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, 2012

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, 2012
Common Stock, $1.00 par value of NV Energy, Inc.	235,999,750 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, 2012

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, 2012 and 2011	5
		Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	6
		Consolidated Statements of Cash Flows -  Three Months Ended March 31, 2012 and 2011	8
		Consolidated Statements of Shareholders’ Equity - Three Months Ended March 31, 2012 and 2011	9
	Nevada Power Company
		Consolidated Statements of Comprehensive Loss   – Three  Months Ended March 31, 2012 and 2011	10
		Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	11
		Consolidated Statements of Cash Flows -  Three Months Ended March 31, 2012  and 2011	13
		Consolidated Statements of Shareholder’s Equity - Three Months Ended March 31, 2012 and 2011	14
	Sierra Pacific Power Company
		Consolidated Statements of Comprehensive Income   – Three Months Ended March 31, 2012 and 2011	15
		Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	16
		Consolidated Statements of Cash Flows - Three Months Ended March 31, 2012 and 2011	18
		Consolidated Statements of Shareholder’s Equity - Three Months Ended March 31, 2012 and 2011	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	23
		Note 5.     Fair Value of Financial Instruments	25
		Note 6.     Retirement Plan and Post-Retirement Benefits	26
		Note 7.     Commitments and Contingencies	27
		Note 8.     Earnings per Share (NVE)	29
		Note 9.    Dividends	29
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
	NV Energy, Inc.		36
	Nevada Power Company		40
	Sierra Pacific Power Company		48
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		57
ITEM 4.	Controls and Procedures		58
PART II – OTHER INFORMATION
ITEM 1.	Legal Proceedings		58
ITEM 1A.	Risk Factors		58
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		58
ITEM 3.	Defaults Upon Senior Securities		58
ITEM 4.	Mine Safety Disclosures		58
ITEM 5.	Other Information		58
ITEM 6.	Exhibits		59
Signature Page and Certifications			61

2

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)
Acronym/Term	Meaning
2011 Form 10-K	NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2011
AFUDC-debt	Allowance for Borrowed Funds Used During Construction
AFUDC-equity	Allowance for Equity Funds Used During Construction
BOD	Board of Directors
BTER	Base Tariff Energy Rate
BTGR	Base Tariff General Rate
CAISO	California Independent System Operator Corporation
California Assets	SPPC's California electric distribution and generation assets
CWIP	Construction Work-in-Progress
dba	Doing business as
DEAA	Deferred Energy Accounting Adjustment
DSM	Demand Side Management
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.
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	142 megawatt nominally rated Harry Allen Generating Station, expanded in 2011 to 642 total MWs
Higgins Generating Station	598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP	Integrated Resource Plan
kV	Kilovolt
Lenzie Generating Station	1,102 megawatt nominally rated Chuck Lenzie Generating Station
LIBOR	London Interbank Offered Rate
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’s 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
PEC	Portfolio Energy Credit
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
ROE	Return on Equity
ROR	Rate of Return
S&P	Standard & Poor’s
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’s 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

3

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,
			2012		2011
	OPERATING REVENUES		$	611,420	$	640,983
	OPERATING EXPENSES:
		Fuel for power generation		117,035		146,338
		Purchased power		117,116		135,016
		Gas purchased for resale		31,617		52,632
		Deferred energy		(11,739)		(1,952)
		Energy efficiency program costs		19,425		-
		Other operating expenses		103,601		105,974
		Maintenance		32,526		29,762
		Depreciation and amortization		90,862		83,102
		Taxes other than income		14,509		16,245
	Total Operating Expenses			514,952		567,117
	OPERATING INCOME			96,468		73,866
	OTHER INCOME (EXPENSE):
		Interest expense
		(net of AFUDC-debt: $1,595 and $6,210)		(77,931)		(77,343)
		Interest income (expense) on regulatory items		(2,202)		(888)
		AFUDC-equity		1,932		7,642
		Other income		4,194		2,984
		Other expense		(3,060)		(4,656)
	Total Other Income (Expense)			(77,067)		(72,261)
	Income Before Income Tax Expense			19,401		1,605
	Income tax expense (benefit)			7,228		(725)
	NET INCOME			12,173		2,330
	Other comprehensive income (loss):
	Change in compensation retirement benefits liability and amortization
	(Net of taxes $(89) and $(615))			155		1,142
	Change in market value of risk management assets and liabilities
	(Net of taxes $141 in 2012)			(246)		-
	OTHER COMPREHENSIVE INCOME (LOSS)			(91)		1,142
	COMPREHENSIVE INCOME		$	12,082	$	3,472
	Amount per share basic and diluted - (Note 8)
		Net income per share - basic and diluted	$	0.05	$	0.01
	Weighted Average Shares of Common Stock Outstanding - basic			235,999,750		235,526,425
	Weighted Average Shares of Common Stock Outstanding - diluted			237,526,863		236,784,658
	Dividends Declared Per Share of Common Stock		$	0.13	$	0.12
	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,
			2012		2011
ASSETS
Current Assets:
	Cash and cash equivalents		$	100,335	$	145,944
	Accounts receivable less allowance for uncollectible accounts:
		2012 - $6,453; 2011 - $8,150		325,388		355,091
	Materials, supplies and fuel, at average cost			130,628		129,663
	Current income taxes receivable			82		82
	Deferred income taxes			117,079		104,958
	Other current assets			49,802		36,782
Total Current Assets				723,314		772,520
Utility Property:
	Plant in service			11,955,428		11,923,717
	Construction work-in-progress			556,170		487,427
	Total			12,511,598		12,411,144
Less accumulated provision for depreciation				3,240,688		3,184,071
	Total Utility Property, Net			9,270,910		9,227,073
Investments and other property, net				59,273		57,021
Deferred Charges and Other Assets:
	Deferred energy (Note 3)			99,566		102,525
	Regulatory assets			1,174,069		1,186,127
	Regulatory asset for pension plans			212,259		215,656
	Other deferred charges and assets			88,020		74,206
Total Deferred Charges and Other Assets				1,573,914		1,578,514
TOTAL ASSETS			$	11,627,411	$	11,635,128
		(Continued)

6

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
		March 31,		December 31,
LIABILITIES AND SHAREHOLDERS' EQUITY		2012		2011
Current Liabilities:
	Current maturities of long-term debt (Note 4)	$	138,048	$	139,985
	Accounts payable		270,828		312,990
	Accrued expenses		97,816		128,144
	Deferred energy (Note 3)		233,071		245,164
	Other current liabilities		68,489		65,572
Total Current Liabilities			808,252		891,855
Long-term debt (Note 4)			5,035,066		5,008,931
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
	Deferred income taxes		1,311,996		1,306,510
	Deferred investment tax credit		15,500		16,140
	Accrued retirement benefits		94,572		92,351
	Regulatory liabilities		503,911		486,259
	Other deferred credits and liabilities		470,633		427,003
Total Deferred Credits and Other Liabilities			2,396,612		2,328,263
Shareholders' Equity:
	Common stock, $1.00 par value; 350 million shares authorized
	235,999,750 issued and outstanding for 2012 and 2011		236,000		236,000
	Other paid-in capital		2,713,736		2,713,736
	Retained earnings		445,770		464,277
	Accumulated other comprehensive loss		(8,025)		(7,934)
Total Shareholders' Equity			3,387,481		3,406,079
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	11,627,411	$	11,635,128
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,
			2012		2011
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	12,173	$	2,330
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		90,862		83,102
		Deferred taxes and deferred investment tax credit		(5,183)		(414)
		AFUDC-equity		(1,932)		(7,642)
		Deferred energy		(9,134)		3,118
		Amortization of other regulatory assets		39,028		38,839
		Deferred rate increase		2,691		15,334
		Other, net		1,575		3,269
	Changes in certain assets and liabilities:
		Accounts receivable		31,208		38,185
		Materials, supplies and fuel		(874)		(8,639)
		Other current assets		(13,021)		(5,653)
		Accounts payable		(37,825)		(23,364)
		Accrued retirement benefits		2,221		3,521
		Other current liabilities		(29,348)		(34,708)
		Other deferred assets		(1,602)		(511)
		Other regulatory assets		4,164		(18,608)
		Other deferred liabilities		(17,687)		(2,636)
Net Cash from Operating Activities				67,316		85,523
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(115,817)		(144,097)
		Proceeds from sale of asset		-		131,789
		Customer advances for construction		(184)		(672)
		Contributions in aid of construction		26,052		20,178
		Investments and other property - net		48		286
Net Cash from (used by) Investing Activities				(89,901)		7,484
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		10,951		-
		Retirement of long-term debt		(3,295)		(18,481)
		Sale of Common Stock		-		5,353
		Dividends paid		(30,680)		(28,276)
Net Cash used by Financing Activities				(23,024)		(41,404)
Net Increase (Decrease) in Cash and Cash Equivalents				(45,609)		51,603
Beginning Balance in Cash and Cash Equivalents				145,944		86,189
Ending Balance in Cash and Cash Equivalents			$	100,335	$	137,792
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	88,606	$	92,323
		Income taxes	$	-	$	1
	Significant non-cash transactions:
		Accrued construction expenses as of March 31,	$	85,850	$	77,033
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		Other				Other		Total
		Stock	Stock		Paid-in		Retained		Comprehensive		Shareholders'
		Shares	Amount		Capital		Earnings		Income (Loss)		Equity
December 31, 2010		235,322,553	$	235,323	$	2,705,954	$	416,432	$	(6,891)	$	3,350,818
	Net Income	-		-		-		2,330		-		2,330
	Dividend Reinvestment and Employee Benefits	450,852		450		4,591		-		-		5,041
	Tax benefit from stock options exercised	-		-		312		-		-		312
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(615))	-		-		-		-		1,142		1,142
	Dividends Declared	-		-		-		(28,276)		-		(28,276)
March 31, 2011		235,773,405	$	235,773	$	2,710,857	$	390,486	$	(5,749)	$	3,331,367
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
The accompanying notes are an integral part of the financial statements.

