Sierra Pacific Power 10-Q 2013 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED   March 31, 2013

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM      TO  

	Registrant, Address of	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	Number	Incorporation
1-08788	NV ENERGY, INC.	88-0198358	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada  89146
	(702) 402-5000
2-28348	NEVADA POWER COMPANY d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000
0-00508	SIERRA PACIFIC POWER COMPANY d/b/a	88-0044418	Nevada
	NV ENERGY
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

Indicate by check mark whether 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  þ          No  o   (Response applicable to all registrants)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).       Yes  þ          No  o     (Response applicable to all registrants)

Indicate by check mark whether any 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", "non-accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

NV Energy, Inc.:	Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company     o
Nevada Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company     o
Sierra Pacific Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	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 þ   (Response applicable to all registrants)

Indicate the number of shares outstanding of each of the issuer’s classes of Common Stock, as of the latest practicable date.

Class	Outstanding at May 7, 2013
Common Stock, $1.00 par value of NV Energy, Inc.	235,447,475 Shares

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company.

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 stated value, of Sierra Pacific Power Company.

This combined Quarterly Report on Form 10-Q is separately filed by NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company.  Information contained in this document relating to Nevada Power Company is filed by NV Energy, Inc. and separately by Nevada Power Company on its own behalf.  Nevada Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Nevada Power Company.  Information contained in this document relating to Sierra Pacific Power Company is filed by NV Energy, Inc. and separately by Sierra Pacific Power Company on its own behalf.  Sierra Pacific Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Sierra Pacific Power Company.

NV ENERGY, INC.

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

QUARTERLY REPORTS ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2013

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

Acronyms & Terms			3
ITEM 1.	Financial Statements
	NV Energy, Inc.
		Consolidated Statements of Comprehensive Income  – Three Months Ended March 31, 2013 and 2012	5
		Consolidated Balance Sheets – March 31, 2013 and December 31, 2012	6
		Consolidated Statements of Cash Flows -  Three Months Ended March 31, 2013 and 2012	8
		Consolidated Statements of Shareholders’ Equity - Three Months Ended March 31, 2013 and 2012	9
	Nevada Power Company
		Consolidated Statements of Comprehensive Income (Loss) – Three  Months Ended March 31, 2013 and 2012	10
		Consolidated Balance Sheets – March 31, 2013 and December 31, 2012	11
		Consolidated Statements of Cash Flows -  Three Months Ended March 31, 2013  and 2012	13
		Consolidated Statements of Shareholder’s Equity - Three Months Ended March 31, 2013 and 2012	14
	Sierra Pacific Power Company
		Consolidated Statements of Comprehensive Income   – Three Months Ended March 31, 2013 and 2012	15
		Consolidated Balance Sheets – March 31, 2013 and December 31, 2012	16
		Consolidated Statements of Cash Flows - Three Months Ended March 31, 2013 and 2012	18
		Consolidated Statements of Shareholder’s Equity - Three Months Ended March 31, 2013 and 2012	19
	Condensed Notes to Financial Statements
		Note 1.     Summary of Significant Accounting Policies	20
		Note 2.     Segment Information	21
		Note 3.     Regulatory Actions	22
		Note 4.     Long-Term Debt	24
		Note 5.     Fair Value of Financial Instruments	24
		Note 6.     Retirement Plan and Post-Retirement Benefits	25
		Note 7.     Commitments and Contingencies	26
		Note 8.     Earnings per Share (NVE)	29
		Note 9. Common Stock and Other Paid-In Capital	29
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
	NV Energy, Inc.		35
	Nevada Power Company		39
	Sierra Pacific Power Company		46
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		53
ITEM 4.	Controls and Procedures		54
PART II – OTHER INFORMATION
ITEM 1.	Legal Proceedings		55
ITEM 1A.	Risk Factors		55
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		55
ITEM 3.	Defaults Upon Senior Securities		55
ITEM 4.	Mine Safety Disclosures		55
ITEM 5.	Other Information		55
ITEM 6.	Exhibits		56
Signature Page and Certifications			57

2

ACRONYMS AND TERMS

(The following common acronyms and terms are found in multiple locations within the document)

Acronym/Term	Meaning
2012 Form 10-K	NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2012
AFUDC-debt	Allowance for Borrowed Funds Used During Construction
AFUDC-equity	Allowance for Equity Funds Used During Construction
ARO	Asset Retirement Obligation
BOD	Board of Directors
BTER	Base Tariff Energy Rate
BTGR	Base Tariff General Rate
CA ISO	California Independent System Operator Corporation
California Assets	SPPC's California electric distribution and generation assets
CalPeco	California Pacific Electric Company
CDD	Cooling degree days
CDWR	California Department of Water Resources
CIAC	Contributions in Aid of Construction
CWIP	Construction Work-in-Progress
dba	Doing business as
DEAA	Deferred Energy Accounting Adjustment
Dth	Decatherm
EEIR	Energy Efficiency Implementation Rate
EEPR	Energy Efficiency Program Rate
EPA	Environmental Protection Agency
EPS	Earnings per Share
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Ltd.
Ft. Churchill Generating Station	226 megawatt nominally rated Fort Churchill Generating Station
GAAP	Generally Accepted Accounting Principles in the United States
GBT	Great Basin Transmission, LLC, a wholly owned subsidiary of Texas Nevada Transmission, LLC
GBT-South	Great Basin Transmission South, LLC, a wholly owned subsidiary of GBT
GRC	General Rate Case
Harry Allen Generating Station	642 megawatt nominally rated Harry Allen Generating Station
HDD	Heating degree days
Higgins Generating Station	598 megawatt nominally rated Walter M. Higgins, III Generating Station
kV	Kilovolt
Lenzie Generating Station	1,102 megawatt nominally rated Chuck Lenzie Generating Station
Mohave Generating Station	1,580 megawatt nominally rated Mohave Generating Station
Moody’s	Moody’s Investors Services, Inc.
MW	Megawatt
MWh	Megawatt hour
Navajo Generating Station	255 megawatt nominally rated Navajo Generating Station
NEICO	Nevada Electric Investment Company
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NOL	Net Operating Loss
NPC	Nevada Power Company d/b/a NV Energy
NPC Credit Agreement	$500 million Revolving Credit Facility entered into in March 2012 between NPC and Wells Fargo Bank,
	N.A., as administrative agent for the lenders a party thereto
NPC Indenture	NPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and the Bank
	of New York Mellon Trust Company, N.A., as Trustee
NRSRO	Nationally Recognized Statistical Rating Organization
NVE	NV Energy, Inc.
NV Energize	A smart grid infrastructure that is expected to enable the widespread use of Smart Meters that will provide
	customers the ability to more directly manage their energy usage
ON Line	250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
Portfolio Standard	Nevada Renewable Energy Portfolio Standard
PUCN	Public Utilities Commission of Nevada
Reid Gardner Generating Station	325 megawatt nominally rated Reid Gardner Generating Station
REPR	Renewable Energy Program Rate
ROR	Rate of Return
S&P	Standard & Poor’s

3

Salt River	Salt River Project
SEC	United States Securities and Exchange Commission
Silverhawk Generating Station	395 megawatt nominally rated Silverhawk Generating Station
Smart Meters	Advanced service delivery meters installed as part of the NV Energize project
SNWA	Southern Nevada Water Authority
SPPC	Sierra Pacific Power Company d/b/a NV Energy
SPPC Credit Agreement	$250 million Revolving Credit Facility entered into in March 2012 between SPPC and Wells Fargo
	Bank, N.A., as administrative agent for the lenders a party thereto
SPPC Indenture	SPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and
	the Bank of New York Mellon Trust Company, N.A., as Trustee
STPR	Solar Thermal Program Rate
Term Loan	$195 million loan agreement entered into on October 7, 2011 between NVE and JPMorgan Chase Bank,
	N.A., as administrative agent for the lenders a party thereto
TMWA	Truckee Meadows Water Authority
Tracy Generating Station	541 megawatt nominally rated Frank A. Tracy Generating Station
TRED	Temporary Renewable Energy Development
TUA	Transmission Use and Capacity Exchange Agreement with GBT-South
U.S.	United States of America
Utilities	Nevada Power Company and Sierra Pacific Power Company
Valmy Generating Station	261 megawatt nominally rated Valmy Generating Station
VIE	Variable Interest Entity
WSPP	Western Systems Power Pool

4

ITEM 1.                FINANCIAL STATEMENTS

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

		Three Months Ended
		March 31,
		2013		2012
OPERATING REVENUES		$	584,222	$	611,420
OPERATING EXPENSES:
	Fuel for power generation		147,248		117,035
	Purchased power		121,310		117,116
	Gas purchased for resale		37,620		31,617
	Deferred energy		(79,065)		(11,739)
	Energy efficiency program costs		9,845		19,425
	Other operating expenses		104,672		103,601
	Maintenance		24,906		32,526
	Depreciation and amortization		96,002		90,862
	Taxes other than income		16,476		14,509
Total Operating Expenses			479,014		514,952
OPERATING INCOME			105,208		96,468
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $2,131 and $1,595)		(73,337)		(77,931)
	Interest expense on regulatory items		(827)		(2,202)
	AFUDC-equity		2,889		1,932
	Other income		3,820		4,194
	Other expense		(4,251)		(3,060)
Total Other Income (Expense)			(71,706)		(77,067)
Income Before Income Tax Expense			33,502		19,401
Income tax expense			12,027		7,228
NET INCOME			21,475		12,173
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization
(Net of taxes $(136) and $(89) in 2013 and 2012, respectively)			246		155
Change in market value of risk management assets and liabilities
(Net of taxes $(110) and $141 in 2013 and 2012, respectively)			199		(246)
OTHER COMPREHENSIVE INCOME (LOSS)			445		(91)
COMPREHENSIVE INCOME		$	21,920	$	12,082
Amount per share basic and diluted (Note 8)
	Net income per share - basic and diluted	$	0.09	$	0.05
Weighted Average Shares of Common Stock Outstanding - basic		235,193,702		235,999,750
Weighted Average Shares of Common Stock Outstanding - diluted		237,005,888		237,526,863
Dividends Declared Per Share of Common Stock		$	0.19	$	0.13
The accompanying notes are an integral part of the financial statements.

5

NV ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			March 31,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	250,953	$	298,271
	Accounts receivable less allowance for uncollectible accounts:
		2013 - $6,533; 2012 - $8,748		317,191		373,099
	Materials, supplies and fuel, at average cost			133,613		138,337
	Deferred income taxes			88,648		60,592
	Other current assets			54,397		40,750
Total Current Assets				844,802		911,049
Utility Property:
	Plant in service			12,077,001		12,031,053
	Construction work-in-progress			730,262		708,109
	Total			12,807,263		12,739,162
Less accumulated provision for depreciation				3,378,468		3,313,188
	Total Utility Property, Net			9,428,795		9,425,974
Investments and other property, net				58,389		56,660
Deferred Charges and Other Assets:
	Deferred energy (Note 3)			84,120		87,072
	Regulatory assets			1,102,348		1,132,768
	Regulatory asset for pension plans			277,836		281,195
	Other deferred charges and assets			82,343		89,418
Total Deferred Charges and Other Assets				1,546,647		1,590,453
TOTAL ASSETS			$	11,878,633	$	11,984,136
		(Continued)

6

		NV ENERGY, INC.
		CONSOLIDATED BALANCE SHEETS
		(Dollars in Thousands, Except Share Amounts)
		(Unaudited)
			March 31,		December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY			2013		2012
Current Liabilities:
	Current maturities of long-term debt (Note 4)		$	481,342	$	356,283
	Accounts payable			280,206		332,245
	Accrued expenses			95,080		127,693
	Deferred energy (Note 3)			56,336		136,865
	Other current liabilities			69,306		66,221
Total Current Liabilities				982,270		1,019,307
Long-term debt (Note 4)				4,541,241		4,669,798
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
	Deferred income taxes			1,510,369		1,470,973
	Deferred investment tax credit			12,984		13,538
	Accrued retirement benefits			164,315		162,260
	Regulatory liabilities			558,692		550,687
	Other deferred credits and liabilities			564,911		540,202
Total Deferred Credits and Other Liabilities				2,811,271		2,737,660
Shareholders' Equity:
	Common stock, $1.00 par value; 350 million shares authorized; 235,999,750 issued
		for 2013 and 2012; 235,526,514 and 235,079,156 outstanding for 2013 and 2012, respectively		236,000		236,000
	Treasury stock at cost, 473,236 shares and 920,594 shares for 2013 and 2012, respectively			(8,660)		(16,804)
	Other paid-in capital			2,714,107		2,712,943
	Retained earnings			612,030		635,303
	Accumulated other comprehensive loss			(9,626)		(10,071)
Total Shareholders' Equity				3,543,851		3,557,371
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$	11,878,633	$	11,984,136
The accompanying notes are an integral part of the financial statements.
(Concluded)

7

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Three Months Ended,
			March 31,
			2013		2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	21,475	$	12,173
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		96,002		90,862
		Deferred taxes and deferred investment tax credit		11,956		(5,183)
		AFUDC-equity		(2,889)		(1,932)
		Deferred energy		(77,578)		(9,134)
		Amortization of other regulatory assets		41,621		39,028
		Deferred rate increase		2,103		2,691
		Other, net		(897)		1,575
	Changes in certain assets and liabilities:
		Accounts receivable		68,131		31,208
		Materials, supplies and fuel		4,815		(874)
		Other current assets		(13,648)		(13,021)
		Accounts payable		(29,795)		(37,825)
		Accrued retirement benefits		2,055		2,221
		Other current liabilities		(29,335)		(29,348)
		Other deferred assets		(1,263)		(1,602)
		Other regulatory assets		(2,379)		4,164
		Other deferred liabilities		(1,480)		(17,687)
Net Cash from Operating Activities				88,894		67,316
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(97,948)		(115,817)
		Customer advances for construction		(629)		(184)
		Contributions in aid of construction		13,570		26,052
		Investments and other property - net		111		48
Net Cash used by Investing Activities				(84,896)		(89,901)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		-		10,951
		Retirement of long-term debt		(3,671)		(3,295)
		Sale of common stock		754		-
		Common stock repurchased		(3,651)		-
		Dividends paid		(44,748)		(30,680)
Net Cash used by Financing Activities				(51,316)		(23,024)
Net Decrease in Cash and Cash Equivalents				(47,318)		(45,609)
Beginning Balance in Cash and Cash Equivalents				298,271		145,944
Ending Balance in Cash and Cash Equivalents			$	250,953	$	100,335
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	88,337	$	88,606
		Income taxes	$	2	$	-
	Significant non-cash transactions:
		Accrued construction expenses as of March 31,	$	61,262	$	85,850
		Issuance of treasury stock	$	11,041	$	-
The accompanying notes are an integral part of the financial statements.

