulate mercury emissions from coal-fueled generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") inchallenging ~~February 2008~~the MATS. In ~~March 2011~~April 2014, the ~~EPA~~D.C. ~~proposed~~Circuit aupheld ~~new rule that would require coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through~~ the ~~establishment~~MATS ~~of "Maximum Achievable Control Technology" standards rather than a cap-and-trade system~~requirements. ~~The~~In ~~final~~November ~~rule~~2014, ~~Mercury~~the ~~and~~United ~~Air~~States ~~Toxics~~Supreme ~~Standards~~Court ~~("MATS"),~~agreed ~~was~~to ~~published~~hear in the ~~Federal~~MATS ~~Register~~appeal inon ~~February 2012,~~the ~~with~~limited anissue ~~effective date~~ of ~~April 16,~~whether ~~2012,~~the ~~and~~EPA ~~requires~~unreasonably ~~that~~refused ~~new~~to ~~and~~consider ~~existing~~costs ~~coal-fueled~~in ~~generating~~determining ~~facilities~~whether ~~achieve~~it ~~emission~~is ~~standards~~appropriate ~~for~~to ~~mercury,~~regulate ~~acid gases and other non-mercury~~ hazardous air pollutants. ~~Existing~~emitted ~~sources are required to comply with the new standards~~ by ~~April 16,~~electric ~~2015~~utilities. ~~Individual~~Oral ~~sources~~argument ~~may~~in bethe ~~granted~~case upwas toheld ~~one~~before ~~additional year, at~~ the ~~discretion~~United ofStates ~~the~~Supreme ~~Title~~Court Vin ~~permitting~~March ~~authority~~2015, toand ~~complete~~a ~~installation~~decision ofis ~~controls~~expected orby ~~for~~the ~~transmission~~end ~~system~~of ~~reliability~~June ~~reasons~~2015. The ~~Company~~outcome ~~believes~~of ~~that~~the ~~its~~United ~~emissions~~States ~~reduction~~Supreme ~~projects~~Court's ~~completed~~decision tois ~~date~~uncertain orand ~~currently~~until ~~permitted~~the orcourt ~~planned~~renders ~~for~~its ~~installation,~~decision ~~including~~or ~~scrubbers,~~otherwise ~~baghouses~~implements ~~and~~a ~~electrostatic~~stay ~~precipitators,~~of ~~are consistent with~~ the ~~EPA's~~ MATS ~~and~~requirements, ~~will support~~ the Company's ~~ability~~is toproceeding ~~comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. The Company will be required~~ to ~~take~~fulfill ~~additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of~~ its ~~coal-fueled~~legal ~~generating~~obligations ~~facilities~~to ~~and otherwise~~ comply with the ~~final rule's standards, which may include retiring certain units~~MATS.

18Coal Combustion Byproduct Disposal

~~Incremental~~In ~~costs~~May 2010, tothe ~~install~~EPA ~~and~~released ~~maintain~~a ~~emissions~~proposed ~~control~~rule ~~equipment~~to atregulate the ~~Company's~~management and disposal of coal~~-fueled~~ ~~generating~~combustion ~~facilities~~byproducts, ~~and~~presenting ~~any~~two ~~requirement~~alternatives to ~~shut~~regulation ~~down~~under ~~what~~the ~~have~~Resource ~~traditionally~~Conservation ~~been~~and ~~low~~Recovery ~~cost~~Act ~~coal-fueled~~("RCRA"). ~~generating~~The ~~facilities~~public ~~will~~comment ~~likely~~period ~~increase~~closed ~~the~~in ~~cost~~November 2010. ofThe ~~providing~~final ~~service~~rule towas ~~customers.~~released Inby ~~addition,~~the ~~numerous~~EPA ~~lawsuits~~on ~~were~~December 19, ~~filed~~2014, ~~against~~was ~~the~~published ~~MATS~~ in the ~~D.C.~~Federal ~~Circuit.~~Register Inon April ~~2014~~17, 2015 ~~the~~and will be effective on October 14, 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.C. ~~Circuit~~Under ~~upheld~~the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the ~~MATS~~more stringent regulatory requirements.

~~Regional~~As ~~Haze~~defined by the final rule, the Company does not operate evaporative surface impoundments that are likely to fall within the definition of the final rule and operates one landfill that contains coal combustion byproducts. The Company is assessing the requirements of the final rule to determine required compliance activities and the associated costs.

The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas"). Some of the Company's and Nevada Power'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.