9

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(Dollars in Thousands)
(Unaudited)
		Three Months Ended
		March 31,
		2012		2011
OPERATING REVENUES		$	395,688	$	390,068
OPERATING EXPENSES:
	Fuel for power generation		80,549		101,070
	Purchased power		81,531		95,566
	Deferred energy		2,171		6,730
	Energy efficiency program costs		15,774		-
	Other operating expenses		66,462		65,101
	Maintenance		23,073		22,337
	Depreciation and amortization		64,990		57,673
	Taxes other than income		8,454		10,058
Total Operating Expenses			343,004		358,535
OPERATING INCOME			52,684		31,533
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $1,179 and $5,790)		(54,405)		(52,033)
	Interest income (expense) on regulatory items		(2,016)		635
	AFUDC-equity		1,413		7,098
	Other income		1,709		1,546
	Other expense		(1,346)		(2,732)
Total Other Expense			(54,645)		(45,486)
Loss Before Income Tax Expense			(1,961)		(13,953)
Income tax benefit			(645)		(4,933)
NET LOSS			(1,316)		(9,020)
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization
(Net of taxes $(32) and $(405))			63		753
COMPREHENSIVE LOSS		$	(1,253)	$	(8,267)
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,
			2012		2011
ASSETS
Current Assets:
	Cash and cash equivalents		$	38,710	$	65,887
	Accounts receivable less allowance for uncollectible accounts:
		2012 - $4,981; 2011 - $6,751		210,654		233,096
	Materials, supplies and fuel, at average cost			74,829		72,529
	Deferred income taxes			101,492		88,782
	Other current assets			37,617		28,943
Total Current Assets				463,302		489,237
Utility Property:
	Plant in service			8,355,133		8,345,771
	Construction work-in-progress			410,417		352,541
		Total		8,765,550		8,698,312
	Less accumulated provision for depreciation			1,950,742		1,906,617
		Total Utility Property, Net		6,814,808		6,791,695
Investments and other property, net				52,595		50,768
Deferred Charges and Other Assets:
	Deferred energy (Note 3)			99,566		102,525
	Regulatory assets			851,458		852,989
	Regulatory asset for pension plans			106,877		108,528
	Other deferred charges and assets			61,834		46,855
Total Deferred Charges and Other Assets				1,119,735		1,110,897
TOTAL ASSETS			$	8,450,440	$	8,442,597
(Continued)

11

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
		March 31,		December 31,
		2012		2011
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 4)	$	137,929	$	139,985
	Accounts payable		161,525		182,183
	Accounts payable, affiliated companies		35,511		28,429
	Accrued expenses		60,796		89,311
	Deferred energy (Note 3)		160,890		159,799
	Other current liabilities		54,744		50,725
Total Current Liabilities			611,395		650,432
Long-term debt (Note 4)			3,346,026		3,319,605
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
	Deferred income taxes		1,003,426		997,921
	Deferred investment tax credit		5,743		6,098
	Accrued retirement benefits		11,027		9,454
	Regulatory liabilities		287,747		274,951
	Other deferred credits and liabilities		376,352		335,159
Total Deferred Credits and Other Liabilities			1,684,295		1,623,583
Shareholder's Equity:
	Common stock, $1.00 par value; 1,000 shares authorized
	issued and outstanding for 2012 and 2011		1		1
	Other paid-in capital		2,308,219		2,308,219
	Retained earnings		504,558		544,874
	Accumulated other comprehensive loss		(4,054)		(4,117)
Total Shareholder's Equity			2,808,724		2,848,977
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	8,450,440	$	8,442,597
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,
			2012		2011
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Loss		$	(1,316)	$	(9,020)
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		64,990		57,673
		Deferred taxes and deferred investment tax credit		(6,349)		(4,725)
		AFUDC-equity		(1,413)		(7,098)
		Deferred energy		4,050		9,980
		Amortization of other regulatory assets		18,301		18,870
		Deferred rate increase		2,691		15,334
		Other, net		(796)		2,288
Changes in certain assets and liabilities:
		Accounts receivable		22,441		35,397
		Materials, supplies and fuel		(2,209)		(2,971)
		Other current assets		(8,674)		(6,075)
		Accounts payable		(14,248)		(15,946)
		Accrued retirement benefits		1,572		1,313
		Other current liabilities		(27,419)		(25,513)
		Other deferred assets		(1,288)		(781)
		Other regulatory assets		9,880		(12,328)
		Other deferred liabilities		(7,495)		(1,911)
Net Cash from Operating Activities				52,718		54,487
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(66,843)		(120,455)
		Customer advances for construction		654		(211)
		Contributions in aid of construction		15,951		16,479
		Investments and other property - net		40		278
Net Cash used by Investing Activities				(50,198)		(103,909)
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		12,432		-
		Retirement of long-term debt		(3,129)		(3,007)
		Additional investment by parent company		-		54,000
		Dividends paid		(39,000)		-
Net Cash from (used by) Financing Activities				(29,697)		50,993
Net Increase (Decrease)  in Cash and Cash Equivalents				(27,177)		1,571
Beginning Balance in Cash and Cash Equivalents				65,887		60,077
Ending Balance in Cash and Cash Equivalents			$	38,710	$	61,648
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	71,276	$	69,936
		Income taxes	$	-	$	1
	Significant non-cash transactions:
		Accrued construction expenses as of March 31,	$	72,179	$	66,894
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, 2010		1,000	$	1	$	2,254,219	$	511,288	$	(3,876)	$	2,761,632
	Net Loss	-		-		-		(9,020)		-		(9,020)
	Capital contribution from parent	-		-		54,000		-		-		54,000
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(405))	-		-		-		-		753		753
March 31, 2011		1,000	$	1	$	2,308,219	$	502,268	$	(3,123)	$	2,807,365
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
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,
		2012		2011
OPERATING REVENUES:
	Electric	$	169,806	$	178,617
	Gas		45,922		72,294
Total Operating Revenues			215,728		250,911
OPERATING EXPENSES:
	Fuel for power generation		36,486		45,268
	Purchased power		35,585		39,450
	Gas purchased for resale		31,617		52,632
	Deferral of energy - electric - net		(12,670)		(11,931)
	Deferral of energy - gas - net		(1,240)		3,249
	Energy efficiency program costs		3,651		-
	Other operating expenses		36,432		40,216
	Maintenance		9,453		7,425
	Depreciation and amortization		25,872		25,429
	Taxes other than income		5,863		6,024
Total Operating Expenses			171,049		207,762
OPERATING INCOME			44,679		43,149
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $416 and $420)		(16,973)		(16,946)
	Interest income (expense) on regulatory items		(186)		(1,523)
	AFUDC-equity		519		544
	Other income		2,183		1,264
	Other expense		(1,335)		(1,594)
Total Other Income (Expense)			(15,792)		(18,255)
Income Before Income Tax Expense			28,887		24,894
Income tax expense			10,243		8,318
NET INCOME			18,644		16,576
Other comprehensive income:
Change in compensation retirement benefits liability and amortization
(Net of taxes $(23) and $(841))			42		1,561
COMPREHENSIVE INCOME		$	18,686	$	18,137
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,
			2012		2011
ASSETS
Current Assets:
	Cash and cash equivalents		$	23,852	$	55,195
	Accounts receivable less allowance for uncollectible accounts:
	2012 - $1,472; 2011 - $1,399			114,499		121,863
	Materials, supplies and fuel, at average cost			55,799		57,134
	Intercompany income taxes receivable			10,351		10,351
	Deferred income taxes			26,362		32,311
	Other current assets			12,069		7,504
Total Current Assets				242,932		284,358
Utility Property:
	Plant in service			3,600,295		3,577,946
	Construction work-in-progress			145,753		134,886
		Total		3,746,048		3,712,832
	Less accumulated provision for depreciation			1,289,946		1,277,454
		Total Utility Property, Net		2,456,102		2,435,378
Investments and other property, net				6,326		5,901
Deferred Charges and Other Assets:
	Regulatory assets			322,611		333,138
	Regulatory asset for pension plans			102,497		104,159
	Other deferred charges and assets			19,890		21,074
Total Deferred Charges and Other Assets				444,998		458,371
TOTAL ASSETS			$	3,150,358	$	3,184,008
(Continued)

16

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
		March 31,		December 31,
		2012		2011
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt (Note 4)	$	120	$	-
	Accounts payable		86,494		99,897
	Accounts payable, affiliated companies		18,506		27,788
	Accrued expenses		27,566		32,840
	Deferred energy (Note 3)		72,181		85,365
	Other current liabilities		13,744		14,846
Total Current Liabilities			218,611		260,736
Long-term debt (Note 4)			1,179,041		1,179,326
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
	Deferred income taxes		395,885		398,787
	Deferred investment tax credit		9,757		10,042
	Accrued retirement benefits		74,664		74,297
	Regulatory liabilities		216,164		211,308
	Other deferred credits and liabilities		83,008		74,970
Total Deferred Credits and Other Liabilities			779,478		769,404
Total Shareholder's Equity
	Common stock, $3.75 par value; 20,000,000 shares authorized
	1,000 shares issued and outstanding for 2012 and 2011		4		4
	Other paid-in capital		1,111,262		1,111,262
	Retained deficit		(136,696)		(135,340)
	Accumulated other comprehensive loss		(1,342)		(1,384)
Total Shareholder's Equity			973,228		974,542
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	3,150,358	$	3,184,008
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,
			2012		2011
CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES:
	Net Income		$	18,644	$	16,576
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		25,872		25,429
		Deferred taxes and deferred investment tax credit		3,537		8,109
		AFUDC-equity		(519)		(544)
		Deferred energy		(13,184)		(6,862)
		Amortization of other regulatory assets		20,668		19,944
		Other, net		2,249		1,136
	Changes in certain assets and liabilities:
		Accounts receivable		8,869		2,837
		Materials, supplies and fuel		1,335		(5,668)
		Other current assets		(4,564)		(479)
		Accounts payable		(17,675)		4,835
		Accrued retirement benefits		367		1,703
		Other current liabilities		(5,388)		(8,667)
		Other deferred assets		(314)		270
		Other regulatory assets		(5,716)		(6,280)
		Other deferred liabilities		(4,214)		(104)
Net Cash from Operating Activities				29,967		52,235
CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(48,974)		(23,642)
		Proceeds from sale of asset		-		131,789
		Customer advances for construction		(838)		(461)
		Contributions in aid of construction		10,101		3,699
		Investments and other property - net		8		8
Net Cash from (used by) Investing Activities				(39,703)		111,393
CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt, net of costs		(1,441)		-
		Retirement of long-term debt		(166)		(15,390)
		Dividends paid		(20,000)		(92,000)
Net Cash used by Financing Activities				(21,607)		(107,390)
Net Increase (Decrease) in Cash and Cash Equivalents				(31,343)		56,238
Beginning Balance in Cash and Cash Equivalents				55,195		9,552
Ending Balance in Cash and Cash Equivalents			$	23,852	$	65,790
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	15,944	$	15,925
	Significant non-cash transactions:
		Accrued construction expenses as of March 31,	$	13,671	$	10,139
The accompanying notes are an integral part of the financial statements.

18

SIERRA PACIFIC 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		Deficit		Income (Loss)		Equity
December 31, 2010		1,000	$	4	$	1,111,262	$	(135,226)	$	(2,620)	$	973,420
	Net Income	-		-		-		16,576		-		16,576
	Tax benefit from stock options exercised	-		-		312		-		-		312
	Change in compensation retirement benefits liability
	and amortization (net of taxes $(841))	-		-		-		-		1,561		1,561
	Dividends Declared	-		-		-		(38,000)		-		(38,000)
March 31, 2011		1,000	$	4	$	1,111,574	$	(156,650)	$	(1,059)	$	953,869
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
The accompanying notes are an integral part of the financial statements.

19

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.        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 2011 Form 10-K.