8

NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

													Accumulated
		Common	Common		Treasury		Treasury	Other					Other		Total
		Stock	Stock		Stock		Stock	Paid-in		Retained			Comprehensive		Shareholders'
		Shares	Amount		Shares		Amount	Capital		Earnings			Income (Loss)		Equity
December 31, 2011		235,999,750	$	236,000	-	$	-	$	2,713,736	$	464,277		$	(7,934)	$	3,406,079
	Net Income	-		-	-		-		-		12,173			-		12,173
	Change in compensation retirement benefits
	liability and amortization (net of taxes $(89))	-		-	-		-		-		-			155		155
	Change in market value of risk management
	assets and liabilities (net of taxes $ 141)	-		-	-		-		-		-			(246)		(246)
	Dividends Declared	-		-	-		-		-		(30,680)			-		(30,680)
March 31, 2012		235,999,750	$	236,000	-	$	-	$	2,713,736	$	445,770		$	(8,025)	$	3,387,481
December 31, 2012		235,999,750	$	236,000	(920,594)	$	(16,804)	$	2,712,943	$	635,303	��	$	(10,071)	$	3,557,371
	Net Income	-		-	-		-		-		21,475			-		21,475
	Employee Benefits	-		-	644,536		11,795		1,164		-			-		12,959
	Change in compensation retirement benefits
	liability and amortization (net of taxes $(136))	-		-	-		-		-		-			246		246
	Change in market value of risk management
	assets and liabilities (net of taxes $(110))	-		-	-		-		-		-			199		199
	Common stock repurchased	-		-	(197,178)		(3,651)		-		-			-		(3,651)
	Dividends Declared	-		-	-		-		-		(44,748)			-		(44,748)
March 31, 2013		235,999,750	$	236,000	(473,236)	$	(8,660)	$	2,714,107	$	612,030		$	(9,626)	$	3,543,851
The accompanying notes are an integral part of the financial statements.

9

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)

		Three Months Ended
		March 31,
		2013		2012
OPERATING REVENUES		$	371,863	$	395,688
OPERATING EXPENSES:
	Fuel for power generation		105,531		80,549
	Purchased power		81,408		81,531
	Deferred energy		(45,355)		2,171
	Energy efficiency program costs		7,967		15,774
	Other operating expenses		67,392		66,462
	Maintenance		18,075		23,073
	Depreciation and amortization		68,661		64,990
	Taxes other than income		9,959		8,454
Total Operating Expenses			313,638		343,004
OPERATING INCOME			58,225		52,684
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $1,837 and $1,179)		(51,259)		(54,405)
	Interest income (expense) on regulatory items		(802)		(2,016)
	AFUDC-equity		2,366		1,413
	Other income		2,404		1,709
	Other expense		(2,401)		(1,346)
Total Other Income (Expense)			(49,692)		(54,645)
Income (Loss) Before Income Tax Expense			8,533		(1,961)
Income tax expense			3,088		(645)
NET INCOME (LOSS)			5,445		(1,316)
Other comprehensive income:
Change in compensation retirement benefits liability and amortization
(Net of taxes $(54) and $(32) in 2013 and 2012, respectively)			97		63
COMPREHENSIVE INCOME (LOSS)		$	5,542	$	(1,253)
The accompanying notes are an integral part of the financial statements.

10

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			March 31,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	132,216	$	201,202
	Accounts receivable less allowance for uncollectible accounts:
		2013 - $5,580; 2012 - $7,622		198,740		248,501
	Materials, supplies and fuel, at average cost			80,998		77,675
	Deferred income taxes			80,265		48,590
	Other current assets			38,008		28,763
Total Current Assets				530,227		604,731
Utility Property:
	Plant in service			8,399,239		8,363,566
	Construction work-in-progress			603,495		567,941
		Total		9,002,734		8,931,507
	Less accumulated provision for depreciation			2,091,598		2,035,322
		Total Utility Property, Net		6,911,136		6,896,185
Investments and other property, net				51,201		49,808
Deferred Charges and Other Assets:
	Deferred energy (Note 3)			84,120		87,072
	Regulatory assets			781,916		804,013
	Regulatory asset for pension plans			135,191		136,682
	Other deferred charges and assets			64,924		62,654
Total Deferred Charges and Other Assets				1,066,151		1,090,421
TOTAL ASSETS			$	8,558,715	$	8,641,145
(Continued)

11

		NEVADA POWER COMPANY
		CONSOLIDATED BALANCE SHEETS
		(Dollars in Thousands, Except Share Amounts)
		(Unaudited)
			March 31,		December 31,
			2013		2012
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 4)		$	231,075	$	106,048
	Accounts payable			168,582		201,193
	Accounts payable, affiliated companies			39,650		42,036
	Accrued expenses			58,774		86,433
	Deferred energy (Note 3)			38,915		86,102
	Other current liabilities			54,935		52,567
Total Current Liabilities				591,931		574,379
Long-term debt (Note 4)				3,102,390		3,230,808
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
	Deferred income taxes			1,136,115		1,101,804
	Deferred investment tax credit			4,407		4,688
	Accrued retirement benefits			50,328		49,381
	Regulatory liabilities			329,806		323,400
	Other deferred credits and liabilities			465,878		434,367
Total Deferred Credits and Other Liabilities				1,986,534		1,913,640
Shareholder's Equity:
	Common stock, $1.00 par value; 1,000 shares authorized
		issued and outstanding for 2013 and 2012		1		1
	Other paid-in capital			2,308,211		2,308,211
	Retained earnings			574,057		618,612
	Accumulated other comprehensive loss			(4,409)		(4,506)
Total Shareholder's Equity				2,877,860		2,922,318
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY			$	8,558,715	$	8,641,145
The accompanying notes are an integral part of the financial statements.
(Concluded)

12

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Three Months Ended,
			March 31,
			2013		2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income (Loss)		$	5,445	$	(1,316)
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		68,661		64,990
		Deferred taxes and deferred investment tax credit		2,949		(6,349)
		AFUDC-equity		(2,366)		(1,413)
		Deferred energy		(44,235)		4,050
		Amortization of other regulatory assets		22,119		18,301
		Deferred rate increase		2,103		2,691
		Other, net		(4,261)		(796)
	Changes in certain assets and liabilities:
		Accounts receivable		50,792		22,441
		Materials, supplies and fuel		(3,232)		(2,209)
		Other current assets		(9,246)		(8,674)
		Accounts payable		(24,421)		(14,248)
		Accrued retirement benefits		947		1,572
		Other current liabilities		(25,097)		(27,419)
		Other deferred assets		(491)		(1,288)
		Other regulatory assets		(801)		9,880
		Other deferred liabilities		(1,348)		(7,495)
Net Cash from Operating Activities				37,518		52,718
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(59,357)		(66,843)
		Customer advances for construction		(749)		654
		Contributions in aid of construction		6,890		15,951
		Investments and other property - net		103		40
Net Cash used by Investing Activities				(53,113)		(50,198)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		-		12,432
		Retirement of long-term debt		(3,391)		(3,129)
		Dividends paid		(50,000)		(39,000)
Net Cash used by Financing Activities				(53,391)		(29,697)
Net Decrease in Cash and Cash Equivalents				(68,986)		(27,177)
Beginning Balance in Cash and Cash Equivalents				201,202		65,887
Ending Balance in Cash and Cash Equivalents			$	132,216	$	38,710
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	71,187	$	71,276
		Income taxes	$	1	$	-
	Significant non-cash transactions:
		Accrued construction expenses as of March 31,	$	48,812	$	72,179
The accompanying notes are an integral part of the financial statements.

13

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

									Accumulated
		Common	Common		Other				Other		Total
		Stock	Stock		Paid-in		Retained		Comprehensive		Shareholder's
		Shares	Amount		Capital		Earnings		Income (Loss)		Equity
December 31, 2011		1,000	$	1	$	2,308,219	$	544,874	$	(4,117)	$	2,848,977
	Net Loss	-		-		-		(1,316)		-		(1,316)
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(32))	-		-		-		-		63		63
	Dividends Declared	-		-		-		(39,000)		-		(39,000)
March 31, 2012		1,000	$	1	$	2,308,219	$	504,558	$	(4,054)	$	2,808,724
December 31, 2012		1,000	$	1	$	2,308,211	$	618,612	$	(4,506)	$	2,922,318
	Net Income	-		-		-		5,445		-		5,445
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(54))	-		-		-		-		97		97
	Dividends Declared	-		-		-		(50,000)		-		(50,000)
March 31, 2013		1,000	$	1	$	2,308,211	$	574,057	$	(4,409)	$	2,877,860
The accompanying notes are an integral part of the financial statements.

14

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

		Three Months Ended
		March 31,
		2013		2012
OPERATING REVENUES:
	Electric	$	172,627	$	169,806
	Gas		39,729		45,922
Total Operating Revenues			212,356		215,728
OPERATING EXPENSES:
	Fuel for power generation		41,717		36,486
	Purchased power		39,902		35,585
	Gas purchased for resale		37,620		31,617
	Deferral of energy - electric - net		(19,335)		(12,670)
	Deferral of energy - gas - net		(14,375)		(1,240)
	Energy efficiency program costs		1,878		3,651
	Other operating expenses		35,805		36,432
	Maintenance		6,831		9,453
	Depreciation and amortization		27,341		25,872
	Taxes other than income		6,295		5,863
Total Operating Expenses			163,679		171,049
OPERATING INCOME			48,677		44,679
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $294 and $416)		(15,525)		(16,973)
	Interest expense on regulatory items		(25)		(186)
	AFUDC-equity		523		519
	Other income		1,140		2,183
	Other expense		(1,248)		(1,335)
Total Other Income (Expense)			(15,135)		(15,792)
Income Before Income Tax Expense			33,542		28,887
Income tax expense			11,638		10,243
NET INCOME			21,904		18,644
Other comprehensive income:
Change in compensation retirement benefits liability and amortization
(Net of taxes $(31) and $(23) in 2013 and 2012, respectively)			59		42
COMPREHENSIVE INCOME		$	21,963	$	18,686
The accompanying notes are an integral part of the financial statements.

15

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

			March 31,		December 31,
			2013		2012
ASSETS
Current Assets:
	Cash and cash equivalents		$	85,280	$	60,786
	Accounts receivable less allowance for uncollectible accounts:
	2013 - $953; 2012 - $1,126			118,326		124,464
	Materials, supplies and fuel, at average cost			52,615		60,662
	Intercompany income taxes receivable			10,351		10,351
	Deferred income taxes			18,770		21,589
	Other current assets			16,268		11,633
Total Current Assets				301,610		289,485
Utility Property:
	Plant in service			3,677,762		3,667,487
	Construction work-in-progress			126,767		140,168
		Total		3,804,529		3,807,655
	Less accumulated provision for depreciation			1,286,870		1,277,866
		Total Utility Property, Net		2,517,659		2,529,789
Investments and other property, net				6,836		6,499
Deferred Charges and Other Assets:
	Regulatory assets			320,432		328,755
	Regulatory asset for pension plans			138,843		140,268
	Other deferred charges and assets			11,811		21,477
Total Deferred Charges and Other Assets				471,086		490,500
TOTAL ASSETS			$	3,297,191	$	3,316,273
(Continued)

16

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
			March 31,		December 31,
			2013		2012
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 4)		$	250,267	$	250,235
	Accounts payable			90,697		106,415
	Accounts payable, affiliated companies			22,387		21,534
	Accrued expenses			26,464		32,936
	Deferred energy (Note 3)			17,421		50,763
	Other current liabilities			14,368		13,655
Total Current Liabilities				421,604		475,538
Long-term debt (Note 4)				928,851		928,990
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
	Deferred income taxes			473,937		465,508
	Deferred investment tax credit			8,577		8,850
	Accrued retirement benefits			98,956		98,676
	Regulatory liabilities			228,886		227,287
	Other deferred credits and liabilities			75,681		72,688
Total Deferred Credits and Other Liabilities				886,037		873,009
Shareholder's Equity:
	Common stock, $3.75 par value; 20,000,000 shares authorized
		1,000 shares issued and outstanding for 2013 and 2012		4		4
	Other paid-in capital			1,111,266		1,111,266
	Retained deficit			(49,082)		(70,986)
	Accumulated other comprehensive loss			(1,489)		(1,548)
Total Shareholder's Equity				1,060,699		1,038,736
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY			$	3,297,191	$	3,316,273
The accompanying notes are an integral part of the financial statements.
(Concluded)

17

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

			For the Three Months Ended,
			March 31,
			2013		2012
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	21,904	$	18,644
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		27,341		25,872
		Deferred taxes and deferred investment tax credit		11,707		3,537
		AFUDC-equity		(523)		(519)
		Deferred energy		(33,343)		(13,184)
		Amortization of other regulatory assets		19,441		20,668
		Other, net		2,099		2,249
	Changes in certain assets and liabilities:
		Accounts receivable		17,331		8,869
		Materials, supplies and fuel		8,047		1,335
		Other current assets		(4,635)		(4,564)
		Accounts payable		(3,198)		(17,675)
		Accrued retirement benefits		280		367
		Other current liabilities		(5,757)		(5,388)
		Other deferred assets		(772)		(314)
		Other regulatory assets		(1,578)		(5,716)
		Other deferred liabilities		(1,787)		(4,214)
Net Cash from Operating Activities				56,557		29,967
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(38,591)		(48,974)
		Customer advances for construction		120		(838)
		Contributions in aid of construction		6,680		10,101
		Investments and other property - net		8		8
Net Cash used by Investing Activities				(31,783)		(39,703)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		-		(1,441)
		Retirement of long-term debt		(280)		(166)
		Dividends paid		-		(20,000)
Net Cash used by Financing Activities				(280)		(21,607)
Net Increase (Decrease) in Cash and Cash Equivalents				24,494		(31,343)
Beginning Balance in Cash and Cash Equivalents				60,786		55,195
Ending Balance in Cash and Cash Equivalents			$	85,280	$	23,852
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	15,780	$	15,944
	Significant non-cash transactions:
		Accrued construction expenses as of March 31,	$	12,450	$	13,671
The accompanying notes are an integral part of the financial statements.