Environmental groups have challenged both of the EPA's final determinations with respect to Nevada's regional haze SIP. In May 2012, WildEarth Guardians petitioned the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") to review the EPA's March 2012 approval of Nevada's SIP for all affected units and emissions except nitrogen oxides controls at the Reid Gardner Generating Station. Both the Company and Nevada Power intervened in the lawsuit and briefing was completed in February 2013. The matter was heard before the Ninth Circuit in May 2014. On July 17, 2014, the Ninth Circuit issued its decision, dismissing the petition in part because WildEarth Guardians did not have standing to challenge a portion of the SIP, and denying the petition in part based on its conclusion that the EPA's approval of the Nevada SIP was appropriate.

Climate Change

In June 2014, the EPA released proposed regulations to address greenhouse gas emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on four building blocks that it determined were the "Best System of Emission Reduction." The four building blocks include: (a) a 6% heat rate improvement from coal-fueled generating facilities; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities to 70%; (c) increased deployment of renewable and non-carbon generating resources; and (d) increased energy efficiency. Under the EPA's proposal, Nevada may utilize any measure to achieve the specified emission reduction goals, with an initial implementation period of 2020-2029 and the final goal to be achieved by 2030. When fully implemented, the proposal is expected to reduce carbon dioxide emissions in the power sector to 30% below 2005 levels by 2030. The EPA is taking comment on its proposal until December 1, 2014 and is scheduled to issue final rules in June 2015. States are required to submit implementation plans by June 2016, but they may request an extension to June 2017, or June 2018 if they plan to participate in a regional compliance program. The impacts of the proposal on the Company cannot be determined until the EPA finalizes the proposal and Nevada develops its implementation plan. The Company has historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of its generating fleet to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.

Water Quality Standards

The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. In July 2004, the EPA established significant new technology-based performance standards for existing electricity generating facilities that take in more than 50 million gallons of water per day. These rules were aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the United States Court of Appeals for the Second Circuit ("Second Circuit") remanded almost all aspects of the rule to the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to conduct further proceedings consistent with its opinion.

In June 2013, the EPA published proposed effluent limitation guidelines and standards for the steam electric power generating sector. 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 have changed the effluent discharged from coal- and natural gas-fueled generating facilities. While the EPA expected the final rule to be published in May 2014, the final rule is now scheduled for release by September 30, 2015. It is likely that the new guidelines will impose more stringent limits on wastewater discharges from coal-fueled generating facilities and ash and scrubber ponds. However, until the revised guidelines are finalized, the Company cannot predict the impact on its generating facilities.

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. As currently proposed, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits will be required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. The public comment period has been extended on the proposal to November 14, 2014. Until the rule is finalized, the Company cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs, or increased requirements for compensatory mitigation.

Collateral and Contingent Features

Debt of the Company is rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of the Company's ability to, in general, meet the obligations of its issued debt. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.

The Company has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide rights to demand cash or other security in the event of a credit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2014, credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of September 30, 2014, the Company would have been required to post $16 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.18

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2015, the applicable credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of March 31, 2015, the Company would have been required to post $13 million of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.

New Accounting Pronouncements

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

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of 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, ~~2013~~ 2014. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, ~~2013~~ 2014.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2013~~ 2014. The Company's exposure to market risk and its management of such risk has not changed materially since December 31, ~~2013~~ 2014.

Item 4. Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon that evaluation, the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that the Company's disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act 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 management, including the Company's President (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company's internal control over financial reporting during the quarter ended ~~September~~March 3031, ~~2014~~2015 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

2119

PART II

Item 1. Legal Proceedings

None.

Item 1A. Risk Factors

There has been no material change to the Company's risk factors from those disclosed in Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2013~~ 2014.


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

None.


Item 5.	Other Information

Not applicable.


Item 6.	Exhibits

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

2220

SIGNATURES

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

		SIERRA PACIFIC POWER COMPANY
		(Registrant)
Dated:	November 7, 2014	/s/ E. Kevin Bethel
Date:	May 1, 2015	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Senior Vice President and Chief Financial Officer
		Senior Vice President, Chief Financial Officer and Director
		(principal financial and accounting officer)

2321

EXHIBIT INDEX


Exhibit No.	Description

10.1 $250,000,000 Amended and Restated Credit Agreement, dated as of June 27, 2014, among Sierra Pacific Power Company, as borrower, the Initial Lenders, Wells Fargo Bank, National Association, as administrative agent and swingline lender and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Sierra Pacific Power Company Current Report on Form 8-K dated June 27, 2014).


15	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.

101 The following financial information from Sierra Pacific Power Company's Quarterly Report on Form 10-Q for the quarter ended ~~September~~March 3031, ~~2014~~2015, 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 Changes in Shareholder's Equity, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail.

2422

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