                The results of operations and cash flows of NVE, NPC and SPPC for the three months ended March 31, 2012, are not necessarily indicative of the results to be expected for the full year.

Reclassifications

                Certain financial statement line items for prior periods have been reclassified to conform with current year presentation.  The reclassifications have not affected previously reported reports of operations, statements of financial position or shareholders’ equity. 

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, 2012, 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.

      Derivatives and Hedging Activities

NVE, NPC and SPPC apply the accounting guidance as required by the Derivatives and Hedging Topic of the FASC.  The accounting guidance for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measurethose instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge.  The accounting guidance for derivative instruments also provides a scope exception for commodity contracts that meet the normal purchases and normal sales criteria specified in the standard.  The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business.  Contracts that are designated as normal purchases and normal sales are accounted for under deferred energy accounting and not recorded on the consolidated balance sheets of NVE and the Utilities at fair value. As a result of the suspension of the Utilities’ hedging program, derivative transactions were immaterial for the period ended March 31, 2012.

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.  Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (See Note 3, Regulatory Actions, of the Notes to Financial Statements in 2011 Form 10-K). Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense.  The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

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, 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		$	96,468	$	(895)	$	52,684	$	44,679

Three Months Ended
March 31, 2011			NVE
		Consolidated		NVE Other		NPC Electric		SPPC Total		SPPC Electric		SPPC Gas
Operating Revenues		$	640,983	$	4	$	390,068	$	250,911	$	178,617	$	72,294
Energy Costs:
	Fuel for power generation		146,338		-		101,070		45,268		45,268		-
	Purchased power		135,016		-		95,566		39,450		39,450		-
	Gas purchased for resale		52,632		-				52,632		-		52,632
	Deferred energy		(1,952)		-		6,730		(8,682)		(11,931)		3,249
Energy efficiency program costs			-		-		-		-		-		-
Total Costs		$	332,034	$	-	$	203,366	$	128,668	$	72,787	$	55,881
Gross Margin		$	308,949	$	4	$	186,702	$	122,243	$	105,830	$	16,413
Other operating expenses			105,974		657		65,101		40,216
Maintenance			29,762		-		22,337		7,425
Depreciation and amortization			83,102		-		57,673		25,429
Taxes other than income			16,245		163		10,058		6,024
OPERATING INCOME		$	73,866	$	(816)	$	31,533	$	43,149

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 2011 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, 2012 (dollars in thousands):

		March 31, 2012
		NVE Total		NPC Electric		SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance as of December 31, 2011	$	(260,079)	$	(174,714)	$	(56,337)	$	(29,028)
	2012 Amortization		77,059		38,126		25,498		13,435
	2012 Deferred Energy Over Collections (1)		(64,975)		(39,226)		(13,213)		(12,536)
Deferred Energy Balance at March 31, 2012 - Subtotal		$	(247,995)	$	(175,814)	$	(44,052)	$	(28,129)
Reinstatement of deferred energy (effective 6/07, 10 years)			114,490		114,490		-		-
	Total Deferred Energy	$	(133,505)	$	(61,324)	$	(44,052)	$	(28,129)
Deferred Assets
	Deferred energy	$	99,566	$	99,566	$	-	$	-
Current Liabilities
	Deferred energy		(233,071)		(160,890)		(44,052)		(28,129)
	Total Deferred Energy	$	(133,505)	$	(61,324)	$	(44,052)	$	(28,129)

⁽¹⁾ These deferred energy over collections are subject to quarterly rate resets as discussed in Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K.

Pending Regulatory Actions

 Nevada Power Company

         NPC 2012 DEAA, TRED and REPR, Rate Filings

In March 2012, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ending December 31, 2011, to reset the TRED and REPR rate elements and to retire the unamortized balance of NPC’s 2008 GRC deferred rate increase, as discussed in Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K.  The recoveries requested in this filing result in an overall increase in revenue requirement of approximately $30.1 million.  The March 2012 application includes the following (dollars in millions): 

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	2008 GRC Deferred Rate Increase(1)		Oct. 2012	$	13.1	$	-	$	13.1
	REPR		Oct. 2012		28.2		8.5		19.7
	TRED		Oct. 2012		15.3		18.0		(2.7)
		Total Revenue Requirement		$	56.6	$	26.5	$	30.1

⁽¹⁾ This rate request represents revenues previously recorded as a result of NPC’s 2008 GRC.  As such, NPC will not record further revenue related to this rate request, but does expect to collect such amounts from its customers.  Reference Note 3, Regulatory Actions, NPC 2008 GRC, of the Notes to Financial Statements in the 2011 Form 10-K.

          NPC 2012 EEIR, EEPR Rate Filings

Subsequent to filing NPC’s DEAA, TRED, and REPR rate filings in March 2012, the PUCN issued a final order in NPC’s Annual Demand Side Management Update Report, requiring NPC to revise all lighting-specific calculations used in the EEIR and EEPR rate applications.  As a result, in a pre-hearing conference on April 10, 2012, the parties agreed to bifurcate the EEIR and EEPR portions of the March filing to allow NPC to amend in July 2012 the EEIR and EEPR rate requests using revised lighting-specific calculations and to hold a separate hearing on these components.  It is anticipated upon final hearing and approval of the amendments  by the PUCN, rates for the EEIR and EEPR components would become effective January 2013. 

22

          NPC Petition for Declaratory Order and Accounting Guidance- Telecommunication Tower Sale

In March 2012, NPC filed a petition with the PUCN to obtain a declaratory order and the accounting guidance necessary to establish a regulatory account for the gain on sale of NPC’s telecommunication towers to Global Tower Partners, LLC in August 2011 as discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements of the 2011 Form 10-K. NPC seeks authorization to apportion approximately $14 million of the $32 million gain on sale to ratepayers with amortization of the gain to coincide with the rate effective date of NPC’s next GRC, which is mandated in 2015.

 Sierra Pacific Power Company

        SPPC 2012 Electric DEAA, TRED and REPR Rate Filings

In March 2012, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ending December 31, 2011 and to reset the TRED and REPR rate elements.  The recoveries requested in this filing result in an overall decrease in revenue requirement of approximately $7.1 million.  The March 2012 application includes the following (dollars in millions):

			Anticipated	Requested		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	REPR		Oct. 2012	$	34.5	$	38.5	$	(4.0)
	TRED		Oct. 2012		6.1		9.2		(3.1)
		Total Revenue Requirement		$	40.6	$	47.7	$	(7.1)

          SPPC 2012 EEIR, EEPR Rate Filings

Subsequent to filing SPPC’s DEAA, TRED, and REPR rate filings in March 2012, the PUCN issued a final order in SPPC’s Annual Demand Side Management Update Report, requiring SPPC to revise all lighting-specific calculations used in the EEIR and EEPR rate applications.  As a result, in a pre-hearing conference on April 10, 2012, the parties agreed to bifurcate the EEIR and EEPR portions of the March filing to allow SPPC to amend in July 2012 the EEIR and EEPR rate requests using revised lighting-specific calculations and to hold a separate hearing on these components.  It is anticipated upon final hearing and approval of the amendments  by the PUCN, rates for the EEIR and EEPR components would become effective January 2013. 

        SPPC 2012 Nevada Gas DEAA

In March 2012, 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 ending December 31, 2011 and to reset the REPR.  The recoveries requested in this filing result in an overall increase of $0.2 million.

NOTE 4.                LONG-TERM DEBT

Maturities of Long-Term Debt

As of March 31, 2012, NPC’s, SPPC’s and NVE’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):

		NVE		NVE
			Consolidated		Holding Co.	NPC		SPPC
2012(1)		$	132,929	$	-	$	132,841	$	88
2013			256,585		-		6,517		250,068
2014			324,153		195,000		129,142		11
2015			251,579		-		251,567		12
2016			661,682		-		211,677		450,005
	Total Debt 2012-2016		1,626,928		195,000		731,744		700,184
Thereafter			3,544,214		315,000		2,762,784		466,430
	Total Debt Before Unamortized Premium (Discount)		5,171,142		510,000		3,494,528		1,166,614
Unamortized Premium (Discount) Amount			1,972		(2)		(10,573)		12,547
	Total Debt	$	5,173,114	$	509,998	$	3,483,955	$	1,179,161

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⁽¹⁾ Amounts may differ from current portion of long-term debt as reported on the consolidated balance sheet due to the timing difference of payments and the change in obligation.

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.

Nevada Power Company

$500 Million Revolving Credit Facility

In March 2012, NPC terminated its $600 million secured revolving credit facility which would have expired in April 2013 and replaced it with a $500 million revolving credit facility, maturing in March 2017 and secured by NPC’s General and Refunding Mortgage Bond, Series Z, in an aggregate principal amount of $500 million (the “NPC Credit Agreement”). The administrative agent for the NPC Credit Agreement remains Wells Fargo Bank, National Association.  NPC may use the facility for general corporate purposes and for the issuance of letters of credit. 

The rate for outstanding loans under the NPC Credit Agreement will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin.  The margin varies based upon NPC’s secured debt credit rating by S&P and Moody’s.  Currently, NPC’s applicable base rate margin is 0.50% and the LIBOR rate margin is 1.50%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The NPC Credit Agreement contains one financial maintenance covenant that requires NPC to 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. In the event that NPC did not meet the financial maintenance covenant or there is a different event of default, the NPC Credit Agreement would restrict dividends to NVE. Moreover, so long as NPC's senior secured debt remains rated investment grade by S&P and Moody's (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC's business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that NPC's senior secured debt rating were rated below investment grade by either S&P or Moody's, or investment grade by either S&P or Moody's but with a negative outlook, a representation concerning no material adverse change in NPC's business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

The NPC Credit Agreement provides for an event of default if there is a failure under NPC's other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.

Similar to the $600 million secured revolving credit facility that it replaced, the NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends.  These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements in the 2011 Form 10-K.

The NPC Credit Agreement contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the reduction in availability under the revolving credit facility to NPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of the Utilities' hedging program, there was no negative mark-to-market exposure for NPC as of May 7, 2012 that would impact borrowings.

Maturity of General and Refunding Mortgage Notes, Series I

In April 2012, NPC used $120 million from its revolving credit facility along with cash on hand to pay for the maturity of its General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million. 

Sierra Pacific Power Company

$250 Million Revolving Credit Facility

In March 2012, SPPC terminated its $250 million secured revolving credit facility which would have expired in April 2013 and replaced it with a $250 million revolving credit facility, maturing in March 2017 and secured by SPPC’s General and Refunding Mortgage Bond, Series S, in an aggregate principal amount of $250 million (the “SPPC Credit Agreement”). The administrative agent for the SPPC Credit Agreement is Wells Fargo Bank, National Association.  SPPC may use the facility for general corporate purposes and for the issuance of letters of credit. 