18

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Dollars in Thousands, Except Share Amounts)

(Unaudited)

									Accumulated
		Common	Common		Other				Other		Total
		Stock	Stock		Paid-In		Retained		Comprehensive		Shareholder's
		Shares	Amount		Capital		Deficit		Income (Loss)		Equity
December 31, 2011		1,000	$	4	$	1,111,262	$	(135,340)	$	(1,384)	$	974,542
	Net Income	-		-		-		18,644		-		18,644
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(23))	-		-		-		-		42		42
	Dividends Declared	-		-		-		(20,000)		-		(20,000)
March 31, 2012		1,000	$	4	$	1,111,262	$	(136,696)	$	(1,342)	$	973,228
December 31, 2012		1,000	$	4	$	1,111,266	$	(70,986)	$	(1,548)	$	1,038,736
	Net Income	-		-		-		21,904		-		21,904
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(31))	-		-		-		-		59		59
March 31, 2013		1,000	$	4	$	1,111,266	$	(49,082)	$	(1,489)	$	1,060,699
The accompanying notes are an integral part of the financial statements.

19

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both utility and non-utility operations are as follows:

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., NVE Insurance Company, Inc. and Sierra Gas Holding Company.  All intercompany balances and transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities.  These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period.  Actual results could differ from these estimates.

                In the opinion of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessary to present fairly the consolidated financial position, results of operations and cash flows for the periods shown.  These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statements included in the 2012 Form 10-K.

                The results of operations and cash flows of NVE, NPC and SPPC for the three months ended March 31, 2013, are not necessarily indicative of the results to be expected for the full year.

Accounting Policies

Consolidations of VIEs

To identify potential variable interests, management reviewed contracts under leases, long-term purchase power contracts, tolling contracts and jointly owned facilities.  The Utilities identified certain long-term purchase power contracts that could be defined as variable interests.  However, the Utilities are not the primary beneficiary as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.  The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers are unable to deliver power.  However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism.  As of March 31, 2013, the carrying amount of assets and liabilities in the Utilities’ balance sheets that relate to their involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.

Recent Accounting Standards Update

      Other Comprehensive Income (ASU 220)

In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income.  In February 2013, the FASB reinstated certain portions of the deferred amendment.  The reinstated amendment is applied prospectively and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance does not have a material impact on the presentation of the financial statements for NVE and the Utilities.

      Balance Sheet Offsetting Disclosures (ASU 210)

In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance current disclosures regarding offsetting (netting) of assets and liabilities on the face of the financial statements.  The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position.  The scope of this amendment includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements.  The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013.  The adoption of this guidance does not have a material impact on the disclosure requirements for NVE and the Utilities.

20

NOTE 2.SEGMENT INFORMATION

The Utilities operate three regulated business segments, NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC.  Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada by SPPC.  Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada.  Other information includes amounts below the quantitative thresholds for separate disclosure.

Operational information of the different business segments is set forth below based on the nature of products and services offered.  NVE evaluates performance based on several factors, of which the primary financial measure is business segment gross margin.  Gross margin, which the Utilities calculate as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of the Utilities.  See Note 1, Summary of Significant Accounting Policies, of the 2012 Form 10-K for further information regarding energy efficiency program costs.  

Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements (dollars in thousands). 

Three Months Ended
March 31, 2013			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	584,222	$	3	$	371,863	$	212,356	$	172,627	$	39,729
Energy Costs:
	Fuel for power generation		147,248		-		105,531		41,717		41,717		-
	Purchased power		121,310		-		81,408		39,902		39,902		-
	Gas purchased for resale		37,620		-		-		37,620		-		37,620
	Deferred energy		(79,065)		-		(45,355)		(33,710)		(19,335)		(14,375)
Energy efficiency program costs			9,845		-		7,967		1,878		1,878		-
Total Costs		$	236,958	$	-	$	149,551	$	87,407	$	64,162	$	23,245
Gross Margin		$	347,264	$	3	$	222,312	$	124,949	$	108,465	$	16,484
Other operating expenses			104,672		1,475		67,392		35,805
Maintenance			24,906		-		18,075		6,831
Depreciation and amortization			96,002		-		68,661		27,341
Taxes other than income			16,476		222		9,959		6,295
Operating Income (Loss)		$	105,208	$	(1,694)	$	58,225	$	48,677

Three Months Ended
March 31, 2012			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	611,420	$	4	$	395,688	$	215,728	$	169,806	$	45,922
Energy Costs:
	Fuel for power generation		117,035		-		80,549		36,486		36,486		-
	Purchased power		117,116		-		81,531		35,585		35,585		-
	Gas purchased for resale		31,617		-				31,617		-		31,617
	Deferred energy		(11,739)		-		2,171		(13,910)		(12,670)		(1,240)
Energy efficiency program costs			19,425		-		15,774		3,651		3,651		-
Total Costs		$	273,454	$	-	$	180,025	$	93,429	$	63,052	$	30,377
Gross Margin		$	337,966	$	4	$	215,663	$	122,299	$	106,754	$	15,545
Other operating expenses			103,601		707		66,462		36,432
Maintenance			32,526		-		23,073		9,453
Depreciation and amortization			90,862		-		64,990		25,872
Taxes other than income			14,509		192		8,454		5,863
Operating Income (Loss)		$	96,468	$	(895)	$	52,684	$	44,679

21

NOTE 3.REGULATORY ACTIONS

NPC and SPPC follow deferred energy accounting.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding deferred energy accounting by the Utilities.

The following deferred energy amounts were included in the consolidated balance sheets as of March 31, 2013 (dollars in thousands):

		March 31, 2013
		NVE Total		NPC Electric		SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance as of December 31, 2012	$	(151,880)	$	(101,117)	$	(32,693)	$	(18,070)
	2013 Amortization		55,053		30,313		11,296		13,444
	2013 Deferred Energy Under Collections  (1)		25,498		16,896		7,795		807
Deferred Energy Balance at March 31, 2013 - Subtotal		$	(71,329)	$	(53,908)	$	(13,602)	$	(3,819)
Reinstatement of deferred energy (effective 6/07, 10 years)			99,113		99,113		-		-
	Total Deferred Energy	$	27,784	$	45,205	$	(13,602)	$	(3,819)
Deferred Assets
	Deferred energy	$	84,120	$	84,120	$	-	$	-
Current Liabilities
	Deferred energy		(56,336)		(38,915)		(13,602)		(3,819)
	Total Net Deferred Energy	$	27,784	$	45,205	$	(13,602)	$	(3,819)
(1)	These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting
	Policies, Deferred Energy Accounting, of the Notes to Financial Statements in the 2012 Form 10-K.

Pending Regulatory Actions

 Nevada Power Company

         NPC 2013 DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEIR and EEPR rate elements.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the table above.  The March 2013 application includes the following changes in revenue requirement (dollars in millions):

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR(1)		Oct. 2013	$	28.4	$	38.7	$	(10.3)
	TRED(1)		Oct. 2013		15.7		15.9		(0.2)
	EEPR Base(1)		Oct. 2013		45.9		32.6		13.3
	EEPR Amortization(1)		Oct. 2013		(29.9)		9.0		(38.9)
	EEIR Base		Oct. 2013		15.1		10.6		4.5
	EEIR Amortization		Oct. 2013		(6.7)		10.7		(17.4)
		Total Revenue Requirement		$	68.5	$	117.5	$	(49.0)
(1)	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
	revenues collected.  As a result, such programs have no effect on Operating or Net Income.

Sierra Pacific Power Company

        SPPC 2013 Electric DEAA, REPR, TRED, EEIR and EEPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEPR and EEIR rate elements.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above.The March 2013 application includes the following changes in revenue requirement includes the following (dollars in millions):

22

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR (1)		Oct. 2013	$	42.3	$	44.4	$	(2.1)
	TRED (1)		Oct. 2013		7.4		6.3		1.1
	EEPR Base (1)		Oct. 2013		6.0		5.6		0.4
	EEPR Amortization (1)		Oct. 2013		(2.2)		1.8		(4.0)
	EEIR Base		Oct. 2013		5.6		4.7		0.9
	EEIR Amortization		Oct. 2013		1.1		1.9		(0.8)
		Total Revenue Requirement		$	60.2	$	64.7	$	(4.5)
(1)	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
	revenues collected.  As a result, such programs have no effect on Operating or Net Income.

SPPC 2013 Nevada Gas DEAA and REPR Rate Filings

In March 2013, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ended December 31, 2012 and to reset the REPR.  DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above.  The amounts requested in this filing result in an overall decrease in revenue requirement of $0.2 million with an anticipated effective date of October 2013.

FERC Matters

   NPC

      NPC 2012 FERC Transmission Rate Case

In October 2012, NPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2003.  The rate changes requested in this filing would result in an overall annual revenue increase of $11.3 million.  In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013.  All rates are subject to final approval by the FERC.  However, at this time management is unable to determine the final revenue impact of the case.

 SPPC 

      SPPC 2012 FERC Transmission Rate Case

In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003, respectively.  The rate changes requested in this filing would result in an overall annual revenue increase of $3.2 million.  In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013.  Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013.  All rates are subject to final approval by the FERC.However, at this time management is unable to determine the final revenue impact of the case.

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NOTE 4.LONG-TERM DEBT

NVE’s, NPC’s and SPPC’s long-term debt consists of the following (dollars in thousands): 

						March 31,								December 31,
						2013								2012
Long-Term Debt:			Stated Rate		Maturity Date	Consolidated		NVE Holding Co.		NPC		SPPC		Consolidated		NVE Holding Co.		NPC		SPPC
Secured Debt
	General and Refunding Mortgage Securities
		NPC Series L	5.875	%	2015	$	250,000	$	-	$	250,000	$	-	$	250,000	$	-	$	250,000	$	-
		NPC Series M	5.950	%	2016		210,000		-		210,000		-		210,000		-		210,000		-
		NPC Series N	6.650	%	2036		370,000		-		370,000		-		370,000		-		370,000		-
		NPC Series O	6.500	%	2018		325,000		-		325,000		-		325,000		-		325,000		-
		NPC Series R	6.750	%	2037		350,000		-		350,000		-		350,000		-		350,000		-
		NPC Series S	6.500	%	2018		500,000		-		500,000		-		500,000		-		500,000		-
		NPC Series U	7.375	%	2014		125,000		-		125,000		-		125,000		-		125,000		-
		NPC Series V	7.125	%	2019		500,000		-		500,000		-		500,000		-		500,000		-
		NPC Series X	5.375	%	2040		250,000		-		250,000		-		250,000		-		250,000		-
		NPC Series Y	5.450	%	2041		250,000		-		250,000		-		250,000		-		250,000		-
		SPPC Series M	6.000	%	2016		450,000		-		-		450,000		450,000		-		-		450,000
		SPPC Series P	6.750	%	2037		251,742		-		-		251,742		251,742		-		-		251,742
		SPPC Series Q	5.450	%	2013		250,000		-		-		250,000		250,000		-		-		250,000
	Variable Rate Debt (Secured
	by General and Refunding
	Mortgage Securities)
		NPC IDRB Series 2000A			2020		98,100		-		98,100		-		98,100		-		98,100		-
		NPC PCRB Series 2006			2036		37,700		-		37,700		-		37,700		-		37,700		-
		NPC PCRB Series 2006A			2032		37,975		-		37,975		-		37,975		-		37,975		-
		SPPC PCRB Series 2006A			2031		58,200		-		-		58,200		58,200		-		-		58,200
		SPPC PCRB Series 2006B			2036		75,000		-		-		75,000		75,000		-		-		75,000
		SPPC PCRB Series 2006C			2036		81,475		-		-		81,475		81,475		-		-		81,475
Senior Notes
		NVE Senior Notes	6.250	%	2020		315,000		315,000		-		-		315,000		315,000		-		-
		NVE Term Loan	2.810	%	2014		195,000		195,000		-		-		195,000		195,000		-		-
Obligations under capital leases							40,872		-		39,268		1,604		44,258		-		42,908		1,350
Unamortized bond premium and discount, net							1,519		-		(9,578)		11,097		1,631		-		(9,827)		11,458
Current maturities							(481,342)		-		(231,075)		(250,267)		(356,283)		-		(106,048)		(250,235)
Total Long-Term Debt						$	4,541,241	$	510,000	$	3,102,390	$	928,851	$	4,669,798	$	510,000	$	3,230,808	$	928,990

Substantially all utility plant is subject to the liens of the NPC Indenture and the SPPC Indenture under which their respective General and Refunding Mortgage bonds are issued.

NOTE 5. FAIR VALUE OF FINANCIAL INSTRUMENTS

The March 31, 2013 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments.  As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2012 Form 10-K, investments held in Rabbi Trust continues to be considered Level 1 in the fair value hierarchy.

The total fair value of NVE’s consolidated long-term debt at March 31, 2013 is estimated to be $5.9 billion based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities.  The total fair value was estimated to be $5.9 billion as of December 31, 2012.

The total fair value of NPC’s consolidated long-term debt at March 31, 2013, is estimated to be $4.0 billion based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities.  The total fair value was estimated to be $4.1 billion at December 31, 2012.

The total fair value of SPPC’s consolidated long-term debt at March 31, 2013, is estimated to be $1.3 billion based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities.  The total fair value was estimated to be $1.3 billion as of December 31, 2012. 

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NOTE 6.RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities.  NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPC based upon the current, or in the case of the retirees, previous, employment location.  Certain grandfathered and union employees are covered under a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees.   A summary of the components of net periodic pension and other postretirement costs for the three months ended March 31 follows.  This summary is based on a December 31, measurement date (dollars in thousands):

NVE
	Pension Benefits					Other Postretirement Benefits
		For the Three Months Ended March 31,				For the Three Months Ended March 31,
		2013		2012		2013		2012
Service cost	$	5,132	$	4,406	$	660	$	595
Interest cost		9,303		10,228		1,677		1,905
Expected return on plan assets		(12,708)		(12,447)		(1,687)		(1,563)
Amortization of prior service cost		(720)		(724)		(952)		(987)
Amortization of net loss		4,797		3,473		890		731
Net periodic benefit cost	$	5,804	$	4,936	$	588	$	681
The average percentage of NVE net periodic costs capitalized during 2013 and 2012 was 33.8% and 33.2%, respectively.

NPC
	Pension Benefits				Other Postretirement Benefits
		For the Three Months Ended March 31,				For the Three Months Ended March 31,
		2013		2012		2013		2012
Service cost	$	2,761	$	2,358	$	389	$	350
Interest cost		4,453		4,881		556		602
Expected return on plan assets		(6,270)		(6,237)		(631)		(592)
Amortization of prior service cost		(453)		(456)		(23)		229
Amortization of net loss		2,117		1,363		289		221
Net periodic benefit cost	$	2,608	$	1,909	$	580	$	810
The average percentage of NPC net periodic costs capitalized during 2013 and 2012 was 35.1% and 35.6%, respectively.

SPPC
	Pension Benefits				Other Postretirement Benefits
	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2013		2012		2013		2012
Service cost	$	1,926	$	1,695	$	251	$	227
Interest cost		4,558		5,043		1,104		1,283
Expected return on plan assets		(6,162)		(5,937)		(1,022)		(941)
Amortization of prior service cost		(277)		(277)		(933)		(1,220)
Amortization of net loss		2,501		2,026		592		504
Net periodic benefit cost	$	2,546	$	2,550	$	(8)	$	(147)
The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 was 34.4% and 33.0%, respectively.

As discussed in Note 10, Retirement Plan and Postretirement Benefits,in the 2012 Form 10-K, NVE offered a voluntary lump sum pension payout to former employees not currently of retirement age but eligible for future benefits and certain retiree participants already receiving benefits under NVE’s pension plan in an effort to reduce NVE’s future pension obligation.  As of March 31, 2013, NVE expects to payout an additional $11.0 million in lump sum pension pay outs from the pension assets during 2013. 

During the three months ended March 31, NVE made no contributions to either of the plans.  At the present time, NVE expects neither plan will require additional funding in 2013 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006.  However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding.  The amounts to be contributed in 2013 may change subject to market conditions.

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NOTE 7. COMMITMENTS AND CONTINGENCIES

Environmental

NPC 

      NEICO

NEICO, a wholly-owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility.  The site has a reclamation estimate supported by a bond of approximately $4 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs.  Management is continuing to evaluate various options for this property going forward, including reclamation or sale to a third party.

      Reid Gardner Generating Station

On October 4, 2011, NPC received a request for information from the EPA-Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for NPC’s Reid Gardner Generating Station located near Moapa, Nevada.  NPC operates the facility and owns Units 1-3.  Unit 4 of the facility is co-owned with the CDWR.  The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant.  NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request.  At this time, NPC cannot predict the impact, if any, associated with this information request.

SPPC 

      Valmy Generating Station

On June 22, 2009, SPPC received a request for information from the EPA-Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada.  SPPC co-owns and operates this coal-fired plant.  Idaho Power Company owns the remaining 50%.  The EPA’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 EPA relating to the plant.  SPPC completed its response to the EPA in December 2009 and will continue to monitor developments relating to this Section 114 request.  At this time, SPPC cannot predict the impact, if any, associated with this information request.

   NPC and SPPC

     Regional Haze Rules 

In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.

In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations.  In March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station.  The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015.  In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station Units at a later date.  In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP.For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice.  Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015.On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline for the Reid Gardner Generating Station retrofits so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada.  On March 26, 2013,the  EPA granted reconsideration of the compliance date for the  BART retrofits for Units 1, 2, and 3 at Reid Gardner Generating Station, proposing to extend the compliance date by 18 months, from January 1, 2015, to June 30, 2016. The EPA held a public hearing on April 29, 2013, to accept written and oral comments on this proposed action. The comment period for this action is scheduled to close on May 30, 2013.  

NVE continues to work toward finalizing the retrofit designs for the affected BART units.  NVE has received approval from the PUCN to retire Tracy Generating Station Units 1 and 2, and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2.  NVE intends to also file with the PUCN the request to install SNCRs on Reid Gardner Generating Station Units 1, 2 & 3.  Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units.  NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.

Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal.  In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule.  NVE has intervened in that lawsuit.  In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club, and the National Parks Conservation Association, petitioned

26

the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station.  NVE has intervened in this lawsuit.  At this time management is unable to determine the likelihood of success by petitioners in these litigation matters.  An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned. 

The Navajo Generating Station is also an affected unit under EPA’s Regional Haze Rules. On January 17, 2013, the EPAannounced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline forreducing NOx emissions. NVE, along with the other owners of the facility, have been reviewing the EPA proposal to determine its impacton the viability of the plant’s future operations. The land lease for the Navajo Generating Station is up for renewal in 2019.  Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations.  It is believed that the EPA BART proposal will require an investment of up to $1.1 billion inadditional emission controls at the plant of which NPC’s ownership share is 11.3%.

The comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested a 90-day extension, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners.  In March, 2013, the EPA granted a 90-day extension to August 5, 2013. Prior to the close of the comment period, the EPA is expected to hold public hearings in Arizona.

Given that the lease must be renegotiated by 2019, the timeline for BART installation is unclear,and EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predictat this timethe ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take at this time.

      Mercury and Air Toxics Standards (MATS)

In December 2011, the EPA signed for publication in the Federal Registera final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units.  The rule, referred to as the MATS rule, requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the Maximum Achievable Control Technology (MACT). The final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia.  The Court has established a schedule for the litigation; however, the Utilities cannot predict the outcome at this time.

The final rule does not specifically list control technologies that are required to achieve the MATS emission standards.  Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO₂ and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards.  At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC.  Note that the actual cost will be dependent upon final engineering design.

The three units at the Navajo Generating Station are also subject to MATS. The plant operator intends to file a one year extension request associated with the compliance date in order allow for additional testing of various mercury control strategies.  Due to the uncertainty of what control equipment will be ultimately required to control mercury from the Navajo units, a cost estimate is unable to be determined at this time.

Currently, all four of the units at the Reid Gardner Generating Station, as well as Unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend.  However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.

Other Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.  In addition, NVE and the Utilities may also be subject to future state or federal regulations.  Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites.  This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties.  The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation.  Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility, which may be accelerated by any decision to retire a generating station or other facility.  If remediation activities involve statutory joint and several liability provisions, strict liability or cost recovery of contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties.  In some instances, NVE or the Utilities may share liability associated with contamination with other parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs.  These types of sites/situations are generally managed in the normal course of business operations.

                In 2008, NPC signed an Administrative Order of Consent (AOC) as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owners and operating agent of Unit No. 4.  Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs.  However, actual costs of work under the AOC may vary significantly once the scope of work is defined and additional site characterization has been completed.

                NVE and the Utilities seek to continually comply with environmental regulations; however, given the uncertainties involved in the federal, state and local regulatory environment, future costs to comply may be material.

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Litigation Contingencies

NPC 

      Peabody Western Coal Company – Royalty Claim

NPC owns an 11% interest in the Navajo Generating Station, which is located in northern Arizona and operated by Salt River. Other participants in the Navajo Generating Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with Salt River and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station which is located in Laughlin, Nevada and was operated by Southern California Edison (SCE) prior to the time it became non-operational on December 31, 2005.

In June 1999, the Navajo Nation filed suit against Salt River, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”).  NPC was not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station.The DC Lawsuit asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process.  The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.

In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit.  In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible re-filing.

In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement amongthe Navajo Nation, Peabody, Salt River and SCE.  At the request of Salt River, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station. 

SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station.  NPC has not agreed to contribute to SCE’s portion of the DC Lawsuit settlement.  Management has discussed the matters with SCE, but does not believe the impact of any claim by, or settlement with, SCE will be material to NPC.

     SPPC

        Farad Dam

In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million.  One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume.  Under the terms of the contract with TMWA, SPPC is not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably  acceptable to TMWA or, alternatively, SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.  The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.

SPPC filed a claim with the Farad Dam’s insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers.  The insurers contested the extent and amount of insurance coverage.  Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.

In July 2012, the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC’s right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost.  In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three year time to rebuild to start at the conclusion of all litigation.

It is not known at this time when the District Court will set hearings for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC.

   Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.

Other Commitments

   NPC and SPPC

      ON Line TUA

During the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  ON Line has an expected in-service date of no later than December 31, 2013.  The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE’s future lease payments are adjusted for final capital costs, for which the Utilities

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expect to get regulatory recovery.  For accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of March 31, 2013, capitalized construction costs associated with GBT’s 75% interest of $297.5 million and $17.0 million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.

NOTE 8. EARNINGS PER SHARE (NVE)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan. 

			Three Months Ended March 31,
			2013		2012
Basic EPS
	Numerator ($000)
		Net Income	$	21,475	$	12,173
	Denominator
		Weighted average number of common shares outstanding		235,193,702		235,999,750
	Per Share Amounts
		Net Income per share - basic	$	0.09	$	0.05
Diluted EPS
	Numerator ($000)
		Net Income	$	21,475	$	12,173
	Denominator(1)
		Weighted average number of shares outstanding before dilution		235,193,702		235,999,750
		Stock options		18,767		35,283
		Non-Employee Director stock plan		179,971		153,686
		Employee stock purchase plan		10,539		10,888
		Restricted Shares		579,000		497,750
		Performance Shares		1,023,909		829,506
		Diluted Weighted Average Number of Shares		237,005,888		237,526,863
	Per Share Amounts
		Net income per share - diluted	$	0.09	$	0.05
(1)		The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the prior period.  If the conditions for conversion were met under this plan, 0 and 333,140 shares would be included for the three months ended March 31, 2013 and 2012, respectively.

NOTE 9.COMMON STOCK AND OTHER PAID-IN CAPITAL

Dividends

The following dividend declarations were made by the BOD of NVE:

Declaration Date		Amount	Payable Date	Shareholders of Record Date
February 7, 2013	$	0.19	March 20, 2013	March 5, 2013
May 8, 2013	$	0.19	June 19, 2013	June 4, 2013

On May 8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0 million and $20.0 million, respectively.  For the three months ended March 31, 2013, NPC paid dividends to NVE of $50.0 million.

Treasury Stock

NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program.  All shares repurchased are held as treasury stock and may be reissued

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upon exercise or settlement of the stock compensation award.  Treasury stock is accounted for using the cost method. During the three months ended March 31, 2013, NVE repurchased 197,178 shares of common stock for approximately $3.7 million.  During the three months ended March 31, 2013, NVE re-issued 644,536 treasury shares to satisfy employee benefit plans.

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ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

The information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.  These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking.  These statements are based on management’s beliefs and assumptions and on information currently available to management.  Actual results could differ materially from those contemplated by the forward-looking statements.  In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of NVE, NPC or SPPC (NPC and SPPC are collectively referred to as the “Utilities”) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

Operational Risks

· economic conditions, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, each of which affect customer growth, customer collections, customer demand and usage patterns;

· changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, and the impact of energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

· construction risks, including but not limited to those associated with ON Line, such as difficulty in securing adequate skilled labor, cost and availability of materials and equipment, third-party disputes, equipment failure, engineering and design failure, work accidents, fire or explosions, business interruptions, recovery of possible cost overruns, delay of in-service dates, and pollution and environmental damage;

· security breaches of our information technology or supervisory control and data systems, or the systems of others  upon which the Utilities rely, whether through cyber-attack, cyber-crime, sabotage, accident or other means, which may affect our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information; 

· unseasonable or severe weather, drought, wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, seriously impact the Utilities’ ability and/or cost to procure adequate supplies of fuel or purchased power, affect the amount of water available for electric generating plants in the southwestern U.S., and have other adverse effects on our business;

· employee workforce factors, changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, an aging workforce, and the ability to adjust the labor cost structure to changes in growth within our service territories;

· whether the Utilities’ newly installed advanced metering systems continue to operate as intended, accurately and timely measure customer energy usage and generate billing information, and whether the Utilities can continue to rely on third-party vendors or contractors to support certain proprietary components of the advanced metering systems;

· changes in and/or implementation of FERC and NERC mandatory reliability, security, and other requirements for system infrastructure, which could significantly affect existing and future operations;

· explosions, fires, accidents, mechanical breakdowns or vandalism that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory, including gas distribution services that the Utilities may rely upon, that can cause unplanned outages, reduce generating output, damage the Utilities’ assets or operations, subject the Utilities to third-party claims for property damage, personal injury or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;

· the extent to which NVE or the Utilities incur costs in connection with third-party claims or litigation that are not recoverable through insurance, rates, or from other third parties;

· changes in the business of the Utilities’ major customers engaged in mining or gaming, including availability and cost of capital or power demands, which may result in changes in the demand for the Utilities’ services, including the effect on the Nevada gaming industry from the opening of additional gaming establishments in other states and internationally;

· the effect that any future terrorist attacks, wars, threats of war or pandemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general;

· unusual or unanticipated changes in normal business operations of the Utilities, including unusual maintenance or repairs.