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The rate for outstanding loans under the SPPC Credit Agreement will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin.  The margin varies based upon SPPC’s secured debt credit rating by S&P and Moody’s.  Currently, SPPC’s applicable base rate margin is 0.50% and the LIBOR rate margin is 1.50%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The SPPC Credit Agreement contains one financial maintenance covenant that requires SPPC to 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. In the event that SPPC did not meet the financial maintenance covenant or there is a different event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC's senior secured debt remains rated investment grade by S&P and Moody's (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC's business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that SPPC's senior secured debt rating were rated below investment grade by either S&P or Moody's, or investment grade by either S&P or Moody's but with a negative outlook, a representation concerning no material adverse change in SPPC's business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC's other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.

Similar to the $250 million secured revolving credit facility that it replaced, the SPPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends.  These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements in the 2011 Form 10-K.

The SPPC Credit Agreement contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the reduction in availability under the revolving credit facility to SPPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of the Utilities' hedging program, there was no negative mark-to-market exposure for SPPC as of May 7, 2012 that would impact borrowings.

NOTE 5.                FAIR VALUE OF FINANCIAL INSTRUMENTS

The March 31, 2012 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 2011 Form 10-K, investments held in Rabbi Trust and cash surrender value of life insurance policies continue to be considered Level 1 and Level 2, respectively, in the fair value hierarchy.

The total fair value of NVE’s consolidated long-term debt at March 31, 2012, 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 $6.0 billion as of December 31, 2011.

The total fair value of NPC’s consolidated long-term debt at March 31, 2012, is estimated to be $4.1 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, 2011.

The total fair value of SPPC’s consolidated long-term debt at March 31, 2012, 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, 2011.

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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,
		2012		2011		2012		2011
Service cost	$	4,406	$	4,607	$	595	$	653
Interest cost		10,228		10,169		1,905		2,090
Expected return on plan assets		(12,447)		(12,192)		(1,563)		(1,596)
Amortization of prior service cost		(724)		(738)		(987)		(987)
Amortization of net loss		3,473		4,155		731		1,083
Net periodic benefit cost	$	4,936	$	6,001	$	681	$	1,243
The average percentage of NVE net periodic costs capitalized during 2012 and 2011 was 33.2% and 32.2%, respectively.

NPC
	Pension Benefits				Other Postretirement Benefits
		For the Three Months Ended March 31,				For the Three Months Ended March 31,
		2012		2011		2012		2011
Service cost	$	2,358	$	2,445	$	350	$	363
Interest cost		4,881		4,880		602		615
Expected return on plan assets		(6,237)		(6,169)		(592)		(590)
Amortization of prior service cost		(456)		(470)		229		229
Amortization of net loss		1,363		1,690		221		302
Net periodic benefit cost	$	1,909	$	2,376	$	810	$	919
The average percentage of NPC net periodic costs capitalized during 2012 and 2011 was 35.6% and 37.2%, respectively.

SPPC
	Pension Benefits				Other Postretirement Benefits
	For the Three Months Ended March 31,				For the Three Months Ended March 31,
	2012		2011		2012		2011
Service cost	$	1,695	$	1,840	$	227	$	271
Interest cost		5,043		5,013		1,283		1,457
Expected return on plan assets		(5,937)		(5,741)		(941)		(976)
Amortization of prior service cost		(277)		(277)		(1,220)		(1,219)
Amortization of net loss		2,026		2,412		504		773
Net periodic benefit cost	$	2,550	$	3,247	$	(147)	$	306
The average percentage of SPPC net periodic costs capitalized during 2012 and 2011 was 33% and 29.3%, respectively.

During the three months ended March 31, the company made no contributions to the pension plan and $0.9 million in contributions to the other postretirement benefits plan.  At the present time, it is not anticipated that additional funding will be required for either plan in 2012 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 2012 assumptions funding levels similar to the 2011 funding.  The amounts to be contributed in 2012 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 $5 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 including reclamation and sale.

      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 California Department of Water Resources.  The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant.  Responses were provided back to the EPA in February 2012.  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.  SPPC cannot predict the impact, if any, associated with this information request.

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.  NVE and the Utilities continue to comply with these environmental commitments.  As of March 31, 2012, environmental expenditures did not change materially from those disclosed in the 2011 Form 10-K.

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 is 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 October 2004, the Navajo Generating Station’s coal supplier, Peabody Western Coal Company (Peabody WC), filed a complaint against the Navajo Joint Owners in Missouri State Court in St. Louis, alleging, among other things, a declaration that the Navajo Joint Owners are obligated to reimburse Peabody WC for any royalty, tax or other obligations arising out of a lawsuit that the Navajo Nation filed against Salt River, several Peabody Coal Company entities (including Peabody WC and collectively referred to as “Peabody”) and SCE in June 1999 in the U.S. District Court for the District of Columbia (DC Lawsuit).

The Navajo Joint Owners were first served in the Missouri lawsuit in January 2005. The operating agent for the Navajo Generating Station, Salt River, defended the suit on behalf of the Navajo Joint Owners. In July 2008, the Court dismissed all counts

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against NPC, two without prejudice to their possible refiling at a later date. NPC is unable to predict whether any liability may arise from any of these matters, including from the ultimate outcome of the DC Lawsuit.

NPC is 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 consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo Generating Station and the Mohave Generating Station by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. Initially, the DC Lawsuit sought $600 million in damages, treble damages and punitive damages of not less than $1.0 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River. In April 2010, the Navajo Nation amended their complaint; it no longer seeks treble damages. Factual discovery was completed in October 2010, after which the parties engaged in settlement discussions. In April 2011, SCE indicated that it reached a settlement in the DC Lawsuit in principle. On August 1, 2011, the Navajo Nation, Peabody, Salt River and SCE executed a written settlement agreement in return for dismissal of all claims by the Navajo Nation. Salt River has asked that the Navajo Joint Owners, including NPC, contribute towards the settlement based on its 11% ownership stake in the Navajo Generating Station. NPC has paid Salt River the requested contribution, which did not have a material impact on the financial statements. SCE has asked that the Mohave Joint Owners, including NPC, contribute towards the settlement based upon their ownership stake in the Mohave Generating Station. NPC has not agreed to pay SCE the requested contribution. Management is currently negotiating a settlement with SCE, but does not believe the impact of such settlement will be material to NPC at this time.

     SPPC

        Farad Dam

SPPC sold four hydro generating units (10.3 MW total capacity), located in Nevada and California, for $8 million to TMWA in June 2001. The Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. 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.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company (collectively, the "Insurers") for the Farad Dam.  In 2003, SPPC initiated federal court litigation against the insurers of the failed unit, who contested the extent and amount of insurance coverage.  Coverage has been established through this litigation, but the matter remains pending before the Ninth Circuit Court of Appeals for determination of the amount of coverage which could range from approximately $1.3 million to the estimated cost to rebuild the diversion dam, which is estimated to be in excess of $20 million. The Ninth Circuit is expected to make a decision in 2012, which may be followed by further proceedings. Management cannot assess or predict the outcome or the impact of the court decisions at this time, but they are not expected to be material to SPPC as a whole.

   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 Generating Station on the NPC system.  NVE does not anticipate that ON Line will be placed in service until the latter part of 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 construction costs, including cost overruns; therefore, 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, 2012, NVE has

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capitalized construction costs associated with GBT’s 75% interest of approximately $199.2 million, or $184.0 and $15.2 million at NPC and SPPC, respectively, in CWIP with a corresponding credit to other deferred liabilities. 

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,
				2012		2011
	Basic EPS
		Numerator ($000)
			Net Income	$	12,173	$	2,330
		Denominator
			Weighted average number of common shares outstanding		235,999,750		235,526,425
		Per Share Amounts
			Net Income per share - basic	$	0.05	$	0.01
	Diluted EPS
		Numerator ($000)
			Net Income	$	12,173	$	2,330
		Denominator(1)
			Weighted average number of shares outstanding before dilution		235,999,750		235,526,425
			Stock options		35,283		33,399
			Non-Employee Director stock plan		153,686		163,902
			Employee stock purchase plan		10,888		14,345
			Restricted Shares		497,750		101,240
			Performance Shares		829,506		945,347
		Diluted Weighted Average Number of Shares			237,526,863		236,784,658
		Per Share Amounts
			Net Income per share - diluted	$	0.05	$	0.01
(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 all periods.  If the conditions for conversion were met under this plan, 466,183 and 581,757 shares would be included for the three months ended March 31, 2012 and 2011, respectively.

NOTE 9.                DIVIDENDS 

Dividends

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

Declaration Date		Amount Per Share	Payable Date	Shareholders of Record Date
May 7, 2012	$	0.17	June 20, 2012	June 5, 2012

On May 7, 2012, NPC declared dividends to NVE for $40 million.

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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:

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

(2)   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;

(3)   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, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(4)   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 could have other adverse effects on our business;

(5)   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;

(6)   security breaches of our information technology or supervising 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; 

(7)   unfavorable rulings in rate or other cases filed or to be filed by the Utilities with the PUCN, 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;

(8)   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, current suspension of their hedging programs, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs)  and/or power, or a ratings downgrade;

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

(10)   whether the Utilities’ newly installed advanced metering system will integrate with other computer information systems, perform as expected, and in all other respects, meet operational, commercial and regulatory requirements;

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(11)   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;

(12)   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;

(13)   explosions, fires, accidents and mechanical breakdowns that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory 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;

(14)   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, or use alternative sources of energy, or change the conditions under which they may do so;

(15)   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 as a result of the viability of European sovereign debt 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;

(16)   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 in NVE's and the Utilities' agreements;

(17)   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;

(18)   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;

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

(20)   changes in the business of the Utilities’ major customers engaged in gold 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;

(21)   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;

(22) 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;

(23)   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;

(24)   whether, following the Great Basin Water Network, et al. v. Nevada State Engineer litigation, certain permitted water rights of the SNWA that are used to supply water to the Utilities’ power production plants and service territories could be re-opened, which could adversely impact the operations of those plants and future growth and customer usage patterns; and

(25)   unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs.

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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.

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

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.

NVE recognized net income of $12.2 million for the three months ended March 31, 2012, compared to net income of $2.3 million for the same period in 2011.   The increase is primarily due to an increase in gross margin. The increase in gross margin is primarily due to increased BTGR rates, effective January 1, 2012, as a result of NPC’s 2011 GRC.  The increase was partially offset by an increase in depreciation and a reduction in AFUDC primarily due to the completion of the Harry Allen Generating Station in May 2011, which is now included in rates.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K for further discussion of NPC’s 2011 GRC.  

The Utilities are regulated by the PUCN.  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, which necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term 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 are essential to the operating and financial performance of the Utilities. 