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Regulatory/Legislative Risks

· unfavorable rulings, penalties and findings by the PUCN in rate or other cases, investigations or proceedings, including GRCs, the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution business, renewable energy and energy efficiency recovery programs, and unfavorable rulings, penalties or findings by the FERC in rate or other cases, investigations and proceedings with regard to wholesale power sales and transmission services;

· the effect of existing or future Nevada or federal laws or regulations affecting the electric industry, including those which could allow additional customers to choose new electricity suppliers, use alternative sources of energy, generate their own electricity, or change the conditions under which they may do so;

· whether the Utilities can procure, obtain, and/or maintain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada; and

· changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject or which change the rate of federal or state taxes payable by our shareholders or common stock dividends.

Environmental Risks

· changes in and/or implementation of environmental laws or regulations, including the imposition of limits on emissions of carbon or other pollutants from electric generating facilities, which could significantly affect the Utilities existing operations as well as our construction program.

Liquidity and Capital Resources Risks

· whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs)  and/or power, or a ratings downgrade;

· wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving credit facilities, which may affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

· whether provisions of the Dodd-Frank Act or rules made under the act governing derivative transaction reporting, trading, and clearing or imposing margin or collateral requirements will materially increase the cost, or limit the availability or usefulness, to the Utilities of financial transactions and techniques important in managing risks the Utilities face in the commodity, power and financial markets; 

· the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly in the event of: volatility in the global credit markets or other problems, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN,  a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;

· whether NVE's BOD will declare NVE's common stock dividends based on the BOD’s periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions contained in NVE's and the Utilities' agreements;

· whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act; and

· further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension and other postretirement plans, which can affect future funding obligations, costs and pension and other postretirement plan liabilities.

Other factors and assumptions not identified above may also have been involved in deriving forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected.  NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.

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NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

In reviewing the agreements filed as exhibits to this Quarterly Report on Form 10-Q, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements.  The agreements contain representations and warranties by each of the parties that are specific to the applicable agreement.  These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

• should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;

• have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

• may apply standards of materiality in a way that is different from what may be viewed as material to investors; and

• were made only as of the date of the applicable agreement or such other date or dates as may be specified in such agreements and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

NOTE REGARDING STATISTICAL DATA

The statistical data used throughout this 10-Q, other than data relating specifically to NVE and its subsidiaries, are based upon independent industry publications, government publications, reports by market research firms or other published independent sources.   NVE and the Utilities did not commission any of these publications or reports.  These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy or completeness of such information.  While NVE and the Utilities believe that each of these studies and publications is reliable, NVE and the Utilities have not independently verified such data and make no representation as to the accuracy of such information.

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EXECUTIVE OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes discussion of the following:

• Critical Accounting Policies and Estimates:

• Recent Pronouncements

• For each of NVE, NPC and SPPC:

• Results of Operations

• Analysis of  Cash Flows

• Liquidity and Capital Resources

• Regulatory Proceedings (Utilities)

NVE’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas.  The Utilities are public utilities engaged in the generation, transmission, distribution and sale of electricity and, in the case of SPPC, sale of natural gas.  Other operations consist mainly of unregulated operations and the holding company operations.  The Utilities are the principal operating subsidiaries of NVE and account for substantially all of NVE’s assets and revenues.  NVE, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (NVE, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.

The Utilities are regulated by the PUCN with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations.  The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission.  The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.  As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities’ 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.  NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning.  SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter.  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 Utilities.  Additionally, the timely recovery of purchased power and 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 Utilities. 

Overview of Major Factors Affecting Results of Operations

NVE recognized net income of $21.5 million for the three months ended March 31, 2013, compared to $12.2 million for the same period in 2012.  The increase in net income is primarily due to the following pre-tax items:

• An increase in gross margin of $9.3 million; see the Utilities’ respective Results of Operations for further discussion of gross margin;

• A decrease in maintenance expense of $7.6 million due to the timing of outages; see the Utilities’ respective Results of Operations for further discussion; and

• A decrease in interest expense of $4.6 million primarily due to the redemption of NPC’s 6.5% General and Refunding Mortgage Notes, Series I in April 2012 and an increase in AFUDC-debt.

NVE Transformation

Beginning in 2006, NVE committed to an energy strategy to manage resources against our load by constructing/purchasing generating facilities, purchasing and developing renewable energy, encouraging energy efficiency and conservation programs, as well as, expanding our transmission capability in an effort to reduce our reliance on purchased power.  The implementation of this strategy required significant amounts of liquidity and capital.  To meet these capital requirements during the transformation, NVE and the Utilities issued, refinanced and reduced debt which improved credit ratings and decreased interest costs.  At the same time, management worked with the PUCN to communicate the necessity of investments to better serve our customers, the prudency of costs incurred and the importance of a reasonable and timely return on such investments for our shareholders. 

The energy strategy and regulatory diligence discussed above created a strong foundation for NVE and the Utilities to earn their allowable return on their investments while meeting a higher percentage of their load through owned generation.  Additionally, as a result of their financial policies, which focused on lowering interest rates and reducing debt, interest costs and their capital structure continues to improve.  Furthermore, through employee dedication and increased use of technology we continue to improve processes to enhance performance while keeping operating and maintenance costs relatively stable.  As a result, NVE expects to generate free cash flow in 2013, which may provide NVE the ability to increase its dividend while preserving its ability to invest in new opportunities. 

Key Initiatives

The economy in Nevada continues to recover slowly.  While a low growth environment can be challenging, the foundation established in prior years, including establishing energy independence, improving capital structure and liquidity and managing our regulatory environment, has positioned the Utilities to operate in this environment.  However, NVE and the Utilities continue to implement and develop key initiatives that collectively may further our ability to increase our common stock dividend, strengthen our capital structure and consider new investment opportunities.  These initiatives should enable us to contain operating and

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maintenance costs while effectively managing our regulatory environment and continuing to promote and improve a safe and reliable work environment.   These key initiatives are discussed below.

Continuous Improvement ofSafety 

The safety of NVE’s employees and the public is a core value of NVE and the Utilities. Accordingly, NVE has worked to integrate a set of safety principles into its business operations and culture.  These principles include not only complying with applicable safety, health and security regulations, but also implementing programs and processes aimed at continually improving safety and security conditions.  Our initiatives in 2013 and beyond will continue modeling a safety culture in all areas of the company. 

Construction of ON Line and One Company Merger

ON Line is Phase 1 of a joint project between the Utilities and GBT-South. Completion of ON Line, expected in late 2013, will connect NVE’s southern and northern service territories.  Pending certain state and federal regulatory approvals, ON Line will provide:

• Ability to dispatch energy jointly throughout the state;

• Access for southern Nevada to renewable energy resources in parts of northern and eastern Nevada which will enhance NVE’s ability to meet its Portfolio Standard;

• Ability to optimize its generating and transmission facilities to benefit its customers; and

• The opportunity for NVE to merge NPC and SPPC (the “One Company” merger).  A merger application is expected to be filed with the PUCN and FERC in June 2013.

Empower Customers through Focused Service and Efficiency Programs

NV Energize is a NVE project that includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management.  The NV Energize capabilities will allow NVE to help customers better manage their usage with the most cost-effective mix of pricing, service, efficiency and conservation options.  As of March 31, 2013, the installation of the Smart Meters is nearly complete. 

The NV Energize system provides more convenience for customers and is achieving operating savings through both automated meter reading and the elimination annually of approximately 1 million trips to customers’ premises to process service requests.  The system also enables NVE to launch new customer programs.  Recruitment of participants for a trial of a combination of time based rates, supporting technology and education options is now underway.  New detailed customer usage reports have been integrated into our web self-service capability, and customers can also request alerts on their billing information.  An enhanced air conditioning demand response program was launched in the fourth quarter.   It is designed to provide energy market based rebates for specific event participation and also includes an energy efficiency management capability.  Similar programs for commercial customers are under development.

Managing Generation Portfolio Within Environmental Compliance

As discussed in more detail in Note 7, Commitments and Contingencies, of the Notes to Financial Statements, certain generating stations of NVE are affected under EPA’s Regional Haze Rules.  The implementation costs of the Regional Haze Rules are significant.  Therefore, NVE must balance the cost of implementing the retrofits associated with the Regional Haze Rule with the effect current and future load requirements, retirements of generating stations, including the effects of NVision discussed below, and plant outages will have on its ability to serve its customers reliably. 

  Investment opportunities

NVE continues to explore investment opportunities that may benefit our customers and that will add to our core business of generation, transmission and distribution of energy.  In addition, NVE’s geographical location affords it access to various renewable resources for potential investment opportunities.

Proposed Legislation in Nevada

The Nevada Legislature is currently in session and is expected to complete its session in the second quarter of 2013.  The most significant legislation under consideration that would directly impact NVE is Senate Bill 123 (SB 123), which is a bill supported by NVE as part of its NVision initiative.  NVision is a comprehensive plan for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and natural gas-fired plants and the implementation of further demand response programs.  At the time of this filing, management cannot predict whether SB 123 will be adopted in its present or an amended form, or its ultimate impact on NVE and the Utilities.

NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. and Other Subsidiaries

NVE (Holding Company)

The operating results of NVE primarily reflect those of NPC and SPPC, discussed later.  The holding company’s (stand alone) operating results included approximately $6.3 million and $6.3 million of long term debt interest costs for the three months ended March 31, 2013 and 2012, respectively. 

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For the period ended March 31, 2013, NPC paid $50.0 million in dividends to NVE. On May 8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0 million and $20.0 million, respectively.

Other Subsidiaries

Other subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.

ANALYSIS OF CASH FLOWS

NVE’s cash flows decreased during the three months ended March 31, 2013, compared to the same period in 2012, due to an increase in cash used by financing activities, offset partially by an increase in cash from operating activities and a decrease in cash used by investing activities.

Cash from Operating Activities -The increase in cash from operating activities was primarily due to increased cash flows from accounts receivable as a result of higher balances at December 31, 2012, compared to balances at December 31, 2011, due to higher BTGR rates resulting from NPC’s 2011 GRC which were effective January 1, 2012.  Also contributing to the increase was a reduction in refunds to customers for previously over collected BTER balances, a reduction in coal and gas purchases, and the receipt of approximately $9.0 million in insurance proceeds related to a previous claim.  These increases were offset by an under collection of energy costs in 2013 as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates.

Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to the decrease in construction activity related to the NV Energize project, partially offset by the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, also related to the NV Energize project.

Cash used by Financing Activities - Cash used by financing activities increasedprimarily due to anincrease in dividends to shareholders, a reduction in draws from the NPC’s revolving credit facility, and the repurchase of common stock, which may be reissued to satisfy future equity compensation costs.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

NVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC.  The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and, in the case of SPPC, natural gas.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest.  Another significant use of cash is the refunding of previously over-collected BTER amounts from customers.Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes and economic conditions.  Available liquidity as of March 31, 2013 was as follows (in millions):

Available Liquidity as of March 31, 2013 (in millions)
			NVE		NPC		SPPC
Cash and Cash Equivalents			$	27.4	$	132.2	$	85.3
	Balance available on Revolving Credit Facilities(1)			N/A		497.3		243.7
				27.4		629.5		329.0
(1)		As of May 7, 2013, NPC and SPPC had approximately $497.3 million and $243.7 million available under their revolving credit facilities, which includes reductions in availability for letters of credit.

NVE and the Utilities’ attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, the Utilities may use their revolving credit facilities in order to meet their liquidity needs.  Alternatively, depending on the usage of their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NVE has no debt maturities in 2013.However, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020 prior to ON Line’s commercial operation date expected by December 31, 2013 and its $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014.  SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature in September 2013.  To meet these long term maturing debt obligations, the Utilities intend to use a combination of internally generated funds, the Utilities’ revolving credit facilities, and/or the issuance of long term debt.  The Utilities’ credit ratings on their senior secured debt remains at investment grade (see Credit Ratings below).  NVE and the Utilities have not recently experienced any limitations in the credit markets, nor do we expect any for the remainder of 2013.  However, disruption in the banking and capital markets not specifically related to NVE and the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.  

In prior years, NVE and the Utilities required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As NVE and the Utilities have transitioned to slower growth, the amount of capital expenditures has declined.  NVE’sand the Utilities’ investment in generating stations in the past several years and more stable energy markets have positioned the Utilities to better manage and optimize their resources.  As a result, NVE and the Utilities anticipate that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of the Utilities revolving credit facilities.  Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, NVE and the Utilities expect to generate free cash flow in 2013; however, NVE’s and the Utilities’ cash flow may vary from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.

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However, if energy costs rise at a rapid rate, or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less.  In order to maintain sufficient liquidity under such circumstances, NVE and the Utilities may be required to delay capital expenditures, re-finance debt or issue equity at NVE.  Additionally, if deemed prudent, the Utilities may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs.  Currently, the Utilities are not operating under a PUCN approved hedging plan.  Hedging transactions may have a material impact on the Utilities’ cash flows, unless recovered in rates in a timely manner. 

As of May8, 2013, NVE has approximately $22.9 million payable of debt service obligations remaining for 2013, which it intends to fund through dividends from subsidiaries.  (See Factors Affecting Liquidity-Dividends from Subsidiaries, below).  For the three months ended March 31, 2013, NPC paid dividends to NVE of approximately $50.0 million.  On May8, 2013, NPC and SPPC declared dividends payable to NVE of $30.0 million and $20.0 million, respectively.

NVE designs operating and capital budgets to control operating costs and capital expenditures.  In addition to operating expenses, NVE has continuing commitments for capital expenditures for construction, environmental compliance, improvement and maintenance of facilities.  As discussed, in Note 12, Commitments and Contingencies of the 2012 Form 10-K, capital projects include NPC’s purchase of Reid Gardner Generating Station Unit No. 4 from CDWR.  The purchase is expected to be completed mid 2013 for approximately $47.1 million, subject to final approval by the FERC.

During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in NVE’s 2012 Form 10-K.

Factors Affecting Liquidity

   Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence and liens, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four-quarter period on a pro forma basis is at least 1.50 to 1.00 and the ratio of consolidated total indebtedness to consolidated capitalization does not exceed .70 to 1.00.  Under these covenant restrictions, as of March 31, 2013, NVE (consolidated) would be allowed to incur up to $3.2 billion of additional indebtedness.  The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.  NPC’s and SPPC’s Ability to Issue Debt sections further discuss their limitations on their ability to issue debt.

   Effect of Holding Company Structure

As of March 31, 2013, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: a $195 million Term Loan due 2014; and$315 million of unsecured 6.25% Senior Notes due 2020.

Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors.  Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

As of March 31, 2013, NVE, NPC, SPPC and their subsidiaries had approximately $5.0 billion of debt and other obligations outstanding, consisting of approximately $3.3 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510.0 million of debt at the holding company and other subsidiaries.  Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE.  Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of March 31, 2013, there were no dividend restrictions imposed on the Utilities by the PUCN.

 In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid.  As a result of the Utilities’ credit rating on their senior secured debt being rated investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as such debt remains investment grade by both rating agencies.  In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.”  Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts.  If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.

Credit Ratings

The liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt.  On April 30, 2013, Fitch upgraded NVE’s corporate credit ratings from BB to BB+, and for NPC and SPPC, from BB+ to investment grade BBB-.  NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P.  The senior debt credit ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NVE		Sr. Unsecured Debt	BB+	Ba1	BB+
NPC		Sr. Secured Debt	BBB+*	Baa1*	BBB+*
SPPC		Sr. Secured Debt	BBB+*	Baa1*	BBB+*
*	Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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Fitch’s, Moody’s and S&P’s rating outlooksare stable for NVE, NPC and SPPC.  

A security rating is not a recommendation to buy, sell or hold securities.  Security ratings are subject to revision and withdrawal at any time by the assigning rating organization.  Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

Energy Supplier Matters

With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP.  The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change, which includes a credit rating downgrade of NPC and SPPC, may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  A default must be declared within 30 days of the event, giving rise to the default becoming known.  A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received.  The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time.  The net mark-to-market value as of March 31, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $94.6 million payment or obligation to NPC.  No amounts would be due to or from SPPC.  These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. 

   Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily mean a credit rating downgrade below investment grade.  Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.   

Gas transmission service is secured under FERC tariffs or custom agreements.  These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.  NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.   As of March 31, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million.  Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade. 

   Financial Gas Hedges

The Utilities may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Financial Statements in the 2012 Form 10-K, NPC’s and SPPC’s Financing Transactions, the availability under the Utilities’ revolving credit facilities is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities.  Currently, there are no negative mark-to-market exposures that would impact borrowings of the Utilities.  If deemed prudent, the Utilities may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   Cross Default Provisions

None of the Utilities’ financing agreements contains a cross default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements.  Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in an event of default by NVE upon an event of default by the Utilities under their respective financing agreements.  In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due.  Most of these default provisions (other than ones relating to a failure to pay other

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indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of approximately $5.4 million during the three months ended March 31, 2013, compared to a net loss of approximately $1.3 million for the same period in 2012.

For the period ended March 31, 2013, NPC paid $50.0 million in dividends to NVE.  On May 8, 2013, NPC declared a dividend of $30.0 million to NVE.

Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level.  Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which NPC calculates as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of NPC.  For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

The components of gross margin were (dollars in thousands):

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		Three Months Ended March 31,
		2013		2012			Variance	% Change
Operating Revenues:		$	371,863	$	395,688	$	(23,825)	(6.0)	%
Energy Costs:
	Fuel for power generation		105,531		80,549		24,982	31.0	%
	Purchased power		81,408		81,531		(123)	(0.2)	%
	Deferred energy		(45,355)		2,171		(47,526)	(2,189.1)	%
Energy efficiency program costs			7,967		15,774		(7,807)	(49.5)	%
	Total Costs	$	149,551	$	180,025	$	(30,474)	(16.9)	%
Gross Margin		$	222,312	$	215,663	$	6,649	3.1	%

Gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012. The increase is primarily due to $2.6 million related to a slight increase in the BTGR effective rate, a $2.3 million net increase in usage primarily due to milder weather in 2012 as indicated in the table below, and approximately $1.4 million due to customer growth.

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period.  A degree day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F.  For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1.  In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.

The following table shows the HDDs and CDDswithin NPC’s service territory:

		Three Months Ended March 31,
		2013	2012	Variance	% Change
NPC
	Heating	1,050	924	126	13.6	%
	Cooling	86	41	45	109.8	%

The causes for significant changes in specific lines comprising the results of operations for NPC for the respective periods are provided below (dollars in thousands except for amounts per unit):

Operating Revenue
				Three Months Ended March 31,
	Operating Revenues:			2013		2012		Variance		% Change
		Residential		$	191,894	$	194,489	$	(2,595)	(1.3)	%
		Commercial			79,561		87,735		(8,174)	(9.3)	%
		Industrial			88,477		99,914		(11,437)	(11.4)	%
			Retail revenues		359,932		382,138		(22,206)	(5.8)	%
		Other			11,931		13,550		(1,619)	(11.9)	%
			Total Operating Revenues	$	371,863	$	395,688	$	(23,825)	(6.0)	%
	Retail sales in thousands of MWhs
		Residential			1,611		1,536		75	4.9	%
		Commercial			916		957		(41)	(4.3)	%
		Industrial			1,635		1,652		(17)	(1.0)	%
	Retail sales in thousands of MWhs				4,162		4,145		17	0.4	%
	Average retail revenue per MWh			$	86.48	$	92.19		(5.71)	(6.2)	%

NPC’s retail revenues decreased for the three months ended March 31, 2013, as compared to the same period in 2012 primarily due to $22.1 million in rate decreases largely due to NPC’s various BTER and DEAA quarterly updates (See Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K), and $7.7 million from decreases in EEPR rates effective January 1, 2013. Thesedecreases were offset by an increase of $6.5 million resulting from increased residential usage, primarily due to an increase in HDDs.

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For the three months ended March 31, 2013, the average number of retail customers increased slightly by 0.6%, consisting of an increase in residential, commercial and industrial customers of 0.6%, 1.1% and 0.7%, respectively, compared to the same period in the prior year.

Electric operating revenue – other for the three months ended March 31, 2013, compared to the same period in 2012, did not change materially. 

Energy Costs

Energy Costs include fuel for generation and purchased power.  Energy costs are dependent upon several factors which may vary by season or period.  As a result, NPC’s usage and average cost per MWh of fuel for generation versus purchased power to meet demand can vary significantly.  Factors that may affect energy costs include, but are not limited to:

• weather

• generation efficiency

• plant outages

• total system demand

• resource constraints

• transmission constraints

• natural gas constraints

• long-term contracts

• mandated power purchases; and

• volatility of commodity prices

		Three Months Ended March 31,
		2013		2012			Variance	% Change
Energy Costs
	Fuel for power generation	$	105,531	$	80,549	$	24,982	31.0	%
	Purchased power		81,408		81,531		(123)	(0.2)	%
Total Energy Costs		$	186,939	$	162,080	$	24,859	15.3	%
MWhs
	MWhs Generated (in thousands)		3,675		3,287		388	11.8	%
	Purchased Power (in thousands)		643		1,026		(383)	(37.3)	%
Total MWhs			4,318		4,313		5	0.1	%
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	28.72	$	24.51	$	4.21	17.2	%
	Average cost per MWh of Purchased Power	$	126.61	$	79.46	$	47.14	59.3	%
	Average total cost per MWh	$	43.29	$	37.58	$	5.71	15.2	%

Energy Costs and the average total cost per MWh increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to an increase in costs associated with higher natural gas prices partially offset by a decrease in the volume of purchased power which is typically more expensive than generated power.

• Fuel for generation costs increased for the three months ended March 31, 2013, compared to the same period in 2012.  Approximately $13.5 million of the increase is due to an increase in natural gas prices and approximately $11.5 million of the increase is due to an increase in volume.Volume increased due to continued reliance on internal generation to satisfy load requirements. 

• Purchased power costs decreased slightly for the three months ended March 31, 2013, compared to the same period in 2012.  Approximately $65.5 million of the decrease was due to a decrease in volume.  The decrease was largely offset by an increase of approximately $65.4 million in the cost of purchased power.  As the volume of purchased power decreases, the remaining contracts consist primarily of higher cost renewable energy contracts and other long term fixed capacity contracts which are increasing the average cost per unit.  Also contributing to the increase in the average cost per unit is the increase in the volume of power sales which are offset in purchased power. 

Deferred Energy
		Three Months Ended March 31,
		2013		2012			Variance	% Change
	Deferred energy	$	(45,355)	$	2,171	$	(47,526)	(2,189.1)	%

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Deferred Energy for the three months ended March 31, 2013 include amortizations of $(27.3) million, which primarily represents cash refunds to our customers for previous over-collections.  Further contributing to the 2013 deferred energy balance are under-collections of amounts recoverable in rates of $(18.0) million. 

Deferred Energy for the three months ended March 2012 include amortizations of previous over-collections of $(35.2) million, partially offset by over-collections of amounts recoverable in rates of $37.3 million. 

Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates.  To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs.  Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs.  Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred.  Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Other Operating Expenses
		Three Months Ended March 31,
		2013		2012			Variance	% Change
	Energy efficiency program costs	$	7,967	$	15,774	$	(7,807)	(49.5)	%
	Other operating expenses	$	67,392	$	66,462	$	930	1.4	%
	Maintenance	$	18,075	$	23,073	$	(4,998)	(21.7)	%
	Depreciation and amortization	$	68,661	$	64,990	$	3,671	5.6	%

For the three months ended March 31, 2013 energy efficiency program costs decreased compared to the same period in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013.  Reference Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortization rate filings.

Other operating expense increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $2.7 million increase in stock compensation costs, offset by a $1.3 million decrease in telecommunications, meter reading and meter replacement software costs, and $0.7 million in lower pension and benefit costs.

Maintenance expense decreased for the threemonths ended March 31, 2013, compared to the same period in 2012, primarily due to $5.3 million in planned maintenance and outages at the Silverhawk, Higgins, Reid Gardner and Lenzie Generating Stations in 2012.

Depreciation and amortization increased slightly for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service. 

Interest Expense
		Three Months Ended March 31,
		2013		2012			Variance	% Change
	Interest expense
	(net of AFUDC-debt: $1,837 and $1,179)	$	51,259	$	54,405	$	(3,146)	(5.8)	%

Interest expense decreased for the three months ended March 31, 2013, compared to the same period in 2012 due to a $2.2 million decrease in interest cost primarily due to the redemption of the 6.5% General and Refunding Mortgage Notes, Series I in April 2012 and an increase in AFUDC-debt of $0.7 million. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 4, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.

Other Income (Expense)
		Three Months Ended March 31,
		2013		2012			Variance	% Change
	Interest income (expense) on regulatory items	$	(802)	$	(2,016)	$	1,214	(60.2)	%
	AFUDC-equity	$	2,366	$	1,413	$	953	67.4	%
	Other income	$	2,404	$	1,709	$	695	40.7	%
	Other expense	$	(2,401)	$	(1,346)	$	(1,055)	78.4	%

Interest expense on regulatory items decreased for the three months ended March 31, 2013, compared to the same period in 2012, due to a $1.6 million decrease in interest on deferred energy as a result of lower over-collected  balances in 2013, and a decrease of $0.7 million in estimated interest expense accrued on the deferred gain on NPC’s wireless towers sold in 2011 pending final accounting approval by the PUCN in 2012, offset by $1.3 million net decrease of interest income due to lower regulatory asset balances.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K.

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AFUDC-equity increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to various construction projects. 

Other income increased for the three months ended March 31, 2013, compared to the same period in 2012, by several items, all of which were immaterial. 

Other expense increased for the three months ended March 31, 2013, compared to the same period in 2012,by several items, all of which were immaterial. 

Analysis of Cash Flows

NPC’s cash flows decreased during the three months ended March 31, 2013, compared to the same period in 2012, due to a decrease in cash from operating activities and an increase in cash used by investing and financing activities.

Cash from Operating Activities - The decrease in cash from operating activities was primarily due to an under collection of energy costs in 2013 as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates, and reduced energy efficiency rates.  These decreases were partially offset by increased cash flows from accounts receivable as a result of higher balances at December 31, 2012, compared to balances at December 31, 2011, due to higher BTGR rates resulting from NPC’s 2011 GRC which were effective January 1, 2012.  Further offsetting the decrease in cash from operating activities was the reduction in refunds to customers for previously over collected BTER balances. 

Cash used by Investing Activities - The increase in cash used by investing activities was primarily due to the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, related to the NV Energize project, partially offset by decreased construction activity related to the NV Energize project.

Cash used by Financing Activities - Cash used by financing activities increased primarily due to an increase in dividends paid to NVE and a reduction in draws from the NPC revolving credit facility.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness.  Another significant use of cash is the refunding of previously over-collected amounts from customers.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.  Available liquidity as of March 31, 2013 was as follows (in millions):

Available Liquidity as of March 31, 2013 (in millions)
			NPC
Cash and Cash Equivalents			$	132.2
	Balance available on Revolving Credit Facility(1)			497.3
			$	629.5
(1)		As of May 7, 2013, NPC had approximately $497.3 million available under its revolving credit facility which includes reductions for letters of credits.

NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, NPC may use its revolving credit facility in order to meet its liquidity needs.  Alternatively, depending on the usage of the revolving credit facility, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. 

NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date, expected no later than December 31, 2013 and its $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014.  To meet these maturing debt obligations, NPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt.  As of May 8, 2013, NPC has no borrowings on its revolving credit facility, not including letters of credit.  NPC’s credit ratings on its senior secured debt remains at investment grade (see Credit Ratings below).   NPC has not recently experienced any limitations in the credit markets, nor does NPC expect any significant limitations for the remainder of 2013.  However, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

In prior years, NPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As NPChas transitioned to slower growth, the amount of capital expenditures required has declined.  NPC’s investment in generating stations in the past several years and more stable energy markets have positioned NPC to bettermanage and optimize its resources.  As a result, NPC anticipates that they will be able to meet short-term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility.  Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL and a decrease in capital expenditures, NPC expects to generate free cash flow in 2013; however, NPC’s cash flow may vary significantly from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.