Future Challenges

In 2012, NVE and the Utilities must continue to balance the needs of our customers and regulatory requirements while still providing value to our shareholders.   As customer growth and demand have stabilized, the Utilities are transitioning from an emphasis on capital investment to an emphasis on optimizing our assets and resources. The Utilities believe they are entering a period of decreasing need for rate relief, more stable earnings, improving returns and sustained free cash flow.  We expect that this transition will allow NVE to build shareholder value through a combination of increasing its common stock dividend payout ratio, strengthening its capital structure and considering new investment opportunities.  As a result, on May 7, 2012, the BOD voted to increase the quarterly dividend to $0.17 per share, and approved a dividend policy which targets a dividend payout ratio of 55% to 65%.  However, this transition may be affected by certain challenges including:

• Economic conditions in Nevada;

• Executing the evolution of energy strategy; and

• Managing our regulatory environment.

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Economic Conditions

Economic conditions in Nevada are beginning to stabilize; however, leading economic indicators for Nevada and Southern Nevada suggest that improvements in economic conditions will be very slow.  Although the unemployment rate in Nevada remains above the national average, it has improved over the past year. 

Economic conditions in Nevada have significant influence on NVE’s business decisions as we consider various interrelated factors including:

• customer growth;

• customer  usage;

• load factors;

• managing operating and maintenance expenses within projected revenue without compromising safety, reliability and efficiency;

• pressure on regulators to limit necessary rate increases or otherwise lessen rate impacts upon customers;

• collections on accounts receivable; and

• future capital projects and capital requirements.

Executing the Evolution of the Energy Strategy

As discussed in their 2011 Form 10-K, NVE and the Utilities have transitioned from their three part energy strategy to the evolution of energy strategy outlined below, with less emphasis on capital investment to more emphasis on optimizing our assets and resources.

Evolution of Energy Strategy:

• Empower customers through more focused energy efficiency programs

• Pursue cost-effective renewable energy initiatives

• Optimize generation efficiency and transmission facilities

• Engage employees to improve processes, reduce costs, and enhance performance

Empower customers through more focused energy efficiency programs

                The Utilities will continue with the implementation of NV Energize which not only provides metering and customer service operating savings, but will also provide customers with better opportunities to become more energy efficient.  NVE’s traditional conservation and energy efficiency programs, which have focused on behavioral change and technology replacement, will be enhanced by the new features enabled by NV Energize.  Customers will have access to better information to help them manage their usage and select from enhanced energy efficiency options, including demand response and pricing programs.  NVE has installed approximately 800,000 Smart Meters in southern Nevada and expects to have 1.4 million installed statewide by the end of 2012.  The NV Energize capabilities will allow NVE to help customers implement the most cost-effective mix of energy efficiency and conservation options that will also qualify toward fulfillment of the Portfolio Standard.    

   Pursue cost-effective renewable energy initiatives

NVE must strive to effectively balance the need to meet the Portfolio Standard, with the changes in load forecast and the uncertainty of renewable energy project development, either for financial or resource related reasons.   In 2011, Nevada’s Portfolio Standard was 15%.  Both NPC and SPPC surpassed the minimum requirement delivering 16.7% and 24.9%, respectively.  This represented the culmination of several years of developing a portfolio of diverse renewable resources throughout Nevada.  While NVE is better positioned to meet the continued challenge based on recent renewable successes, NVE remains committed to incorporating clean, cost-effective renewable energy into its portfolio.  As part of this continued commitment, NVE will continue to seek the best and most cost effective opportunities that will benefit our state, customers and environment. Depending on its needs and continuous analysis of the existing portfolio, NVE has a number of tools available to seek renewable energy values for our customers.  These tools may include issuing requests for proposals for new renewable energy contracts, exploring opportunities to either jointly construct or develop projects using wind, geothermal and solar, undertaking additional short-term purchases from existing renewable facilities and restructuring existing renewable relationships for the benefit of our customers.

The Portfolio Standard requires a specific percentage of an electric service provider’s total retail energy sales to be obtained from renewable energy resources. Renewable resources include biomass, geothermal, solar, waterpower, wind and qualified recovered energy generation projects. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the portfolio percentage. In 2012, the Utilities are required to obtain an amount of PECs equivalent to

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15% of their total retail energy from renewables. Currently, the Portfolio Standard increases to 18% for 2013 and 2014, to 20% in 2015, after which it increases to 22% for the years 2020 through 2024, and to 25% for 2025 and beyond. Moreover, not less than 5% of the total Portfolio Standard must be satisfied from solar resources until 2016 when a minimum of 6% must be solar. 

The Utilities acquire PECs through competitively-priced purchase power contracts, investments in renewable generating facilities and DSM programs.  NVE seeks to meet the standard using the most cost-effective means for our customers and to pursue the best-value options that are available to the Utilities.  In addition to the foregoing, this may also include economical short-term purchases of PECs (usually from outside of Nevada) to fulfill projected shortfalls due to the attrition or timing of development of renewable energy projects, weather variability or other supplier issues.

   Optimize generation efficiency and transmission facilities

Since 2006, when NVE began its energy independence initiative, we have added over 3,800 MWs (nominally rated) of internal generation and, with the completion of Harry Allen Generating Station, NVE has the ability to obtain approximately 80% of its energy from internal generation.  In 2012, NVE’s management continues to strive to optimize the Utilities’ energy portfolio in order to meet load obligations in a cost effective and reliable manner.  In addition, to the extent the Utilities have the economical opportunity to sell excess capacity or energy, they may enter into such transactions to reduce overall energy costs.  NVE anticipates it will have sufficient resources to meet its forecasted load requirements for 2012. However, resource adequacy could be affected by a number of factors, including the retirement of generating stations, plant outages, the timing of commercial operation of renewable energy projects and associated purchase power agreements, customer behavior with respect to energy efficiency and conservation programs, and environmental regulations which may limit our ability to operate certain generating units. 

The construction of the ON Line will enable us to optimize our transmission capabilities.  Upon completion, the ON Line will connect NVE’s southern and northern service territories and, pending certain state and federal regulatory approvals, will provide the ability to jointly dispatch energy throughout the state and provide access to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to manage its Portfolio Standard, discussed above, and optimize its generating facilities. 

ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South.  The Joint Project consists of two phases.  In Phase 1 of the Joint Project, the parties would complete construction of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  The Utilities own a 25% interest in ON Line and have entered into a TUA with GBT-South for its 75% interest in ON Line. The Utilities’ 25% interest in ON Line, which approximates $127 million, will be allocated 95% and 5% to NPC and SPPC, respectively.  The Utilities will have rights to 100% of the capacity of ON Line, which is estimated to be approximately 600 MW.  If GBT elects to construct Phase 2, it would construct two additional transmission segments at either end of ON Line: one extending from Robinson Summit north to Midpoint, Idaho, and the other commencing at the Harry Allen substation and interconnecting south to the Eldorado substation.  GBT would pay for and own 100% of Phase 2 facilities.  However, NPC and SPPC would have rights to additional transmission capacity from Midpoint to Eldorado (for a total of approximately 760 MW based on a rating of 2,000 MW for the complete path).

In March 2012, NVE announced that the in service date for the ON Line will be delayed due to on-going efforts to address wind-related damage sustained by some of the tower structures erected for the project.  As a result, NVE is also further delaying the merger application of the Utilities.  At this time, NVE does not anticipate that ON Line will be placed in service until the latter half of 2013. 

Engage employees to improve processes, reduce costs, and enhance performance

The Utilities will continue to control operating, maintenance and capital costs through diligent review and process improvement initiatives by providing appropriate tools to our employees to find ways to reduce costs, improve processes, and enhance performance.  This is particularly important at a time when customer growth is low.  Going forward this will continue to be an over-arching theme of our energy strategy. Our goal is to maintain, reduce, or eliminate upward pressure on our customers’ prices while always delivering safe and reliable energy and assure compliance with all laws and regulations.

Managing Regulatory Environment

The Utilities’ most recent GRC’s provide an opportunity to earn a 10% ROE and 10.1% ROE for NPC and SPPC, respectively.  However, assets not currently included in rate base or that the Utilities are not allowed to earn a return, affect their ability to achieve their allowed ROE.  See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K, for details of regulatory assets not included in rate base or not earning a return.  Other items which may not earn a return are certain plant assets completed between GRC filings or that were not requested in a GRC.  The Utilities are required to file rate cases every three years to adjust general rates in order to recover their cost of service and return on investment.  In addition, the Utilities are

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required to file a triennial IRP which is a comprehensive plan that considers customer energy requirements and proposes the resources to meet that requirement.  Historically, resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes.  Between IRP filings, the Utilities may seek PUCN approval for modifications to their resource plans and for power purchases.  The Utilities remain focused on communicating with regulators the necessity of investments to better serve our customers, the prudency of the costs incurred, and the importance of a reasonable return on investment for our shareholders.  In 2012, the Utilities will continue to focus on reducing regulatory lag and stabilizing cash flow by filing quarterly applications to reset the BTER and DEAA rates.  Furthermore, the Utilities will file annual EEIR and EEPR base rate and amortization applications in an effort to recover these amounts in a timely manner. 

2012 Goals

Management cannot predict when economic recovery may occur in Nevada, but expects that the Nevada economy will continue to struggle for the next several years.  As such, our primary goals will focus on meeting the challenges discussed above by:

• Effectively adjusting our business decisions based on economic conditions in Nevada;

• Building a sustainable foundation for future requirements by executing our evolution of energy strategy:

• Continuing to meet system deployment milestones in order to achieve NV Energize project completion by 2012;

• Empower customers through more focused energy efficiency programs;

• Pursue cost effective renewable energy initiatives;

• Continued investment in cost effective energy efficiency and conservation programs;

• Optimizing the use of generation facilities;

• Construction of ON Line;

• Engage employees to improve processes, reduce costs, enhance performance; and

• Managing our regulatory environment.

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 $8.2 million of long term debt interest costs for the three months ended March 31, 2012 and 2011, respectively. 

For the period ended March 31, 2012, NPC and SPPC paid $39 million and $20 million respectively in dividends to NVE. 

On May 7, 2012, NPC declared dividends of $40 million.

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, 2012, compared to the same period in 2011, due to a decrease in cash from operating and investing activities, offset partially by a reduction in cash used by financing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to quarterly BTER adjustments and negative DEAA rates to refund prior period over collected balances to customers.  Also contributing to this decrease was a change in payment terms with energy counterparties from weekly to monthly settlements in mid-2011, expiration of rates to collect the deferred rate increase from NPC’s 2008 GRC, timing of property tax payments and open market purchases of common stock to settle stock awards.  These decreases were partially offset by higher BTGR rates resulting from NPC’s 2011 GRC, EEIR, over collections under the EEPR, a reduction in employee incentive pay and a reduction in purchases of coal for the Valmy Generating Station.

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Cash From Investing Activities. The change in cash from investing activities was primarily due to the receipt of proceeds from the sale of California Assets in 2011 and a decrease in the use of cash as a result of a decrease in construction activity primarily for the Harry Allen Generating Station expansion. 

Cash Used By Financing Activities. Cash used by financing activities decreased due to the repayment of draws under SPPC’s revolving credit facility in 2011 and a draw on NPC’s revolving credit facility in 2012.