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However, if energy costs rise at a rapid rate or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available NPC could be significantly less.  In order to maintain sufficient liquidity under such circumstances, NPC may be required to delay capital expenditures, re-finance debt or receive capital contributions from NVE.

During the three months ended March 31, 2013, NPC paid dividends to NVE of $50.0 million.  OnMay 8, 2013, NPC declared a dividend to NVE of $30.0 million.

NPC designs operating and capital budgets to control operating costs and capital expenditures.  In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, environmental compliance, improvement and maintenance of facilities.  As discussed in Note 12, Commitments and Contingencies, of the 2012 Form 10-K, capital projects include NPC’s purchase of Reid Gardner Generating Station Unit No. 4 from CDWR.  The purchase is expected to be completed mid 2013 for approximately $47.1 million, subject to final approval by the FERC.

 During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in NPC’s 2012 Form 10-K.

Factors Affecting Liquidity

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements, its revolving credit facility agreement, and the terms of certain NVE debt.  As of March 31, 2013, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $725.0 million in long-term debt, in addition to the use of its existing credit facility.  However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting NPC’s ability to issue debt are further detailed below:

a.	Financing authority from the PUCN - As of March 31, 2013, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725.0 million; (2) to refinance up to approximately $422.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion.
b.	Financial covenants within NPC’s financing agreements – Under the NPC Credit Agreement, NPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.00.  Based on March 31, 2013 financial statements, NPC was in compliance with this covenant and could incur up to $2.8 billion of additional indebtedness.
	All other financial covenants contained in NPC’s financing agreements are suspended as NPC’s senior secured debt is currently rated investment grade.  However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; and
c.	Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.2 billion.

   Ability to Issue General and Refunding Mortgage Securities

To the extent that NPC has the ability to issue debt under the most restrictive covenants in its and NVE’s financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the NPC Indenture.

The NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada.  As of March 31, 2013,$3.8 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.6 billion of General and Refunding Mortgage Securities as of March 31, 2013.  That amount is determined on the basis of:

1.	70% of net utility property additions; and/or
2.	the principal amount of retired General and Refunding Mortgage Securities.

Property additions include plant in service.  Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.

NPC also has the ability to release property from the lien of the NPC Indenture on the basis of net property additions, cash and/or retired bonds.  To the extent NPC releases property from the lien of the NPC Indenture, it will reduce the amount of securities issuable under the NPC Indenture.

Credit Ratings

The liquidity of NPC, the cost and availability of borrowing by NPC under the NPC Credit Agreement, the potential exposure of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for NPC’s debt.  On April 30, 2013, Fitch upgraded NPC’s corporate credit rating from BB+ to investment grade BBB-.  NPC’s senior secured debt is rated investment grade by three NRSRO’s:  Fitch, Moody’s and S&P.  The senior secured debt credit ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NPC		Sr. Secured Debt	BBB+*	Baa1*	BBB+*
*	Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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Fitch’s, Moody’s and S&P’s rating outlooksare stable for NPC.    

               A security rating is not a recommendation to buy, sell or hold securities.  Security ratings are subject to revision and withdrawal at any time by the assigning rating organization.  Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

Energy Supplier Matters

With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP.  The WSPP agreement is posted on the WSPP website.

Under these contracts, a material adverse change, which includes a credit rating downgrade, in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  A default must be declared within 30 days of the event giving rise to the default becoming known.  A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received.  The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time.  The net mark-to-market value as of March 31, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $94.6 million payment or obligation to NPC.  These contracts qualify for the normal purchases and normal sales scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. 

   Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade.  Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances.  Forward physical gas supplies are purchased under index based pricing terms, and as such, do not carry forward mark-to-market exposure.  

Gas transmission service is secured under FERC tariffs or custom agreements.  These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.  NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.   As of March 31, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million.  Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade. 

   Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Financial Statements in the 2012 Form 10-K,  NPC’s Financing Transactions, the availability under the NPC’s revolving credit facility is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the credit facility.  Currently, there are no negative mark-to-market exposures that would impact borrowings of NPC.  If deemed prudent, NPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   Cross Default Provisions

None of the financing agreements of NPC contains a cross default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of its financing agreements.  In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due.  Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.

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Sierra Pacific Power Company

RESULTS OF OPERATIONS

SPPC recognized net income of $21.9 million for the three months ended March 31, 2013, compared to net income of $18.6 million for the same period in 2012. 

During the three months ended March 31, 2012, SPPC did not pay dividends to NVE. On May 8, 2013, SPPC declared a dividend of $20.0 million to NVE.

Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level.  Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis.  Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers.  While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers.  Gross margin, which SPPC calculates as operating revenues less energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of SPPC.  For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements.  Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).

The components of gross margin were (dollars in thousands):

		Three Months Ended March 31,
		2013		2012			Variance	% Change
Operating Revenues:
	Electric	$	172,627	$	169,806	$	2,821	1.7	%
	Gas		39,729		45,922		(6,193)	(13.5)	%
		$	212,356	$	215,728	$	(3,372)	(1.6)	%
Energy Costs:
	Fuel for power generation		41,717		36,486		5,231	14.3	%
	Purchased power		39,902		35,585		4,317	12.1	%
	Gas purchased for resale		37,620		31,617		6,003	19.0	%
	Deferral of energy - electric - net		(19,335)		(12,670)		(6,665)	52.6	%
	Deferral of energy - gas - net		(14,375)		(1,240)		(13,135)	1,059.3	%
Energy efficiency program costs			1,878		3,651		(1,773)	(48.6)	%
	Total Costs	$	87,407	$	93,429	$	(6,022)	(6.4)	%
Cost by Segment:
	Electric	$	64,162	$	63,052		1,110	1.8	%
	Gas		23,245		30,377		(7,132)	(23.5)	%
		$	87,407	$	93,429	$	(6,022)	(6.4)	%
Gross Margin by Segment:
	Electric	$	108,465	$	106,754	$	1,711	1.6	%
	Gas		16,484		15,545		939	6.0	%
		$	124,949	$	122,299	$	2,650	2.2	%

Electric gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012.  Approximately $1.2 million of the increase is due to customer growth and approximately $1.1 million of the increase is due to an increase in customer usage primarily due to an increase in HDDs as shown in the tables below. 

Gas gross margin increased for the three months ended March 31, 2013, compared to the same period in 2012.  The increase is primarily due to the increase in HDDs as shown in the tables below.

HDDs and CDDs

MWh usage may be affected by the change in HDDs or CDDs in a given period.  A degree day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F.  For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1.  In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.

The following table shows the HDDs and CDDs within SPPC’s service territory:

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		Three Months Ended March 31,
		2013	2012	Variance	% Change
SPPC
	Heating	2,285	2,128	157	7.4	%
	Cooling	-	-	N/A	N/A

The causes for significant changes in specific lines comprising the results of operations for SPPC for the respective periods are provided below (dollars in thousands except for amounts per unit):

Electric Operating Revenue
				Three Months Ended March 31,
	Operating Revenues:			2013		2012			Variance	% Change
		Residential		$	62,978	$	61,360	$	1,618	2.6	%
		Commercial			56,886		58,712		(1,826)	(3.1)	%
		Industrial			34,640		33,070		1,570	4.7	%
			Retail  revenues		154,504		153,142		1,362	0.9	%
		Other			18,123		16,664		1,459	8.8	%
			Total Operating Revenues	$	172,627	$	169,806	$	2,821	1.7	%
	Retail sales in thousands of MWhs
		Residential			629		600		29	4.8	%
		Commercial			650		659		(9)	(1.4)	%
		Industrial			668		633		35	5.5	%
	Retail sales in thousands of MWhs				1,947		1,892		55	2.9	%
	Average retail revenue per MWh			$	79.35	$	80.94	$	(1.59)	(2.0)	%

Retail revenue increased for the three months ended March 31, 2013, as compared to the same period in 2012, primarily due to a $2.2 million increase in residential customer usage primarily due to an increase in HDDs as outlined in the table above, a $1.2 million increase in usage by mining customers and $0.7 million attributable to customer growth. These increases were partially offset by $1.8 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013 (see Note 3, Regulatory Actions of the Notes to Financial Statements) and $1.6 million of rate decreases due to various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions of the Notes to Financial Statements).

For the three months ended March 31, 2013, the average number of residential, commercial and industrial customers increased 0.6%, 0.7% and 4.8%, respectively, compared to the same period in 2012.

Electric operating revenues – Other increased by $1.5 million for the three months ended March 31, 2013, compared to the same period in 2012,primarily due to an increase in energy sales to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K).

Gas Operating Revenue
				Three Months Ended March 31,
				2013		2012			Variance	% Change
	Gas Operating Revenues:
		Residential		$	22,545	$	26,557	$	(4,012)	(15.1)	%
		Commercial			8,719		10,966		(2,247)	(20.5)	%
		Industrial			2,278		2,715		(437)	(16.1)	%
			Retail  Revenues		33,542		40,238		(6,696)	(16.6)	%
		Wholesale Revenues			5,325		4,830		495	10.2	%
		Miscellaneous			862		854		8	0.9	%
			Total Gas Revenues	$	39,729	$	45,922	$	(6,193)	(13.5)	%
	Retail sales in thousands of Dths
		Residential			4,136		3,708		428	11.5	%
		Commercial			2,076		1,879		197	10.5	%
		Industrial			533		476		57	12.0	%
	Retail sales in thousands of Dths				6,745		6,063		682	11.2	%
	Average retail revenue per Dth			$	4.97	$	6.64	$	(1.67)	(25.1)	%

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SPPC’s retail gas revenues decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $9.7 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012, and various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K). The decrease was partially offset by a $2.7 million increase in customer usage primarily due to an increase in HDDs, as shown in the table above.

 Wholesale revenues increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to an increase in natural gas prices. 

Energy Costs

Energy Costs include purchased power and fuel for generation.  These costs are dependent upon many factors which may vary by season or period.  As a result, SPPC’s usage and average cost per MWh of purchased power versus fuel for generation can vary significantly as the company meets the demands of the season.  These factors include, but are not limited to:

• weather

• plant outages

• total system demand

• resource constraints

• transmission constraints

• gas transportation constraints

• natural gas constraints

• long-term contracts

• mandated power purchases

• generation efficiency; and

• volatility of commodity prices

		Three Months Ended March 31,
		2013		2012			Variance	% Change
Energy Costs
	Fuel for power generation	$	41,717	$	36,486	$	5,231	14.3	%
	Purchased power		39,902		35,585		4,317	12.1	%
Total Energy Costs		$	81,619	$	72,071	$	9,548	13.2	%
MWhs
	MWhs Generated (in thousands)		1,147		1,178		(31)	(2.6)	%
	Purchased Power (in thousands)		1,105		1,011		94	9.3	%
Total MWhs			2,252		2,189		63	2.9	%
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	36.37	$	30.97	$	5.40	17.4	%
	Average cost per MWh of Purchased Power	$	36.11	$	35.20	$	0.91	2.6	%
	Average total cost per MWh	$	36.24	$	32.92	$	3.32	10.1	%

Energy Costs and the average total cost per MWh increased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to higher natural gas prices.Total MWhs increased for the three month period primarily due to an increase in HDDs.

• Fuel for generation costs increased for the three months ended March 31, 2013, compared to the same period in 2012.  Approximately $6.4 million of the change is due to higher natural gas prices partially offset by a decrease in volume of approximately $1.2 million.

• Purchased power costs for the three months ended March 31, 2013, compared to the same period in 2012. Approximately $3.1 million of the increase is due to increased reliance on purchased power along with a $1.2 million increase due to higher natural gas prices.  Volume increased due to less reliance on internal generation.

Gas Purchased for Resale
		Three Months Ended March 31,
		2013		2012			Variance	% Change
	Gas purchased for resale	$	37,620	$	31,617	$	6,003	19.0	%
	Gas purchased for resale (in thousands of Dths)		8,427		8,274		153	1.8	%
	Average cost per Dth	$	4.46	$	3.82	$	0.64	16.8	%

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Gas purchased for resale increased for the three months ended March 31, 2013,compared to the same period in 2012.  Approximately $5.3 million of the increase is due to higher natural gas prices and approximately $0.7 million is due to an increase in volume. 

Deferred Energy
		Three Months Ended March 31,
		2013		2012			Variance	% Change
	Deferral of energy - electric - net	$	(19,335)	$	(12,670)	$	(6,665)	52.6	%
	Deferral of energy - gas - net		(14,375)		(1,240)		(13,135)	1,059.3	%
		$	(33,710)	$	(13,910)	$	(19,800)	142.3	%

Deferred energy-electric for the three months ended March 31, 2013 include amortization of $(11.3) million which represent cash refunds to our customers for previous over-collections.  Further contributing to the 2013 deferred energy balance are under-collections of amounts recoverable in rates of $(8.0) million. 

Deferred energy-electric for the three months ended March 31, 2012 include amortization of previous over-collections of $(25.5) million, partially offset by over-collections of amounts recoverable in rates of $12.8 million. 

Deferred energy-gas for the three months ended March 31, 2013 include amortizations of previous over-collections of ($13.4) million and under-collections of amounts recoverable in rates of $(0.9) million.

Deferred energy-gas for the three months ended March 31, 2012 include amortization of previous over-collections of ($13.4) million, partially offset by over-collections of amounts recoverable in rates of $12.2 million.

Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates.  To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs.  Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs.  Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred.  Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Other Operating Expenses
		Three Months Ended March 31,
		2013		2012		Variance	% Change
	Energy efficiency program costs	$	1,878	$	3,651	(1,773)	(48.6)	%
	Other operating expenses	$	35,805	$	36,432	(627)	(1.7)	%
	Maintenance	$	6,831	$	9,453	(2,622)	(27.7)	%
	Depreciation and amortization	$	27,341	$	25,872	1,469	5.7	%

For the three months ended March 31, 2013, energy efficiency program costs decreased compared to the same period in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013.  Reference Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortization rate filings.