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 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, 2012 was as follows (in millions):

Available Liquidity as of March 31, 2012 (in millions)
			NVE		NPC		SPPC
Cash and Cash Equivalents			$	33.4	$	38.7	$	23.9
	Balance available on Revolving Credit Facilities(1)			N/A		464.4		239.5
		Less Reduction for Hedging Transactions(2)		N/A		-		-
			$	33.4	$	503.1	$	263.4
(1)		As of May 7, 2012, NPC and SPPC had approximately $359.4 million and $239.5 million available under their revolving credit facilities,  which includes reductions for letters of credit and hedging transactions, as discussed further under NPC's and SPPC's Financing Transactions.
(2)		Reduction for hedging transactions reflects balances as of February 29, 2012.  NPC and SPPC are currently unhedged.

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 either 2012 or 2013.  In April 2012, NPC used $120 million from its revolving credit facility along with cash on hand to pay for the maturity of its General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million.  NPC does not have any other debt maturities in 2012; 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 in late 2013.  SPPC has no debt maturities in 2012.  However, SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013.

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 transition to more steady growth the amount of capital expenditures is expected to decline significantly.  Additionally, NVE’s and 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, current federal tax NOL and a decrease in capital expenditures, NVE and the Utilities expect to generate free cash flow.  The free cash flow may be used to reduce debt, increase dividend payout and for potential investment opportunities.   To meet long term maturing debt obligations, the Utilities may use a combination of internally generated funds, the Utilities’ revolving credit facilities, the issuance of long-term debt and/or equity and, in the case of the Utilities, capital contributions from NVE. 

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. 

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The ability to issue debt, as discussed later, is subject to certain covenant calculations which include 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’ utilization of their revolving credit facilities may be limited.  Additionally, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

As of May 7, 2012, NVE has approximately $22.9 million payable of debt service obligations remaining for 2012, which it intends to pay through dividends from subsidiaries.  (See Factors Affecting Liquidity-Dividends from Subsidiaries, below).  For the three months ended, March 31, 2012, NPC and SPPC paid dividends to NVE of approximately $39 million and $20 million, respectively.  On May 7, 2012, NPC declared dividends payable to NVE of $40 million.

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.

During the three months ended March 31, 2012, there were no material changes to contractual obligations as set forth in NVE’s 2011 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, 2012, NVE (consolidated) would be allowed to incur up to $2.7 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, 2012, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: $195 million Term Loan due 2014; and $315 million of its 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, 2012, NVE, NPC, SPPC and their subsidiaries had approximately $5.2 billion of debt and other obligations outstanding, consisting of approximately $3.5 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510 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 impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.

 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

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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.  NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P.  As of March 31, 2012, the ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NVE		Sr. Unsecured Debt	BB	Ba2	BB+
NPC		Sr. Secured Debt	BBB*	Baa2*	BBB*
SPPC		Sr. Secured Debt	BBB*	Baa2*	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 outlook for NVE, NPC and SPPC is Stable.  

                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, 2012 for all suppliers continuing to provide power under a WSPP agreement would approximate a $36.5 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.  Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements in the 2011 Form 10-K for further discussion.

   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 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.   

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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, 2012, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $54.3 million.  Of this amount, approximately $19.6 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 $34.7 million would be required if NPC’s Senior Secured ratings 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 under NPC’s and SPPC’s Financing Transactions, the availability under NPC’s and SPPC’s Credit Agreement 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. As a result of the suspension of the Utilities hedging programs, there was no negative mark-to-market exposure for NPC and SPPC as of May 7, 2012, that would impact credit availability.  If deemed prudent, the Utilities may still 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 contain 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 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 a net loss of approximately $1.3 million during the three months ended March 31, 2012, compared to a net loss of approximately $9.0 million for the same period in 2011. 

For the period ended March 31, 2012, NPC paid $39 million in dividends to NVE.  On May 7, 2012, NPC declared a dividend of $40 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).

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

			Three Months Ended March 31,
							Change from
			2012		2011		Prior Year %
Operating Revenues:			$	395,688	$	390,068	1.4	%
Energy Costs:
	Fuel for power generation			80,549		101,070	(20.3)	%
	Purchased power			81,531		95,566	(14.7)	%
	Deferred energy			2,171		6,730	(67.7)	%
Energy efficiency program costs				15,774		-	N/A
		Total Costs	$	180,025	$	203,366	(11.5)	%
Gross Margin			$	215,663	$	186,702	15.5	%

Gross margin increased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to an increase in BTGR revenue as a result of NPC’s 2011 GRC effective January 1, 2012.  See Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2011 Form 10-K.

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,
							Change from
Operating Revenues:			2012		2011		Prior Year %
	Residential		$	194,489	$	184,973	5.1	%
	Commercial			87,735		85,856	2.2	%
	Industrial			99,914		103,475	(3.4)	%
		Retail revenues		382,138		374,304	2.1	%
	Other			13,550		15,764	(14.0)	%
		Total Operating Revenues	$	395,688	$	390,068	1.4	%
Retail sales in thousands of MWhs
	Residential			1,536		1,528	0.5	%
	Commercial			957		915	4.6	%
	Industrial			1,652		1,697	(2.7)	%
Retail sales in thousands of MWhs				4,145		4,140	0.1	%
Average retail revenue per MWh			$	92.19	$	90.41	2.0	%

NPC’s retail revenues increased for the three months ended March 31, 2012, as compared to the same period in 2011 due to the implementation of new BTGR rates effective January 1, 2012 as a result of NPC’s 2011 GRC (See Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2011 Form 10-K).  Also contributing to the increase was the implementation of EEPR rates effective July 1, 2011 (See Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2011 Form 10-K).  These increases were partially offset by decreases in energy rates from NPC’s various BTER quarterly updates and the Deferred Energy case effective October 1, 2011 (see Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2011 Form 10-K).  The average number of retail customers increased by 1.4%, consisting of an increase in residential and commercial customers of 1.5% and 0.1%, respectively, and a decrease in industrial customers of 2.5%, compared to the same period in the prior year.

Electric Operating Revenues – Other decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to a decrease in rental income as a result of the sale of the wireless communications towers in 2011 and a decrease in connection fees. 

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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,
						Change from
		2012		2011		Prior Year %
Energy Costs
	Fuel for power generation	$	80,549	$	101,070	(20.3)	%
	Purchased power		81,531		95,566	(14.7)	%
Total Energy Costs		$	162,080	$	196,636	(17.6)	%
MWhs
	MWhs Generated (in thousands)		3,287		2,773	18.5	%
	Purchased Power (in thousands)		1,026		1,583	(35.2)	%
Total MWhs			4,313		4,356	(1.0)	%
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	24.51	$	36.45	(32.8)	%
	Average cost per MWh of Purchased Power	$	79.46	$	60.37	31.6	%
	Average total cost per MWh	$	37.58	$	45.14	(16.8)	%

Energy Costs and the average cost per MWh decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to a decrease in costs associated with hedging activities and lower natural gas prices.

• Fuel for generation costs and the average cost per MWh decreased for the three months ended March 31, 2012, primarily due to a decrease in costs associated with hedging activities and lower natural gas prices. Volume increased due to the addition of the Harry Allen Generating Station in May of 2011.

• Purchased power costs and MWhs decreased for the three months ended March 31, 2012, primarily due to increased internal generation. The average cost per MWh increased for the three months ended March 31, 2012, primarily due to an increase in renewable energy purchases, as mandated by the Portfolio Standard, and a decrease in traditional power purchases due to increased self generation, discussed above.

Deferred Energy
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Deferred energy	$	2,171	$	6,730	(67.7)	%

 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

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costs previously deferred.  Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

                Amounts for the three months ended March 31, 2012 and 2011 include amortization of deferred energy of $(35.2) million and $(17.9) million, respectively; and an over-collection of amounts recoverable in rates of $37.3 million and $24.6 million, respectively.

Other Operating Expenses
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Energy efficiency program costs	$	15,774	$	-	N/A
	Other operating expenses	$	66,462	$	65,101	2.1	%
	Maintenance	$	23,073	$	22,337	3.3	%
	Depreciation and amortization	$	64,990	$	57,673	12.7	%

Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K). Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense discussed below.  The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

Other operating expense increased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to amortization of energy efficiency and conservation costs and a reduction in capitalized costs as a result of a decrease in construction activity.  The increase was partially offset by lower lease expenses, bad debt expense and systems support costs.

Maintenance expense increased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to planned maintenance outages at the Higgins, Lenzie and Silverhawk Generating Stations, offset by planned maintenance outages that occurred in 2011 at the Reid Gardner and Navajo Generating Stations.   

Depreciation and amortization increased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to the expansion at Harry Allen Generating Station placed in service in May 2011, a January 2012 change in depreciation rates resulting from a recent depreciation study and other general plant in service increases.

Interest Expense
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Interest expense
	(net of AFUDC-debt: $1,179 and $5,790)	$	(54,405)	$	(52,033)	4.6	%

Interest expense increased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to a decrease in AFUDC as a result of the completion of the Harry Allen Generating Station in May 2011 and the issuance of the $250 million, Series Y, General and Refunding Mortgage Notes in May 2011.  The increase was partially offset by a reduction in interest expense due to the redemption of the $350 million, Series A, General and Refunding Mortgage Notes in June 2011.

Other Income (Expense)
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Interest income (expense) on regulatory items	$	(2,016)	$	635	(417.5)	%
	AFUDC-equity	$	1,413	$	7,098	(80.1)	%
	Other income	$	1,709	$	1,546	10.5	%
	Other expense	$	(1,346)	$	(2,732)	(50.7)	%

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The change in interest income (expense) on regulatory items for the three months ended March 31, 2012, compared to the same period in 2011, is primarily due to a decrease in interest income related to the deferred BTGR balance, discussed in Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2011 Form 10-K and increased interest costs related to the deferred gain on  NPC’s wireless towers sold in 2011 that is subject to the final accounting approval by the PUCN.  See Note 16, Assets Held for Sale, of the Notes to Financial Statements in the 2011 Form 10-K. 

AFUDC-equity decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to completion of the Harry Allen Generating Station in May 2011.

Other income increased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to an increase in income from investments.

Other expense decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to a decrease in donations and an adjustment for a deferred energy settlement in 2011.

Analysis of Cash Flows

NPC’s cash flows decreased during the three months ended March 31, 2012, compared to the same period in 2011, due to a decrease in cash from operating and financing activities, offset partially by a reduction in cash used by investing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to quarterly BTER adjustments and negative DEAA rates to refund prior period over collected balances.  Also contributing to the decrease was the expiration of rates to collect the deferred rate increase from NPC’s 2008 GRC, the timing of property tax and interest payments and open market purchases of common stock to settle stock awards.  These decreases were partially offset by higher BTGR rates resulting from NPC’s 2011 GRC, EEIR and over collections under the EEPR.

Cash Used By Investing Activities.The decrease in cash used by investing activities was primarily due to the completion of construction at the Harry Allen Generating Station in May 2011.