Other operating expensesdecreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to $1.0 million in lower telecommunications and software costs, and $0.6 million in lower pension and benefit costs. The decrease was partially offset by a $1.2 million increase in stock compensation costs.

Maintenance expense decreased for the threemonths ended March 31, 2013, compared to the same period in 2012, primarily due to a $1.4 million planned major outage at the Tracy Generating Station in 2012 and maintenance at the Valmy Generating Station in 2012 for $0.7 million.

Depreciation and amortization increased slightlyfor the three months ended March 31, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service.

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Interest Expense
		Three Months Ended March 31,
		2013		2012		Variance	% Change
	Interest expense
	(net of AFUDC-debt: $294 and $416)	$	15,525	$	16,973	(1,448)	(8.5)	%

Interest expense decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to decreased debt amortization expense of $1.5 million. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding long-term debt.

Other Income (Expense)
		Three Months Ended March 31,
		2013		2012		Variance	% Change
	Interest expense on regulatory items	$	(25)	$	(186)	161	(86.6)	%
	AFUDC-equity	$	523	$	519	4	0.8	%
	Other income	$	1,140	$	2,183	(1,043)	(47.8)	%
	Other expense	$	(1,248)	$	(1,335)	87	(6.5)	%

Interest expense on regulatory items decreased for the three months ended March 31, 2013, compared to the same period in 2012, primarily due to a $0.6 milliondecrease in interest on deferred energy as a result of lower over-collected balances in 2013, offset by a $0.4 million decrease in carrying charges on solar conservation programs. See Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further details of deferred energy balances.

AFUDC-equity did not change materially for the three months ended March 31, 2013, compared to the same period in 2012. 

Other income decreased for the three months ended March 31, 2013, compared to same period in 2012, primarily due to the $1.1 million settlement with CAISO in 2011, recognized in 2012. See Note 3, Regulatory Actions, FERC Matters, in the Notes to Financial Statements in the 2012 Form 10-K.

Other expense is comparable for the three months ended March 31, 2013, as compared to the same period in 2012.

Analysis of Cash Flows

SPPC’s cash flows increased during the three months ended March 31, 2013, compared to the same period in 2012, due to an increase in cash from operating activities and a decrease in cash used by investing and financing activities.

Cash from Operating Activities - The increase in cash from operating activities was primarily due to reduced coal and gas purchases, over collections of EEPR and reduction in refunds to customers for previously over collected BTER balances.  Also contributing to the increase was the receipt of approximately $9.0 million in insurance proceeds related to a previous claim.  These increases were partially offset by an under collection of energy costs in 2013, as opposed to an over collection of energy costs in 2012, resulting from adjustments to BTER rates. 

Cash used by Investing Activities - The decrease in cash used by investing activities was primarily due to decreased capital expenditure for the NV Energize project, partially offset by the reduction of CIAC received under the American Recovery and Reinvestment Act of 2009, also related to the NV Energize project.

Cash used by Financing Activities - The decrease in cash used by financing activities is primarily due to a reduction in dividends to NVE.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs.  Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness.  Another significant use of cash is the refunding of previously over-collected amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.  Available liquidity as of March 31, 2013 was as follows (in millions):

Available Liquidity as of March 31, 2013 (in millions)
			SPPC
Cash and Cash Equivalents			$	85.3
	Balance available on Revolving Credit Facility(1)			243.7
			$	329.0
(1)		As of May 7, 2013, SPPC had approximately $243.7 million available under its revolving credit facility which includes reductions for letters of credits.

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SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, SPPC may use its revolving credit facility in order to meet its liquidity needs.  Alternatively, depending on the usage of the revolving credit facility, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. 

SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013.  To meet this maturing debt obligation, SPPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt.  As of May 8, 2013, SPPC has no borrowings on its revolving credit facility, not including letters of credit. In 2012, SPPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below).  In 2012, SPPC did not experience any limitations in the credit markets, nor do we expect any significant limitations in 2013.  However, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

In prior years, SPPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets.  As SPPChas transitioned to slower growth, the amount of capital expenditures required has declined.  SPPC’s investment in generating stations in the past several years and more stable energy markets have positioned SPPC to better manage and optimize its resources.  As a result, SPPC anticipates that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility.  Furthermore, with significant investments in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL, and a decrease in capital expenditures, SPPC expects to generate free cash flow in 2013; however, SPPC’s cash flow may vary from quarter to quarter due to the seasonality of our business.  Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.   To meet long term maturing debt obligations, SPPC may use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt, or capital contributions from NVE.

However, if energy costs rise at a rapid rate, or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less.  In order to maintain sufficient liquidity under such circumstances, SPPC may be required to delay capital expenditures, refinance debt, or receive capital contributions from NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities.  As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.  Additionally, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

During the three months ended March 31, 2013, SPPC did not pay dividends to NVE.On May 8, 2013 SPPC declared a dividend to NVE of $20.0 million.

SPPC designs operating and capital budgets to control operating costs and capital expenditures.  In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, environmental compliance, improvement, and maintenance of facilities.

During the three months ended March 31, 2013, there were no material changes to contractual obligations as set forth in SPPC’s 2012 Form 10-K.

Factors Affecting Liquidity

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt.  As of March 31, 2013, the most restrictive of the factors below is the PUCN authority.  Based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million.  However, depending on NVE’s or NPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting SPPC’s ability to issue debt are further detailed below:

a.	Financing authority from the PUCN - As of March 31, 2013, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority (1) to issue additional long-term debt securities of up to $350million; (2) to refinance up to approximately $598.3 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million;
b.	Financial covenants within SPPC’s financing agreements – Under the SPPC Credit Agreement, the Utility must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.00.  Based on March 31, 2013 financial statements, SPPC was in compliance with this covenant and could incur up to $1.1 billion of additional indebtedness;
	All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently rated investment grade.  However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants; and
c.	Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.2 billion.

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   Ability to Issue General and Refunding Mortgage Securities

To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its and NVE’s financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the SPPC Indenture.

The SPPC Indenture creates a lien on substantially all of SPPC’s properties in Nevada.  As of March 31, 2013, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $824 millionof additional General and Refunding Mortgage Securities as of March 31, 2013.  That amount is determined on the basis of:

1.	70% of net utility property additions; and/or
2.	the principal amount of retired General and Refunding Mortgage Securities.

Property additions include plant in service.  Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.

SPPC also has the ability to release property from the lien of the SPPC Indenture on the basis of net property additions, cash, and/or retired bonds.  To the extent SPPC releases property from the lien of the SPPC Indenture, it will reduce the amount of securities issuable under the SPPC Indenture.

Credit Ratings

The liquidity of SPPC, the cost and availability of borrowing by SPPC under the SPPC Credit Agreement, the potential exposure of SPPC to collateral calls under various contracts, and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for SPPC’s debt.  On April 30, 2013, Fitch upgraded SPPC’s corporate credit rating from BB+ to investment grade BBB-.  SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P.  The senior secured debt credit ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
SPPC	Sr. Secured Debt	BBB+*	Baa1*	BBB+*
	*Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

Fitch’s, Moody’s and S&P’s rating outlooksare stable for SPPC.  

A security rating is not a recommendation to buy, sell or hold securities.  Security ratings are subject to revision and withdrawal at any time by the assigning rating organization.  Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

Energy Supplier Matters

With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP.  The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change, which includes a credit rating downgrade in SPPC may allow the counterparty to request adequate financial assurance, which if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  A default must be declared within 30 days of the event, giving rise to the default becoming known.  A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received.  The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time.  According to the net mark-to-market value as of March 31, 2013, no amounts would be due to or from SPPC for all suppliers continuing to provide power under a WSPP agreement.  These contracts qualify for the normal purchases and normal sales scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet. 

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Gas Supplier Matters

With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts.  The natural gas contract terms and conditions are more varied than the electric contracts.  Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.  Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery.  At the present time, no counterparties require payment in advance of delivery. 

Gas transmission service is secured under FERC tariffs or custom agreements.  These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service.  Service contracts are subject to FERC approved tariffs, which under certain circumstances require the Utilities to provide collateral to continue receiving service.

Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt,of the Notes to Financial Statements in the 2012 Form 10-K,  SPPC’s Financing Transactions, the availability under the SPPC’s revolving credit facility is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the credit facility.  Currently, there are no negative mark-to-market exposures that would impact borrowings of SPPC.  If deemed prudent, SPPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

Cross Default Provisions

None of the financing agreements of SPPC contains a crossdefault provision that would result in an event of default by SPPC upon an event of default by NVE or NPC under any of its financing agreements.  In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due.  Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.

RECENT PRONOUNCEMENTS

See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements, and Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements in the 2012 Form 10-K for discussion of accounting policies and recent pronouncements.

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of March 31, 2013, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity.  Such instruments are fixed and variable rate debt.  Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands):

					2013
					Expected Maturities
																									Fair
				2013			2014			2015			2016			2017		Thereafter			Total				Value
Long-Term Debt
	NVE
	Fixed Rate			$	-		$	195,000		$	-		$	-		$	-	$	315,000		$	510,000		$	575,444
		Average Interest Rate			-			2.81	%		-			-			-		6.25	%		4.93	%		-
	NPC
	Fixed Rate			$	-		$	125,000		$	250,000		$	210,000		$	-	$	2,545,000		$	3,130,000		$	3,873,718
		Average Interest Rate			-			7.38	%		5.88	%		5.95	%		-		6.47	%		6.42	%		-
	Variable Rate			$	98,100		$	-		$	-		$	-		$	-	$	75,675		$	173,775		$	170,737
		Average Interest Rate			0.61	%		-			-			-			-		0.56	%		0.59	%		-
	SPPC
	Fixed Rate			$	250,000		$	-		$	-		$	450,000		$	-	$	251,742		$	951,742		$	1,115,492
		Average Interest Rate			5.45	%		-			-			6.00	%		-		6.75	%		6.05	%		-
	Variable Rate			$	-		$	-		$	-		$	-		$	-	$	214,675		$	214,675		$	184,895
		Average Interest Rate			-			-			-			-			-		0.56	%		0.56	%		-
			TOTAL DEBT	$	348,100		$	320,000		$	250,000		$	660,000		$	-	$	3,402,092		$	4,980,192		$	5,920,286

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Commodity Price Risk

See the 2012 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk.  No material changes in commodity risk have occurred since December 31, 2012.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties.  Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition.  The Utilities’ credit risk associated with trading counterparties was approximately $98.6 million as of March 31, 2013, which compares to balances of $77.5 million at December 31, 2012. The increase from December 31, 2012 is primarily due to the increase in forward prices of power and natural gas during the first quarter of 2013.

ITEM 4.CONTROLS AND PROCEDURES 

(a)Evaluation of disclosure controls and procedures. 

NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of March 31, 2013, the registrants’ disclosure controls and procedures were effective.

(b)Change in internal controls over financial reporting.

There were no changes in the registrants’ internal controls over financial reporting in the first quarter of 2013 that have materially affected, or are reasonably likely to materially affect, the registrants’ internal controls over financial reporting.

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PART II  -  OTHER INFORMATION

ITEM 1.                      LEGAL PROCEEDINGS

Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had, or in the opinion of management, is expected to have a significant impact on their financial positions or results of operations.  See Note 7, Commitments and Contingencies, of the Condensed Notes to Financial Statements for further discussion of other legal matters.

ITEM 1A.RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC).  The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2012 Form 10-K.  The risks and uncertainties described below are not the only ones we face.  Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2012 Form 10-K.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

The following table contains information about NVE’s purchases of common stock for the quarter ended March 31, 2013:

					Total Number of Shares	Maximum Number of
					Purchased as Part of	Shares that may yet be
		Total Number of	Average Price		Publicly Announced	Purchased Under the
Period		Shares Purchased (1)	Paid Per Share		Plans or Programs	Plans or Programs
January 1 - January 31, 2013		197,178	$	18.49	N/A	N/A
February 1 - February 28, 2013		-		-	N/A	N/A
March 1 - March 31, 2013		-		-	N/A	N/A
	Total	197,178	$	18.49	-	-
(1)	Represents shares of common stock purchased on the open market to provide shares to participants under various NVE stock compensation plans. These purchases were not made pursuant to a publicly announced stock repurchase plan or program.

ITEM 3.DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.OTHER INFORMATION

None. 

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ITEM 6.EXHIBITS

(a)Exhibits filed with this Form 10-Q:

(10)    NV Energy, Inc.:

10.1 Form of Performance Shares Agreement for 2013 Awards.

10.2 Form of Restricted Stock Unit Agreement for 2013 Awards.

(12)    NV Energy, Inc.:

12.1 Statement regarding computation of Ratios of Earnings to Fixed Charges.

          Nevada Power Company:

12.2 Statement regarding computation of Ratios of Earnings to Fixed Charges.

          Sierra Pacific Power Company:

12.3 Statement regarding computation of Ratios of Earnings to Fixed Charges.

(31)    NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

31.1	Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3	Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4	Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.5	Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.6	Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 (32)    NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

32.1	Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.3	Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.4	Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.5	Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.6	Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(101)    NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Schema
101.CAL	XBRL Calculation Linkbase
101.LAB	XBRL Label Linkbase
101.PRE	XBRL Presentation Linkbase
101.DEF	XBRL Definition Linkbase

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

	NV Energy, Inc.
	(Registrant)
Date:May 8, 2013	By:	/s/ Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)
Date:  May 8, 2013	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)
	Nevada Power Company d/b/a NV Energy
	(Registrant)
Date:  May 8, 2013	By:	/s/ Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)
Date:  May 8, 2013	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)
	Sierra Pacific Power Company d/b/a NV Energy
	(Registrant)
Date:  May 8, 2013	By:	/s/ Jonathan S. Halkyard
		Jonathan S. Halkyard
		Chief Financial Officer
		(Principal Financial Officer)
Date: May 8, 2013	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

57