Cash From Financing Activities. Cash from financing activities decreased primarily due to a reduction in capital contribution from NVE and an increase in dividends paid to NVE.  These decreases were partially offset by a draw on NPC’s revolving credit facility in 2012.

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, 2012 was as follows (in millions):

Available Liquidity as of March 31, 2012 (in millions)
			NPC
Cash and Cash Equivalents			$	38.7
	Balance available on Revolving Credit Facility(1)			464.4
		Less Reduction for Hedging Transactions(2)		-
			$	503.1
(1)		As of May 7, 2012, NPC had approximately $359.4 million available under its revolving credit facility which includes reductions for letters of credit and hedging transactions, as discussed below under Financing Transactions.
(2)		Reduction for hedging transactions reflects balances as of February 29, 2012.  NPC is currently unhedged.

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. 

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In April 2012, NPC used $120 million from its revolving credit facility along with cash on hand to pay for the maturity of its General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million.  NPC does not have any other debt maturities in 2012; 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 in late 2013.  As of May 7, 2012, NPC has $120 million in borrowings on its revolving credit facility, not including letters of credit.

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 NPC transitions to more steady growth, the amount of capital expenditures is expected to decline significantly.  Additionally, NPC’s investment in generating stations in the past several years and more stable energy markets have positioned NPC to better manage 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.  The free cash flow may be used to reduce debt, increase dividend payout and for potential investment opportunities.   To meet long term maturing debt obligations, NPC 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 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.

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 NPC 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, 2012, NPC paid dividends to NVE of $39 million.  On May 7, 2012, NPC declared a dividend to NVE of $40 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.

During the three months ended March 31, 2012, there were no material changes to contractual obligations as set forth in NPC’s 2011 Form 10-K. 

Financing Transactions

$500 Million Revolving Credit Facility

In March 2012, NPC terminated its $600 million secured revolving credit facility which would have expired in April 2013 and replaced it with a $500 million revolving credit facility, maturing in March 2017 and secured by NPC’s General and Refunding Mortgage Bond, Series Z, in the aggregate principal amount of $500 million (the “NPC Credit Agreement”). The administrative agent for the NPC Credit Agreement remains Wells Fargo Bank, National Association.  NPC may use the facility for general corporate purposes and for the issuance of letters of credit. 

The rate for outstanding loans under the NPC Credit Agreement will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin.  The margin varies based upon NPC’s secured debt credit rating by S&P and Moody’s.  Currently, NPC’s applicable base rate margin is 0.50% and the LIBOR rate margin is 1.50%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The NPC Credit Agreement contains one financial maintenance covenant that requires NPC to 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. In the event that NPC did not meet the financial maintenance covenant or there is a different event of default, the NPC Credit Agreement would restrict dividends to NVE. Moreover, so long as NPC's senior secured debt remains rated investment grade by S&P and Moody's (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC's business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that NPC's

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senior secured debt rating were rated below investment grade by either S&P or Moody's, or investment grade by either S&P or Moody's but with a negative outlook, a representation concerning no material adverse change in NPC's business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

The NPC Credit Agreement provides for an event of default if there is a failure under NPC's other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.

Similar to the $600 million secured revolving credit facility that it replaced, the NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends.  These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements in the 2011 Form 10-K.

The NPC Credit Agreement contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the reduction in availability under the revolving credit facility to NPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of the Utilities' hedging program, there was no negative mark-to-market exposure for NPC as of May 7, 2012 that would impact borrowings.

Maturity of General and Refunding Mortgage Notes, Series I

In April 2012, NPC used $120 million from its revolving credit facility along with cash on hand to pay for the maturity of its General and Refunding Mortgage Notes, Series I, in an aggregate principal amount of $130 million. 

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 and its revolving credit facility agreement, and the terms of certain NVE debt.  As of March 31, 2012, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $725 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, 2012, 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 million; (2) to refinance up to approximately $322.5 million of long-term debt securities.  However, with the maturity of the General and Refunding Mortgage Notes, Series I, discussed above, such amount is reduced to $192.5 million of refinancing authority; 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, 2012 financial statements, NPC was in compliance with this covenant and could incur up to $2.5 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 $2.7 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.

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The NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada.  As of March 31, 2012, $4.0 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.5 billion of General and Refunding Mortgage Securities as of March 31, 2012.  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 and specific assets in CWIP.  The amount of bond capacity listed above does not include 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 NPC’s 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.  NPC’s senior secured debt is rated investment grade by three NRSRO’s:  Fitch, Moody’s and S&P.    As of March 31, 2012, the ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NPC		Sr. Secured Debt	BBB*	Baa2*	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 outlook for NPC is Stable.  

                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, 2012 for all suppliers continuing to provide power under a WSPP agreement would approximate a $36.5 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.  Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements in the 2011 Form 10-K for further discussion. 

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   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 one 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, 2012, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $54.3 million.  Of this amount, approximately $19.6 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 $34.7 million would be required if NPC’s Senior Secured ratings 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 under NPC’s Financing Transactions, the availability under NPC’s Credit Agreement is reduced by the amount of net negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of NPC’s hedging program, there was no negative mark-to-market exposure for NPC as May 7, 2012 that would impact credit availability.  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 contain 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.

Sierra Pacific Power Company

RESULTS OF OPERATIONS

SPPC recognized net income of $18.6 million for the three months ended March 31, 2012 compared to net income of $16.6 million for the same period in 2011. 

For the period ended March 31, 2012, SPPC paid $20 million in dividends 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  

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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,
						Change from
		2012		2011		Prior Year %
Operating Revenues:
	Electric	$	169,806	$	178,617	(4.9)	%
	Gas		45,922		72,294	(36.5)	%
		$	215,728	$	250,911	(14.0)	%
Energy Costs:
	Fuel for power generation		36,486		45,268	(19.4)	%
	Purchased power		35,585		39,450	(9.8)	%
	Gas purchased for resale		31,617		52,632	(39.9)	%
	Deferral of energy - electric - net		(12,670)		(11,931)	6.2	%
	Deferral of energy - gas - net		(1,240)		3,249	(138.2)	%
Energy efficiency program costs			3,651		-	N/A	%
	Total Costs	$	93,429	$	128,668	(27.4)	%
Cost by Segment:
	Electric	$	63,052	$	72,787	(13.4)	%
	Gas		30,377		55,881	(45.6)	%
		$	93,429	$	128,668	(27.4)	%
Gross Margin by Segment:
	Electric	$	106,754	$	105,830	0.9	%
	Gas		15,545		16,413	(5.3)	%
		$	122,299	$	122,243	-	%

Electric gross margin increased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to a marginal increase in usage per customer among the industrial class, offset by a slight decrease in customer growth for commercial and industrial customers. 

Gas gross margin decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to decreased customer usage as a result of warmer weather. 

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

Electric Operating Revenue
			Three Months Ended March 31,
							Change from
Operating Revenues:			2012		2011		Prior Year %
	Residential		$	61,360	$	64,047	(4.2)	%
	Commercial			58,712		62,087	(5.4)	%
	Industrial			33,070		34,491	(4.1)	%
		Retail  revenues		153,142		160,625	(4.7)	%
	Other			16,664		17,992	(7.4)	%
		Total Operating Revenues	$	169,806	$	178,617	(4.9)	%
Retail sales in thousands of MWhs
	Residential			600		595	0.8	%
	Commercial			659		655	0.6	%
	Industrial			633		603	5.0	%
Retail sales in thousands of MWhs				1,892		1,853	2.1	%
Average retail revenue per MWh			$	80.94	$	86.68	(6.6)	%

SPPC’s retail revenues decreased for the three months ended March 31, 2012 as compared to the same period in 2011, primarily due to decreases in retail energy rates as a result of SPPC’s various BTER quarterly updates and the annual Deferred Energy

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Case effective October 1, 2011, which also provided for quarterly DEAA updates beginning January 1, 2012. (See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2011 Form 10-K). These decreases were partially offset by increased retail rates due to the implementation of EEPR rates effective July 1, 2011. (See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2011 Form 10-K).  The average number of retail customers increased 0.3%, consisting of an increase in residential customers of 0.6% while commercial and industrial customers decreased by 1.1% and 3.7%, respectively. 

Electric Operating Revenues – Other decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to decreased sales of wholesale power to other utilities as a result of warmer winter weather.

Gas Operating Revenue
				Three Months Ended March 31,
								Change from
				2012		2011		Prior Year %
	Gas Operating Revenues:
		Residential		$	26,557	$	39,177	(32.2)	%
		Commercial			10,966		17,277	(36.5)	%
		Industrial			2,715		4,786	(43.3)	%
			Retail  Revenues		40,238		61,240	(34.3)	%
		Wholesale Revenues			4,830		10,178	(52.5)	%
		Miscellaneous			854		876	(2.5)	%
			Total Gas Revenues	$	45,922	$	72,294	(36.5)	%
	Retail sales in thousands of Dths
		Residential			3,708		3,962	(6.4)	%
		Commercial			1,879		2,001	(6.1)	%
		Industrial			476		571	(16.6)	%
	Retail sales in thousands of Dths				6,063		6,534	(7.2)	%
	Average retail revenue per Dth			$	6.64	$	9.37	(29.2)	%

SPPC’s retail gas revenues decreased for the three months ended March 31, 2012, compared to the same period in 2011 primarily due to decreased retail energy rates as a result of SPPC’s various BTER quarterly updates and the annual Natural Gas and Propane Deferred Rate Case effective October 1, 2011 which also provided for quarterly DEAA updates beginning January 1, 2012. (See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2011 Form 10-K). Retail revenues also decreased due to lower customer usage as a result of warmer 2012 winter weather.  For the three months ended March 31, 2012, the average number of retail customers increased 0.6%, consisting of an increase in residential customers of 0.6% and a decrease in the average number of commercial and industrial customers of 0.1% and 8.4%, respectively.

Wholesale revenues decreased for the three months ended March 31, 2012, compared to the same period in 2011 primarily due to less excess supply of gas.    

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

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		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
Energy Costs
	Fuel for power generation	$	36,486	$	45,268	(19.4)	%
	Purchased power		35,585		39,450	(9.8)	%
Total Energy Costs		$	72,071	$	84,718	(14.9)	%
MWhs
	MWhs Generated (in thousands)		1,178		1,049	12.3	%
	Purchased Power (in thousands)		1,011		1,099	(8.0)	%
Total MWhs			2,189		2,148	1.9	%
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	30.97	$	43.15	(28.2)	%
	Average cost per MWh of Purchased Power	$	35.20	$	35.90	(1.9)	%
	Average total cost per MWh	$	32.92	$	39.44	(16.5)	%

Energy costs and average cost per MWh decreased for the three months ended March 31, 2012, compared to the same period in 2011 primarily due to lower natural gas prices and a decrease in costs associated with hedging activities.

• The average cost per MWh of generated power decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to lower natural gas costs and a decrease in costs associated with hedging activities.  Fuel for generation volume increased due to higher reliance on internal generation.

• Purchased power costs and average cost per MWh decreased due to lower market prices, driven by lower natural gas costs.  Purchased power volume decreased due to the reliance on internal generation.

Gas Purchased for Resale
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Gas purchased for resale	$	31,617	$	52,632	(39.9)	%
	Gas purchased for resale (in thousands of Dths)		8,274		9,149	(9.6)	%
	Average cost per Dth	$	3.82	$	5.75	(33.6)	%

Gas purchased for resale and average cost per Dth decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to lower natural gas prices and a decrease in costs associated with hedging activities. The volume of gas purchased for resale decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to warmer weather in 2012.

Deferred Energy
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Deferral of energy - electric - net	$	(12,670)	$	(11,931)	6.2	%
	Deferral of energy - gas - net		(1,240)		3,249	(138.2)	%
		$	(13,910)	$	(8,682)

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.

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Deferred energy – electric for the three months ended March 31, 2012 and 2011 reflect amortization of deferred energy costs of ($25.5) million and ($25.1) million respectively; and an over-collection of amounts recoverable in rates of $12.8 million and $13.1 million, respectively. 

Deferred energy - gas for the three months ended March 31, 2012 and 2011 reflect amortization of deferred energy of ($13.4) million, and ($7.4) million, respectively; and an over-collection of amounts recoverable in rates of $12.2 million and $10.6 million respectively.

Other Operating Expenses
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Energy efficiency program costs	$	3,651	$	-	N/A	%
	Other operating expenses	$	36,432	$	40,216	(9.4)	%
	Maintenance	$	9,453	$	7,425	27.3	%
	Depreciation and amortization	$	25,872	$	25,429	1.7	%

Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (See Note 3, Regulatory Actions, of the Notes to Financial Statements of the 2011 Form 10-K). Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense discussed below.  The EEPR mechanism is designed such that conservation costs expense are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset. As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

Other operating expense decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to lower compensation costs, employee pension and benefit expenses, and to a lesser degree, a decrease in system support costs and lower uncollectible rates. 

Maintenance expense increased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to planned maintenance at the Tracy Generating Station.

Depreciation and amortization for the three months ended March 31, 2012, compared to the same period in 2011, did not change materially. 

Interest Expense
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Interest expense
	(net of AFUDC-debt: $416 and $420)	$	(16,973)	$	(16,946)	0.2	%

Interest expense did not change materially for the three months ended March 31, 2012, compared to the same period in 2011.  See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2011 Form 10-K for additional information regarding long-term debt.

Other Income (Expense)
		Three Months Ended March 31,
						Change from
		2012		2011		Prior Year %
	Interest income (expense) on regulatory items	$	(186)	$	(1,523)	(87.8)	%
	AFUDC-equity	$	519	$	544	(4.6)	%
	Other income	$	2,183	$	1,264	72.7	%
	Other expense	$	(1,335)	$	(1,594)	(16.2)	%

Interest income (expense) on regulatory items decreased for the three months ended March 31, 2012, compared to the same period in 2011, due to lower over-collected deferred energy balances in 2012. 

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AFUDC-equity did not change materially for the three months ended March 31, 2012, compared to the same period in 2011.

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

Other expense decreased for the three months ended March 31, 2012, compared to the same period in 2011, primarily due to a decrease in donations in 2012.

Analysis of Cash Flows

SPPC’s cash flows decreased during the three months ended March 31, 2012, compared to the same period in 2011, due to a decrease in cash from operating and investing activities, offset partially by a reduction in cash used by financing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to a change in payment terms with energy counterparties from weekly to monthly settlements in mid-2011, and the receipt of cash in 2011 under the affiliate tax sharing agreement.  Also contributing to the reduction were higher negative DEAA rates to refund prior period over collected balances to customers, the timing of property tax payments and open market purchases of common stock to settle stock awards.  These decreases were partially offset by collections for wholesale energy sales and a reduction in purchases of coal for the Valmy Generating Station.

Cash From Investing Activities.The change in cash from investing activities was primarily due to the receipt of proceeds from the sale of California Assets in 2011 and an increased capital expenditure for the NV Energize project in 2012.

Cash Used By Financing Activities.The decrease in cash used by financing activities is primarily due to a reduction in dividends to NVE and the repayment of draws under SPPC’s revolving credit facility in 2011.  

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, 2012 was as follows (in millions):

Available Liquidity as of March 31, 2012 (in millions)
			SPPC
Cash and Cash Equivalents			$	23.9
	Balance available on Revolving Credit Facility(1)			239.5
		Less Reduction for Hedging Transactions(2)		-
			$	263.4
(1)		As of May 7, 2012, SPPC had approximately $239.5 million available under its revolving credit facility which includes reductions for letters of credit and hedging transactions, as discussed below under Financing Transactions.
(2)		Reduction for hedging transactions reflects balances as of February 29, 2012.  SPPC is currently unhedged.

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 has no significant debt maturities in 2012.  However, SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013.  As of May 7, 2012, SPPC has no borrowings outstanding on its revolving credit facility, not including letters of credit. 

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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 SPPC transitions to more steady growth the amount of capital expenditures is expected to decline significantly.  Additionally, 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.  The free cash flow may be used to reduce debt, 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 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, 2012, SPPC paid dividends to NVE of $20 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, 2012, there were no material changes to contractual obligations as set forth in SPPC’s 2011 Form 10-K. 

Financing Transactions

$250 Million Revolving Credit Facility

In March 2012, SPPC terminated its $250 million secured revolving credit facility which would have expired in April 2013 and replaced it with a $250 million revolving credit facility, maturing in March 2017 and secured by SPPC’s General and Refunding Mortgage Bond, Series S, in the aggregate principal amount of $250 million (the “SPPC Credit Agreement”). The administrative agent for the SPPC Credit Agreement is Wells Fargo Bank, National Association.  SPPC may use the facility for general corporate purposes and for the issuance of letters of credit. 

The rate for outstanding loans under the SPPC Credit Agreement will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus 0.5% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin.  The margin varies based upon SPPC’s secured debt credit rating by S&P and Moody’s.  Currently, SPPC’s applicable base rate margin is 0.50% and the LIBOR rate margin is 1.50%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The SPPC Credit Agreement contains one financial maintenance covenant that requires SPPC to 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. In the event that SPPC did not meet the financial maintenance covenant or there is a different event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC's senior secured debt remains rated investment grade by S&P and Moody's (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC's business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that SPPC's senior secured debt rating were rated below investment grade by either S&P or Moody's, or investment grade by either S&P or Moody's but with a negative outlook, a representation concerning no material adverse change in SPPC's business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

The SPPC Credit Agreement provides for an event of default if there is a failure under SPPC's other financing agreements to meet certain payment terms or to observe other covenants that would result in an acceleration of payments due.

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Similar to the $250 million secured revolving credit facility that it replaced, the SPPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends.  These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions, of the Notes to Financial Statements in the 2011 Form 10-K.

The SPPC Credit Agreement contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the reduction in availability under the revolving credit facility to SPPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of the Utilities' hedging program, there was no negative mark-to-market exposure for SPPC as of May 7, 2012 that would impact borrowings.

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, 2012, 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, 2012, SPPC has financing authority from the PUCN for the period ending December 31, 2012, consisting of authority (1) to issue additional long term debt securities of up to $350 million; (2) to refinance approximately $348 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, 2012 financial statements, SPPC was in compliance with this covenant and could incur up to $878.4 million 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 $2.7 billion.

   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, 2012, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $773.0 millionof additional General and Refunding Mortgage Securities as of March 31, 2012.  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 and specific assets in CWIP.  The amount of bond capacity listed above does not include 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 SPPC’s Indenture, it will reduce the amount of securities issuable under the SPPC Indenture.

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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.  SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P.  As of March 31, 2012, the ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
SPPC	Sr. Secured Debt	BBB*	Baa2*	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 outlook for SPPC is Stable.  

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, 2012, 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.  Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements in the 2011 Form 10-K for further discussion.

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.

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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 under SPPC’s Financing Transactions, the availability under SPPC’s Credit Agreement is reduced by the amount of net negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility. As a result of the suspension of  SPPC’s hedging program, there was no negative mark-to-market exposure for SPPC as of May 7, 2012  that would impact credit availability.  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 contain a cross default 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 Notes to Financial Statements and in the 2011 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, 2012, 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):

					2012
					Expected Maturities
																										Fair
				2012			2013			2014			2015			2016			Thereafter			Total				Value
Long-Term Debt
	NVE
	Fixed Rate			$	-		$	-		$	195,000		$	-		$	-		$	315,000		$	510,000		$	536,851
		Average Interest Rate			-			-			2.81	%		-			-			6.25	%		4.93	%		-
	NPC
	Fixed Rate			$	130,000		$	-		$	125,000		$	250,000		$	210,000		$	2,545,000		$	3,260,000		$	3,917,837
		Average Interest Rate			6.5	%		-			7.38	%		5.88	%		5.95	%		6.47	%		6.42	%		-
	Variable Rate			$	-		$	-		$	-		$	-		$	-		$	188,775		$	188,775		$	182,699
		Average Interest Rate			-			-			-			-			-			0.84	%		0.84	%		-
	SPPC
	Fixed Rate			$	-		$	250,000		$	-		$	-		$	450,000		$	251,742		$	951,742		$	1,118,517
		Average Interest Rate			-			5.5	%		-			-			6.00	%		6.75	%		6.05	%		-
	Variable Rate			$	-		$	-		$	-		$	-		$	-		$	214,675		$	214,675		$	190,989
		Average Interest Rate			-			-			-			-			-			0.73	%		0.73	%		-
			TOTAL DEBT	$	130,000		$	250,000		$	320,000		$	250,000		$	660,000		$	3,515,192		$	5,125,192		$	5,946,893

Commodity Price Risk

                See the 2011 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, 2011.

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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 $41.6 million as of March 31, 2012, which compares to balances of $40.7 million at December 31, 2011. 

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, 2012, 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 2012 that have materially affected, or are reasonably likely to materially affect, the registrants’ internal controls over financial reporting. 

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 2011 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 2011 Form 10-K.

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

None.

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 Credit Agreement entered into on March 23, 2012, between Nevada Power Company d/b/a NV Energy and Wells Fargo Bank, National Association, as administrative agent, swingline lender and issuing bank, and the other lenders parties thereto.

10.2 Credit Agreement entered into on March 23, 2012, between Sierra Pacific Power Companyd/b/a NV Energy and Wells Fargo Bank, National Association, as administrative agent, swingline lender and issuing bank, and the other lenders parties thereto.

 (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.

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(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

*  XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.

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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, 2012	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date:  May 8, 2012	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, 2012	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date:  May 8, 2012	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, 2012	By:	/s/ Dilek L. Samil
		Dilek L. Samil
		Chief Financial Officer
		(Principal Financial Officer)
Date:  May 8, 2012	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Chief Accounting Officer
		(Principal Accounting Officer)

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